ML080440179

Safety Evaluation Report, Related to the License Renewal of Vermont Yankee Nuclear Power Station.

ML080440179
Person / Time
Site:	Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date:	01/31/2008
From:	Rowley J NRC/NRR/ADRO/DLR
To:
Rowley J, NRR/DLR/RLRB, 415-4053
References
Download: ML080440179 (770)

Text

[[:#Wiki_filter:Safety Evaluation Report Related to the License Renewal of Vermont Yankee Nuclear Power Station Docket No. 50-271 Entergy Nuclear Operations, Inc. U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation January 2008

THIS PAGE INTENTIONALLY LEFT BLANK. ABSTRACT This safety evaluation report (SER) documents the technical review of the Vermont Yankee Nuclear Power Station (VYNPS) license renewal application (LRA) by the United States (US) Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated January 25, 2006, Entergy Nuclear Operations, Inc. (ENO or the applicant) submitted the LRA in accordance with Title 10, Part 54, of the Code of Federal Regulations, Requirements for Renewal of Operating Licenses for Nuclear Power Plants. ENO requests renewal of the VYNPS operating license (Facility Operating License Number DPR-28) for a period of 20 years beyond the current expiration at midnight March 21, 2012. VYNPS is located approximately five miles south of Brattleboro, Vermont. The NRC issued the VYNPS construction permit on December 11, 1967, and the operating license on February 28, 1973. VYNPS is of a Mark 1 Boiling Water Reactor (BWR) design. General Electric supplied the nuclear steam supply system and Ebasco originally designed and constructed the plant. The VYNPS licensed power output is 1912 megawatt thermal with a gross electrical output of approximately 650 megawatt electric. This SER presents the status of the staffs review of information submitted through October January XX, 2007 2008, the cutoff date for consideration in the SER. The staff identified six confirmatory items which were resolved before the staff made a final determination on the LRA. SER Section 1.6 summarizes these items and their resolution. Section 6.0 provides the staff's final conclusion on the review of the VYNPS LRA. iii

THIS PAGE INTENTIONALLY LEFT BLANK. TABLE OF CONTENTS Abstract . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii Table of Contents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v Abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xiii 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-7 1.6 Summary of Confirmatory Items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-7 1.7 Summary of Proposed License Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-9 Structures and Components Subject to Aging Management Review . . . . . . . . . . . . . . . . . . . 2-1 2.1 Scoping and Screening Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1 2.1.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1 2.1.2 Summary of Technical Information in the Application . . . . . . . . . . . . . . 2-1 2.1.3 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 LRA Development . . . . . . . . . . . . 2-6 2.1.3.3 Training . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-6 2.1.3.4 Conclusion of Scoping and Screening Program Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-7 2.1.4 Plant Systems, Structures, and Components Scoping Methodology . . 2-7 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) . . 2-12 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 . . . . . . . . . 2-21 2.1.4.5 Mechanical Component Scoping . . . . . . . . . . . . . . . . . . . . . 2-24 2.1.4.6 Structural Component Scoping . . . . . . . . . . . . . . . . . . . . . . 2-27 2.1.4.7 Electrical Component Scoping . . . . . . . . . . . . . . . . . . . . . . . 2-28 2.1.4.8 Conclusion for Scoping Methodology . . . . . . . . . . . . . . . . . . 2-29 2.1.5 Screening Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-29 2.1.5.1 General Screening Methodology . . . . . . . . . . . . . . . . . . . . . 2-29 2.1.5.2 Mechanical Component Screening . . . . . . . . . . . . . . . . . . . 2-30 2.1.5.3 Structural Component Screening . . . . . . . . . . . . . . . . . . . . . 2-32 2.1.5.4 Electrical Component Screening . . . . . . . . . . . . . . . . . . . . . 2-33 2.1.5.5 Conclusion for Screening Methodology . . . . . . . . . . . . . . . . 2-35 2.1.6 Summary of Evaluation Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-35 2.2 Plant-Level Scoping Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-36 v

2.2.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-36 2.2.2 Summary of Technical Information in the Application . . . . . . . . . . . . . 2-36 2.2.3 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-36 2.2.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-38 2.3 Scoping and Screening Results: Mechanical Systems . . . . . . . . . . . . . . . . . . . 2-38 2.3.1 Reactor Coolant System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-40 2.3.1.1 Reactor Vessel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-43 2.3.1.2 Reactor Vessel Internals . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-45 2.3.1.3 Reactor Coolant Pressure Boundary . . . . . . . . . . . . . . . . . . 2-46 2.3.2 Engineered Safety Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-48 2.3.2.1 Residual Heat Removal . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-48 2.3.2.2 Core Spray . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-51 2.3.2.3 Automatic Depressurization . . . . . . . . . . . . . . . . . . . . . . . . . 2-52 2.3.2.4 High Pressure Coolant Injection . . . . . . . . . . . . . . . . . . . . . 2-53 2.3.2.5 Reactor Core Isolation Cooling . . . . . . . . . . . . . . . . . . . . . . 2-55 2.3.2.6 Standby Gas Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-56 2.3.2.7 Primary Containment Penetrations . . . . . . . . . . . . . . . . . . . 2-58 2.3.3 Auxiliary Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-59 2.3.3.1 Standby Liquid Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-59 2.3.3.2 Service Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-61 2.3.3.3 Reactor Building Closed Cooling Water . . . . . . . . . . . . . . . . 2-67 2.3.3.4 Emergency Diesel Generator . . . . . . . . . . . . . . . . . . . . . . . 2-69 2.3.3.5 Fuel Pool Cooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-70 2.3.3.6 Fuel Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-73 2.3.3.7 Instrument Air . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-75 2.3.3.8 Fire Protection-Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-77 2.3.3.9 Fire Protection-Carbon Dioxide . . . . . . . . . . . . . . . . . . . . . . 2-89 2.3.3.10 Heating, Ventilation, and Air Conditioning . . . . . . . . . . . . . 2-94 2.3.3.11 Primary Containment Atmosphere Control / Containment Atmosphere Dilution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-96 2.3.3.12 John Deere Diesel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-101 2.3.3.13 Miscellaneous Systems In-scope as required by 10 CFR 54.4(a)(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-103 2.3.3.13A Augmented Off-gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-103 2.3.3.13B Sampling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-105 2.3.3.13C Condensate Demineralizer . . . . . . . . . . . . . . . . . . . . . . . 2-106 2.3.3.13D RWCU Filter Demineralizer . . . . . . . . . . . . . . . . . . . . . . 2-107 2.3.3.13E Circulating Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-108 2.3.3.13F Demineralized Water . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-110 2.3.3.13G Feedwater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-112 2.3.3.13H MG Lube Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-113 2.3.3.13I Neutron Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-114 2.3.3.13J Potable Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-115 2.3.3.13K Radwaste, Liquid and Solid . . . . . . . . . . . . . . . . . . . . . . 2-116 2.3.3.13L Equipment Retired in Place . . . . . . . . . . . . . . . . . . . . . . 2-117 2.3.3.13M Reactor Water Clean-Up . . . . . . . . . . . . . . . . . . . . . . . . 2-118 2.3.3.13N Stator Cooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-121 2.3.3.13O HD & HV Instruments . . . . . . . . . . . . . . . . . . . . . . . . . . 2-122 vi

2.3.3.13P Air Evacuation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-123 2.3.3.13Q Building (Drainage System Components) . . . . . . . . . . . 2-124 2.3.3.13R Circulating Water Priming . . . . . . . . . . . . . . . . . . . . . . . 2-124 2.3.3.13S Extraction Steam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-125 2.3.3.13T Heater Drain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-126 2.3.3.13U Heater Vent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-127 2.3.3.13V Make-up Demineralizer . . . . . . . . . . . . . . . . . . . . . . . . . 2-128 2.3.3.13W Seal Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-129 2.3.3.13X Turbine Building Closed Cooling Water . . . . . . . . . . . . . 2-130 2.3.3.13Y Main Turbine Generator . . . . . . . . . . . . . . . . . . . . . . . . 2-131 2.3.3.13Z Turbine Lube Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-132 2.3.3.13AA Hydrogen Water Chemistry . . . . . . . . . . . . . . . . . . . . . 2-133 2.3.4 Steam and Power Conversion Systems . . . . . . . . . . . . . . . . . . . . . . 2-135 2.3.4.1 Auxiliary Steam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-135 2.3.4.2 Condensate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-136 2.3.4.3 Main Steam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-138 2.3.4.4 101 (Main Steam, Extraction Steam, and Auxiliary Steam Instruments) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-139 2.4 Scoping and Screening Results: Structures . . . . . . . . . . . . . . . . . . . . . . . . . . 2-140 2.4.1 Primary Containment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-141 2.4.1.1 Summary of Technical Information in the Application . . . . 2-141 2.4.1.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-142 2.4.1.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-142 2.4.2 Reactor Building . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-143 2.4.2.1 Summary of Technical Information in the Application . . . . 2-143 2.4.2.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-144 2.4.2.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-144 2.4.3 Intake Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-144 2.4.3.1 Summary of Technical Information in the Application . . . . 2-144 2.4.3.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-145 2.4.3.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-147 2.4.4 Process Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-147 2.4.4.1 Summary of Technical Information in the Application . . . . 2-147 2.4.4.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-148 2.4.4.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-150 2.4.5 Yard Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-150 2.4.5.1 Summary of Technical Information in the Application . . . . 2-150 2.4.5.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-152 2.4.5.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-152 2.4.6 Bulk Commodities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-152 2.4.6.1 Summary of Technical Information in the Application . . . . 2-152 2.4.6.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-153 2.4.6.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-154 2.5 Scoping and Screening Results: Electrical and Instrumentation and Control Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-154 2.5.1 Summary of Technical Information in the Application . . . . . . . . . . . . 2-155 2.5.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-156 2.5.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-159 vii

2.6 Conclusion for Scoping and Screening . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-160 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-3 3.0.1.2 Overview of Table 2s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-3 3.0.2 Staff's Review Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-4 3.0.2.1 Review of AMPs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-5 3.0.2.2 Review of AMR Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-6 3.0.2.3 UFSAR Supplement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-6 3.0.2.4 Documentation and Documents Reviewed . . . . . . . . . . . . . . 3-6 3.0.3 Aging Management Programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-7 3.0.3.1 AMPs Consistent with the GALL Report . . . . . . . . . . . . . . . 3-10 3.0.3.2 AMPs Consistent with the GALL Report with Exceptions and/or Enhancements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-41 3.0.3.3 AMPs Not Consistent with or Not Addressed in the GALL Report

                             . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-110 3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-145 3.0.4.1 Summary of Technical Information in the Application . . . . 3-146 3.0.4.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-146 3.0.4.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-148 3.1 Aging Management of Reactor Vessel, Reactor Vessel Internals, and Reactor Coolant System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-148 3.1.1 Summary of Technical Information in the Application . . . . . . . . . . . . 3-148 3.1.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-149 3.1.2.1 AMR Results Consistent with the GALL Report . . . . . . . . . 3-168 3.1.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended . . . . . . . . . . . . . . . . . . . . . . . 3-180 3.1.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-193 3.1.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-199 3.2 Aging Management of Engineered Safety Features Systems . . . . . . . . . . . . . 3-199 3.2.1 Summary of Technical Information in the Application . . . . . . . . . . . . 3-200 3.2.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-200 3.2.2.1 AMR Results Consistent with the GALL Report . . . . . . . . . 3-210 3.2.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended . . . . . . . . . . . . . . . . . . . . . . . 3-220 3.2.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-231 3.2.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-241 3.3 Aging Management of Auxiliary Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-241 3.3.1 Summary of Technical Information in the Application . . . . . . . . . . . . 3-241 3.3.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-242 3.3.2.1 AMR Results Consistent with the GALL Report . . . . . . . . . 3-262 3.3.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended . . . . . . . . . . . . . . . . . . . . . . . 3-296 viii

3.3.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-319 3.3.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-361 3.4 Aging Management of Steam and Power Conversion Systems . . . . . . . . . . . 3-361 3.4.1 Summary of Technical Information in the Application . . . . . . . . . . . . 3-361 3.4.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-361 3.4.2.1 AMR Results Consistent with the GALL Report . . . . . . . . . 3-372 3.4.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended . . . . . . . . . . . . . . . . . . . . . . . 3-380 3.4.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-389 3.4.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-393 3.5 Aging Management of SC Supports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-393 3.5.1 Summary of Technical Information in the Application . . . . . . . . . . . . 3-393 3.5.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-393 3.5.2.1 AMR Results Consistent with the GALL Report . . . . . . . . . 3-408 3.5.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended . . . . . . . . . . . . . . . . . . . . . . . 3-428 3.5.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-457 3.5.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-476 3.6 Aging Management of Electrical and Instrumentation and Controls System . . 3-476 3.6.1 Summary of Technical Information in the Application . . . . . . . . . . . . 3-476 3.6.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-476 3.6.2.1 AMR Results Consistent with the GALL Report . . . . . . . . . 3-480 3.6.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended . . . . . . . . . . . . . . . . . . . . . . . 3-482 3.6.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-487 3.6.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-509 3.7 Conclusion for Aging Management Review Results . . . . . . . . . . . . . . . . . . . . 3-510 Time-limited Aging Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 4.1 Identification of Time-Limited Aging Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 4.1.1 Summary of Technical Information in the Application . . . . . . . . . . . . . . 4-1 4.1.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-2 4.1.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-2 4.2 Reactor Vessel Neutron Embrittlement Analyses . . . . . . . . . . . . . . . . . . . . . . . . 4-3 4.2.1 Reactor Vessel Fluence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-4 4.2.1.1 Summary of Technical Information in the Application . . . . . . 4-4 4.2.1.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-5 4.2.1.3 UFSAR Supplement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-6 4.2.1.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-7 4.2.2 Pressure-Temperature Limits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-7 4.2.2.1 Summary of Technical Information in the Application . . . . . . 4-7 4.2.2.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-8 4.2.2.3 UFSAR Supplement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-9 4.2.2.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-10 ix

4.2.3 Charpy Upper-Shelf Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-10 4.2.3.1 Summary of Technical Information in the Application . . . . . 4-10 4.2.3.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-11 4.2.3.3 UFSAR Supplement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-12 4.2.3.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-13 4.2.4 Adjusted Reference Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-13 4.2.4.1 Summary of Technical Information in the Application . . . . . 4-13 4.2.4.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-14 4.2.4.3 UFSAR Supplement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-15 4.2.4.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-15 4.2.5 Reactor Vessel Circumferential Welds Inspection Relief . . . . . . . . . . 4-15 4.2.5.1 Summary of Technical Information in the Application . . . . . 4-15 4.2.5.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-16 4.2.5.3 UFSAR Supplement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-19 4.2.5.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-19 4.2.6 Reactor Vessel Axial Weld Failure Probability . . . . . . . . . . . . . . . . . . 4-20 4.2.6.1 Summary of Technical Information in the Application . . . . . 4-20 4.2.6.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-20 4.2.6.3 UFSAR Supplement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-22 4.2.6.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-23 4.3 Metal Fatigue Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-23 4.3.1 Class 1 Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-23 4.3.1.1 Reactor Pressure Vessel . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-24 4.3.1.2 Reactor Vessel Internals . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-28 4.3.1.3 Class 1 Piping and Components . . . . . . . . . . . . . . . . . . . . . 4-29 4.3.2 Non-Class 1 Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-31 4.3.2.1 Summary of Technical Information in the Application . . . . . 4-31 4.3.2.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-31 4.3.2.3 UFSAR Supplement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-32 4.3.2.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-33 4.3.3 Effects of Reactor Water Environment on Fatigue Life . . . . . . . . . . . 4-33 4.3.3.1 Summary of Technical Information in the Application . . . . . 4-33 4.3.3.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-34 4.3.3.3 UFSAR Supplement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-38 4.3.3.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-38 4.4 Environmental Qualification Analyses for Electrical Components . . . . . . . . . . . 4-38 4.4.1 Summary of Technical Information in the Application . . . . . . . . . . . . . 4-39 4.4.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-39 4.4.3 UFSAR Supplement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-40 4.4.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-40 4.5 Concrete Containment Tendon Prestress Analysis . . . . . . . . . . . . . . . . . . . . . . 4-41 4.5.1 Summary of Technical Information in the Application . . . . . . . . . . . . . 4-41 4.5.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-41 4.5.3 UFSAR Supplement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-41 4.5.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-41 4.6 Containment Liner Plate, Metal Containment, and Penetrations Fatigue Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-41 4.6.1 Fatigue of the Torus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-41 x

4.6.1.1 Summary of Technical Information in the Application . . . . . 4-41 4.6.1.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-42 4.6.1.3 UFSAR Supplement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-42 4.6.1.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-42 4.6.2 Fatigue of Safety Relief Valve Discharge Piping . . . . . . . . . . . . . . . . 4-43 4.6.2.1 Summary of Technical Information in the Application . . . . . 4-43 4.6.2.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-43 4.6.2.3 UFSAR Supplement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-44 4.6.2.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-44 4.6.3 Fatigue of Other Torus-Attached Piping . . . . . . . . . . . . . . . . . . . . . . . 4-44 4.6.3.1 Summary of Technical Information in the Application . . . . . 4-44 4.6.3.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-44 4.6.3.3 UFSAR Supplement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-45 4.6.3.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-45 4.7 Other Time-Limited Aging Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-45 4.7.1 Reflood Thermal Shock of the Reactor Vessel Internals . . . . . . . . . . 4-45 4.7.1.1 Summary of Technical Information in the Application . . . . . 4-45 4.7.1.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-45 4.7.1.3 UFSAR Supplement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-46 4.7.1.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-46 4.7.2 Time- Limited Aging Analysis in BWRVIPs . . . . . . . . . . . . . . . . . . . . 4-46 4.7.2.1 BWRVIP-05, Reactor Vessel Axial Welds . . . . . . . . . . . . . . 4-46 4.7.2.2 BWRVIP-25, Core Plate . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-47 4.7.2.3 BWRVIP-38, Shroud Support . . . . . . . . . . . . . . . . . . . . . . . 4-50 4.7.2.4 BWRVIP-47, Lower Plenum Fatigue Analysis . . . . . . . . . . . 4-51 4.7.2.5 BWRVIP-48, Vessel ID Attachment Welds Fatigue Analysis

                                      ...............................................                                                4-52 4.7.2.6 BWRVIP-49, Instrument Penetrations Fatigue Analysis . . .                                           4-52 4.7.2.7 BWRVIP-74, Reactor Pressure Vessel . . . . . . . . . . . . . . . .                                  4-53 4.7.2.8 BWRVIP-76, Core Shroud . . . . . . . . . . . . . . . . . . . . . . . . . .                          4-54 4.8 Conclusion for Time-Limited Aging Analyses . . . . . . . . . . . . . . . . . . . . . . . . . .                              4-55 Review by the Advisory Committee on Reactor Safeguards . . . . . . . . . . . . . . . . . . . . . . . . . 5-1 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 Appendix A: VYNPS License Renewal Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1 Appendix B: Chronology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-1 Appendix C: Principal Contributors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-1 Appendix D: References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . D-1 xi

Tables Table 1.4-1 Current Interim Staff Guidance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-7 Table 3.0.3-1 VYNPS Aging Management Programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-7 Table 3.1-1 Staff Evaluation for Reactor Vessel, Reactor Vessel Internals, and Reactor Coolant System Components in the GALL Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-150 Table 3.2-1 Staff Evaluation for Engineered Safety Features Systems Components in the GALL Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-201 Table 3.3-1 Staff Evaluation for Auxiliary System Components in the GALL Report . . . . 3-243 Table 3.3-2 AMR Line Items for Elastomer Penetration Sealants . . . . . . . . . . . . . . . . . . . 3-287 Table 3.3-3 AMR Line Item for Elastomer Seismic Isolation Joints . . . . . . . . . . . . . . . . . 3-289 Table 3.4-1 Staff Evaluation for Steam and Power Conversion Systems Components in the GALL Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-362 Table 3.5-1 Staff Evaluation for SC Supports in the GALL Report . . . . . . . . . . . . . . . . . . 3-394 Table 3.5-2 Groundwater and Soil Sample Data from April 2002 Through April 2006 . . . 3-460 Table 3.6-1 Staff Evaluation for Electrical and I&C Components in the GALL Report . . . 3-477 xii

ABBREVIATIONS AAC alternate AC AC alternating current ACAR aluminum conductor alloy reinforced ACI American Concrete Institute ACRS Advisory Committee on Reactor Safeguards ACS alternate cooling system ACSR aluminum core steel reinforced ADAMS Agencywide Document Access and Management System ADS automatic depressurization system AE air evacuation AEC Atomic Energy Commission AERM aging effect requiring management AFW auxiliary feedwater AISC American Institute of Steel Construction AM aging management AMP aging management program AMR aging management review ANSI American National Standards Institute AOG augmented off-gas APCSB Auxiliary and Power Conversion Systems Branch ART adjusted reference temperature AS auxiliary system ASME American Society of Mechanical Engineers ASTM American Society for Testing and Materials ATWS anticipated transient without scram AWWA American Water Works Association BAF bottom of the active fuel BLD building drainage system BOP balance of plant B&PV Boiler and Pressure Vessel BTP Branch Technical Position BWR boiling water reactor BWRVIP Boiling Water Reactor Vessel and Internals Project CAD containment atmosphere dilution CAP corrective action program CASS cast austenitic stainless steel CBI Chicago Bridge & Iron CCW closed cooling water CCWS closed cooling water system CD condensate demineralizer CDF core damage frequency CEA control element assembly CF chemistry factor xiii

CFR Code of Federal Regulations CI confirmatory item CLB current licensing basis CMAA Crane Manufactures Association of America CO2 carbon dioxide CPPU constant pressure power uprate CRL component record list CRD control rod drive CRGT control rod guide tube CS core spray CSS core spray system CSCS core standby cooling system CST condensate storage and transfer CUF cumulative usage factor CUFD reactor water cleanup unit filter demineralizer CvUSE Charpy upper-shelf energy CW circulating water CWP circulating water priming DBA design basis accident DBE design basis event DC direct current DG diesel generator DLO diesel lube oil DW demineralized water ECCS emergency core cooling system EDG emergency diesel generator EFPD effective full power days EFPY effective full-power year EIC electrical and instrumentation and control EMPAC Enterprise Maintenance, Planning, and Control ENO Entergy Nuclear Operations, Inc. Entergy VY Entergy Nuclear Vermont Yankee, LLC EOL end of life EPRI Electric Power Research Institute EPRI-MRP Electric Power Research Institute Materials Reliability Program EPU Extended Power Uprate EQ Environmental qualification ER Applicant's Environmental Report - Operating License Renewal Stage ES extraction steam ESF engineered safety feature FAP fatigue action plan FCV flow control valve FW feedwater Fen environmental fatigue life correction factor FERC Federal Energy Regulatory Commission xiv

FF flency factor FIV flow-induced vibration FO fuel oil FPC fuel pool cooling FPFD fuel pool filter-demineralizer FR Federal Register FSAR final safety analysis report ft-lb foot-pound FW feedwater GALL Generic Aging Lessons Learned Report GDC general design criteria or general design criterion GE General Electric GEIS Generic Environmental Impact Statement GL generic letter GSC gland seal condenser GSI generic safety issue HB heating boiler HCU hydraulic control unit HD heater drain HELB high-energy line break HPCI high pressure coolant injection HPCIS high pressure coolant injection system HPSI high pressure safety injection HVAC heating, ventilation, and air conditioning HV heater vent HWC hydrogen water chemistry HX heat exchanger I&C instrumentation and controls IA instrument air IASCC irradiation assisted stress corrosion cracking ID inside diameter IEEE Institute of Electrical and Electronics Engineers IGA intergranular attack IGSCC intergranular stress corrosion cracking IN information notice INEL Idaho National Engineering Laboratory INPO Institute of Nuclear Power Operations IPA integrated plant assessment IPE individual plant examination IR insulation resistance ISA Instrument Society of America ISG interim staff guidance ISI inservice inspection ISP integrated surveillance program xv

IST inservice testing JDD John Deere diesel ksi 1000 pounds per square inch KV or kV kilo-volt KW kilo-watt LOCA loss of coolant accident LPCI low pressure coolant injection LRA license renewal application LRBD license renewal boundary drawings LRIS License Renewal Information System LRPG license renewal project guideline MEB metal-enclosed bus MeV mega-electron volt MG motor generator MGLO motor generator lube oil MIC microbiologically influenced corrosion MS main stream MSIV main stream isolation valve MUD make-up demineralizer MWe megawatts-electric MWt megawatts-thermal N2 nitrogen NaOH sodium hydroxide NB nuclear boiler NBVIS nuclear boiler vessel instrumentation system n/cm2 neutrons per square centimeter NDE nondestructive examination NEI Nuclear Energy Institute NESC National Electric Safety Code NFPA National Fire Protection Association NPS nominal pipe size NRC US Nuclear Regulatory Commission NSAC Nuclear Science Advisory Committee NSSS nuclear steam supply system NUMARC Nuclear Management and Resources Council (now NEI) NUREG US Nuclear Regulatory Commission Regulatory Guide NUREG/CR US Nuclear Regulatory Commission Regulatory Guide contractor report NWC normal water chemistry ODSCC outside-diameter stress corrosion cracking OE operating experience OI open item xvi

PASS post-accident sampling system PCAC primary containment atmosphere control pH potential hydrogen P&ID piping and instrumentation diagram ppm parts per million P-T pressure-temperature PTS pressurized thermal shock PUSAR power uprate safety analysis report PVC polyvinyl chloride PW potable water PWR pressurized water reactor PWSCC primary water stress corrosion cracking QA quality assurance Q&A question and answer RAI request for additional information RBCCW reactor building closed cooling water RCIC reactor core isolation cooling RCPB reactor coolant pressure boundary RCS reactor coolant system RDW radwaste RFO refueling outage RG regulatory guide RHRS residual heat removal system RHRSW residual heat removal service water RIP retired in place RPV reactor pressure vessel RRP reactor recirculation pump RRS reactor recirculation system RT radiographic testing RTD resistance temperature detector RTNDT reference temperature nil ductility transition RV reactor vessel RVI reactor vessel internals RVID reactor vessel integrity database RWCU reactor water cleanup SA service air SBFPC standby fuel pool cooling SBGT standby gas treatment SBO station blackout SC structure and component SCC stress-corrosion cracking SE safety evaluation SER safety evaluation report SFP spent fuel pool SIF stress intensification factor xvii

SLC standby liquid control SO seal oil SPL sampling SOC statement of consideration SRP Standard Review Plan SRP-LR Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants SRV safety relief valve SS stainless steel SSC system, structure, and component SSE safe-shutdown earthquake SW service water SWS service water systems TBCCW turbine building closed cooling water TG turbine generator TLAA time-limited aging analysis TLO turbine lube oil TS technical specifications UFSAR updated final safety analysis report USAR updated safety analysis report USAS United States of America Standard USE upper-shelf energy UT ultrasonic testing UV ultra violet VHS Vernon Hydroelectric Station VT visual testing VYNPS Vermont Yankee Nuclear Power Station 1/4 T one-fourth of the way through the vessel wall xviii

SECTION 1 INTRODUCTION AND GENERAL DISCUSSION 1.1 Introduction This document is a safety evaluation report (SER) on the license renewal application (LRA) for Vermont Yankee Nuclear Power Station (VYNPS), as filed by Entergy Nuclear Operations, Inc. (ENO or the applicant). By letter dated January 25, 2006, ENO submitted its application to the United States (US) Nuclear Regulatory Commission (NRC) for renewal of the VYNPS 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, of the Code of Federal Regulations, Requirements for Renewal of Operating Licenses for Nuclear Power Plants (10 CFR Part 54). The NRC project manager for the license renewal review is Jonathan Rowley. Mr. Rowley may be contacted by telephone at 301-415-4053 or by electronic mail at JGR@nrc.gov. Alternatively, written correspondence may be sent to the following address: Division of License Renewal US Nuclear Regulatory Commission Washington, DC 20555-0001 Attention: Jonathan Rowley, Mail Stop 011-F1 In its January 25, 2006 submission letter, the applicant requested renewal of the operating license issued in accordance with Section 104b (Operating License No. DPR-28) of the Atomic Energy Act of 1954, as amended, for VYNPS for a period of 20 years beyond the current expiration at midnight March 21, 2012. VYNPS is located approximately five miles south of Brattleboro, Vermont. The NRC issued the VYNPS construction permit on December 11, 1967, and the operating license on February 28, 1973. VYNPS is of a Mark 1 Boiling Water Reactor (BWR) design. General Electric supplied the nuclear steam supply system (NSSS) and Ebasco originally designed and constructed the plant. The VYNPS licensed power output is 1912 megawatt thermal with a gross electrical output of approximately 650 megawatt electric. 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 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 VYNPS license renewal is based on the applicants LRA and responses to staff requests for additional information. The applicant supplemented the LRA and provided clarifications through its responses to the staffs requests for additional information in audits, meetings, and docketed correspondence. Unless otherwise noted, the staff reviewed and considered information submitted through July 3, 2007 January XX, 2008. The staff reviewed information received after that date case by case depending on the stage of the safety review and the volume and complexity of the information. The public may view the LRA and all pertinent information and materials, including the UFSAR, at the NRC Public Document Room, on the first floor of One White Flint North, 11555 Rockville Pike, Rockville, MD 20852-2738 1-1

(301-415-4737 / 800-397-4209), and at Dickinson Memorial Library, 115 Main St., Northfield, MA 01360. 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. This SER summarizes the results of the staffs safety review of the LRA and describes the technical details considered in evaluating the safety aspects of the units proposed operation for an additional 20 years beyond the term of the current operating license. The staff reviewed the LRA in accordance with the NRC regulations and the guidance in the US NRC 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 through 4 address the staffs evaluation of license renewal issues considered during the review of the LRA. SER Section 5 is reserved for the report of the Advisory Committee on Reactor Safeguards (ACRS). SER Section 6 presents the conclusions of this report. SER Appendix A is a table of the applicants commitments for renewal of the operating license. SER Appendix B is a chronology of the principal correspondence between the staff and the applicant on the LRA review. SER Appendix C is a list of principal contributors to this SER. Appendix D is a bibliography of the references in support of the staffs review. In accordance with 10 CFR Part 51, the staff prepared a plant-specific supplement to NUREG-1437, Generic Environmental Impact Statement for License Renewal of Nuclear Plants (GEIS). This supplement discusses the environmental considerations related to the VYNPS license renewal. The staff issued a plant-specific supplement to the GEIS, Generic Environmental Impact Statement for License Renewal of Nuclear Plants Supplement 30 Regarding Vermont Yankee Nuclear Power Station, on August 1, 2007. 1.2 License Renewal Background Pursuant to the Atomic Energy Act of 1954, as amended, and NRC regulations, operating licenses for commercial power reactors are issued for 40 years. These licenses can be renewed for up to 20 additional years. The original 40-year license term was selected on the basis of economic and antitrust considerations, rather than on technical limitations; however, some individual plant and equipment designs may have been engineered based on 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 for life extension of 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. 1-2

In 1991, the staff published the license renewal rule in 10 CFR Part 54 (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 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 license renewal. However, during the demonstration program, the staff found that many aging effects on plant systems and components are managed during the period of initial license. In addition, the staff found that the scope of the review did not allow sufficient credit for existing programs, particularly the implementation of 10 CFR 50.65, which also manages plant-aging phenomena. As a result, the staff amended 10 CFR Part 54 in 1995. As published in 60 FR 22461, dated May 8, 1995, 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 process. In particular, as amended, 10 CFR Part 54 focuses on the management of adverse aging effects rather than on identifying age-related degradation unique to license renewal. The staff initiated these rule changes to ensure that important systems, structures, and components (SSCs) will continue to perform their intended functions during periods of extended operation. In addition, the revised 10 CFR Part 54 rule clarifies and simplifies the integrated plant assessment for consistency with the revised focus on passive, long-lived structures and components (SCs). In parallel with these initiatives, the NRC pursued a separate rulemaking effort (61 FR 28467, dated June 5, 1996) and developed an amendment to 10 CFR Part 51 to focus the scope of the review of license renewal environmental impacts and to fulfill the NRCs responsibilities in accordance with 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 exception 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 that (1) are safety-related, (2) the failure of which could affect safety-related functions, or (3) are relied on for compliance with the NRC fire protection, environmental qualification (EQ), pressurized thermal shock (PTS), anticipated transient without scram (ATWS), and station blackout (SBO) regulations. 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). SCs subject to an AMR perform an intended function without moving parts or without a change in configuration or properties and are not subject to replacement after a qualified life or specified time period. As required by 10 CFR 54.21(a), license renewal applicants must demonstrate that the aging effects will be managed so that the intended function(s) of those SCs will be 1-3

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 are readily detectable and can be 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. Pursuant to 10 CFR 54.21(d), the LRA is required to include a UFSAR supplement that must have a summary description of the applicants 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 were made about the length of time the plant can operate. These assumptions were 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 2001, the NRC developed and issued Regulatory Guide (RG) 1.188, Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses. This RG endorses Nuclear Energy Institute (NEI) 95-10, Revision 3, Industry Guideline for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule, issued in March 2001. NEI 95-10 details an acceptable method of implementing 10 CFR Part 54. The staff also used the SRP-LR in reviewing 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 the aging of many SCs subject to an AMR. If an applicant commits to implementing these staff-approved AMPs, the time, effort, and resources to review the LRA can be greatly reduced, 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 SCs throughout the industry. The report is also a quick reference for both the applicant and staff reviewers to AMPs and activities that can provide adequate aging management during the period of extended operation. 1.2.2 Environmental Review Part 51 of 10 CFR governs environmental protection regulations. In December 1996, the staff revised the environmental protection regulations to facilitate the environmental review for license renewal. The staff prepared the Generic Environmental Impact Statement (GEIS) to document its evaluation of the possible environmental impacts of nuclear power plant license renewals. For certain environmental impacts, the GEIS establishes findings applicable to all nuclear power plants. These generic findings are codified in Appendix B, Environmental Effect of Renewing the Operating License of a Nuclear Power Plant, to Subpart A, National 1-4

Environmental Policy Act - Regulations Implementing Section 102(2), of 10 CFR Part 51. Pursuant to 10 CFR 51.53(c)(3)(i), license renewal applicants may incorporate these generic findings in their environmental reports. In accordance with 10 CFR 51.53(c)(3)(ii), an environmental report must also 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 the GEIS had not considered new and significant information. As part of its scoping process, the staff held a public meeting on June 7, 2006, in Brattleboro, Vermont, to identify plant-specific environmental issues. Draft, plant-specific GEIS Supplement 30 documents the results of the environmental review and makes a preliminary recommendation as to the license renewal action. The staff held another public meeting on January 31, 2007, in Brattleboro, Vermont, to discuss draft, plant-specific GEIS Supplement 30. 1.3 Principal Review Matters Part 54 of 10 CFR describes the requirements for renewing operating licenses for nuclear power plants. The staffs technical review of the LRA was in accordance with NRC guidance and the requirements of 10 CFR Part 54. Section 54.29, Standards for Issuance of a Renewed License, of 10 CFR sets forth the standards for license renewal. This SER describes the results of the staffs safety review. In accordance with 10 CFR 54.19(a), the NRC requires license renewal applicants to submit general information. The applicant provided this general information in LRA Section 1. The staff reviewed LRA Section 1 and finds that the applicant has submitted the information required by 10 CFR 54.19(a). In accordance with 10 CFR 54.19(b), the NRC requires that LRAs include conforming changes to the standard indemnity agreement, 10 CFR 140.92, Appendix B, to account for the expiration term of the proposed renewed license. On this issue, in the LRA, the applicant stated: The agreement shall terminate at the time of expiration of the license specified in Item 3 of the attachment to the agreement, which is the last to expire. Item 3 of the attachment to the indemnity agreement, as revised by Amendment No. 6, lists VYNPS operating license number DPR-28. ENO requests that conforming changes be made to Article VII of the indemnity agreement, and Item 3 of the attachment to that agreement, specifying the extension of agreement until the expiration date of the renewed VYNPS facility operating license sought in this application. In addition, should the license number be changed upon issuance of the renewal license, ENO requests that conforming changes be made to Item 3 of the attachment and other sections of the indemnity agreement as appropriate. The staff intends to maintain the original license number upon issuance of the renewed license, if approved. Therefore, conforming changes to the indemnity agreement need not be made and the requirements of 10 CFR 54.19(b) have been met. 1-5

In accordance with 10 CFR 54.21,Contents of Application - Technical Information, the NRC requires that LRAs contain (a) an integrated plant assessment, (b) a description of any current licensing basis (CLB) changes occurring during the staffs review of the LRA, (c) an evaluation of TLAAs, and (d) a UFSAR supplement. LRA Sections 3 and 4 and Appendix B address the license renewal requirements of 10 CFR 54.21(a), 10 CFR 54.21(b), and 10 CFR 54.21(c). LRA Appendix A satisfies the license renewal requirements of 10 CFR 54.21(d). In accordance with 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 staffs review, the applicant submit an LRA amendment identifying any CLB changes of the facility that materially affect the contents of the LRA, including the UFSAR supplement. In accordance with 10 CFR 54.22, Contents of Application - Technical Specifications, the NRC requires that the LRA include changes or additions to the technical specifications necessary to manage the aging effects during the period of extended operation. In LRA Appendix D, the applicant stated that it had not identified any technical specification changes necessary to support issuance of the renewed VYNPS operating license. This statement adequately addresses the 10 CFR 54.22 requirement. 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 staffs evaluation of the technical information in the LRA. 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 staffs LRA review and SER. SER Section 5 will incorporate the ACRS report when issued. SER Section 6 will document the findings required by 10 CFR 54.29. The final, plant-specific GEIS Supplement 30 will document the staffs evaluation of the environmental information required by 10 CFR 54.23, Contents of Application - Environmental Information, and will specify the considerations related to the VYNPS operating license renewal. The staff will prepare this supplement separately from the SER. 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 staffs 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 the GALL Report. Table 1.4-1 shows the current set of interim staff guidance (ISGs), as well as the SER sections in which the staff addresses them. 1-6

Table 1.4-1 Current Interim Staff Guidance ISG Issue Purpose SER Section (Approved ISG Number) Nickel-alloy components in the Cracking of nickel-alloy Not applicable [Pressurized Water reactor coolant pressure boundary components in the reactor pressure Reactors (PWRs )only] (LR-ISG-19B) boundary. ISG under development. NEI and EPRI-MRP 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 EPRI-MRP. Corrosion of drywell shell in Mark I To address concerns related to 3.5.2.2.1 containments corrosion of drywell shell in Mark I (LR-ISG-2006-01) containments. 1.5 Summary of Open Items As a result of its review of the LRA, including additional information submitted to the staff through July 3, 2007, the staff determined that no open items exist which would require a formal response from the applicant. An item would have been considered open if the applicant had not presented a sufficient basis for resolution of an issue. 1.6 Summary of Confirmatory Items As a result of its review of the LRA, including additional information submitted to the staff through March 23, 2007, the staff identified the following confirmatory items (CIs). An item was considered confirmatory if the staff and the applicant had reached a satisfactory resolution, but the resolution had not been submitted to the staff. Each CI was assigned a unique identifying number. By letters dated July 3, July 30, and August 16, 2007, the applicant responded to these CIs. The staff reviewed these responses and closed each of the CIs. The basis for closing the CIs is as follows: CI 2.3.3.2a-1 License renewal drawing LRA-G-191159-SH-01-0, at location H-11, depicts pipe section 2-SW-566C as within the scope of license renewal. The license renewal boundary flag for 2-SW-566C is located on an unisolable section of pipe. The actual location of the license renewal scope boundary for this pipe section is not clear. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components meet the requirements of 10 CFR 54.4(a)(2). 1-7

In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the regional inspection team stated in part that the applicant has included in-scope for spatial interaction the portion of the SW system in the service water pump area of the intake structure and the reactor building. Pipe section 2" SW-566C is in the reactor building and is therefore in-scope for spatial interaction. As described in LRA Section 2.1.2.1.3, portions of systems included for 10 CFR 54.4(a)(2) are not shown on LRA drawings. Further, the applicant's letter to the NRC dated July 3, 2007, LRA Amendment 27, Attachment 2 indicates that pipe section 4" SW-567 which attaches to pipe section 2" SW-566C is in-scope for spatial interaction. Based on its review, the staff found the above response acceptable because the inspection team and the applicant acknowledged that service water pipe 2" SW-566C is within the scope of license renewal and subject to an AMR based on the potential for physical interaction with safety-related systems in accordance with 10 CFR 54.4(a)(2). Therefore, the staff concern described in Inspection Item 2.3.3.2a-1 is resolved. CI 2.3.3.2a-2 LRA Section 2.1.2.1.2 states in part that nonsafety-related piping systems connected to safety-related systems were included up to the structural boundary or to a point that includes an adequate portion of the nonsafety-related piping run to conservatively include the first seismic or equivalent anchor. In addition, if isometric drawings were not readily available to identify the structural boundary, connected lines were included to a point beyond the safety/nonsafety interface, like a base-mounted component, flexible connection, or the end of a piping run (i.e, a drain line). It is not clear whether the nonsafety-related piping systems were included up to the structural boundary or to a point that includes an adequate portion of the nonsafety-related piping run to include the first seismic or equivalent anchor. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components satisfy the requirements of 10 CFR 54.4(a)(2). In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team stated in part that for structural support considerations, the applicant has included components outside the safety class pressure boundary, yet relied upon to provide structural/seismic support for the pressure boundary. The application describes the types of components which are included in the scope of license renewal for 10 CFR 54.4(a)(2) and subject to an AMR in the service water system in LRA Table 2.3.3-13-42. This table was developed by including all nonsafety-related portions of fluid systems which are located within a building containing safety-related components and all nonsafety-related piping connected to safety-related systems back to the structural boundary using an isometric drawing. In cases where an isometric drawing which depicts the structural boundary is not readily available, connected lines were included back to a point beyond the 1-8

safety/nonsafety interface to a base-mounted component, flexible connection, or the end of a piping run (such as a drain line) in accordance with the response to RAI 2.1-2. As described in LRA Section 2.1.2.1.3, portions of systems included for 10 CFR 54.4(a)(2) are not shown on LRA drawings. Further, the applicant's letter to the NRC dated July 3, 2007, LRA Amendment 27, Attachment 2 states that there are no nonsafety-related systems for which the applicant has not identified the nonsafety-related portions of systems which are attached to safety-related systems and required to be in the scope of license renewal in accordance with 10 CFR 54.4(a)(2). However, as a result of discussions with the staff during the Region I inspection (February 2007), the applicant determined that some safety-related SSCs in the VY turbine building required consideration for potential spatial impacts from nonsafety-related SSCs based on 10 CFR 54.4(a)(2). Therefore, an expanded review for SSCs in the turbine building determined that additional components required an AMR. Those additional component types have been added to LRA Table 2.3.3-13-42, as addressed in the applicant's letters to the NRC dated July 30, 2007 and August 16, 2007. Based on its review, the staff found the above response acceptable because the applicant stated that there are no nonsafety-related portions of systems which are attached to safety-related systems that are not within the scope of license renewal in accordance with 10 CFR 54.4(a)(2), but that there were spatial impact concerns from nonsafety-related SSCs in the turbine building. The additional component types have been added to LRA Table 2.3.3-13-42. Therefore, the staff concern described in Inspection Item 2.3.3.2a-2 is resolved. CI 2.3.3.12-1 LRA Section 2.3.3.12 indicates that the John Deere Diesel (JDD) is installed in compliance with 10 CFR 50, Appendix R, requirements. However, due to a lack of available drawings and/or detailed description of the diesel equipment listed in LRA Table 2.3.3-12, it is difficult to determine if any AMR category components may have been omitted from the table. It is recommended that the JDD be inspected to assure all AMR category components are included in the list of LRA Table 2.3.3-12. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components satisfy the requirements of 10 CFR 54.4(a)(3). In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team stated that the John Deere diesel system components are listed in LRA Table 2.3.3-12 and the supporting fuel oil day tank, fiberglass underground storage tank, and supply lines are listed in LRA Table 2.3.3-6, "Fuel Oil System." Based on its review, the staff found the above response acceptable because the NRC Regional Inspection Team verified that all components subject to an AMR are included in LRA Table 2.3.3-12 and LRA Table 2.3.3-6 and confirmed that no other portions of the John Deere diesel system should have been included within scope based on 10 CFR 54.4(a)(3). Therefore, the staff concern described in Inspection Item 2.3.3.12-1 is resolved. 1-9

CI 2.3.3.13a-1 The LRA states that the augmented off-gas system is within the scope of license renewal based on requirements of 10 CFR 54.4(a)(2) because of the potential for physical interaction with safety-related components described in LRA Table 2.3.3.13-A. The determination of whether a component meets the requirements of 10 CFR 54.4(a)(2) for physical interactions is based on where it is located in a building and its proximity to safety-related equipment or where a structural/seismic boundary exists. This information is not provided on license renewal drawings nor was a detailed description provided in the LRA. Consequently, any omission of augmented off-gas components subject to an AMR cannot be determined. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components meet the requirements of 10 CFR 54.4(a)(2) and all the components subject to an AMR are included in LRA Table 2.3.3-13-1. In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team noted LRA Table 2.3.3.13-B states that the portion of the AOG system associated with the plant stack loop seal is subject to an AMR based on 10 CFR 54.4(a)(2) for physical interactions. Since the boundaries for the portion of the system as described in LRA Table 2.3.3.13-B were not well defined, in its letter dated July 30, 2007, the applicant amended the table to read "portion of the system inside the plant stack." The inspector walked down the remainder of the system and confirmed that no other portions of the system should have been included based on 10 CFR 54.4(a)(2). Based on its review, the staff found the above response acceptable because the applicant amended LRA Table 2.3.3.13-B as appropriate and the NRC regional inspector walked down the remainder of the AOG system outside the plant stack and confirmed that no other portions of the system should have been included within scope based on 10 CFR 54.4(a)(2). Therefore, the staff concern described in Inspection Item 2.3.3.13a-1 is resolved. CI 2.3.3.13e-1 The LRA states that the circulating water system is within the scope of license renewal based on the potential for physical interaction with safety-related components as required by 10 CFR 54.4(a)(2) and described in LRA Table 2.3.3.13-A. The applicant did not provide drawings highlighting in-scope components required by 10 CFR 54.4(a)(2), stating that the drawings would not provide significant additional information because they do not indicate proximity of components to safety-related equipment and do not identify structural/seismic boundaries. Without license renewal drawings and/or detailed description of the circulating water system, the omission of components subject to an AMR cannot be determined (see LRA Table 2.3.3-13-9). The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components satisfy the requirements of 10 CFR 54.4(a)(2) and all the components subject to an AMR are included in LRA Table 2.3.3-13-9. 1-10

In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team stated that if any nonsafety-related portion of a fluid system is located within a building containing safety-related components, the components within the system are within the license renewal scope. Further, applicant's letter to the NRC dated July 3, 2007, LRA Amendment 27, Attachment 2 states that there are no nonsafety-related systems for which the applicant has not identified the nonsafety-related portions of systems which are attached to safety-related systems and required to be in the scope of license renewal in accordance with 10 CFR 54.4(a)(2). However, as a result of discussions with the staff during the Region I inspection (February 2007), the applicant determined that some safety-related SSCs in the VY turbine building required consideration for potential spatial impacts from nonsafety-related SSCs in accordance with 10 CFR 54.4(a)(2). Therefore, an expanded review for SSCs in the turbine building determined that additional components required an AMR. Those additional component types were added to LRA Table 2.3.3-13-9, as addressed in the applicant's letters to the staff dated July 30, 2007 and August 16, 2007. Based on its review, the staff found the above response acceptable because the applicant stated that if any nonsafety-related portion of a fluid system is located within a building containing safety-related components, the components within the system are within the license renewal scope in accordance with 10 CFR 54.4(a)(2) but that there were spatial impact concerns from nonsafety-related SSCs in the turbine building. The additional component types have been added to LRA Table 2.3.3-13-9. Therefore, the staff concern regarding components of the CW system described in Inspection Item 2.3.3.13e-1 is resolved. CI 2.3.3.13m-1 The LRA states that the reactor water clean up system is within the scope of license renewal in accordance with 10 CFR 54.4(a)(2) because of the potential for physical interaction with safety-related components as described in LRA Table 2.3.3.13-A. The determination of whether a component meets the requirements of 10 CFR 54.4(a)(2) for physical interactions is based on where it is located in a building and its proximity to safety-related equipment or where a structural/seismic boundary exists. This information is not provided on license renewal drawings nor was a detailed description provided in the LRA. Consequently, any omission of the reactor water clean up components subject to an AMR cannot be determined. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components satisfy the requirements of 10 CFR 54.4(a)(2) and all the components subject to an AMR are included in LRA Table 2.3.3-13-36. In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team stated that if any nonsafety-related portion of a fluid system is located within a building containing safety-related components, the components within the system are within the license renewal scope. Further, the applicant's letter to the NRC dated July 3, 2007, LRA Amendment 27, Attachment 2 states that there are no nonsafety-related systems for which the applicant has not identified the nonsafety-related portions of systems which are attached to safety-related systems and required to be in the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The 1-11

applicant also stated that there were no additional components that should be within scope based on 10 CFR 54.4(a) as identified during the NRC Regional Inspection and subsequent applicant reviews. Based on its review, the staff found the above response acceptable because the applicant stated that if any nonsafety-related portion of a fluid system is located within a building containing safety-related components, the components within the system are within the license renewal scope in accordance with 10 CFR 54.4(a)(2) and that there were no additional components identified that should be in-scope based on 10 CFR 54.4(a). Therefore, the staff concern regarding the components of the RWCU system described in Inspection Item 2.3.3.13m-1 is resolved. 1.7 Summary of Proposed License Conditions Following the staffs review of the LRA, including subsequent information and clarifications provided by the applicant, the staff identified three proposed license conditions. The first license condition requires the applicant to include the UFSAR supplement required by 10 CFR 54.21(d) in the next UFSAR update, as required by 10 CFR 50.71(e), following the issuance of the renewed license. The second license condition requires future activities identified in the UFSAR supplement to be completed prior to the period of extended operation. The third license condition requires that all capsules in the reactor vessel, that are removed and tested, must meet the 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 staff prior to implementation. All capsules placed in storage must be maintained for future insertion. Any changes to storage requirements must be approved by the staff as required by 10 CFR Part 50, Appendix H. 1-12

THIS PAGE INTENTIONALLY LEFT BLANK. SECTION 2 STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW 2.1 Scoping and Screening Methodology 2.1.1 Introduction Title 10, Section 54.21, of the Code of Federal Regulations (CFR), Contents of Application Technical Information (10 CFR 54.21), requires for each license renewal application (LRA) an integrated plant assessment (IPA) listing structures and components (SCs) subject to an aging management review (AMR) from all of the systems, structures, and components (SSCs) within the scope of license renewal. LRA Section 2.1, Scoping and Screening Methodology, describes the methodology for identifying SSCs at the Vermont Yankee Nuclear Power Station (VYNPS) within the scope of license renewal and SCs subject to an AMR. The staff of the United States (US) Nuclear Regulatory Commission (NRC) (the staff) reviewed the Entergy Nuclear Operations, Inc. (ENO or the applicant) scoping and screening methodology to determine whether 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 considered the requirements of 10 CFR Part 54, Requirements for Renewal of Operating Licenses for Nuclear Power Plants (the Rule), statements of consideration on 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. The applicant also considered the correspondence between the staff, other applicants, and the NEI. 2.1.2 Summary of Technical Information in the Application LRA Sections 2 and 3 state the technical information required by 10 CFR 54.4 and 54.21(a). LRA Section 2.1 describes the process for identifying SSCs meeting the license renewal scoping criteria of 10 CFR 54.4(a) and the process for identifying SCs subject to an AMR as required by 10 CFR 54.21(a)(1). The applicant provided the results of the process for identifying such SCs 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 2-1

LRA Section 3, Aging Management Review Results, states the applicants aging management results in the following LRA sections:

• Section 3.1, Reactor Vessel, Internals and Reactor Coolant System
• Section 3.2, Engineered Safety Features Systems
• Section 3.3, Auxiliary Systems
• Section 3.4, Steam and Power Conversion Systems
• Section 3.5, Structures and Component Supports
• Section 3.6, Electrical and Instrumentation and Controls LRA Section 4, Time-Limited Aging Analyses, states the applicants evaluation of time-limited aging analyses.

2.1.3 Scoping and Screening Program Review The staff evaluated the LRA scoping and screening methodology in accordance with the guidance in Section 2.1, NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants, Revision 1, (SRP-LR), and the Nuclear Energy Institute (NEI) 95-10, Industry Guidelines for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule, Revision 6, (NEI 95-10). The following regulations form the basis for the acceptance criteria for the scoping and screening methodology review:

• 10 CFR 54.4(a) as to identification of plant SSCs within the scope of the Rule
• 10 CFR 54.4(b) as to identification of the intended functions of plant systems and structures within the scope of the Rule
• 10 CFR 54.21(a)(1) and 10 CFR 54.21(a)(2) as to the methods utilized by the applicant to identify plant SCs subject to an AMR With the guidance of the corresponding SRP-LR sections, the staff reviewed, as part of the applicants scoping and screening methodology, the activities described in the following LRA sections:
• Section 2.1 to ensure that the applicant described a process for identifying SSCs within the scope of license renewal in accordance with 10 CFR 54.4(a)
• Section 2.2 to ensure that the applicant described a process for identifying SCs subject to an AMR in accordance with 10 CFR 54.21(a)(1) and 10 CFR 54.21(a)(2)

The staff conducted a scoping and screening methodology audit at VYNPS in Vernon, Vermont during the week of April 24-28, 2006. The audit focused on whether the applicant had developed and implemented adequate guidance for the scoping and screening of SSCs by the methodologies in the LRA and the requirements of the Rule. The staff reviewed implementation of the project level guidelines and topical reports describing the applicants scoping and screening methodology. The staff discussed with the applicant details of the implementation and control of the license renewal program and reviewed administrative control documentation and selected design documentation used by the applicant during the scoping and screening process. The staff reviewed the applicants processes for quality assurance (QA) for development of the LRA. The staff reviewed the quality attributes of the applicants aging 2-2

management program (AMP) activities described in LRA Appendix A, Updated Final Safety Analysis Report Supplement, and LRA Appendix B, Aging Management Programs and Activities and the LRA training and qualification development team. The staff reviewed scoping and screening results reports for the core spray (CS) system and intake structure for the applicants appropriate implementation of the methodology outlined in the administrative controls and for results 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 implementation procedures as documented in the audit report dated August 10, 2006 to verify whether the process for identifying SCs subject to an AMR was consistent with the LRA and the SRP-LR. Additionally, the staff reviewed the scope of CLB documentation sources and the applicants process for appropriate consideration of CLB commitments and for adequate implementation of the 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, the applicant addressed the following information sources for the license renewal scoping and screening process:

• System and Topical Design Basis Documents (DBDs)
• VYNPS Enterprise Maintenance, Planning, and Control (EMPAC) Component Database
• Updated Final Safety Analysis Report (UFSAR)
• Appendix R Safe Shutdown Capability Assessment
• Fire Hazards Analysis Report
• Safe Shutdown Capability Assessment
• Technical Specifications
• Maintenance Rule Scoping Basis Documents
• Safety Classification Documents
• Plant Layout Drawings The applicant stated that it used this information to identify the functions performed by plant systems and structures. It then compared these functions to the scoping criteria in 10 CFR 54.4(a)(1-3) to determine whether the associated plant system or structure performed a license renewal intended function. It also used these sources to develop the list of SCs subject to an AMR.

The license renewal boundary drawings (LRBDs) show the systems within the scope of license renewal highlighted in color. 2-3

2.1.3.1.2 Staff Evaluation Scoping and Screening Implementation Procedures. The staff reviewed the following scoping and screening methodology implementation procedures: The staff reviewed the applicants scoping and screening methodology implementation procedures, including license renewal project guidelines (LRPGs), license renewal project documents/reports (LRPDs), AMR reports (e.g., AMRMs - mechanical, AMREs- electrical, and AMRCs - structural), as documented in the audit report, to ensure the guidance was consistent with the requirements of the Rule, NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants, Revision 1, (SRP-LR), and the Nuclear Energy Institute (NEI) 95-10, Industry Guidelines for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule, Revision 6, (NEI 95-10). The staff found the overall process for implementing 10 CFR Part 54 requirements included in the LRPGs, LRPDs, and AMRs was consistent with the Rule and industry guidance. The staff found guidance for identifying plant SSCs within the scope of the Rule, including guidelines for identifying SC component types within the scope of license renewal subject to an AMR, in the LRA, including in the implementation of NRC staff positions documented in NUREG-1800, and the information in requests for additional information (RAI) responses dated July 10, 2006. The review of these procedures focused on the consistency of the detailed procedural guidance with information in the LRA reflecting implementation of staff positions in the SRP-LR and interim staff guidance documents. After reviewing the LRA and supporting documentation, the staff finds LRA Section 2.1 consistent with the scoping and screening methodology instructions. The applicants methodology has sufficiently detailed guidance for the scoping and screening implementation process followed in the LRA. Sources of Current Licensing Basis Information. For VYNPS, system safety functions are stated in safety classification documents, the Maintenance Rule SSC basis documents for each system, and in design basis documents for systems for which DBDs were written. The staff considered the safety objectives in the UFSAR system descriptions and identified objectives meeting the safety-related Criterion of 10 CFR 54.4(a)(1) as system intended functions. The staff reviewed the scope and depth of the applicant's CLB information to verify whether the applicants methodology had identified all SSCs within the scope of license renewal as well as component types requiring AMRs. As defined in 10 CFR 54.3(a), the CLB applies NRC requirements, written licensee commitments for compliance with, and operation within, applicable NRC requirements, and plant-specific design bases docketed and in effect. The CLB includes NRC regulations, orders, license conditions, exemptions, technical specifications, design-basis information in the most recent UFSAR, and licensee commitments in docketed correspondence like licensee responses to NRC bulletins, generic letters, and enforcement actions as well as commitments in NRC safety evaluations or licensee event reports. During the audit, the staff reviewed the applicants information sources and samples of such information, including the UFSAR, DBDs, controlled plant reference drawings, LRBDs, and Maintenance Rule information. In addition, the applicants license renewal process identified 2-4

additional potential sources of plant information pertinent to the scoping and screening process, including, licensing correspondence, the Fire Hazards Analysis, safety evaluations, and design documentation such as engineering calculations and design specifications. Additionally, the applicant supplemented the review by using an electronic database developed during the plant FSAR accuracy verification project conducted between 1998 and 2000. The database contained approximately 10,000 documents including all correspondence in the public document room. The searchable database was available for query during the review of the CLB information in support of LRA development. The staff confirmed that the applicants detailed license renewal program guidelines required use of the CLB source information developing scoping evaluations. The VYNPS component database is the applicants primary repository for component safety classification information. During the audit, the staff reviewed the applicants administrative controls for VYNPS component database safety classification data. These controls are described and implementation is governed by plant administrative procedures. Based on a review of the administrative controls, and a sample of the VYNPS component database component safety classifications, the NRC staff concluded that the applicant had established adequate measures to control the integrity and reliability of VYNPS component database safety classification data, and therefore, the staff concluded that the VYNPS component database provided a sufficiently controlled source of component data to support scoping and screening evaluations. During the staffs review of the applicants CLB evaluation process, the applicant provided the staff with a discussion regarding the incorporation of updates to the CLB and the process used to ensure those updates are adequately incorporated 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 NUREG-1800. In addition, the staff reviewed technical reports utilized to support identification of SSCs relied upon to demonstrate compliance with the safety-related criteria, nonsafety-related criteria, as well as the five regulated events referenced in 10 CFR 54.4(a)(1-3). The applicants license renewal program guidelines provided a comprehensive listing of documents used to support scoping and screening evaluations. The staff found these design documentation sources to be useful for ensuring that the initial scope of SSCs identified by the applicant was consistent with the plant's CLB. 2.1.3.1.3 Conclusion Based on its review of LRA Section 2.1, the detailed scoping and screening implementation procedures, and the results from the scoping and screening audit, the staff concludes that the applicant's scoping and screening methodology considers CLB information consistently with SRP-LR and NEI 95-10 guidance and, therefore, is acceptable. 2-5

2.1.3.2 Quality Controls Applied to LRA Development 2.1.3.2.1 Staff Evaluation The staff reviewed the quality controls used by the applicant to ensure that scoping and screening methodologies described in the LRA were adequately implemented. Although the applicant did not develop the LRA in accordance with a 10 CFR 50, Appendix B, QA program, the applicant utilized the following QA processes during the LRA development:

• Implementation of the scoping and screening methodology was governed by written procedures.
• The applicant reviewed previous LRA NRC requests for additional information to ensure that applicable issues were addressed in the LRA.
• The LRA was reviewed by the Offsite and Onsite Safety Review Committees prior to submittal to the NRC.
• The applicant performed an industry peer review of the LRA.
• The applicants QA organization performed an independent review of the LRA. The purpose of this review was to ensure that the technical information used to develop the LRA was updated and approved in accordance with the stations QA program, and that industry peer and Offsite and Onsite Safety Review Committee issues were resolved and associated corrective actions implemented.

2.1.3.2.2 Conclusion Based on its review of pertinent LRA development guidance, discussion with the applicant's license renewal personnel, and review of the quality audit reports, the staff concludes that these QA activities add assurance that LRA development activities have been performed in accordance with the scoping and screening methodologies described in the LRA. 2.1.3.3 Training 2.1.3.3.1 Staff Evaluation The staff reviewed the applicants training process for consistent and appropriate guidelines and methodology for the scoping and screening activities and to ensure the guidelines and methodology were performed in a consistent and appropriate manner. The LRPGs provided the guidance and requirements for the training of the license renewal project and site personnel. The training consisted of a combination of reading and attending training sessions. The LRPGs specified the level of training which was required for the various groups participating in the development of the LRA and began with initial training, documented on a qualification card. The training was required for both the license renewal project personnel who prepared the application and for the site personnel who reviewed the application. In addition, license renewal refresher training was provided for the license renewal project and site personnel participating in the review. Refresher training included information on the license renewal process and information specific to the site. License renewal project and site personnel 2-6

were required to review applicable license renewal regulations, NEI 95-10 and associated procedures. The applicant developed periodic production meetings in which the license renewal project personnel shared their knowledge and experience of a given subject with each other. The NRC staff reviewed completed qualification and training records of several of the applicant's license renewal project personnel and also reviewed completed check lists. The staff found these records adequately documented the required training for the license renewal project personnel. Additionally, based on discussions with the applicant's license renewal project personnel during the audit, the NRC staff confirmed that the applicant's license renewal project personnel were knowledgeable on the license renewal process requirements and the specific technical issues within their areas of responsibility. On the basis of discussions with the applicants license renewal project personnel responsible for the scoping and screening process, and a review of selected design documentation in support of the process, the NRC staff concluded that the applicants license renewal project personnel understood the requirements of and adequately implemented the scoping and screening methodology established in the applicants renewal application. The staff did not identify any concerns regarding the training of the applicants license renewal project or site personnel. 2.1.3.3.2 Conclusion Based on discussions with the applicants license renewal personnel responsible for the scoping and screening process and review of selected documentation supporting the process, the staff concludes that the applicants technical personnel understood the requirements and adequately implemented the scoping and screening methodology documented in the LRA. The staff concludes that the license renewal personnel were adequately trained and qualified for license renewal activities. 2.1.3.4 Conclusion of Scoping and Screening Program Review Based on its review of LRA Section 2.1, review of the applicants detailed scoping and screening implementation procedures, discussions with the applicants LRA personnel, and review of the scoping and screening audit results, the staff concludes that the applicants scoping and screening program is consistent with SRP-LR guidance and, therefore, acceptable. 2.1.4 Plant Systems, Structures, and Components Scoping Methodology LRA Section 2.1, describes the methodology for scoping SSCs as required by 10 CFR 54.4(a) and the plant scoping process for systems and structures. Specifically, the scoping process consisted of developing a list of plant systems and structures and identifying their intended functions. Intended functions are those functions that are the basis for including a system or structure within the scope of license renewal as defined in 10 CFR 54.4(b) and are identified by comparing the system or structure function with the criteria in 10 CFR 54.4(a). The systems list was developed from the VYNPS component database and the structures list from a review of plant layout drawings and structure-specific system codes in the VYNPS component database. 2-7

Finally, the applicant evaluated the components in the systems and structures that were in-scope of license renewal. The in-scope system boundary of SSCs subject to an AMR is depicted on the license renewal drawings. The applicants scoping methodology, as described in the LRA, is discussed in the sections below. 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 In LRA Section 2.1.1.1, Application of Safety-Related Scoping Criteria, the applicant described the scoping methodology required by 10 CFR 54 as it relates to safety-related criteria in accordance with 10 CFR 54.4(a)(1). With respect to the safety-related criteria, the applicant stated that at VYNPS system safety functions are identified in safety classification documents, the maintenance rule SSC basis documents for each system, and in design basis documents (DBDs) for those systems for which a DBD was written. SSCs that are identified as safety-related in the UFSAR, in DBDs, or in the CRL were classified as satisfying criteria of 10 CFR 54.4(a)(1) and included within the scope of license renewal. The review also confirmed that all plant conditions, including conditions of normal operation, abnormal operational transients, design basis accidents, internal and external events, and natural phenomena for which the plant must be designed, were considered for license renewal scoping in accordance with 10 CFR 54.4(a)(1) criteria. The VYNPS CLB definition of safety-related SSCs is not identical to the definition provided in the Rule. As a result, the applicant performed an evaluation of the differences between its CLB definition of safety-related and the Rule definition. 2.1.4.1.2 Staff Evaluation Pursuant to 10 CFR 54.4(a)(1), the applicant must consider all safety-related SSCs relied upon to remain functional during and following a design basis event (DBE) to ensure (a) the integrity of the reactor coolant pressure boundary, (b) the ability to shut down the reactor and maintain it in a safe shutdown condition, or (c) the ability to prevent or mitigate the consequences of accidents that could cause offsite exposures comparable to those of 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11. As to identification of DBEs, SRP-LR Section 2.1.3 states: 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 required by 10 CFR 50.49(b)(1)) to ensure the functions required by 10 CFR 54.4(a)(1). 2-8

The staffs review of LRA Section 2.1 of VYNPS identified areas in which additional information was necessary to complete the review of the applicants scoping and screening methodology. The applicant responded to the staffs RAIs as discussed below. During the scoping and screening methodology audit, the staff questioned how non-accident DBEs, particularly DBEs that may not be described in the UFSAR, were considered during scoping. The staff noted that limiting the review of DBEs to those described in the UFSAR accident analysis could result in omission of safety-related functions described in the CLB and requested the applicant provide a list of all DBEs that were evaluated as part of the license renewal review. However, during the audit, the staff was unable to identify such a list. Therefore, in RAI 2.1-1, dated July 10, 2006, the staff requested that the applicant provide: a) a list of DBEs evaluated as part of the license renewal scoping process, b) describe the methodology used to ensure that all DBEs (including conditions of normal operation, anticipated operational occurrences, design-basis accidents, external events, and natural phenomena) were addressed during license renewal scoping evaluation, and c) a list of the documentation sources reviewed to ensure that all DBEs were identified. In its response, by letter dated August 10, 2006, the applicant described the DBEs evaluated during the license renewal effort and described the methodology used to ensure that all DBEs were addressed during license renewal scoping. Specifically, the applicant identified abnormal operational transients, design-basis accidents, events for which the alternate cooling system (ACS) is credited (i.e., loss of the Vernon Pond and flooding or fire in the service water (SW) intake structure), and additional DBEs such as external and internal flooding, earthquakes, tornadoes and natural phenomena as constituting the DBEs for the Vermont Yankee plant. In addition, the applicant described two basic means of ensuring that all of the plant DBEs were addressed during the license renewal scoping process. These include: (1) reviewing the UFSAR and DBDs (i.e., for external and internal events and safety analyses) directly for the identification of the DBEs and subsequently for the identification of the SSCs credited for each event, and (2) reviewing and evaluating the safety classification of systems and components as governed by the plant safety classification process. This process ensures that site-specific procedures, design basis information, regulatory commitments, and regulatory guidance are considered during the classification process. The VYNPS safety classification process identifies those SSCs which are credited for performance of the intended safety functions in accordance with 10 CFR 54.4(a)(1). The NRC staff reviewed a sample of the DBDs identified as sources of this information. The staff found the DBDs to contain a detailed evaluation of events, and included appropriate CLB documentation references to support the review and a resultant matrix of systems and structures relied upon to remain functional during and following these DBEs. The staff concluded that the applicant considered DBEs consistent with the guidance contained in NUREG-1800. The staff reviewed the additional information provided by the applicant and, on the basis of providing (1) a detailed listing of the DBEs for the plant; (2) a description of the design and configuration control processes used to identify the SSCs credited for DBE mitigation; and (3) a 2-9

description of the processes and sources of DBE information used to perform the scoping evaluation consistent with the requirements of 10 CFR 54.4(a)(1), the staff found that the applicant has adequately addressed the staff's RAI. Therefore, the staffs concern described in RAI 2.1-1 is resolved. The applicant performed scoping of SSCs for the 10 CFR 54.4(a)(1) criterion in accordance with the LRPGs which provided guidance for the preparation, review, verification, and approval of the scoping evaluations to assure the adequacy of the results of the scoping process. The staff reviewed these guidance documents governing the applicants evaluation of safety-related SSCs, and sampled the applicants scoping results reports to ensure the methodology was implemented in accordance with those written instructions. In addition, the staff discussed the methodology and results with the applicants technical personnel who were responsible for these evaluations. The staff reviewed a sample of the license renewal scoping results for the CSS and the Intake Structure to provide additional assurance that the applicant adequately implemented their scoping methodology with respect to 10 CFR 54.4(a)(1). The staff confirmed that the scoping results for each of the sampled systems were developed consistent with the methodology, the SSCs credited for performing intended functions were identified, and the basis for the results as well as the intended functions were adequately described. The staff confirmed that the applicant had identified and used pertinent engineering and licensing information to identify the SSCs required to be in-scope in accordance with the 10 CFR 54.4(a)(1) criteria. To help document the identification of SSCs in-scope in accordance with the 10 CFR 54.4(a) criteria, the applicant developed a license renewal information system (LRIS) which contained detailed design description information about each plant system and structure and the relevant functions of those systems and structures. A list of safety-related SCs was initially identified by using the existing components list in the VYNPS component database. The VYNPS component database safety-classification field was reviewed to ensure that any system or structure that has a component identified as safety-related was considered for inclusion into the scope of the license renewal project. For VYNPS, component safety classification fields SC1 - SC3 corresponded to the 10 CFR 54.4(a)(1) criteria. Additionally, the SC1 database safety-classification and associated plant system drawings provided a starting point for identifying specific components which were required to meet the 10 CFR 54.4(a)(1) criteria. During the audit, the applicant described the process used to evaluate components classified as safety-related that did not perform a safety-related intended function. As part of the process, the applicant stated that the safety-classification of several components were reevaluated in order to reconcile differences between scoping determinations and facility database information or CLB information. Those components that were identified as safety-related that did not perform an intended function were explicitly evaluated and described in the LRPDs and the rationale for their exclusion from scope of the license renewal was documented. For instances where components identified as safety-related in the VYNPS component database did not perform any safety-related functions, the applicant identified these components and performed additional evaluations to confirm that the component did not perform or were not credited in the CLB for any specific safety-related functions. Examples included the reactor water cleanup (RWCU) system and the augmented off-gas (AOG) system. 2-10

The staff reviewed the safety classification criteria used to determine the safety classification to verify consistency between the VYNPS CLB definition and the Rule definition in 10 CFR 54.4(a). In addition, the staff reviewed the applicants evaluation of the differences between the Rule definition and the site-specific definition of safety-related to ensure all potential SSCs meeting the requirements of 10 CFR 54.4(a)(1) were adequately addressed. The applicant documented this evaluation in the LRA and LRPDs. As part of the license renewal development activities, the applicant stated that the site-specific definition for safety-related was nearly identical to the Rule definition with the following exception: The CLB definition regarding potential offsite exposure limits refers to 10 CFR 50.67 whereas the Rule also references comparable guidelines in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), and 10 CFR Part 100 respectively. During the audit, the staff reviewed the applicants evaluation of the Rule and VY CLB definitions pertaining to 10 CFR 54.4(a)(1). Based on this review, the staff confirmed that 10 CFR 50.34(a)(1)(ii) is not applicable to VYNPS as it concerns applicants for a construction permit who apply on or after January 10, 1997. In addition, the staff has amended the VYNPS operating license to allow use of an alternative source term for accident analyses in accordance with 10 CFR 50.67. The change to 10 CFR 50.67 dose limits does not affect the VYNPS safety classification definition. The accident analyses with the alternative source term credits additional functions for the standby liquid control (SLC) and residual heat removal (RHR) systems: (1) the SLC system is credited with maintaining pH in the torus to prevent re-evolution of iodine, and (2) the drywell spray function of the RHR system is credited with particulate removal. The staff confirmed that these intended functions were included in the scoping evaluation. During the audit, the staff also confirmed that any SSCs specifically credited for the 10 CFR 50.67(b) leakage pathway, were identified and included in-scope. For VYNPS, the main condenser and main steam (MS) bypass leakage pathway are credited for 10 CFR 50.67(b) leakage pathway and meet the 10 CFR 54.4(a)(1)(iii) criterion for inclusion in-scope. The staff confirmed that these pertinent SSCs were appropriately identified and placed in-scope. Since the specific SSCs were classified as nonsafety-related in the plant component database, they were placed in-scope in accordance with 10 CFR 54.4(a)(2) for nonsafety-related potentially affecting a safety-related functions. The staff reviewed the evaluation and discussed the results of the evaluation with the applicants license renewal team members. The staff determined that the differences between the VYNPS safety-related definition and the Rule definition were adequately identified and evaluated. These differences did not result in any additional components being considered safety-related beyond those identified in the VYNPS CLB. 2.1.4.1.3 Conclusion Based on this sample review, discussions with the applicant, and review of the applicant's scoping process, the staff finds that the applicant's methodology for identifying systems and structures meets 10 CFR 54.4(a)(1) scoping criteria and, therefore, is acceptable. 2-11

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 In LRA Section 2.1.1.2, Application of Criterion for Nonsafety-Related SSCs Whose Failure Could Prevent the Accomplishment of Safety Functions, and Section 2.3.3.13, Miscellaneous Systems in-Scope for (a)(2), the applicant described the scoping methodology as it related to the nonsafety-related criteria in accordance with 10 CFR 54.4(a)(2). The applicant evaluated the SSCs that met 10 CFR 54.4(a)(2) using three categories: (1) Nonsafety-Related SSCs Required to Perform a Function that Supports a Safety-Related SSC The SSCs required to perform a function in support of safety-related components were classified as safety-related and included in the scope of license renewal in accordance with 10 CFR 54.4(a)(1). The applicant reviewed engineering and licensing documents (UFSAR, Maintenance Rule scoping documents, and DBDs) to identify exceptions which were included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). (2) Nonsafety-Related SSCs Connected to Safety-Related SSCs The applicant identified certain nonsafety-related components and piping outside of the safety-class pressure boundary which must be structurally sound in order to maintain the pressure boundary integrity of safety-related piping. These components perform a structural support function. For piping in this structural boundary, pressure integrity is not required (except when required for spatial interaction between nonsafety-related and safety-related SSCs); however, piping within the safety class pressure boundary depends on the structural boundary piping and supports in order for the system to fulfill its safety function. For VYNPS, the structural boundary" is defined as the portion of a piping system outside the safety class pressure boundary, yet relied upon to provide structural support for the pressure boundary. The structural boundary is often shown on piping isometric drawings and was considered synonymous with the first seismic or equivalent anchor. Nonsafety-related piping systems connected to safety-related systems were included up to the structural boundary or to a point that includes an adequate portion of the nonsafety-related piping run to conservatively include the first seismic or equivalent anchor. An equivalent anchor was a combination of hardware or structures that together are equivalent to a seismic anchor. A seismic anchor was defined as hardware or structures that, as required by the analysis, physically restrain forces and moments in three orthogonal directions. The physical arrangement as analyzed insures that the stresses that are developed in the safety-related piping and supports are within the applicable piping and structural code acceptance limits. If isometric drawings were not readily available to identify the structural boundary, connected lines were included to a point beyond the safety-related/nonsafety-related interface, such as a base-mounted component, flexible connection, or the end of a piping run (such as a drain line). The LRA stated that the approach was consistent with the guidance in NEI 95-10, Appendix F. 2-12

(3) Nonsafety-related SSCs with a Potential for Spatial Interaction with Safety-Related SSCs The applicant considered physical impact, and fluid leakage, spray or flooding when evaluating the potential for spatial interaction between nonsafety-related systems and safety-related SSCs. The applicant used a spaces approach for scoping of nonsafety-related systems with potential spatial interaction with safety-related SSCs. The spaces approach focused on the interaction between nonsafety-related and safety-related SSCs that are located in the same space. A "space" was defined as a room or cubicle that is separated from other spaces by substantial objects (such as wall, floors, and ceilings). The space was defined such that any potential interaction between nonsafety-related and safety-related SSCs is limited to the space. Physical Impact or Flooding The applicant evaluated missiles which could be generated from internal or external events such as failure of rotating equipment. Inherent nonsafety-related features that protect safety-related equipment from missiles; overhead-handling systems whose structural failure could result in damage to any system that could prevent the accomplishment of a safety function; and walls, curbs, dikes, doors, etc, that provide flood barriers to safety-related SSCs meet the criteria of 10 CFR 54.4(a)(2). Nonsafety-related equipment that was determined to have a possible impact on safety-related SSCs were included within the scope of license renewal. The applicant evaluated nonsafety-related portions of high-energy lines, including review of the UFSAR and relevant topical design basis document. The applicants high-energy systems were evaluated to ensure identification of components that are part of nonsafety-related high-energy lines that can effect safety-related equipment. If the applicants high-energy line break (HELB) analysis assumed that an nonsafety-related piping system did not fail or assumed failure only at specific locations, then that piping system (piping, equipment and supports) is included within the scope of license renewal. Fluid Leakage or Spray The applicant evaluated moderate and low energy systems which have the potential for spatial interactions of spray and leakage. Nonsafety-related systems and nonsafety-related portions of safety-related systems with the potential for spray or leakage that could prevent safety-related SSCs from performing their required safety function were considered in the scope of license renewal. In addition, the nonsafety-related supports for nonsafety-related piping systems with a potential for spatial interaction with safety-related SSCs were included in the scope of license renewal. The applicant determined that operating experience indicated that nonsafety-related components containing only air or gas have experienced no failures due to aging that could impact the ability of safety-related equipment to perform required safety functions. There are no effects of aging requiring management for these components when the environment is a dry gas. Systems containing only air or gas were not included in the scope of license renewal. 2-13

Protective features, such as whip restraints, spray shields, supports, missile or flood barriers, (which can be applicable preventing physical impact and fluid leakage, spray, or flooding) were installed to protect safety-related SSCs against spatial interaction with nonsafety-related SSCs. Such protective features credited in the plant design were included within the scope of license renewal. 2.1.4.2.2 Staff Evaluation Pursuant to 10 CFR 54(a)(2), the applicant must consider all nonsafety-related SSCs, the failure of which could prevent satisfactory performance of safety-related SSCs relied upon to remain functional during and following a DBE to ensure (a) the integrity of the reactor coolant pressure boundary, (b) the ability to shut down the reactor and maintain it in a safe shutdown condition, or (c) the ability to prevent or mitigate the consequences of accidents that could cause offsite exposures comparable to those of 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11, as applicable. NRC Regulatory Guide (RG) 1.188, Revision 1, Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses, dated September 2005, endorses the use of NEI 95-10, Revision 6, for methods the staff considers acceptable for compliance with 10 CFR Part 54 in preparing LRAs. NEI 95-10, Revision 6, addresses the staff positions on 10 CFR 54.4(a)(2) scoping criteria, nonsafety-related SSCs typically identified in the CLB, consideration of missiles, cranes, flooding, high-energy line breaks, nonsafety-related SSCs connected to safety-related SSCs, nonsafety-related SSCs in proximity of safety-related SSCs, and the mitigative and preventive options in nonsafety-related and safety-related SSCs interactions. The staff states that applicants should not consider hypothetical failures but rather base their evaluation on the plants CLB, engineering judgement and analyses, and relevant operating experience, describing operating experience as all documented plant-specific and industry-wide experience useful in determining the plausibility of a failure. Documentation would include NRC generic communications and event reports, plant-specific condition reports, such industry reports as safety operational event reports, and engineering evaluations. The staff reviewed LRA Section 2.1.1.2, Application of Criterion for Nonsafety-Related SSCs Whose Failure Could Prevent the Accomplishment of Safety Functions, and Section 2.3.3.13, Miscellaneous Systems in-Scope for (a)(2). The applicant described the scoping methodology as it related to the nonsafety-related criteria in accordance with 10 CFR 54.4(a)(2). The applicant evaluated 10 CFR 54.4(a)(2) SSCs with the three categories from the NRC guidance to the industry on identification and treatment of such SSCs: Nonsafety-Related SSCs Required to Perform Functions that Support a Safety-Related SSCs Nonsafety-related SSCs required to perform a function in order to support a safety-related function had been previously classified as safety-related and were identified as such in the equipment data base. Therefore the nonsafety-related SSCs required to perform a function to support a safety-related function had been included in the scope of license renewal as safety-related as required by 10 CFR 54.4(a)(1). This evaluating criteria was discussed in the 2-14

applicants 10 CFR 54.4(a)(2) project report. The single exception to this approach was the main condenser and main steam isolation valve (MSIV) leakage pathway which was classified as an nonsafety-related system and was required to perform a function to support a safety-related function. This system was included in the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The staff found that the applicant implemented an acceptable method for scoping of nonsafety-related systems that perform a function that supports a safety-related intended function. Nonsafety-Related SSCs Connected to Safety-Related SSCs The applicant had previously performed an analysis to identify the nonsafety-related SSCs, outside of the safety-related pressure boundary, which were required to be structurally sound in order to maintain the integrity of the safety-related SSCs. This collection of nonsafety-related and safety-related SSCs was identified as the structural boundary and was typically identified on the plant isometric drawings. The applicant had included all nonsafety-related SSCs within the analyzed structural boundary in the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The LRA states that if the structural boundary was not indicated on the applicable isometric drawings, the applicant had identified the portion of the nonsafety-related SSCs beyond the safety-related SSCs to the first equivalent anchor or seismic anchor and included this portion of the nonsafety-related SSCs within the scope of license renewal. The term equivalent anchor was defined in the LRA as a combination of hardware or structures that together are equivalent to a seismic anchor (a seismic anchor was defined as hardware or structures that, as required by analysis, physically restrain forces and moments in three orthogonal directions). The LRA also indicated that if the structural boundary could not be identified for the applicable nonsafety-related/safety-related interface, the nonsafety-related SSCs were included to a point beyond the nonsafety-related/safety-related interface to a base-mounted component, flexible connection, or to the end of the piping run in accordance with the guidance of NEI 95-10. NEI 95-10, Appendix F describes the use of bounding criteria as a method of determining the portion of nonsafety-related SSCs to be included within the scope of license renewal. The staff was unable to determine whether equivalent anchors (such as a combination of supports in the three orthogonal directions) had been used, in addition to the bounding criteria (base-mounted component, flexible connection, or the end of the piping run) discussed in the LRA and the 10 CFR 54.4(a)(2) project report which described the AMR of nonsafety-related systems and components affecting safety-related systems. In RAI 2.1-2, dated July 10, 2006, the staff requested that the applicant provide information related to the method used to develop the structural boundary and whether equivalent anchors had been used in addition to the bounding criteria discussed in the LRA. In its response, by letters dated August 10, 2006, October 17, 2006, and July 3, 2007 the applicant further described the process used to determine the structural boundaries for those nonsafety-related systems which provided limited structural support to safety-related systems. As part of the applicants evaluation, isometric drawings of plant piping systems were reviewed where applicable to determine the location of structural boundaries. These isometric drawings were developed as part of the plant design process utilizing the results of piping stress analyses. No new analyses or isometric drawings were developed to support the license renewal process. Rather, the existing drawings and analyses were used to develop the 2-15

structural boundaries, and in those instances where isometric drawings were not readily available, the applicant used the bounding criteria in NEI 95-10 to identify the portions of the nonsafety-related system necessary to support the intended function. With respect to the use of equivalent anchors, the applicant stated that other than the actual structural boundaries identified as a result of the existing piping stress analysis, isometric drawings, and use of the bounding criteria, they did not use any equivalent anchors to identify the structural boundaries for the nonsafety-related systems identified as performing a 10 CFR 54.4(a)(2) function. The staff reviewed the additional information provided by the applicant and found that the applicant has adequately addressed the staff's RAI, based on the detailed description of the process used to identify the structural boundaries, and confirmation that equivalent anchors were not used for the purposes of identifying structural boundaries for the nonsafety-related systems identified as performing a 10 CFR 54.4(a)(2) function, the staff. Therefore, the staffs concern described in RAI 2.1-2 is resolved. Nonsafety-Related SSCs with a Potential for Spatial Interation with Safety-Related SSCs The applicant considered physical impact, and fluid leakage, spray or flooding when evaluating the potential for spatial interaction between nonsafety-related systems and safety-related SSCs. The applicant used a spaces approach for scoping of nonsafety-related systems with potential spatial interaction with safety-related SSCs. The spaces approach focused on the interaction between nonsafety-related and safety-related SSCs that are located in the same space. A "space" was defined as a room or cubicle that is separated from other spaces by substantial objects (such as wall, floors, and ceilings). The space was defined such that any potential interaction between nonsafety-related and safety-related SSCs is limited to the space. The 10 CFR 54.4(a)(2) project report stated that the applicant had evaluated situations where missiles could be generated from internal or external events such as failure of rotating equipment. The nonsafety-related design features that protect safety-related SSCs from such missiles are within the scope of license renewal. In addition, the 10 CFR 54.4(a)(2) project report stated that the applicant had evaluated overhead-handling systems to identify those whose structural failure could result in damage to any system that could prevent the accomplishment of a safety function. Nonsafety-related overhead-handling equipment determined to have a possible impact on safety-related SSCs were included within the scope of license renewal. The LRA stated that the applicant had evaluated nonsafety-related portions of high-energy lines, including review of the UFSAR and relevant topical design basis document. As discussed in the 10 CFR 54.4(a)(2) project report, the applicant used these references to evaluate the high-energy lines for postulated pipe breaks and identified eleven systems within the reactor building and five systems outside the reactor building. The applicants high-energy systems were evaluated to ensure identification of components that are part of nonsafety-related high-energy lines that can effect safety-related equipment. If the applicants high-energy line break (HELB) analysis assumed that a nonsafety-related piping system did not fail, or assumed failure only at specific locations, then that piping system (piping, equipment and supports) was included in the scope of license renewal. Many of the identified systems were safety-related and 2-16

included within the scope of license renewal in accordance with 10 CFR 54.4(a)(1). The remaining nonsafety-related high-energy lines that were determined to have potential interaction with safety-related SSCs were included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The applicant evaluated moderate and low energy systems that have the potential for spatial interactions of spray and leakage. Nonsafety-related systems and nonsafety-related portions of safety-related systems with the potential for spray or leakage that could prevent safety-related SSCs from performing their required safety function were considered in the scope of license renewal. In addition, the applicant evaluated retired in place (RIP) systems for potential for spatial interaction. These RIP systems include both air-filled and fluid-filled portions of systems which were depressurized and isolated or capped from the remaining system. The applicant performed a review of the material/environment combinations for the RIP systems to determine if leakage of any fluid-filled portions due to corrosion could create the potential for a spatial interaction. The applicant applied the guidance from the Electric Power Research Institute (EPRI), Non-Class 1 Mechanical Implementation guideline and Mechanical Tools, Revision 4, 2006. Consistent with the EPRI tools guidance, the applicant determined that the current configuration of these systems would not provide the necessary mechanisms to cause a failure in these systems which could result in system degradation and the potential subsequent leakage. The 10 CFR 54.4(a)(2) project report stated that the applicant used a spaces approach to identify the nonsafety-related SSCs which were located within the same space as safety-related SSCs. A space was defined as a room or cubicle, separated by walls, floors, and ceilings. The applicant documented the review of each mechanical system for potential spatial interaction with safety-related SSCs in applicants scoping results report, as documented in the audit report. Following identification of the applicable mechanical systems, the applicant reviewed the system functions to determine whether the system contained fluid, air or gas. Nonsafety-related SSCs containing air or gas were excluded from the scope of license renewal. The applicant then reviewed the mechanical systems to determine whether the system had any components located within a safety-related structure. Those liquid-filled systems determined to have components located within a safety-related structure where then reviewed to determine if the system had components located within a space containing safety-related SSCs. Those nonsafety-related SSCs determined to contain fluid and to be located within a space containing safety-related SSCs were included within the scope license renewal. In its letter dated July 3, 2007, the applicant included addition information in response to RAI 2.1-2 (which discussed nonsafety-related piping attached to safety-related SSCs). As a result of the staffs inspection activities, the applicant expanded its review of nonsafety-related SSCs located in the turbine building and the potential for spatial interaction with safety-related SSCs. The applicant identified that portions of certain systems within the scop of license renewal had been expanded to include additional nonsafety-related components located in the turbine building. These components are within the scope of license renewal due to the potential for spatial interaction with safety-related SSCs and are subject to an aging management review. 2-17

In addition, protective features, such as whip restraints, spray shields, supports, missile or flood barriers (which can prevent physical impact and fluid leakage, spray, or flooding), installed to protect safety-related SSCs against spatial interaction with nonsafety-related SSCs were included within the scope of license renewal. 2.1.4.2.3 Conclusion Based on its review, the staff determines that the applicant's methodology for identifying systems and structures meets 10 CFR 54.4(a)(2) scoping criteria and, therefore, is acceptable. This determination is based on a review of sample systems, discussions with the applicant, and review of the applicant's scoping process. 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 In LRA Section 2.1.1.3, Application of Criterion for Regulated Events, the applicant described the methodology for identifying systems, structures, and components relied on in safety analyses or plant evaluation to perform a function. Mechanical systems and structures that perform a intended 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 (ATWS) (10 CFR 50.62), and station blackout (SBO) (10 CFR 50.63) were included in the scope of license renewal. Mechanical systems and structures that have an intended function for 10 CFR 54.4(a)(3) are identified in LRA Sections 2.3 and 2.4. For example, LRA Section 2.3.2.2 states that the core spray (CS) system has two intended functions for 10 CFR 54.4(a)(3): the Appendix R safe shutdown capability analysis and the SBO coping analysis. LRA Section 2.4.3 states that the intake structure has one intended function for 10 CFR 54.4(a)(3): the Appendix R safe shutdown capability analysis for fire protection. All plant electrical and instrumental and control (EIC) systems and electrical equipment in mechanical systems were included in-scope of license renewal. Fire Protection. The applicant described the scoping of mechanical systems and structures required to demonstrate compliance with the fire protection requirements in LRA Section 2.1.1.3.1, Commissions Regulations for Fire Protection (10 CFR 50.48). The applicant reviewed its CLB and identified the mechanical systems and structures relied upon to meet Appendix R and 10 CFR 50.48 requirements. Mechanical systems and structures credited with fire prevention, detection, mitigation in areas containing equipment important to safe operation of the plant, and equipment credited with safe shutdown in the event of a fire were included in-scope license renewal. Environmental Qualification. The applicant described the environmental qualification requirements of 10 CFR 50.49 in LRA Section 2.1.1.3.2, Commissions Regulations for Environmental Qualification (10 CFR 50.49). All plant EIC systems and electrical equipment in mechanical systems were included in-scope of license renewal. Pressurized Thermal Shock. These requirements are not applicable because Vermont Yankee is a Boiling Water Reactor. 2-18

Anticipated Transient Without Scram. The applicant described the scoping of mechanical systems and structures required to demonstrate compliance with the anticipated transient without scram (ATWS) requirements of 10 CFR 50.62 in LRA Section 2.1.1.3.4, Commissions Regulations for Anticipated Transients without Scram (10 CFR 50.62). Mechanical systems and structures that perform a 10 CFR 50.62 intended function were included in-scope of license renewal. Station Blackout. The applicant described the scoping criteria in LRA Section 2.1.1.3.5, Commissions Regulations for Station Blackout (10 CFR 50.63). The applicants licensing basis requires a SBO coping duration of two hours and mechanical systems and structures required to support the two-hour coping duration are within the scope of license renewal. Although the switchyard is not considered a plant system, the offsite power system and related structures required to restore offsite power were also included in-scope of license renewal. 2.1.4.3.2 Staff Evaluation The staff reviewed the applicants approach to identifying mechanical systems and structures relied upon to perform a function related to the four regulated events applicable to boiling water reactors (BWRs) required by 10 CFR 54.4(a)(3). As part of this review, the staff discussed the methodology with the applicant, reviewed the documentation developed to support the review, and evaluated a sample of the resultant mechanical systems and structures identified as in-scope for 10 CFR 54.4(a)(3) criteria. The LRPGs described the applicants process for identifying systems and structures that are in the scope of license renewal. The LRPGs stated that all mechanical systems and structures that perform an intended function for 10 CFR 54.4(a)(3) are to be included in-scope of license renewal, and that the results of scoping are documented in the applicants scoping results report. The report also described the procedures and data base that were used to identify mechanical systems and structures for regulated events. In addition, the applicant used a variety of The Topical Design Basis Documents, as described in the audit report, to identify the principle systems for each regulated event. The applicants component database uses a classification code of OQA for components that are not safety-related but are subject to the requirements imposed by NRC regulations. Systems initially identified as not meeting the criterion of 10 CFR 54.4(a)(3) based on review of design basis information were reviewed for OQA components in the component database to verify that the systems performed no intended functions for license renewal regulated events. Fire Protection. The applicants LRPDs state that the Fire Hazard Analysis, Fire Protection and Appendix R Program, and Safe Shutdown Capability Analysis, are used to identify mechanical systems and structures that are in-scope of license renewal. The report identifies the mechanical systems that are included in-scope of license renewal because they perform a 10 CFR 50.48 intended function. For example, the fire protection system has one intended function, which is to extinguish fires in the vital areas of the plant. The LRPDs summarizes the scoping results for mechanical systems and identifies 23 mechanical systems which have one 2-19

or more 10 CFR 50.48 intended functions. The report also identifies the structures that are included in-scope of license renewal because they perform a 10 CFR 50.48 function, and provides a summary of the scoping results for ten structures that have one or more 10 CFR 50.48 intended functions. For example, the carbon dioxide (CO2) tank foundation has one intended function, which is to provide support for the CO2 tank. Environmental Qualification. For the environmental qualification regulated event, the staff reviewed the LRA, the applicants implementation procedures, results reports, and the master equipment list. These were used by the applicant to identify environmental qualification components within the scope of license renewal. The staff also reviewed the environmental qualification list which was used by the applicant during the screening process to identify short-lived components. Anticipated Transient Without Scram. The applicants scoping results report identifies the mechanical systems that are included in-scope of license renewal because they perform a 10 CFR 50.62 intended function. For example, one intended function of the control rod drive (CRD) system is to provide alternate rod insertion during an ATWS event. The report summarizes the scoping results for mechanical systems, identifies that the CRD and SLC systems perform 10 CFR 50.62 intended functions, and identifies one structure that is included in-scope of license renewal because it performs a 10 CFR 50.62 intended function. A criterion for including the reactor building in-scope of licensee renewal was that it housed equipment credited for ATWS. Station Blackout. The applicants scoping results report states that mechanical systems and structures credited with the two-hour coping duration and switchyard components required to restore offsite power are included in-scope of license renewal. The report identifies the mechanical systems that are were included in-scope of license renewal because they perform a 10 CFR 50.63 intended function. For example, the CS system has one intended function which is to provide reactor coolant makeup in the SBO coping analysis. The report summarizes the scoping results for mechanical systems, identifies eight mechanical systems that have one or more 10 CFR 50.63 intended functions, and identifies that the Offsite Power system is in-scope of license renewal because it performs a 10 CFR 50.63 intended function. The report also identifies the structures that were included in-scope of license renewal because they perform a 10 CFR 50.63 function. For example, the Vernon Hydroelectric Station (VHS) had one intended function which is to maintain integrity for SBO. The report summarizes the scoping results for structures and identifies five structures that have one or more 10 CFR 50.63 intended functions. Section 54.4(a)(3) of 10 CFR requires that all systems and structures relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission's regulation for SBO (10 CFR 50.63) be included in the scope of license renewal. LRA Section 2.1.1.3.5 stated that the VHS is credited as the alternate alternating current (AC) power source for SBO. LRA Section 2.4.5 states that the VHS structures are in-scope of license renewal. LRA Section 2.3.5 and the applicants scoping results report identify the VHS structures that are in the scope of license renewal. However, the VHS mechanical and electrical systems were not explicitly identified as being included in the scope of license renewal. It was not clear to the staff why the Vernon Station mechanical and electrical systems were not identified in the scope of license renewal in accordance with 10 CFR 54.4(a)(3). Therefore, the staff submitted RAI 2.1-3 requesting that the applicant describe the scoping and screening 2-20

methodology as it applies to the mechanical and electrical systems associated with the VHS, and identify those mechanical and electrical systems and components (SCs) that are in the scope of license renewal and subject to an AMR. In its responses, by letters dated July 14, 2006, August 10, 2006, and October 20, 2006, the applicant further described the scoping and screening process used to evaluate the VHS. The applicant identified the VHS as the alternate alternating current source credited for the VYNPS loss of all alternating current power compliance with 10 CFR 50.63 (SBO rule), and therefore, in-scope of license renewal. The applicant stated, in part, that they had credited the Federal Energy Regulatory Commission dam inspection program to manage the effects of aging on the civil and structural elements of the VHS. All additional mechanical and electrical systems associated with the turbine generator (TG) were considered an active assembly that is routinely confirmed through normal operation and therefore, consistent with the screening process, determined to not be subject to an AMR. Notwithstanding the screening of the mechanical and electrical systems as part of the active assembly, the applicant performed an IPA of the passive, long-lived electrical and mechanical components of the VHS. On the basis of this evaluation, the applicant identified specific structural, mechanical, and electrical SSCs that support one or more of the intended functions of the VHS, which is consistent with the screening methodology described in Safety Evaluation (SE) Section 2.1.5. The staff reviewed the applicants responses to the RAI and concluded that the applicant has adequately described its process for scoping and screening of the VHS, and has identified the VHS as in-scope. The applicant has also evaluated the SSCs associated with the VHS, consistent with the screening methodology described in SE Section 2.1.5. The staff found that the applicant has adequately addressed the staff's RAI. Therefore, the staffs concern described in RAI 2.1-3 is resolved. 2.1.4.3.3 Conclusion On the basis of the sample review, discussions with the applicant, the applicants RAI response, and review of the applicant's scoping process, the NRC staff determines that the applicant's methodology for identifying systems and structures meets the scoping criteria of 10 CFR 54.4(a)(3), and is therefore 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. The applicant documented its methodology for performing the scoping of SSCs in accordance with 10 CFR 54.4(a) in its LRPGs and LRPDs. The applicant's approach to system and structure scoping provided in the site guidance was consistent with the methodology described in LRA Section 2.1. The LRPGs specify that the personnel performing license renewal scoping use CLB documents, describe the system or structure, and list the functions that the system or structure is required to accomplish. Sources of information regarding the CLB for systems included the UFSAR, DBDs, VYNPS component database, Maintenance Rule scoping reports, control drawings, and docketed correspondence. The applicant then compared identified system or structures function lists to the scoping criteria to determine whether the functions met the scoping criteria of 10 CFR 54.4(a). The applicant 2-21

documented the results of the plant-level scoping process in accordance with the LRPGs. These results were provided in the systems and structures LRPDs. The information in the LRPDs includes a description of the structure or system, a listing of functions performed by the system or structure, information pertaining to system realignment (as applicable), identification of intended functions, the 10 CFR 54.4(a) scoping criteria met by the system or structure, references, and the basis for the classification of the system or structure intended functions. During the scoping methodology audit, the staff reviewed a sampling of LRPD reports and concluded that the applicant's scoping results in the LRPDs contained an appropriate level of detail to document the scoping process. Conclusion On the basis of a review of the LRA, the scoping and screening implementation procedures, and a sampling review of system and structure scoping results during the methodology audit, the staff concludes that the applicant's scoping methodology for systems and structures was adequate. In particular, the staff determines that the applicant's methodology reasonably identified systems and structures within the scope of license renewal and their associated intended functions. Component Level Scoping. After the applicant identified the systems and structures within the scope of license renewal, a review of mechanical systems and structures was performed to determine the components in each in-scope system and structure. The structural and mechanical components that supported intended functions were considered within the scope of license renewal and screened to determine if an AMR was required. All electrical components within the mechanical and electrical systems were included in-scope as commodity groups (groups of like structures and components). The applicant considered three component classifications during this stage of the scoping methodology: mechanical, structural, and electrical. The VYNPS component database and controlled plant drawings provide a comprehensive listing of plant components. Component type and unique component identification numbers were used to identify each component identified as in-scope and subject to an AMR. Commodity Groups Scoping. Initially all electrical components within the mechanical and electrical systems were included in the scope of license renewal as commodity groups. Since many electrical component types are considered active in accordance with the guidance in NEI 95-10 and the SRP-LR, they were screened out as not meeting the passive criteria and were subsequently not subject to an AMR. In LRA Section 2.1.2.3, the applicant described the commodity groups used to evaluate all in-scope electrical components subject to an AMR. Structural components were grouped as structural commodity types. Commodity types were based on materials of construction. LRA Section 2.1.2.2.1 identified the various structural commodity groups including:

• steel
• threaded fasteners
• concrete
• fire barriers 2-22
• elastomers
• earthen structures
• flouropolymers and lubrite sliding surfaces Insulation. LRA Section 2.4.6, Bulk Commodities, stated that insulation may have the specific intended functions of (1) controlling the heat load during design basis accidents in areas with safety-related equipment, or (2) maintaining integrity such that falling insulation does not damage safety-related equipment (reflective metallic type reactor vessel insulation). As such, insulation is included in the scope of license renewal as a commodity group in those applications where it provides one or both of the above intended function.

Consumables. In LRA Section 2.1.2.4, Consumables, the applicant discussed consumables. The guidance in Table 2.1-3 in NUREG-1800 was used to categorize and evaluate consumables. Consumables were divided into the following four categories for the purpose of license renewal: (a) packing, gaskets, component seals, and O-rings; (b) structural sealants; (c) oil, grease, and component filters; and (d) system filters, fire extinguishers, fire hoses, and air packs. The consumables in both categories (a) and (b) are considered as subcomponents. Category (a) subcomponents are not relied upon to form a pressure-retaining function and, therefore, not subject to an AMR. Category (b) subcomponents are structural sealants for structures within the scope of license renewal that require an AMR. Category (c) consumables are periodically replaced in accordance with plant procedures and, therefore, not subject to an AMR. Category (d) consumables are subject to replacement based on National Fire Protection Association (NFPA) standards in accordance with plant procedures and, therefore, not subject to an AMR. 2.1.4.4.2 Staff Evaluation The staff reviewed the applicants methodology for performing the scoping of plant systems and components to ensure it was consistent with 10 CFR 54.4(a). The methodology used to determine the mechanical systems and components in-scope of license renewal was documented in LRPDs and plant level scoping results were identified in LRA Table 2.2-1. The scoping process defined the entire plant in terms of systems and structures. As specified in the LRPGs, the applicant identified the systems and structures that are subject to 10 CFR 54.4 review, described the processes for capturing the results of the review, and determined if the system or structure performed intended functions consistent with the criteria of 10 CFR 54.4(a). The process was completed for all systems and structures to ensure that the entire plant was addressed. The applicants technical personnel performed initial reviews on systems and structures identified in the CLB. The staff noted that a system or structure was presumed to be in-scope of license renewal if it performed one or more safety-related functions or met the other scoping criteria per the Rule as determined by CLB review. Mechanical and structural component types that supported intended functions were considered in-scope of license renewal. All component types in electrical systems in-scope of license renewal were considered in-scope of license renewal. These component types were placed in commodity groups. The electrical commodity groups were further screened to determine if they required an AMR. The staff did not identify any discrepancies with the methodology used by the applicant. 2-23

The staff reviewed the methodology used by the applicant to generate commodity groups. Separate commodity groups were identified for various mechanical, structural, and electrical components and were identified in the LRPDs. The staff reviewed the commodity group level functions that were identified and evaluated by the applicant in accordance with 10 CFR 54.4(a). This process determined whether the commodity group was considered in-scope of license renewal.The staff found the methodology used acceptable. The staff reviewed the results of the scoping process documented in the LRPDs in accordance with the LRPGs. This documentation included the description of the system or structure and the 10 CFR 54.4(a) scoping criteria met by the system or structure. The staff also reviewed a sample of the applicants scoping documentation and concluded that it contained an appropriate level of detail to document the scoping process. The staff reviewed the applicants evaluation of plant insulation as documented in the LRPD and the bulk commodities AMR. The applicant identified insulation as being in-scope and subject to an AMR based on it providing intended functions of insulating characteristics to reduce heat transfer, and structural or functional support to nonsafety-related SCs whose failure could prevent safety-related functions. Both mirror and non-mirror insulation were evaluated. The staff concludes that the applicants methods and conclusions regarding insulation are acceptable. The staff reviewed the scoping and screening of consumables and finds that the applicant followed the process described in NUREG-1800, and appropriately identified and categorized the various consumables in accordance with the guidance. Plant consumables were initially identified and evaluated to determine if any met the criteria requiring an AMR, such as structural sealants. Additionally, the applicant identified all pertinent industry guidelines which were used as the basis for replacement of the item, such as NFPA standards. 2.1.4.4.3 Conclusion Based on its review of the LRA, scoping and screening implementation procedures, and a sampling of system scoping results during the audit, the staff concludes that the applicants scoping methodology for plant SSCs, commodity groups, insulation, and consumables is acceptable. In particular, the staff determines that the applicants methodology reasonably identifies systems, structures, component types, and commodity groups within the scope of license renewal and their intended functions. 2.1.4.5 Mechanical Component Scoping 2.1.4.5.1 Summary of Technical Information in the Application In LRA Section 2.1, the applicant described the methodology for identifying mechanical system components that are in the scope of license renewal. For mechanical systems, the mechanical components that support the system intended functions are included in the scope of license renewal. For mechanical system scoping, a system was defined as the collection of components in the component database assigned to the system code. System intended functions were determined based on the functions performed by those components. Defining a system by the components in the database is generally consistent with the VYNPS 2-24

maintenance rule scoping documents and safety classification procedure. Each mechanical system was evaluated against the criteria of 10 CFR 54.4 to determine which system components performed the intended functions consistent with the scoping criteria. 2.1.4.5.2 Staff Evaluation The staff evaluated LRA Section 2.1 and the guidance in LRPDs, LRPGs, and aging management (AM) reports to complete the review of mechanical scoping process. The program guidelines and AM reports provided instructions for identifying and evaluating individual mechanical system components with respect to the scoping criteria. The CLB documents were utilized when determining whether a system or component is within the scope of 10 CFR 54.4(a). Examples of these sources included, but were not limited to, the UFSAR, Maintenance Rule database, separate ATWS, environmental qualification, fire protection and SBO documents, technical specifications, safety evaluation reports. Additional sources of mechanical component information included the VYNPS component database and individual system flow diagrams. Mechanical system diagrams were evaluated to create license renewal boundaries for each system showing the in-scope components. Components that support a safety-related function or a regulated event were identified and further evaluated during the screening process to determine if the component should be subject to an AMR. Nonsafety-related components that are connected to safety-related components and provide structural support at the safety/nonsafety interface, or components whose failure could prevent satisfactory accomplishment of a safety-related function due to spatial interaction with safety-related SSCs are included in-scope and individually identified in the AMR associated with the 10 CFR 54.4(a)(2) evaluation, but were not specifically highlighted on the license renewal drawings. As part of the applicants verification process, the list of mechanical components identified as in-scope were compared to the data in LRIS and the VYNPS component database to confirm the scope of components in the system. The staff reviewed the implementation guidance and the CLB documents associated with mechanical system scoping, and found that the guidance and CLB source information noted above were acceptable to identify mechanical components and support structures in mechanical systems that are within the scope of license renewal. The staff conducted detailed discussions with the applicant's license renewal project management personnel and reviewed documentation pertinent to the scoping process. The staff assessed whether the applicant had appropriately applied the scoping methodology outlined in the LRA and implementation procedures and whether the scoping results were consistent with CLB requirements. The staff determined that the applicant's proceduralized methodology was consistent with the description provided in the LRA Section 2.1 and the guidance contained in SRP-LR, Section 2.1, and was adequately implemented. 2-25

Scoping Methodology for the Core Spray System In LRA Section 2.3.2.2, Core Spray, the applicant provided the scoping and screening methodology results for SSCs within the CS system. The CS system is a safety-related system and is credited with mitigating the effects of a loss of coolant events. The CS system accomplishes the following scoping criteria associated with the Rule: The CS system has the following intended functions for 10 CFR 54.4(a)(1):

• Provide injection of water following loss of reactor coolant
• Support primary containment isolation
• Provide reactor coolant pressure boundary The CS system has the following intended function for 10 CFR 54.4(a)(2):
• Maintain integrity of nonsafety-related components such that no physical interaction with safety-related components could prevent satisfactory accomplishment of a safety function The CS system has the following intended function for 10 CFR 54.4(a)(3):
• The CS system is credited in the Appendix R safe shutdown capability analysis (10 CFR 50.48)
• The CS system is credited in the SBO coping analysis (10 CFR 50.63)

The CS license renewal scoping boundary includes those portions of nonsafety-related piping and equipment that extend beyond the safety-related/nonsafety-related interface. The scoping results indicated that the CS contains six system functions within the scope of license renewal. As part of the audit, The staff reviewed the applicant's methodology for identifying CS mechanical component type meeting the scoping criteria as defined in the Rule. The staff also reviewed the scoping methodology implementation procedures and discussed the methodology and results with the applicant. The staff confirmed that the applicant had identified and used pertinent engineering and licensing information in order to determine the CS mechanical component type required to be in-scope of license renewal. As part of the review process, the staff evaluated each system intended function identified for the CS system, the basis for inclusion of the intended function, and the process used to identify each of the system components credited with performing the intended function. The staff confirmed that the applicant had identified and highlighted system P&IDs to develop the system boundaries in accordance with the procedural guidance. The applicant was knowledgeable about the process and conventions for establishing boundaries as defined in the license renewal implementation procedures. Additionally, the staff confirmed that the applicant had independently confirmed the results in accordance with the governing procedures. Specifically, other license renewal personnel knowledgeable about the system had independently reviewed the marked-up drawings to ensure accurate identification of system intended functions. The applicant performed additional cross-discipline verification and independent reviews of the resultant highlighted drawings before final approval of the scoping effort. 2-26

2.1.4.5.3 Conclusion Based on its review of the LRA, scoping implementation procedures, and the system sample and discussions with the applicant, the staff concludes that the applicants methodology for identifying mechanical systems for 10 CFR 54.4(a) scoping criteria is acceptable. 2.1.4.6 Structural Component Scoping 2.1.4.6.1 Summary of Technical Information in the Application In LRA Section 2.1, the applicant described the methodology for identifying structures that are in the scope of license renewal. All plant structures and SBO-related non-plant structures were initially identified. Structure intended functions were identified using CLB documents such as the UFSAR, the Maintenance Rule document for buildings and structures, safety classification procedures, the fire hazards analysis, and the safe shutdown capability assessment. Structures that have an intended function for 10 CFR 54.4(a) were included in the scope of license renewal and listed in LRA Table 2.2-3. Structures that were not in-scope of license renewal are listed in LRA Table 2.2-4. LRA Section 2.4 describes the scoping results for the individual structures that are in-scope of license renewal. For example, LRA Section 2.4.1 describes the intake structures purpose and seismic classification. The intake structure was in-scope of license renewal because it provides supports, shelter and protection for safety and nonsafety-related systems within the scope of license renewal. 2.1.4.6.2 Staff Evaluation The staff reviewed the applicants approach for identifying structures relied upon to perform the functions as required by 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 several structures that were identified in-scope of license renewal. The LRPGs describe the applicants process for identifying structures that are in the scope of license renewal and state that all structures that perform an intended function are to be included in-scope of license renewal and that the scoping results are to be documented in the scoping results report. The scoping results report lists all the structures that were evaluated and also describes the procedures that were used to identify structures. In additional, the plant UFSAR, Maintenance Rule Document, Fire Hazards Analysis, and Safe Shutdown Capability Analysis were used to identify structures. The applicants component database uses a classification code of BLD for structures, and a search of this data base was used to identify structures. The staff reviewed the applicants implementation procedures and scoping results reports. Structural scoping was performed in a manner to ensure that all plant buildings, yard structures, and SBO related non-plant structures were considered. The scoping results report identified the intended functions for each structure required for compliance with one or more criteria of 10 CFR 54.4(a). The structural component intended functions were identified based on the guidance provided in NEI 95-10 and NUREG-1800. For structures, the evaluation boundaries were determined by developing a complete description of each structure with respect to the 2-27

intended functions performed by the structure. The results of the review were documented in the scoping results report (which contains a list of structures, evaluation results for each of the 10 CFR 54.4(a) criteria for each structure, a description of structural intended functions, and source reference information for the functions). The staff conducted detailed discussions with the applicants license renewal team and reviewed documentation pertinent to the scoping process. The staff assessed if the scoping methodology outlined in the LRA and procedures were appropriately implemented and if the scoping results were consistent with CLB requirements. The staff also reviewed structural scoping evaluation results for the intake structure and VHS to verify proper implementation of the scoping process. Based on these audit activities, the staff did not identify any discrepancies between the methodology documented and the implementation results. 2.1.4.6.3 Conclusion Based on its review of the LRA, the applicant's detailed scoping implementation procedures, and a sampling of structural scoping results, the staff concludes that the applicant's methodology for identification of structural component types within the scope of license renewal meets 10 CFR 54.4(a) requirements 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 2.1.1, Scoping Methodology describes the scoping process associated with electrical systems and components. For the purposes of system level scoping, plant EIC systems were included in the scope of license renewal. EIC components in mechanical systems were included in the evaluation of electrical systems. LRA Section 2.1.1 refers to LRA Section 2.5, Scoping and Screening Results: Electrical and Instrumentation and Control Systems, which further states that the default inclusion of plant electrical and instrumentation and controls (EIC) systems in the scope of license renewal reflects the method used for the scoping of electrical systems, which is different from the methods used for mechanical systems and structures. The approach used for EIC components was to include components in the review unless they were specifically screened out. When used with the plant spaces approach, this method eliminated the need for unique identification of every component and its specific location. This gave assurance that components were not excluded from an AMR. 2.1.4.7.2 Staff Evaluation The staff evaluated LRA Sections 2.1.1 and 2.5 and the applicants implementing procedures and aging management reports, as documented in the audit report, governing the electrical scoping methodology. The scoping phase for electrical components began with placing all electrical components from plant systems within the scope of license renewal. In addition, any electrical components from non-plant systems that met the criteria for inclusion of 10 CFR 54.4(a) (such as components credited for SBO) were also included within the scope of license renewal. The staff determined that the data sources used for scoping included the EMPAC data base, the station single line drawing, and the cable design procurement specifications. The applicant gathered and sorted the collection of all electrical components 2-28

from the data sources and assembled the data into word processing file, called the scoping file. The staff reviewed selected portions of the data sources and the resulting assemblage of the data contained in the scoping file. The staff selected components for validation. The applicant demonstrated the component location in the data source and how the component was included in the scoping file through implementation of the LRPGs. 2.1.4.7.3 Conclusion Based on its review of the LRA, the applicants detailed scoping implementation procedures, and a sampling of electrical scoping results, the staff concludes that the applicants methodology for identification of electrical components within the scope of license renewal meets 10 CFR 54.4(a) requirements and, therefore, is acceptable. 2.1.4.8 Conclusion for Scoping Methodology Based on its review of the LRA and the scoping implementation procedures, the staff determines that the applicant's scoping methodology is consistent with SRP-LR guidance and has identified SSCs within the scope of license renewal as required by 10 CFR 54.4(a)(1), (a)(2), and (a)(3). Therefore, the staff concludes that the applicants methodology meets 10 CFR 54.4(a) requirements. 2.1.5 Screening Methodology 2.1.5.1 General Screening Methodology After identifying systems and structures within the scope of license renewal, the applicant implemented a process for identifying SCs subject to an AMR in accordance with 10 CFR 54.21. 2.1.5.1.1 Summary of Technical Information in the Application In LRA Section 2.1.2, Screening Methodology, the applicant discussed the method of identifying components from in-scope systems and structures that are subject to an AMR. The screening process consisted of the following steps: Identification of components that are long-lived or passive for each in-scope mechanical system, structure and electrical commodity group. Identification of the license renewal intended function(s) for all mechanical and structural component types and electrical commodity groups. Active components were screened out and therefore, did not require an AMR. The screening process also identified short lived components and consumables. The short lived components are not subject to an AMR. Consumables are a special class of items that include packing, gaskets, component seals, O-rings, oil, grease, component filters, system filters, fire extinguishers, fire hoses, and air packs. Structural sealants for structures were the only consumables in-scope of license renewal that require an AMR. 2-29

2.1.5.1.2 Staff Evaluation Pursuant to 10 CFR 54.21, the Commission requires that each LRA must contain an IPA that identifies 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 time period (long-lived). The IPA includes 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 function(s) will be maintained in accordance with 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 determine if mechanical and structural component types, and electrical commodity groups in-scope of license renewal should be subject to an AMR. The applicant implemented a process for determining which SCs were subject to an AMR as required by 10 CFR 54.21(a)(1). In LRA Section 2.1.2, the applicant discussed these screening activities as they related to the component types and commodity groups within the scope of license renewal. The screening process evaluated these in-scope component types and commodity groups to determine which ones were long-lived and passive and therefore, subject to an AMR. The staff reviewed LRA Sections 2.3, 2.4, and 2.5 that provided the results of the process used to identify component types and commodity groups subject to an AMR. The staff also reviewed the screening results reports for the CS system and intake structure. The applicant provided the staff with a detailed discussion of the processes used for each discipline and provided administrative documentation that described the screening methodology. Specific methodology for mechanical, electrical, and structural is discussed below. 2.1.5.1.3 Conclusion Based on its review of the LRA, the screening implementation procedures, and a sampling of screening results, the staff determines that the applicants screening methodology is consistent with SRP-LR guidance and capable of identifying passive, long-lived components within the scope of license renewal and subject to an AMR. The staff determines that the applicants process for identifying component types and commodity groups subject to an AMR meets 10 CFR 54.21 requirements and, therefore, is acceptable. 2.1.5.2 Mechanical Component Screening 2.1.5.2.1 Summary of Technical Information in the Application In LRA Section 2.1.2.1, Screening of Mechanical Systems, the applicant discussed the screening methodology for identifying passive and long-lived mechanical components and their support structures that are subject to an AMR. License renewal drawings were prepared to indicate portions of systems that support system intended functions within the scope of License renewal (with the exception of those systems in-scope for 10 CFR 54.4(a)(2) for physical 2-30

interactions, as discussed below). In addition, the drawings identify components that are subject to an AMR. Boundary flags are used in conjunction with safety-to-nonsafety class breaks to identify the system intended function boundaries. Boundary flags are noted on the drawings as system intended function boundaries. All components within these boundary flags and class breaks support system intended functions within the scope of license renewal. Components subject to an AMR (i.e., passive, long-lived components that support system intended functions) were highlighted to indicate that the component was subject to an AMR. 2.1.5.2.2 Staff Evaluation The staff evaluated the mechanical screening methodology in LRA 2.1.2.1, Screening of Mechanical Systems, the LRPDs, LRPGs, and the AMR reports, as documented in the audit report. The mechanical system screening process began with the results from the scoping process. The applicant reviewed each mechanical system flow diagram to identify passive and long-lived components. To identify system components required to perform a system intended function, the applicant generated a listing of mechanical system components based on information derived from controlled system diagrams and the VYNPS component database. The LRPGs and LRPDs discuss in detail how to (1) determine system boundaries, (2) indicate components within a specific flow path which are required for performance of intended functions, and (3) determine and identify system and interdisciplinary interfaces (e.g., mechanical/structural, mechanical/electrical, structural/electrical). These components were entered into the LRIS database. The applicant also reviewed components in the VYNPS component database to confirm that all system components were considered. In cases where the mechanical system flow diagrams did not provide sufficient detail, such as large vendor supplied components (e.g., compressors, emergency diesel generators (EDGs)), the applicant reviewed associated component drawings or vendor manuals as necessary to identify individual components. The staff reviewed the results of the boundary evaluation and discussed the process further with the applicant. The staff confirmed that mechanical system evaluation boundaries were established for each system within the scope of license renewal. These boundaries were determined by mapping the pressure boundary associated with system-level license renewal intended functions onto the controlled system drawings. Mechanical component types were loaded into a scoping and screening database and further review was performed to ensure all component types were identified. If a component type was not already in the LRIS, the component type was created for use in the license database. A preparer and an independent reviewer performed a comprehensive evaluation of the boundary drawings to ensure the completeness and accuracy of the review results. As part of the evaluation, the applicant also benchmarked passive and long-lived components for a system against previous LRAs containing similar systems. As part of the audit, the staff reviewed the methodology used by the applicant to identify SSCs which met the screening criteria of the Rule. The staff confirmed that the applicant had implemented and followed the screening guidance in the SRP-LR and NEI 95-10. The staff confirmed the applicant had developed sufficiently detailed procedures for the screening of mechanical systems, had implemented those procedures, and had adequately documented the results in the associated AMR reports. 2-31

Additionally, the staff reviewed the screening activities associated with the CS system. The staff reviewed the system intended functions and associated source documents identified for the system, the CS flow diagrams, and the associated results documented in the AMR report. The staff did not identify any discrepancies with the evaluation, and determined that the applicant has adequately followed the process documented in the LRPDs and adequately documented the results in the AMR reports. 2.1.5.2.3 Conclusion Based on its review of the LRA, the screening implementation procedures, and a sample review of CS screening results, the staff determines that the applicant's mechanical component screening methodology is consistent with SRP-LR guidance. The staff concludes that the applicants methodology for identification of passive, long-lived mechanical components within the scope of License renewal and subject to an AMR meets 10 CFR 54.21(a)(1) requirements. 2.1.5.3 Structural Component Screening 2.1.5.3.1 Summary of Technical Information in the Application The applicant described the methodology used for structural screening in LRA Sections 2.1.2.2, Screening of Structures, and 2.4, Scoping and Screening Results: Structures. LRA Section 2.1.2.2 states that structural components were evaluated to determine those subject to an AMR for each structure within the scope of license renewal. Specific structural components were identified from reviewing the CLB (drawings, etc.). Passive and long-lived structural components that performed an intended function were identified and subject to an AMR. NUREG-1800 and NEI 95-10, Appendix B, were used as the basis for the identification of passive structural components. Structural components (door, gate, pipe support, strut, or siding for example) were categorized as steel, threaded fasteners, concrete, fire barriers, elastomers, earthen structures, or flouropolymers and lubrite sliding surfaces. LRA Section 2.4 summarizes the screening results for structures. For example, LRA Section 2.4.3 and Table 2.4-3 summarize the screening results for the intake structure. LRA Section 2.4.5 and Table 2.4-5 summarize the screening results for the VHS. The structural components common to all structures such as piping supports were categorized as bulk commodities. LRA Section 2.4.6 and Table 2.4-6 summarize the screening results for structural bulk commodities. 2.1.5.3.2 Staff Evaluation The staff reviewed the applicants methodology for identifying structural components that are subject to an AMR as required in 10 CFR 54.21(a)(1). As part of this review, the staff discussed the methodology with the applicant, reviewed the documentation developed to support the activity, and evaluated the screening results for several structures that were identified in-scope of license renewal. The applicants AM reports, as described in the audit report, provided detailed implementation guidance on the applicants process for identifying and screening structural components that are subject to an AMR. The report stated that all structural components that perform an intended function and are passive and long-lived are subject to an AMR. In addition, the screening results for each system were described in separate AM reports for each system. 2-32

The staff reviewed the applicant's methodology used for structural screening described in LRA sections noted above, and in applicants implementing guidance and AM reports The applicant performed the screening review in accordance with the implementation guidance and captured pertinent structure design information, component, materials, environments, and effects of aging. The staff confirmed that the applicant used the lists of passive SCs embodied in the regulatory guidance as an initial starting point and supplemented that list with additional items unique to the site or for which a direct match to the generic lists did not exist (i.e., material/environment combinations). As one of the general rules for structural screening, the applicant determined that components which support or interface with electrical components such as, cable trays, conduits, instrument racks, panels and enclosures, were assessed as structural components. The boundary for a structure was the entire building including base slabs, foundations, walls, beams, slabs, and steel superstructure. The AM reports identified each individual SC and indicated if the component is subject to an AMR. Each component was identified as a component, as a component type (door, gate, anchor support, strut, or siding for example), or as a material. The applicant provided the staff with a detailed discussion that described the screening methodology, as well as the screening reports for a selected group of structures. The staff also examined the applicants results from the implementation of this methodology by reviewing several of the plant structures (intake structure and VHS) identified as being in-scope. As part of this review, the staff reviewed the AM reports to verify that the applicant had performed a comprehensive evaluation and had identified the relevant structural components as part of their evaluation. The review included the evaluation of in-scope components, the corresponding component-level intended functions, and the resulting list of components subject to an AMR. The staff also discussed the process and results with the applicant. The staff did not identify any discrepancies between the methodology documented and the implementation results. 2.1.5.3.3 Conclusion Based on its review of the LRA, the applicant's detailed screening implementation procedures, and a sampling of structural screening results, the staff concludes that the applicant's methodology for identification of passive, long-lived structural component types within the scope of License renewal and subject to an AMR meets 10 CFR 54.21(a)(1) requirements. 2.1.5.4 Electrical Component Screening 2.1.5.4.1 Summary of Technical Information in the Application In the LRA Section 2.1.2.3, Screening of Electrical and Instrumentation and Control Systems, the applicant discussed the use of NEI 95-10, Appendix B, Typical Structure, Component and Commodity Groupings and Active/ Passive Determinations for the Integrated Plant Assessment, which identifies electrical commodities considered to be passive. The electrical commodity groups were identified and cross-referenced to the appropriate NEI 95-10 commodity. 2-33

The applicant determined that the majority of EIC commodity groups are active and do not require an AMR. Two passive EIC commodity groups were identified that meet the 10 CFR 54.21(a)(1)(i) criterion (components that perform an intended function without moving parts or without a change in configuration or properties):

• high-voltage insulators, and
• cables and connections, bus, electrical portions of EIC penetration assemblies Additionally, the pressure boundary function that may be associated with some EIC components identified in NEI 95-10, Appendix B (flow elements, vibration probes) was considered in the mechanical AMRs, as applicable. Electrical components supported by structural commodities (cable trays, conduit and cable trenches) were included in the structural AMRs.

The applicant reviewed the passive electrical components to determine those components that were replaced based on a qualified life and therefore not subject to an AMR. The applicant determined that the components included in the Environmental Qualification of Electric Components Program per 10 CFR 50.49 are replaced based on qualified life and, therefore are not subject to an AMR. The applicant determined that the AMRs would be performed for the identified passive, non-Environmental Qualification EIC components. 2.1.5.4.2 Staff Evaluation The staff reviewed the applicants methodology used for electrical screening in LRA Sections 2.1.2.3 and the applicants implementation procedures and AM reports. The applicant used the screening process described in these documents to identify the electrical commodity groups subject to an AMR. The applicant used the VYNPS component database, the stations single line drawings, and cable procurement specifications as data sources to identify the EIC components including fuses-holders. The applicant determined there were no fuse-holders located outside of active devices and subject to an AMR. The staff determined that the applicant had performed screening by initially identifying passive SCs and subsequently identifying the long-lived SCs contained within the passive SC population. The applicant identified seven commodities that were determined to meet the passive criteria. The seven commodities were further grouped in accordance with NEI 95-10 as (1) cables and connections, electrical portions of penetration assemblies, switchyard bus, transmission bus, transmission conductors and uninsulated ground conductors, and (2) high-voltage insulators. All were included in the passive component table. The applicant then evaluated the passive commodities contained in the passive component table to identify whether they were subject to period replacement based on a qualified life or specified time period (short-lived), or not subject to period replacement based on a qualified life or specified time period (long-lived). The information used to identify short-lived components, which would not be subject to an AMR, included the environmental qualification master list. The 2-34

environmental qualification master list identified the short-lived components included in the Environmental Qualification program. The remaining passive, long-lived components were included in the passive, long-lived component table and were determined to be subject to an AMR. The staff reviewed the information contained in the scoping file, including the passive component table, and the passive, long-lived component table, to verify that the applicant had appropriately identified the identified those passive components which were long-lived and not subject to periodic replacement and therefore subject to an AMR. The staff reviewed the screening of selected components to verify the correct implementation of the LRPGs and AM reports. 2.1.5.4.3 Conclusion The staff reviewed the LRA, procedures, electrical drawings, and a sample of the results of the screening methodology. The staff determines that the applicants methodology was consistent with the description provided in LRA and the applicants implementing procedures. On the basis of a review of information contained in the LRA, the applicants screening implementation procedures, and a sampling review of electrical screening results, the staff concludes that the applicants methodology for identification of electrical commodity groups subject to an AMR is consistent with the requirements of 10 CFR 54.21(a)(1), and is therefore acceptable. 2.1.5.5 Conclusion for Screening Methodology Based on its review of the LRA, the screening implementation procedures, discussions with the applicants staff, and a sample review of screening results, the staff determines that the applicant's screening methodology is consistent with the guidance of the SRP-LR and has identified passive, long-lived components within the scope of license renewal and subject to an AMR. The staff concludes that the applicants methodology is consistent with the requirements of 10 CFR 54.21(a)(1) and, therefore, acceptable. 2.1.6 Summary of Evaluation Findings The information in LRA Section 2.1, the supporting information in the scoping and screening implementation procedures and reports, and the information presented during the scoping and screening methodology audit and the applicants responses to the staffs RAIs dated August 10, 2006, formed the basis of the staffs determination that the applicants scoping and screening methodology was consistent with the requirements of the Rule. Based on this determination, the staff concludes that the applicants methodology for identifying SSCs within the scope of license renewal and SCs requiring an AMR is consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1), and, therefore, acceptable. 2-35

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 used the 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), systems and structures the failure of which 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 Tables 2.2-1a, 2.2-1b, and 2.2.3, the applicant listed plant mechanical systems, structures, and EIC systems, respectively, within the scope of license renewal. In LRA Tables 2.2-2 and 2.2-4, the applicant listed mechanical systems and structures that are not within the scope of license renewal. Based on the DBEs considered in the plants 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 specified 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 reviewed the scoping and screening methodology and provides its evaluation in SER Section 2.1. To verify that the applicant properly implemented its methodology, the staffs review focused on the implementation results shown in LRA Tables 2.2-1a, 2.2-1b, 2.2-2, 2.2-3, and 2.2-4, to confirm that there were no omissions of plant-level systems and structures within the scope of license renewal. The staff determined whether the applicant properly identified the systems and structures within the scope of license renewal in accordance with 10 CFR 54.4. The staff reviewed selected systems and structures that the applicant had not identified as falling within the scope of license renewal to verify whether the systems and structures have any intended functions requiring their inclusion within the scope of license renewal. The staffs review of the applicants implementation was conducted in accordance with the guidance in SRP-LR Section 2.2, Plant-Level Scoping Results. In LRA Section 2.2, the staff identified areas in which additional information was necessary to complete the review of the applicants plant-level scoping results. The applicant responded to the staffs RAIs as discussed below. 2-36

LRA Table 2.2-4, Structures Not within the Scope of License Renewal, identifies the office building (administration and service buildings) as not within the scope of license renewal. The table identifies two UFSAR sections as references for office building. UFSAR Section 12.2.1.1.3 is an appropriate reference that identifies the administration building as a seismic Class II structure. However, the second UFSAR Section 12.2.3 is actually for the turbine building and not the administration or service building. In RAI 2.2-1 dated August 16, 2006, the staff requested that the applicant clarify and correct the reference to UFSAR Section 12.2.3 in LRA Table 2.2-4. In its response dated September 20, 2006, the applicant stated that the office building is called by various names in VYNPS documents: the office building or area, the service building or area, and the administration building. It is sometimes considered part of the turbine building and in other contexts described as a separate building. In UFSAR Section 12.2.3, this area is listed as the "service area" that is part of the turbine building. Although the reference to UFSAR Section 12.2.3 is correct, this reference could have been omitted since UFSAR Section 12.2.3 only lists the service area and provides no description or further information about the service area. The applicant stated that the office building is not within the scope of license renewal. Based on its review, the staff finds the applicants response to RAI 2.2-1 acceptable because the applicant clarified the use of the term office building; therefore, the staffs concern described in RAI 2.2-1 is resolved. The pressure regulator and TG control system is described in USFAR Section 7.11. The purpose of the TG control system is to control steam flow and pressure to the turbine and to protect the turbine from overpressure or excessive speed. The TG controls work in conjunction with the nuclear steam system controls to maintain essentially constant reactor pressure and limit reactor transients during load variations. The LRA does not address the nuclear steam system, nor does it appear to refer to UFSAR Section 7.11 in the text. In RAI 2.2-3 dated August 16, 2006, the staff requested that the applicant clarify whether the nuclear steam system controls are included within the scope of license renewal, or explain the basis for their exclusion. In its response dated September 20, 2006, the applicant stated that the pressure regulator and TG control system as described in UFSAR Section 7.11 is an electrical and instrumentation and control (EIC) portion of the main TG system listed in LRA Table 2.2-2. The TG system provides automatic and manual controls to maintain essentially constant reactor pressure and limit reactor transients during load variations. Components in the system control steam flow and pressure to protect the turbine from overpressure or excessive speed. As discussed in the introduction to Table 2.2-1b, "EIC Systems within the Scope of License Renewal (Bounding Approach)," all EIC commodities contained in electrical and mechanical systems are in-scope by default. LRA Table 2.2-1b provides the list of electrical systems that do not include mechanical components that meet the scoping criteria of 10 CFR 54.4. Systems (such as the TG system) with mechanical components that meet the scoping criteria of 10 CFR 54.4 are listed in LRA Table 2.2-la. The pressure regulator and TG control system as described in UFSAR Section 7.1 1 are not considered separate systems and therefore are not listed in LRA Table 2.2-la. However, the components that perform this function are in-scope as EIC components. The applicant stated that the nuclear steam system controls are within the scope of license renewal. 2-37

Based on its review, the staff finds the applicants response to RAI 2.2-3 acceptable because the applicant stated all EIC commodities contained in electrical and mechanical systems are in-scope by default; therefore, the staffs concern described in RAI 2.2-3 is resolved. In response to concerns raised during the license renewal inspection, documented in the Vermont Yankee Nuclear Power Station - NRC License Renewal Inspection Report 05000271/2007006, dated June 4, 2007, the applicant placed fluid system components within the turbine building within the scope of license renewal. The applicants original scoping had determined that most of the turbine building was not within the scope of license renewal with a few exceptions, i.e., the diesel generator rooms, a few limited areas, and segments of the service water and diesel fuel oil systems. The inspection team determined that the scoping of segments of the service water and diesel fuel oil systems were not, in some instances, in accordance with guidance and that safety-related cables for reactor protection system functions had not been appropriately considered. The applicant added the turbine building to the scope of license renewal. The applicant's response to the inspection report and subsequent submittal of supplementary information related to implementation of an enhanced scoping review are documented in the their letters to the NRC dated July 3, 2007, July 30, 2007, and August 16, 2007. As a result of implementing of scoping review changes, the applicant expanded the scope of license renewal and added the following mechanical systems and associated in-scope components:

• HD and HV instruments system
• air evacuation system
• building (drainage system components)system
• circulating water priming system
• extraction steam system
• heater drain system
• heater vent system
• hydrogen water chemistry system
• make-up demineralizer system
• seal oil system
• turbine building closed cooling water system
• main turbine generator
• turbine lube oil system The above 13 mechanical systems were added to LRA Table 2.2-1a and removed from LRA Table 2.2-2.

The following mechanical systems had system boundary changes. For these systems, new component types were added that affected the scoping and screening results in the LRA. For systems listed below, new components, materials or environments that affected the AMR results in the LRA were added.

• augmented offgas system
• condensate system
• condensate demineralizer system
• condensate storage and transfer system 2-38
• circulating water system
• feedwater system
• fuel oil system
• fire protection system
• house heating boiler system
• heating, ventilation, and air conditioning system
• potable water system
• stator cooling system
• sampling system
• service water system The effects of the above changes are evaluated in the applicable sections of this SER.

The staff reviewed the selected systems and structures that the applicant had not identified as falling within the scope of license renewal to verify whether the systems and structures have any intended functions that would require their inclusion within the scope of license renewal in accordance with 10 CFR 54.4. The staff's review of the applicant's implementation was conducted in accordance with the guidance described in SRP-LR Section 2.2, "Plant-Level Scoping Results." 2.2.4 Conclusion The staff reviewed LRA Section 2.2, the RAI responses, the response to the license renewal inspection concerns, and the UFSAR supporting information to determine whether the applicant failed to identify any systems and structures within the scope of license renewal. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has 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 staffs review of the applicants scoping and screening results for mechanical systems. Specifically, this section discusses:

• reactor coolant system
• engineered safety features
• auxiliary systems
• steam and power conversion systems In accordance with the requirements of 10 CFR 54.21(a)(1), the applicants IPA 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 staffs review focused on the implementation results. This focus allowed the staff to confirm that there were no omissions of mechanical system components that meet the scoping criteria and are subject to an AMR.

The staffs evaluation of the information in the LRA was the same for all mechanical systems. The objective was to determine whether the applicant has identified, in accordance with 10 CFR 54.4, components and supporting structures for specific mechanical systems that 2-39

appear to meet the license renewal scoping criteria. Similarly, the staff evaluated the applicants 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 and component drawings, focusing on components that have not been identified as within the scope of license renewal. The staff reviewed relevant licensing basis documents, including the UFSAR, for each mechanical system to determine whether the applicant has omitted from the scope of license renewal components with intended functions as required by 10 CFR 54.4(a). The staff also reviewed the licensing basis documents to determine whether the LRA specified all intended functions as required by 10 CFR 54.4(a). The staff requested additional information to resolve any omissions or discrepancies identified. After its review of the scoping results, the staff evaluated the applicants screening results. For those SCs with intended functions, the staff sought to determine whether: (1) the functions are performed with moving parts or a change in configuration or properties or (2) the SCs are subject to replacement after a qualified life or specified time period, as required by 10 CFR 54.21(a)(1). For those meeting neither of these criteria, the staff sought to confirm that these SCs were subject to an AMR, as required by 10 CFR 54.21(a)(1). The staff requested additional information to resolve any omissions or discrepancies identified. Two-Tier Scoping Review Process for Balance of Plant (BOP) Systems Of the 78 mechanical systems in the LRA, 44 are BOP systems which include most of the auxiliary systems and all of the steam and power conversion systems. The staff performed a two-tier scoping review for these BOP systems. The two-tier scoping review process consists of Tier-1 and Tier-2 scoping reviews. The staff reviewed the LRA and UFSAR descriptions focusing on the system intended function to screen all the BOP systems into two groups based on the following screening criteria:

• safety importance/risk significance
• potential for system failure to cause failure of redundant safety system trains
• operating experience indicating likely passive failures
• systems subject to omissions based on previous LRA reviews Examples of the safety important/risk significant systems are the instrument air (IA) system, the diesel generator (DG) and support systems, and the SW system, based on the results of the individual plant examination for VYNPS. An example of a system whose failure could result in common cause failure of redundant trains is a drain system providing flood protection.

Examples of systems with operating experience indicating likely passive failures include MS system, feedwater system, and SW system. Examples of systems with identified omissions in previous LRA reviews include spent fuel cooling system and makeup water sources to safety systems. From the 44 BOP systems, the staff selected 23 systems for a detailed Tier-2" scoping review as described above. For the remaining 21 BOP systems, the staff performed a Tier-1" scoping review of the LRA (which may have not included detailed boundary drawings) and UFSAR that 2-40

would identify apparent missing components for an AMR. The following is a list of these 21 systems:

• service air (SA)
• SA and IA instruments
• condensate demineralizer
• RWCU filter demineralizer
• motor generator lube oil (MGLO)
• potable water
• equipment RIP
• stator cooling
• main steam, extraction steam and auxiliary steam instruments
• heater drain and heater vent (HD and HV) instruments
• air evacuation
• building (drainage system components)
• circulating water priming
• extraction steam
• heater drain
• heater vent
• make-up demineralizer
• seal oil
• turbine building closed cooling water
• main turbine generator
• turbine lube oil The staff examined the applicant's environmental report in LRA Appendix E, Attachment E.1, "Evaluation of Probabilistic Safety Analysis Model," to verify that there is no risk significant system on the above list. None of the 21 systems is a significant contributor to the risk reduction worth rankings to core damage frequency or involved in the significant initiating events.

Systems Identified for Inspection The staff used an inspection to verify 10 CFR 54.4(a)(2) scoping results. The staff identified several systems for the regional inspection team to include in its scoping and screening inspection. These systems had been included as within the scope of license renewal by the applicant as a result of the 10 CFR 54.4(a)(2) review. The staff requested that the inspection include a sampling review of the engineering report (if available), plant layout drawings and other documentation, and walkdowns of the plant areas that contain these systems and associated components. The systems identified for inspection include:

• augmented off-gas system
• circulating water system
• reactor water clean-up system As a result of the regional inspection and other staff inquiry, the applicant issued letters to the NRC dated July 3, 2007, July 30, 2007, and August 16, 2007. These letters provided supplementary information that addressed resolution of the issues identified during the 2-41

inspection. Refer to SER Sections 2.3.3.13A, 2.3.3.13E, and 2.3.3.13M for additional discussion. 2.3.1 Reactor Coolant System LRA Section 2.3.1 states that the purposes of the reactor coolant system (RCS) are to house the reactor core and to contain and transport the fluids coming from or going to the reactor core. The RCS includes the reactor vessel and internals, the reactor recirculation system, CRD system, and Class 1 components that comprise the reactor coolant pressure boundary (RCPB), including MS and feedwater components. The applicant described the RCS as including the nuclear boiler (NB) system, the CRD system, and the hydraulic control unit (HCU) system associated with the CRDs. The applicant described the supporting SCs of the RCS in the following LRA sections:

• 2.3.1.1 reactor vessel
• 2.3.1.2 reactor vessel internals
• 2.3.1.3 reactor coolant pressure boundary The staffs findings on review of LRA Sections 2.3.1.1 - 2.3.1.3 are in SER Sections 2.3.1.1 - 2.3.1.3, respectively. The staffs review of the NB, CRD, and HCU systems proceeded as follows:

Summary of Technical Information in the Application. LRA Section 2.3.1 describes the RCS, including the NB, CRD, and HCU systems. Summaries of each system follow: NB System. The NB system consists of Class 1 components, non-Class 1 components, and the following subsystems: reactor vessel and internals, reactor recirculation, MS, feedwater (Class 1), and nuclear boiler vessel instrumentation system (NBVIS). The reactor vessel is a welded vertical cylindrical pressure vessel with hemispherical heads. The cylindrical shell and hemispherical heads are fabricated of low-alloy steel plate. The vessel bottom head is welded directly to the vessel shell. The flanged upper head is secured to the vessel shell by studs and nuts. The reactor vessel includes nozzles, safe ends, CRD penetrations, instrument penetrations, and a support skirt. Additional details of the reactor vessel are described in LRA Section 2.3.1.1. The reactor vessel internals distribute the flow of coolant, locate and support the fuel assemblies, and provide an inner volume containing the core that can be flooded following a break in the nuclear system process barrier external to the reactor pressure vessel. Additional details of the reactor vessel internals are described in LRA Section 2.3.1.2. Reactor recirculation provides a variable moderator (coolant) flow to the reactor core for adjusting reactor power level. Adjustment of the core coolant flow rate changes reactor power output, thus following plant load demand without adjusting control rods. The recirculation system is designed with sufficient fluid and pump inertia that fuel thermal limits cannot be exceeded as a result of recirculation system malfunctions. The reactor core is cooled by demineralized water which enters the lower portion of the core and boils as it flows upward around the fuel rods. The steam leaving the core is dried by steam separators and dryers in the upper portion of the reactor vessel, then directed to the turbine through four MS lines. The steam supply for high-pressure coolant injection (HPCI) and reactor core isolation cooling 2-42

(RCIC) turbine operation is provided by connections to the MS piping. Class 1 feedwater lines provide water to the reactor vessel, entering near the top of the vessel downcomer annulus. Two feedwater lines divide and enter the vessel through four nozzles. Feedwater lines are also for injection of HPCI and RCIC. The NBVIS monitors reactor vessel parameters. The NBVIS is designed (1) to initiate and provide trip signals to interfacing plant safety systems, (2) to provide signals to interfacing plant nonsafety systems, and (3) to provide plant process parameter information necessary for normal, transient, and abnormal (including post-accident) operations. The NBVIS instrument sensing lines, including restriction orifices and excess flow check valves, are parts of the RCPB. The NB system has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the NB system could prevent the satisfactory accomplishment of a safety-related function. In addition, the NB system performs functions that support fire protection safe shutdown capability analysis and SBO coping analysis. LRA Table 2.3.3-13-25 identifies the following nonsafety-related components types of the NB system within the scope of license renewal and subject to an AMR:

• bolting
• filter housing
• flow element
• orifice
• piping
• tubing
• valve body The nonsafety-related NB system component intended function within the scope of license renewal is to provide a pressure boundary.

CRD System. The CRDs provide a means to control changes in core reactivity by incrementally positioning neutron-absorbing control rods within the reactor core in response to manual control signals. The CRD subsystem must shut down the reactor quickly (scram) by inserting control rods rapidly into the core in response to a manual or automatic signal. The CRD system has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the CRD system could prevent the satisfactory accomplishment of a safety-related function. In addition, the CRD system performs functions that support fire protection and ATWS. LRA Table 2.3.3-13-5 identifies the following nonsafety-related CRD system component types within the scope of license renewal and subject to an AMR:

• bolting
• filter housing
• orifice
• piping
• pump casing 2-43
• strainer housing
• tank
• tubing
• valve body The nonsafety-related CRD component intended function within the scope of license renewal is to provide a pressure boundary.

HCU System. The HCU system controls the water flow to the CRDs both for normal operation and during a reactor scram. Each HCU furnishes pressurized water upon signal to a CRD. The drive then positions its control rod as required. Water discharged from the drives during a scram flows through the HCUs to the scram discharge volume. Water discharged from a drive during a normal control rod positioning operation flows through its HCU and the exhaust header to the RWCU system discharge line. The HCU system has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the HCU system could prevent the satisfactory accomplishment of a safety-related function. In addition, the HCU system performs functions that support fire protection safe shutdown capability analysis and SBO coping analysis. LRA Table 2.3.3-13-19 identifies the following nonsafety-related HCU system component types within the scope of license renewal and subject to an AMR:

• bolting
• filter housing
• piping
• tubing
• valve body The nonsafety-related HCU system component intended function within the scope of license renewal is to provide a pressure boundary.

Staff Evaluation. The staff reviewed LRA Section 2.3.1, UFSAR Sections 3.4, 3.5, 4.1 through 4.6, and 7.18 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3, Scoping and Screening Results: Mechanical Systems. The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted any components with intended functions from the scope of license renewal required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant had identified as within the scope of license renewal to verify that no passive and long-lived components subject to an AMR had been omitted as required by 10 CFR 54.21(a)(1). Conclusion. The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the NB, CRD, and HCU systems components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as 2-44

required by 10 CFR 54.21(a)(1). 2.3.1.1 Reactor Vessel 2.3.1.1.1 Summary of Technical Information in the Application LRA Section 2.3.1.1 describes the reactor vessel, which contains the nuclear fuel core, core support structures, control rods, and other parts directly associated with the core. The major components of the reactor vessel are the reactor pressure vessel shell, bottom head, upper closure head, flanges, studs, nuts, nozzles and safe ends. The component evaluation boundaries are the welds between the safe ends and attached piping and the interface flanges for bolted connections. Thermal sleeves welded to vessel nozzles or safe ends, CRD stub tubes, CRD housings, in-core housings, the vessel support skirt, and vessel interior and exterior welded attachments also were included. LRA Table 2.3.1-1 identifies the following reactor vessel component types within the scope of license renewal and subject to an AMR:

• bolting
• heads and shell
• nozzles and penetrations
• safe ends, thermal sleeves, flanges, and caps
• vessel attachments and supports The reactor vessel component intended functions within the scope of license renewal include the following:
• pressure boundary
• structural or functional support for safety-related equipment 2.3.1.1.2 Staff Evaluation The staff reviewed LRA Section 2.3.1.1 and the UFSAR using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). In LRA Table 2.3.1-1, the reactor vessel leakage monitoring piping was not identified as a component within the scope of license renewal and requiring an AMR. In RAI 2.3.1.1-1 dated July 13, 2006, the staff requested that the applicant clarify whether the subject components were included within the scope of license renewal. In its response dated August 15, 2006, the applicant stated that the subject components were 2-45

included within the scope of license renewal in accordance with the category piping and fittings less than 4 inches NPS, orifices (instrumentation), and valve bodies less than 4 inches NPS as part of RCPB components in Table 2.3.1-3. Based on its review, the staff finds the applicants response to RAI 2.3.1.1-1 acceptable because the reactor vessel leakage monitoring piping was proven to be in-scope. The staffs concern described in RAI 2.3.1.1-1 is resolved. In RAI 2.3.1.1-2 dated July 13, 2006, the staff requested that the applicant clarify if the scram discharge piping and volume are within the scope of license renewal because the subject components were not discussed in LRA Section 2.3.1.1. In its response dated August 15, 2006, the applicant stated that the subject components were included within the scope of license renewal and subject to an AMR in accordance with the category piping and fittings less than 4 inches NPS, orifices (instrumentation), and valve bodies less than 4 inches NPS as part of RCPB components in Table 2.3.1-3. Based on its review, the staff finds the applicants response to RAI 2.3.1.1-2 acceptable because the scram discharge piping and volume were proven to be in-scope. The staffs concern described in RAI 2.3.1.1-2 is resolved. In RAI 2.3.1.1-3 dated July 13, 2006, the staff requested that the applicant include the CRD housing supports within the scope of license renewal and requiring an AMR because the subject components were not discussed in LRA Section 2.3.1.1, Reactor Vessel. In its response dated August 15, 2006, the applicant stated that the subject components were considered in the category of structural elements and included in the line item for components and piping supports ASME Class 1, 2, 3 in Table 2.4-6, Bulk Commodities Components Subject to an AMR. Based on its review, the staff finds the applicants response to RAI 2.3.1.1-3 acceptable because the CRD housing supports were proven to be in-scope. The staffs concern described in RAI 2.3.1.1-3 is resolved. 2.3.1.1.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the reactor vessel 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). 2.3.1.2 Reactor Vessel Internals 2.3.1.2.1 Summary of Technical Information in the Application LRA Section 2.3.1.2 describes the reactor vessel internals, which are designed to distribute the reactor coolant flow delivered to the vessel, to locate and support the fuel assemblies, and to contain the core in an inner volume that can be flooded following a break in the nuclear system process barrier. The reactor vessel internals are the control rod guide tubes, core plate, CS lines in the vessel, differential pressure and SLC line, feedwater spargers, fuel support pieces, in-core guide tubes, in-core dry tubes, local power range monitors, jet pump assemblies and jet 2-46

pump instrumentation, shroud (including shroud stabilizers), shroud head and steam separator assembly, shroud support, steam dryer, surveillance sample holders, top guide, and vessel head spray line. LRA Table 2.3.1-2 identifies the following reactor vessel internals component types within the scope of license renewal and subject to an AMR:

• control rod guide tubes
• core plate assembly
• core spray lines
• fuel support pieces
• in-core dry tubes
• in-core guide tubes
• jet pump assemblies
• jet pump casting
• shroud
• shroud repair hardware
• shroud support
• steam dryer
• top guide The reactor vessel internals component intended functions within the scope of license renewal include the following:
• flow distribution
• boundary of a volume in which the core can be flooded and adequately cooled in the event of a breach in the nuclear system process barrier external to the reactor vessel
• pressure boundary
• structural or functional support for safety-related equipment
• structural integrity so loose parts are not introduced 2.3.1.2.2 Staff Evaluation The staff reviewed LRA Section 2.3.1.2 and the UFSAR using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.1.2.3 Conclusion 2-47

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the reactor vessel internals 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). 2.3.1.3 Reactor Coolant Pressure Boundary 2.3.1.3.1 Summary of Technical Information in the Application LRA Section 2.3.1.3 describes the RCPB, which maintains a high-integrity pressure boundary and fission product barrier inside the primary containment and to the first isolation outside the primary containment. Class 1 piping attached to the vessel nozzles or safe ends, including the welded joints, Class 1 pumps, and Class 1 boundary isolation valves, are included in this review. Connected Class 2 piping not part of another AMR, including vents, drains, leakoff, sample lines, and instrumentation lines up to the transmitters, is included as far as necessary to complete the RCS pressure boundary. LRA Table 2.3.1-3 identifies the following RCPB component types within the scope of license renewal and subject to an AMR:

• bolting (flanges, valves, etc.)
• condensing chambers
• detector (CRD)
• drive (CRD)
• driver mount (RR)
• filter housing (CRD)
• flow elements (RR), (SLC)
• orifices (instrumentation)
• piping and fittings < 4 inches NPS
• piping and fittings > 4 inches NPS
• pump casing and cover (RR)
• pump cover thermal barrier (RR)
• restrictors (MS)
• rupture disc (CRD)
• tank (CRD accumulator)
• thermowell
• valve bodies < 4 inches NPS
• valve bodies > 4 inches NPS The RCPB component intended functions within the scope of license renewal include the following:
• flow control
• pressure boundary 2-48

2.3.1.3.2 Staff Evaluation The staff reviewed LRA Section 2.3.1.3 and the UFSAR using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.1.3.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the RCPB 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). 2.3.2 Engineered Safety Features In LRA Section 2.3.2, the applicant identified the SCs of the engineered safety features that are subject to an AMR for license renewal. The applicant described the supporting SCs of the engineered safety features in the following LRA sections:

• 2.3.2.1 residual heat removal
• 2.3.2.2 core spray
• 2.3.2.3 automatic depressurization
• 2.3.2.4 high pressure coolant injection
• 2.3.2.5 reactor core isolation cooling
• 2.3.2.6 standby gas treatment
• 2.3.2.7 primary containment penetrations The staffs review findings regarding LRA Sections 2.3.2.1 - 2.3.2.7 are presented in SER Sections 2.3.2.1 - 2.3.2.7, respectively.

2-49

2.3.2.1 Residual Heat Removal 2.3.2.1.1 Summary of Technical Information in the Application LRA Section 2.3.2.1 describes the RHR system, which removes decay heat energy from the reactor during both operational and accident conditions. The RHR system consists of two closed loops, each with two pumps in parallel, one heat exchanger, and the necessary valves and instrumentation. The RHR heat exchanger in each loop is cooled by the residual heat removal service water (RHRSW) system. The RHR system has eight modes of operation: (1) the low-pressure coolant injection (LPCI) mode takes suction from the suppression pool and injects flow into the core region of the reactor vessel through one of the two reactor recirculation loops to restore and maintain the water level of the reactor vessel following a loss of coolant accident (LOCA), (2) the containment spray cooling mode takes suction from the suppression pool and injects flow into spray headers located in the drywell and suppression chamber to reduce containment pressure and temperature following a LOCA by cooling any non-condensables and condensing any steam present, (3) the suppression pool cooling mode takes water from the suppression pool, passes it through the RHR heat exchangers, and returns flow to the suppression pool to remove heat added to the suppression pool, (4) the shutdown cooling mode takes water from the reactor vessel via the reactor recirculation A loop suction piping, passes it through the RHR heat exchangers, and returns flow to the reactor through the recirculation lines to remove sensible and decay heat from the reactor during shutdown, (5) the alternate shutdown cooling mode provides a cooling path if the normal shutdown cooling path is inoperable and can be initiated from the control room. RHR pumps take water from the suppression pool, pass it through RHR heat exchangers and inject into the vessel via RHR injection valves. Relief valves on the steam lines are open to allow overflow to the suppression pool, (6) the augmented fuel pool cooling (FPC) mode takes water from the FPC system, passes it through RHR heat exchangers, and returns flow to the FPC system to assist in FPC during reactor shutdown periods and the alternate cooling mode of operation and is not a safety function of RHR, (7) the emergency reactor vessel fill mode, which is beyond the design basis mode of operation, provides a cross-tie between the RHRSW system and RHR piping loop A. The RHRSW pumps take suction from the SW system and inject flow into the reactor vessel through RHR piping to provide a source of water to keep the reactor core covered (and fill containment) in the event that core standby cooling system (CSCS) pumps are lost due to loss of containment pressure or adequate core cooling cannot be assured, and (8) the alternate shutdown mode uses the RHR alternate shutdown panel to control the minimum valving required for vessel injection, torus cooling, and shutdown cooling modes to achieve and maintain cold shutdown conditions during a postulated control room or cable vault fire which eliminates normal means of system control. The RHR system has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the RHR system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the RHR system performs functions that support fire protection safe shut down capability analysis. LRA Tables 2.3.2-1 and 2.3.3-13-33 identify the following RHR system component types within the scope of license renewal and subject to an AMR: 2-50

• bolting
• cyclone separator
• heat exchanger (bonnet)
• heat exchanger (shell)
• heat exchanger (tubes)
• nozzle
• orifice
• piping
• pump casing
• strainer
• tank
• thermowell
• tubing
• valve body The RHR system component intended functions within the scope of license renewal include the following:
• flow control
• filtration
• heat transfer
• pressure boundary 2.3.2.1.2 Staff Evaluation The staff reviewed LRA Sections 2.3.2.1 and 2.3.3.13, and UFSAR Sections 4.8 and 6.4.4 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). The LPCI coupling was identified in the Boiling Water Reactor Vessel and Internals Project (BWRVIP) -06 Report as a safety-related component. In RAI 2.3.2.1-1 dated July 13, 2006, the staff requested that the applicant identify LPCI couplings in the LRA as within the scope of license renewal and subject to an AMR if they are part of VYNPS. In its response dated August 15, 2006, the applicant responded that VYNPS does not have LPCI couplings. Based on its review, the staff finds the applicants response to RAI 2.3.2.1-1 acceptable because there are no LPCI couplings in-scope or subject to an AMR since there are no LPCI couplings at VYNPS. The staffs concern described in RAI 2.3.2.1-1 is resolved. In RAI 2.3.2.1-2 dated July 13, 2006, the staff requested the applicant clarify whether vortex breakers are employed in the emergency core cooling system (ECCS) pump suction lines at 2-51

VYNPS, and if so, identify and include these passive components in-scope requiring an AMR. In its response dated August 15, 2006, the applicant said that during the IPA for VYNPS, a review of site documentation for all in-scope mechanical systems, including licensing basis and DBDs, as well as the site component database and drawings was completed. The applicant determined that no vortex breakers were required to support system intended functions in the scope of license renewal per 54.4 (a)(1-3), and therefore, vortex breakers are not included in the LRA for VYNPS. Based on its review, the staff finds the applicants response to RAI 2.3.2.1-2 acceptable because no vortex breakers support the intended function of the ECCS pump suction lines at VYNPS. The staffs concern described in RAI 2.3.2.1-2 is resolved. 2.3.2.1.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the RHR system 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). 2.3.2.2 Core Spray 2.3.2.2.1 Summary of Technical Information in the Application LRA Section 2.3.2.2 describes the CS system, which in conjunction with other CSCS, provides adequate core cooling for all design basis break sizes up to and including double-ended breaks of the reactor recirculation system piping. The CS system protects the core in large breaks in the nuclear system when the RCIC and HPCI systems are unable to maintain reactor vessel water level. CS system protection also extends to small breaks in which the RCIC and HPCI systems are unable to maintain reactor vessel water level and automatic depressurization lowers reactor vessel pressure so the LPCI and the CS systems can cool the core. The CS system has two independent loops, each with a centrifugal water pump driven by an electric motor, a spray sparger in the reactor vessel above the core, and piping and valves to convey water from the suppression pool (primary safety-related source) or condensate storage tank (backup source) to the sparger. The CS system has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the CS system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the CS system performs functions that support fire protection safe shutdown capability analysis and SBO coping analysis. LRA Tables 2.3.2-2 and 2.3.3-13-6 identify the following CS system component types within the scope of license renewal and subject to an AMR:

• bolting
• bearing housing
• cyclone separator
• flow nozzle
• orifice 2-52
• piping
• pump casing
• strainer
• tubing
• valve body The CS system component intended functions within the scope of license renewal include the following:
• flow control
• filtration
• pressure boundary 2.3.2.2.2 Staff Evaluation The staff reviewed LRA Section 2.3.2.2 and UFSAR Sections 6.3 and 6.4.3 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.2.2.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the CS system 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). 2.3.2.3 Automatic Depressurization 2.3.2.3.1 Summary of Technical Information in the Application LRA Section 2.3.2.3 describes the automatic depressurization system (ADS), which actuates nuclear system pressure relief valves to depressurize the nuclear system automatically in a LOCA in which the HPCI system fails to deliver rated flow or break flow exceeds HPCI capacity (intermediate break). The depressurization of the nuclear system allows low-pressure standby cooling systems to supply enough cooling water to cool the fuel adequately. The ADS functions as one of the CSCSs. The ADS, in combination with the LPCI and CS systems, serves as a backup to the HPCI system. The ADS has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related ADS SSCs potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the ADS performs functions that support fire protection safe shutdown capability analysis and SBO coping analysis. 2-53

LRA Table 2.3.2-3 identifies the following ADS component types within the scope of license renewal and subject to an AMR:

• bolting
• orifice
• piping
• tubing
• valve body The ADS component intended functions within the scope of license renewal include the following:
• flow control
• pressure boundary 2.3.2.3.2 Staff Evaluation The staff reviewed LRA Section 2.3.2.3 and UFSAR Sections 4.4 and 6.4.2 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.2.3.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the ADS 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). 2.3.2.4 High Pressure Coolant Injection 2.3.2.4.1 Summary of Technical Information in the Application LRA Section 2.3.2.4 describes the HPCI system, which cools the reactor core adequately in a small break in the nuclear system with subsequent coolant loss which does not cause rapid depressurization of the reactor vessel. It performs this function simultaneously with a loss of normal auxiliary power. The HPCI system permits shutdown of the reactor by maintaining sufficient reactor vessel water inventory until the reactor vessel is depressurized. HPCI continues until reactor vessel pressure is below that at which the LPCI or CS system can maintain core cooling. 2-54

The HPCI system has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the HPCI system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the HPCI system performs functions that support fire protection and SBO coping analysis. LRA Tables 2.3.2-4 and 2.3.3-13-20 identify the following HPCI system component types within the scope of license renewal and subject to an AMR:

• bearing housing
• bolting
• drain pot
• fan housing
• filter housing
• gear box
• governor housing
• heat exchanger (bonnet)
• heat exchanger (shell)
• heat exchanger (tubes)
• orifice
• piping
• pump casing
• sight glass
• steam trap
• strainer
• strainer housing
• tank
• thermowell
• tubing
• turbine casing
• valve body The HPCI system component intended functions within the scope of license renewal include the following:
• flow control
• filtration
• heat transfer
• pressure boundary 2.3.2.4.2 Staff Evaluation The staff reviewed LRA Sections 2.3.2.4 and 2.3.3.13, and UFSAR Sections 6.3 and 6.4 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the 2-55

applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.2.4.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the HPCI system 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). 2.3.2.5 Reactor Core Isolation Cooling 2.3.2.5.1 Summary of Technical Information in the Application LRA Section 2.3.2.5 describes the RCIC and the condensate storage and transfer (CST) systems. In the event of feedwater isolation with a simultaneous loss of normal auxiliary power, the RCIC system replaces the normal sources of makeup water to the reactor vessel to prevent uncovering of the core when it operates automatically without the use of any CSCSs. The RCIC system consists of a steam turbine-driven pump designed to supply water from either the condensate storage tank or the suppression pool to the reactor via the feedwater spargers. The purpose of the CST system is to provide a source of water to various plant systems, including the HPCI and RCIC systems (preferred source), CS system (as a backup source or for testing), the CRD system (backup source), and the spent fuel pool (fill and makeup source). The CST system connects to the condensate system to make up or draw off condensate to or from the hotwell. The CST system consists of the condensate storage tank, two condensate transfer pumps, piping, and valves. The RCIC and CST systems have 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 systems perform functions that support fire protection safe shutdown capability analysis and SBO coping analysis. LRA Tables 2.3.2-5, 2.3.3-13-7, and 2.3.3-13-31 identify the following RCIC and CST systems component types within the scope of license renewal and subject to an AMR:

• bolting
• condenser
• drain pot
• filter housing
• flow indicator
• heat exchanger (bonnet)
• heat exchanger (shell)
• heat exchanger (tubes)
• orifice
• piping 2-56
• pump casing
• rupture disk
• sight glass
• steam heater
• steam trap
• strainer
• strainer housing
• tank
• thermowell
• tubing
• turbine casing
• valve body The component intended functions within the scope of license renewal include the following:
• flow control
• filtration
• heat transfer
• pressure boundary 2.3.2.5.2 Staff Evaluation The staff reviewed LRA Sections 2.3.2.5 and 2.3.3.13, and UFSAR Sections 4.7 and 11.8.3.8 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.2.5.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the RCIC and CST 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). 2.3.2.6 Standby Gas Treatment 2.3.2.6.1 Summary of Technical Information in the Application LRA Section 2.3.2.6 describes the standby gas treatment (SBGT) system, which processes gaseous effluent from the primary and secondary containments when required to limit the 2-57

discharge of radioactive materials to the environs and to limit ex-filtration from the secondary containment during primary containment isolation. This processing is accomplished by two trains, each capable of maintaining a negative pressure in the secondary containment and processing one net secondary containment volume of air per day through high-efficiency filters. The system functions as part of the secondary containment system. The SBGT system consists of two complete, independent trains, each a backup for the other and sized to handle the full system requirement. Each train has a demister, electric heaters, two high-efficiency particulate filters, a carbon absorber, a fan, and miscellaneous valves. The SBGT system has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the SBGT system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Tables 2.3.2-6 and 2.3.3-13-38 identify the following SBGT system component types within the scope of license renewal and subject to an AMR:

• bolting
• duct
• fan housing
• filter
• filter housing
• filter unit housing
• orifice
• piping
• sight glass
• thermowell
• tubing
• valve body The SBGT system component intended functions within the scope of license renewal include the following:
• filtration
• pressure boundary 2.3.2.6.2 Staff Evaluation The staff reviewed LRA Section 2.3.2.6 and UFSAR Sections 1.6.2.15 and 5.3.4 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2-58

2.3.2.6.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the SBGT system 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). 2.3.2.7 Primary Containment Penetrations 2.3.2.7.1 Summary of Technical Information in the Application LRA Section 2.3.2.7 describes the primary containment penetrations, which can rapidly isolate all pipes or ducts penetrating the primary containment with a containment barrier as effective as required to maintain leakage within permissible limits. The primary containment penetrations have safety-related components relied upon to remain functional during and following DBEs. LRA Table 2.3.2-7 identifies the following primary containment penetrations component types within the scope of license renewal and subject to an AMR:

• bolting
• piping
• valve body The intended function of the primary containment penetrations is to provide a pressure boundary.

2.3.2.7.2 Staff Evaluation The staff reviewed LRA Section 2.3.2.7 and UFSAR Sections 5.2.2, 5.2.3.4, and 5.2.3.5 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.2.7.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the primary containment penetrations components within the scope of 2-59

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). 2.3.3 Auxiliary Systems In LRA Section 2.3.3, the applicant identified the SCs of the auxiliary systems 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 standby liquid control
• 2.3.3.2 service water
• 2.3.3.3 reactor building closed cooling water
• 2.3.3.4 emergency diesel generator
• 2.3.3.5 fuel pool cooling
• 2.3.3.6 fuel oil
• 2.3.3.7 instrument air
• 2.3.3.8 fire protection-water
• 2.3.3.9 fire protection-carbon dioxide
• 2.3.3.10 heating, ventilation and air conditioning
• 2.3.3.11 primary containment atmosphere control/containment atmosphere dilution
• 2.3.3.12 John Deere diesel
• 2.3.3.13 miscellaneous systems in-scope for 10 CFR 54.4(a)(2)

The staffs review findings regarding LRA Sections 2.3.3.1 - 2.3.3.13 are presented in SER Sections 2.3.3.1 - 2.3.3.13, respectively. 2.3.3.1 Standby Liquid Control 2.3.3.1.1 Summary of Technical Information in the Application LRA Section 2.3.3.1 describes the SLC system, which, independent of the control rods, shuts down the reactor from full power and maintains the reactor subcritical during cooldown. Maintaining subcriticality as the nuclear system cools assures that the fuel barrier is not threatened by overheating if not enough control rods can be inserted to counteract the positive reactivity effects of a colder moderator. The system, located in the reactor building, consists of a boron solution tank, a test water tank, two positive-displacement pumps, two explosive valves, an ion exchanger, a flush pump, piping, and valves. The liquid is pumped into the reactor vessel and discharged near the bottom of the core shroud to mix with the cooling water rising through the core. 2-60

The SLC system has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the SLC system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the SLC system performs functions that support ATWS. LRA Tables 2.3.3-1 and 2.3.3-13-40 identify the following SLC system component types within the scope of license renewal and subject to an AMR:

• bolting
• gauge
• heater
• orifice
• piping
• pump casing
• sight glass
• strainer housing
• tank
• thermowell
• tubing
• valve body The SLC system component intended function within the scope of license renewal is to provide a pressure boundary.

2.3.3.1.2 Staff Evaluation The staff reviewed LRA Sections 2.3.3.1 and 2.3.3.13, and UFSAR Section 3.8 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.1.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any components subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the SLC system 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). 2-61

2.3.3.2 Service Water 2.3.3.2.1 Summary of Technical Information in the Application LRA Section 2.3.3.2 describes the SW system and the RHRSW system. The purpose of the SW system is to provide cooling water to various normal and emergency operating loads. The SW system consists of two parallel headers which supply cooling water to the following turbine and reactor auxiliary equipment: a reactor building closed cooling water (RBCCW) heat exchanger, RHR corner room ventilation coolers, a DG cooler, and an RHR heat exchanger (via the RHRSW pumps and piping). Each header is supplied by two pumps. The standby fuel pool cooling (SBFPC) system normally is supplied from the SW Train B header. The header and cross tie can be configured to be fed from the A header with B secured. Other turbine and reactor auxiliary equipment is supplied from a line tied into both headers. The purpose of the RHRSW system is to transfer heat from the RHR system during normal operation and accident conditions. The RHRSW system consists of four RHRSW pumps, two RHR heat exchangers and piping, valves, and instrumentation necessary to ensure system operation. The RHRSW pumps are supplied from the SW system. The cooling water then is pumped through the RHR heat exchangers and returned to the SW system. The SW and RHRSW systems have 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 systems perform functions that support fire protection. LRA Tables 2.3.3-2, 2.3.3-13-34, and 2.3.3-13-42 identify the following SW and RHRSW system component types within the scope of license renewal and subject to an AMR:

• bolting
• coil
• expansion joint
• fan housing
• heat exchanger (bonnet)
• heat exchanger (shell)
• heat exchanger (tubes)
• heat exchanger (tubesheets)
• indicator
• orifice
• piping
• pump casing
• strainer
• strainer housing
• suction barrel
• thermowell
• tubing
• valve body 2-62

The component intended functions within the scope of license renewal include the following:

• flow control
• filtration
• heat transfer
• pressure boundary
• structural or functional support for safety-related equipment 2.3.3.2.2 Staff Evaluation The staff reviewed LRA Sections 2.3.3.2 and 2.3.3.13, and UFSAR Sections 10.6, 10.7, and 10.8 using the Tier-2 evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). The staffs review of LRA Section 2.3.3.2 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staffs RAIs as discussed below. The staff noted that license renewal drawing LRA-G-191159-SH-01-0, at location H-12, depicts pipe section 2"-SW- 566C within the scope of license renewal. Upstream from where 2"-SW-566C enters the reactor building from the outside, there is no drawing continuation to depict the license renewal boundary. In RAI 2.3.3.2a-1 dated August 16, 2006, the staff requested that the applicant provide information for the continuation of 2"-SW-566C to the license renewal boundary and justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a). In its response dated September 20, 2006, the applicant stated that pipe section 2"-SW-566C contains vacuum breakers to prevent water-hammer in the nonsafety-related portion of the SW system. The portion of this piping outside of the reactor building wall ends at this point. There is no continuation of this portion of the piping. Based on its review, the staff found the applicant response to RAI 2.3.3.2a-1 acceptable because the applicant confirmed this section of piping ends outside the reactor building wall and does not continue on another drawing. This is a section of piping open to atmosphere immediately outside of the reactor building to allow air flow to the vacuum breakers depicted on pipe section 2"-SW-566C. Therefore, the staff concern described in RAI 2.3.3.2a-1 is resolved. The staff noted that license renewal drawing LRA-G-191159-SH-01-0, at location H-11, drawing note 16 indicates pipe section 4"-SW-567 and its supports on the reactor building alternate cooling supply piping (where the vacuum breakers tie in) are seismic Class II for structural integrity. This pipe section from valve 23D through valves RBAC-1A, 1B, 1C and 1D is not 2-63

shown within the scope of license renewal. Failure of this pipe could have an adverse effect on the intended pressure boundary function for the service water piping. In RAI 2.3.3.2a-2 dated August 16, 2006, the staff requested that the applicant provide additional information about why this section of pipe and components are not shown 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 September 20, 2006, the applicant stated that this portion of piping is included for 10 CFR 54.4(a)(2) since it provides structural support for the safety-related portion of the system. As described in LRA Section 2.1.2.1.3, portions of systems included as required by 10 CFR 54.4(a)(2) are not shown on license renewal drawings. However, as discussed in LRA Table 2.3.3.1 3-8 for the SW system, the components outside the safety class pressure boundary, while relied upon to provide structural/seismic support for the pressure boundary are in-scope and subject to an AMR. This includes the portion of line 4"-SW-567 required to provide structural support for the vacuum breakers. In addition, this piping and associated valves are included as required by 10 CFR 54.4(a)(2) due to spatial interaction from spray or leakage since the line is in the reactor building. Based on its review, the staff found the applicant response to RAI 2.3.3.2a-2 acceptable because the applicant acknowledged this section of piping 4" SW-567 from valve 23D to RBAC-1A, 1B, 1C, and 1D is within the scope of license renewal. As described in LRA Section 2.1.2.1.3, portions of systems included for 10 CFR 54.4(a)(2) are not shown on LRA drawings. Although the applicant did not identify this section of piping as being within the boundary of license renewal on the drawing, the applicant confirmed it is within the scope based on the potential for physical interaction with safety-related systems in accordance with 10 CFR 54.4(a)(2). Therefore, the staff concern described in RAI 2.3.3.2a-2 is resolved. The staff noted license renewal drawing LRA-G-191159-SH-01-0, at location D-5, depicts the license renewal boundary on the downstream side of flow control valve (FCV)-104-17A. The pipe section from FCV-104-17A to the safety class boundary designation flag located at valve 171A and to the intake screens is not shown within the scope of license renewal. Similarly, the pipe section from FCV-104-17 B, C, D, and E to valves 17B, C, D and E and to the intake screens is also not shown within the scope of license renewal. Failure of these sections of pipe could have an adverse effect on the intended pressure boundary function for the service water piping. In RAI 2.3.3.2a-3 dated August 16, 2006, the staff requested that the applicant provide additional information about why these sections of piping and components are not shown 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 September 20, 2006, the applicant stated that the license drawings only show the portions of the system with intended functions that meet the requirements of 10 CFR 54.4(a)(1) or (a)(3). As described in LRA Section 2.1.2.1.3, portions of systems included as required by 10 CFR 54.4(a)(2) are not shown on license renewal drawings. Valves FCV-104-17A/B/C/D and E are normally closed valves that are only open when the traveling screens are being washed. Providing water to clean the screens is not a function that meets the requirements of 10 CFR 54.4(a)(1) or (a)(3). These valves fail to a closed position such that failure of the piping downstream of these valves would not affect the ability of the SW system to perform its functions as required by 10 CFR 54.4(a)(1) or (a)(3). However, as described in LRA Table 2.3.3.13-B, the portion of the SW system in the intake structure near the SW pumps and 2-64

the components outside the safety class pressure boundary, while relied upon to provide structural/seismic support for the pressure boundary are in-scope and subject to an AMR as required by 10 CFR 54.4(a)(2). This includes the portion of lines downstream of FCV-104-17A/B/C/D and E that provide structural support. Based on its review, the staff found the applicant response to RAI 2.3.3.2a-3 acceptable because the applicant acknowledged these sections of piping are within the scope of license renewal. As described in LRA Section 2.1.2.1.3, portions of systems included for 10 CFR 54.4(a)(2) are not shown on LRA drawings. Although the applicant did not identify these sections of piping as being within the boundary of license renewal on the drawing, the applicant confirmed they are within the scope based on the potential for physical interaction with safety-related systems in accordance with 10 CFR 54.4(a)(2). Therefore, the staff concern described in RAI 2.3.3.2a-3 is resolved. The staff noted that license renewal drawing LRA-G-191159-SH-02-0, at location G-6, depicts a license renewal boundary flag at the tee of pipe sections 2"-SW-566D and 8"-SW-34. There are no highlighted pipes or components on 2"-SW-566D or 8"-SW-34. In RAI 2.3.3.2a-4 dated August 16, 2006, the staff requested that the applicant clarify which portions of pipe and components are and are not bounded by the aforementioned boundary flag and justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a). In its response dated September 20, 2006, the applicant stated license renewal drawings only show the portions of the system with intended functions that meet the requirements of 10 CFR 54.4(a)(1) or (a)(3). As described in LRA Section 2.1.2.1.3, portions of systems included as required by 10 CFR 54.4(a)(2) are not shown on license renewal drawings. The piping and valves on line 2"-SW- 566D are safety-related, since they have a safety function to break vacuum and prevent water hammer in the SW system. As a result, a system intended function boundary flag is provided that points towards and includes all the components on line 2"-SW-566D. The reason these components are not highlighted as subject to an AMR is that they perform their system intended function though the active function of the valves opening and breaking vacuum. In accordance with 10 CFR 54.21 (a)(1)(i), components that perform their intended functions with moving parts or a change in configuration are not subject to an AMR. These components do not have a passive intended function of pressure boundary as required by 10 CFR 54.4(a)(1) or (a)(3), since this portion of the system is isolated when aligned to the ultimate heat sink. However, as described in LRA Table 2.3.3.13-6, the portion of the SW system inside the reactor building and the components outside the safety class pressure boundary, while relied upon to provide structural/seismic support for the pressure boundary are in-scope and subject to an AMR as required by 10 CFR 54.4(a)(2). This includes line 2-SW-566D and portions of lines connected to this line that provide structural support and have the potential to affect safety-related components due to spray or leakage. Based on its review, the staff found the applicant response acceptable because the applicant acknowledged that pipe 2" SW-566D is within the scope of license renewal and subject to an AMR based on the potential for physical interaction with safety-related systems in accordance with 10 CFR 54.4(a)(2). As described in LRA Section 2.1.2.1.3, portions of systems included for 10 CFR 54.4(a)(2) are not shown on LRA drawings. Therefore, the staff concern described in RAI 2.3.3.2a-4 is resolved. 2-65

The staffs review of LRA Section 2.3.3.2 identified areas in which information provided in the LRA needed to be confirmed by the NRC Regional Inspection Team to complete the review of the applicant's scoping and screening results. Inspection Item 2.3.3.2a-1 License renewal drawing LRA-G-191159-SH-01-0, at location H-11, depicts pipe section 2-SW-566C as within the scope of license renewal. The license renewal boundary flag for 2-SW-566C is located on an unisolable section of pipe. The actual location of the license renewal scope boundary for this pipe section is not clear. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components meet the requirements of 10 CFR 54.4(a)(2). In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the regional inspection team stated in part that the applicant has included in-scope for spatial interaction the portion of the SW system in the service water pump area of the intake structure and the reactor building. Pipe section 2" SW-566C is in the reactor building and is therefore in-scope for spatial interaction. As described in LRA Section 2.1.2.1.3, portions of systems included for 10 CFR 54.4(a)(2) are not shown on LRA drawings. Further, the applicant's letter to the NRC dated July 3, 2007, LRA Amendment 27, Attachment 2 indicates that pipe section 4"SW-567 which attaches to pipe section 2" SW-566C is in-scope for spatial interaction. Based on its review, the staff found the above response acceptable because the inspection team and the applicant acknowledged that service water pipe 2" SW-566C is within the scope of license renewal and subject to an AMR based on the potential for physical interaction with safety-related systems in accordance with 10 CFR 54.4(a)(2). Therefore, the staff concern described in Inspection Item 2.3.3.2a-1 is resolved. Inspection Item 2.3.3.2a-2 LRA Section 2.1.2.1.2 states in part that nonsafety-related piping systems connected to safety-related systems were included up to the structural boundary or to a point that includes an adequate portion of the nonsafety-related piping run to conservatively include the first seismic or equivalent anchor. In addition, if isometric drawings were not readily available to identify the structural boundary, connected lines were included to a point beyond the safety/nonsafety interface, like a base-mounted component, flexible connection, or the end of a piping run (i.e, a drain line). The staff cannot determine whether all the nonsafety-related piping systems were included up to the structural boundary or to a point that includes an adequate portion of the nonsafety-related piping run to include the first seismic or equivalent anchor. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components satisfy the requirements of 10 CFR 54.4(a)(2). 2-66

In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team stated in part that for structural support considerations, the applicant has included components outside the safety class pressure boundary, yet relied upon to provide structural/seismic support for the pressure boundary. The application describes the types of components which are included in the scope of license renewal for 10 CFR 54.4(a)(2) and subject to an AMR in the service water system in LRA Table 2.3.3-13-42. This table was developed by including all nonsafety-related portions of fluid systems which are located within a building containing safety-related components and all nonsafety-related piping connected to safety-related systems back to the structural boundary using an isometric drawing. In cases where an isometric drawing which depicts the structural boundary is not readily available, connected lines were included back to a point beyond the safety/nonsafety interface to a base-mounted component, flexible connection, or the end of a piping run (such as a drain line) in accordance with the response to RAI 2.1-2. As described in LRA Section 2.1.2.1.3, portions of systems included for 10 CFR 54.4(a)(2) are not shown on LRA drawings. Further, the applicant's letter to the NRC dated July 3, 2007, LRA Amendment 27, Attachment 2 states that there are no nonsafety-related systems for which the applicant has not identified the nonsafety-related portions of systems which are attached to safety-related systems and required to be in the scope of license renewal in accordance with 10 CFR 54.4(a)(2). However, as a result of discussions with the staff during the Region I inspection (February 2007), the applicant determined that some safety-related SSCs in the VY turbine building required consideration for potential spatial impacts from nonsafety-related SSCs based on 10 CFR 54.4(a)(2). Therefore, an expanded review for SSCs in the turbine building determined that additional components required an AMR. Those additional component types have been added to LRA Table 2.3.3-13-42, as addressed in the applicant's letters to the NRC dated July 30, 2007 and August 16, 2007. Based on its review, the staff found the above response acceptable because the applicant stated that there are no nonsafety-related portions of systems which are attached to safety-related systems that are not within the scope of license renewal in accordance with 10 CFR 54.4(a)(2), but that there were spatial impact concerns from nonsafety-related SSCs in the turbine building. The additional component types have been added to LRA Table 2.3.3-13-42. Therefore, the staff concern described in Inspection Item 2.3.3.2a-2 is resolved. 2.3.3.2.3 Conclusion The staff reviewed the LRA, accompanying license renewal drawings, and RAI and inspection item responses to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the SW and RHRSW system 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). 2-67

2.3.3.3 Reactor Building Closed Cooling Water 2.3.3.3.1 Summary of Technical Information in the Application LRA Section 2.3.3.3 describes the RBCCW system, which supplies demineralized water to the reactor building auxiliary equipment systems from a closed cooling loop. The RBCCW system cools equipment which may contain radioactive fluids. The SW system provides the heat sink for the RBCCW system. The RBCCW cooling function is not a safety function. FPC is not a safety function of RBCCW since the safety-related SBFPC system uses SW as a heat sink. RBCCW supplies the heat sink for the nonsafety-related FPC system. RHR pump seal cooling is normally provided by RBCCW, not SW. This is not a safety function for RBCCW because RHR pump seal cooling is not required to support hot safe shutdown. However, if the SW pumps are inoperable and alternate cooling is inservice, the RHR pump seal coolers are manually aligned to the SW supplied by the ACS. In accordance with these conditions (loss of Vernon Pond, flooding of the SW intake structure, or fire in the SW intake structure which disables all four SW pumps), RHR pump seal cooling is a safety function of SW via ACS and the RBCCW system piping, which provides for seal cooling to be supplied by ACS and performs the safety function of maintaining SW system integrity. The RBCCW system has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the RBCCW system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the RBCCW system performs functions that support fire protection. LRA Tables 2.3.3-3 and 2.3.3-13-30 identify the following RBCCW system component types within the scope of license renewal and subject to an AMR:

• bolting
• flow switch housing
• heat exchanger (housing)
• heat exchanger (shell)
• heat exchanger (tubes)
• piping
• pump casing
• sight glass
• strainer housing
• tank
• thermowell
• tubing
• valve body The RBCCW system component intended functions within the scope of license renewal include the following:
• pressure boundary
• structural or functional support for safety-related equipment 2-68

2.3.3.3.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.3 and UFSAR Section 10.9 using the Tier-2 evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). The staffs review of LRA Section 2.3.3.3 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staffs RAI as discussed below. The staff noted that license renewal drawing LRA-G-191159-SH-03-0, at location P-10 at valve 29 shows a section of pipe within the scope of license renewal. This section of pipe is the RBCCW return to the ACS. However, a drawing continuation is not provided. In RAI 2.3.3.3-1 dated August 16, 2006, the staff requested that the applicant provide information for the continuation of this piping section to the license renewal boundary and justify the boundary location with respect to the applicable requirements of 10 CFR 54.4(a). In its response dated September 20, 2006, the applicant stated that the RBCCW return to the ACS shown on license renewal drawing LRA-G-191159-SH-03-0, at location P-10 at valve 29 continues on license renewal drawing LRA-G-191159-SH-02-0, at location E-2. Based on its review, the staff found the applicant response to RAI 2.3.3.3-1 acceptable because the applicant provided the necessary drawings and documentation to demonstrate this section of reactor building closed cooling water piping was connected to the service water system, was identified as being within the scope of license renewal, and with boundaries correctly identified on the service water system flow diagram, LRA-G-191159-SH-2-0. Therefore, the staff concern described in RAI 2.3.3.3-1 is resolved. 2.3.3.3.3 Conclusion The staff reviewed the LRA, accompanying license renewal drawings, and RAI responses to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the RBCCW system 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). 2-69

2.3.3.4 Emergency Diesel Generator 2.3.3.4.1 Summary of Technical Information in the Application LRA Section 2.3.3.4 describes the EDG and the diesel lube oil (DLO) systems. The purpose of the DG system is to provide Class 1E electrical power to the emergency buses in a loss of normal power condition or a LOCA coincident with loss of normal power or degraded grid voltage at the emergency buses and is available to provide Class 1E electrical power to the emergency buses in a LOCA with normal power available. The DG and auxiliary systems will start and be in standby during a LOCA. The purpose of the DLO system is to provide for DLO storage and provide for prelube of the DGs. The DLO system consists of two lube oil day tanks and pre-lube oil pumps only. The DLO system in the component database has only these four components. The remaining components supplying lube oil required during EDG operation are in the DG system. The DG and DLO systems have 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 systems perform functions that support fire protection. LRA Tables 2.3.3-4, 2.3.3-13-10, and 2.3.3-13-11 identify the following EDG system, DG and auxiliaries system, and DLO system component types within the scope of license renewal and subject to an AMR:

• bolting
• expansion joint
• filter housing
• heat exchanger (bonnet)
• heat exchanger (fins)
• heat exchanger (shell)
• heat exchanger (tubes)
• heat exchanger (tubesheets)
• heater housing
• orifice
• piping
• pump casing
• sight glass
• silencer
• strainer
• strainer housing
• tank
• thermowell
• tubing
• turbocharger
• valve body 2-70

The component intended functions within the scope of license renewal include the following:

• flow control
• filtration
• heat transfer
• pressure boundary 2.3.3.4.2 Staff Evaluation The staff reviewed LRA Sections 2.3.3.4 and 2.3.3.13, and UFSAR Section 8.5 using the Tier-2 evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). In letters to the NRC dated July 30, 2007 and August 16, 2007, the applicant reported the deletion of DG compressor housing from LRA Table 2.3.3-13-10 as a component type subject to an AMR. The applicant stated that since the compressor housing will not contain liquid, it should not be subject to an AMR for potential spatial interaction. The staff has reviewed this component type deletion and concurs that the deletion of the DG compressor housing is acceptable. 2.3.3.4.3 Conclusion The staff reviewed the LRA, accompanying license renewal drawings, and RAI responses to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the EDG system, DG and auxiliaries system, and DLO system 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). 2.3.3.5 Fuel Pool Cooling 2.3.3.5.1 Summary of Technical Information in the Application LRA Section 2.3.3.5 describes the FPC system, the safety-related SBFPC subsystem, the fuel pool filter-demineralizer (FPFD) system, and the Boral in the spent fuel racks. The FPC system removes the decay heat released from the spent fuel elements. During normal operation, the system maintains a specified fuel pool water temperature, purity, water clarity, and water level. The system cools the fuel storage pool by transferring the spent fuel decay heat through heat exchangers to the RBCCW. The purpose of the SBFPC system is to maintain pool temperature during design basis accidents (including concurrent LOCAs, loss of offsite power, and single failure) or if an unusually high spent fuel decay heat load is placed in the pool. The purpose of 2-71

the FPFD is to maintain the purity of the spent fuel pool water by minimizing corrosion product buildup and controlling water clarity, minimizing fission product contamination in the water, and controlling removal of water from the fuel pool to the CST system. Boral sheets in the spent fuel storage pool provide neutron absorption. The FPC and SBFPC systems have safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related FPC, SBFPC, and FPFD systems SSCs potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the FPC and SBFPC systems perform functions that support fire protection. LRA Tables 2.3.3-5, 2.3.3-13-16, 2.3.3-13-17, and 2.3.3-13-37 identify the following FPC, FPFD, and SBFPC system component types within the scope of license renewal and subject to an AMR:

• bolting
• filter housing
• heat exchanger (shell)
• heat exchanger (tubes)
• neutron absorber (boral)
• orifice
• piping
• pump casing
• thermowell
• tubing
• valve body The component intended functions within the scope of license renewal include the following:
• heat transfer
• neutron absorption
• pressure boundary 2.3.3.5.2 Staff Evaluation The staff reviewed LRA Sections 2.3.3.5 and 2.3.3.13, and UFSAR Sections 10.3 and 10.5 using the Tier-2 evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2-72

The staffs review of LRA Section 2.3.3.5 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staffs RAI as discussed below. The staff noted that license renewal drawing G-191173, Sheet 1, at location H-5 shows a section of pipe within the scope of license renewal. The section of pipe includes check valve V-30 and a penetration at concrete wall, with changes in seismic classifications at each end. The section of pipe is isolated from all other in-scope piping and is not in an in-scope flow path. Piping upstream of V-30 (8"-FPC-24, 6-FPC-24, and 8-FPC-34) contains two normally closed valves (V-28 and V-53) and is not shown within the scope of license renewal. Piping downstream of V-30 (4"-FPC-24 and 4"-FPC-25) is also not shown within the scope of license renewal. Failure of these sections of piping could have an adverse effect on the intended pressure boundary function for the FPC piping. In RAI 2.3.3.5a-1 dated August 16, 2006, the staff requested that the applicant provide information to justify exclusion from the scope of license renewal the piping from valves V-28 and V-53 to valve V-30 and from the reactor well diffusers to the current license renewal boundary at the penetration upstream of valve V-30. In its response dated September 20, 2006, the applicant stated that license renewal drawings only show the portions of the system with intended functions that meet the requirements of 10 CFR 54.4(a)(1) or (a)(3). As described in LRA Section 2.1.2.1.3, portions of systems required by 10 CFR 54.4(a)(2) are not shown on license renewal drawings. The piping from valves V-28 and V-53 to valve V-30 and from the reactor well diffusers to the license renewal boundary at the penetration upstream of valve V-30 are within the scope of license renewal and subject to an AMR as required by 10 CFR 54.4(a)(2) and as described in LRA Table 2.3.3.13-B for the FPC system. The description includes portions of the system in the primary containment building and reactor building and components outside the safety class pressure boundary which are relied upon to provide structural/seismic support for the pressure boundary. The piping in question is inside the reactor building and attached to safety-related components so it is within the scope of license renewal and subject to an AMR. Based on its review, the staff found the applicant response to RAI 2.3.3.5a-1 acceptable because the applicant acknowledged that piping from valves V-28 and V-53 to valve V-30 and from the reactor well diffusers to the license renewal boundary at the penetration upstream of valve V-30 are included within the scope of license renewal. As described in LRA Section 2.1.2.1.3, portions of systems included for 10 CFR 54.4(a)(2) are not shown on LRA drawings. Although the applicant did not identify these sections of piping within the boundary of license renewal on the drawing, the applicant confirmed they are within the scope of license renewal based on the potential for physical interaction with safety-related systems in accordance with 10 CFR 54.4(a)(2). Therefore, the staff concern described in RAI 2.3.3.5a-1 is resolved. 2-73

2.3.3.5.3 Conclusion The staff reviewed the LRA, accompanying license renewal drawings, and RAI response to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the FPC, FPFD, and SBFPC system 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). 2.3.3.6 Fuel Oil 2.3.3.6.1 Summary of Technical Information in the Application LRA Section 2.3.3.6 describes the fuel oil (FO) system, which supplies FO to the EDGs as well as the nonsafety-related diesel-driven fire pump, John Deere diesel (JDD), and house HB. The portion of the system related to the EDGs consists of a day tank and fuel transfer pump for each diesel, the FO storage tank, valves, and piping. The diesel fire pump FO day tank, JDD day tank, and house HB FO storage tank are not connected to the FO storage tank. Normal makeup to the house HB FO storage tank is by tanker truck. Normal makeup to the diesel fire pump FO day tank and JDD day tank is from a 500-gallon portable tank filled from the FO storage tank. The FO system has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the FO system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the FO system performs functions that support fire protection. LRA Tables 2.3.3-6 and 2.3.3-13-14 identify the following FO system component types within the scope of license renewal and subject to an AMR:

• bolting
• filter housing
• flame arrestor
• flex hose
• injector housing
• piping
• pump casing
• sight glass
• strainer housing
• tank
• thermowell
• tubing
• valve body
• strainer housing 2-74

The FO system component intended functions within the scope of license renewal include the following:

• flow control
• pressure boundary 2.3.3.6.2 Staff Evaluation The staff reviewed LRA Sections 2.3.3.6 and 2.3.3.13, and UFSAR Section 8.5.4 using the Tier-2 evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). The staffs review of LRA Section 2.3.3.6 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staffs RAI as discussed below. The staff noted that license renewal drawing LRA-G-191162, Sheet 2, provides information about the EDGs, diesel-driven fire pump, and house HB systems, supported by the FO system. However, the drawing does not provide sufficient information about the JDD system, also supported by the FO system. For example, more information is required regarding the transfer system between the 75,000-gallon FO storage tank, the day tanks for the two JDDs, and single fire pump diesel, which is necessary to provide an intended function in accordance with 10 CFR 54.4 (a)(3) in support of the fire protection regulation requirements (10 CFR 50.48). The LRA text states only that a 500-gallon portable tank is used to transport FO to the diesel day tanks. Typical components subject to an AMR for diesels like the day tank, strainer, etc., for the JDDs are not covered. In RAI 2.3.3.6-1 dated August 16, 2006, the staff requested that the applicant provide FO system drawings and describe the JDD system. The staff also requested that the applicant explain the relationship between the JDD and the FO systems and clarify what the AMR tables should include in both Sections 2.3.3.6 and 2.3.3.12. The staff further requested that the applicant also provide information for the license renewal boundary that justifies its location with respect to the applicable requirements of 10 CFR 54.4(a). In its response dated September 20, 2006, the applicant stated that the 350-gallon diesel fire pump FO day tank and 550-gallon fiberglass underground storage tank for the JDD are filled with FO from the FO storage tank. The FO is pumped from the FO storage tank drain line into a portable 500-gallon tank. The portable tank is then moved to the intake structure or JDD building by a fork lift. A 12VDC pump on the portable tank then pumps the FO into the diesel fire pump FO day tank or the fiberglass underground storage tank for the JDD. Since the portable tank and pump are not part of the FO system pressure boundary and since levels in the diesel fire pump FO day tank and underground storage tank for the JDD are maintained, the portable tank and pump do not perform a component intended function and are not subject 2-75

to an AMR. A dedicated 550-gallon fiberglass underground storage tank provides fuel to the JDD engine. As the JDD is required for compliance with the staff's regulations concerning fire protection (10 CFR 50.48), providing FO for the engine is an intended function of the FO system in accordance with 10 CFR 54.4 (a)(3). Therefore, the storage tank and associated piping and components that supply FO to the diesel engine injectors are within the scope of license renewal and subject to an AMR. JDD FO components are included in LRA Tables 2.3.3.6 and 3.3.2-6. As the JDD is required for compliance with the staff's regulations concerning fire protection (10 CFR 50.48), it is within the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 (a)(3). The passive mechanical components of the diesel subject to an AMR that were confirmed by walkdown are included in LRA Tables 2.3.3-12 and 3.3.2-12. Based on its review, the staff found the applicant response to RAI 2.3.3.6-1 acceptable because the applicant explained that the 550-gal fiberglass underground storage tank and associated piping and components that supply FO to the diesel engine injectors are within the scope of license renewal and an AMR. The applicant stated that flow diagrams are not available for this skid-mounted diesel, or its FO system, and only a few components are represented in the equipment database. The applicant, however, has verified by walkdown of the system that these passive components are identified in AMR Tables 2.3.3-12 and 3.3.2-12. Therefore, the staff concern described in RAI 2.3.3.6-1 is resolved. 2.3.3.6.3 Conclusion The staff reviewed the LRA, accompanying license renewal drawings, and RAI response to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the FO system 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). 2.3.3.7 Instrument Air 2.3.3.7.1 Summary of Technical Information in the Application LRA Section 2.3.3.7 describes the IA, SA, 105 (IA and SA instruments), and nitrogen (N2) supply systems. The purpose of the IA system is to provide the station continuously with dry, oil-free air for pneumatic instruments and controls through a dual header system. The IA system includes the containment N2 supply described in the UFSAR as a separate N2 subsystem also known as containment air. The purpose of containment N2 is to provide pneumatically-operated components in the drywell with N2 when the primary containment is inerted so any component leakage will not dilute the N2 atmosphere. This N2 source can be from either the N2 system (normal supply) or the containment air compressor (automatic backup supply). When neither N2 supply is available or when the containment is not inerted, IA may be lined up manually as a secondary backup for the containment N2. When the containment is not inerted, IA will be lined up as the primary source of pneumatic pressure. 2-76

The purpose of the SA system is to provide the station with the compressed air requirements for pneumatic instruments and controls and general station services. The IA system also supports this function. The purpose of the 105 system is to provide indication, alarm, and control functions for associated systems. This code is used in the component database for various instrumentation components related to IA and SA. Although the 105 system consists mainly of EIC components, certain IA instrumentation mechanical components are included as well. The purpose of the N2 system is to provide N2 gas to the primary containment atmospheric control (PCAC) system to satisfy the primary containment purge and normal make-up requirements. The IA, SA, 105, and N2 systems have safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the IA and N2 system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the IA system performs functions that support fire protection and SBO. LRA Tables 2.3.3-7, 2.3.3-13-54, 2.3.3-13-22, and 2.3.3-13-24 identify the following IA, SA and N2 system component types within the scope of license renewal and subject to an AMR:

• bolting
• piping
• strainer housing
• tank
• trap
• tubing
• valve body The IA, SA and N2 system component intended function within the scope of license renewal is to provide a pressure boundary.

2.3.3.7.2 Staff Evaluation The staff reviewed LRA Sections 2.3.3.7 and 2.3.3.13, and UFSAR Section 10.14 using the Tier-2 evaluation methodology, for IA and N2, and the Tier-1 methodology, for SA and 105 systems, described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). In letters to the NRC dated July 30, 2007 and August 16, 2007, the applicant reported the deletion of IA compressor housing from LRA Table 2.3.3-13-22 as a component type subject to an AMR. The applicant stated that since the compressor housing will not contain liquid, it should not be subject to an AMR for potential spatial interaction. The staff has reviewed this component type deletion and concurs that the deletion of the IA compressor housing is acceptable. 2-77

2.3.3.7.3 Conclusion The staff reviewed the LRA and accompanying license renewal drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the IA and N2 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). 2.3.3.8 Fire Protection-Water 2.3.3.8.1 Summary of Technical Information in the Application LRA Section 2.3.3.8 describes the fire protection-water system. The fire protection system provides fire protection for the station through the use of water, CO2, dry chemicals, foam, detection and alarm systems, and rated fire barriers, doors, and dampers. Water for the fire protection system is from two vertical turbine-type pumps, one electric motor-driven and one diesel-driven. The pumps and drivers located in the intake structure discharge to an underground piping system serving the exterior and interior fire protection systems. The pressure in the system is maintained at approximately 100 psig by an interconnection to the SW system. A check valve in the connecting pipe prevents backflow. Through an interconnecting valve, the SW system can provide water to fire protection components in the unlikely event that both fire protection pumps are unavailable. The failure of nonsafety-related SSCs in the fire protection-water system potentially could prevent the satisfactory accomplishment of a safety-related function. The fire protection-water system also performs functions that support fire protection. LRA Tables 2.3.3-8 and 2.3.3-13-15 identify the following fire protection-water system component types within the scope of license renewal and subject to an AMR:

• bolting
• expansion joint
• filter
• filter housing
• flow nozzle
• gear box
• heat exchanger (bonnet)
• heat exchanger (shell)
• heat exchanger (tubes)
• heater housing
• nozzle
• orifice
• piping
• pump casing
• silencer
• strainer
• strainer housing 2-78
• tank
• tubing
• turbocharger
• valve body In LRA Table 3.3.2-8, the applicant provides the results of the AMR.

The fire protection-water system component intended functions within the scope of license renewal include the following:

• flow control
• filtration
• heat transfer
• pressure boundary 2.3.3.8.2 Staff Evaluation The staff reviewed LRA Sections 2.3.3.8 and 2.3.3.13, and UFSAR Section 10.11 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). The staff also reviewed the VYNPS fire protection SER, dated January 13, 1978, and supplemental SERs listed in the VYNPS Operating License Condition g.3.F. These reports are referenced in the VYNPS fire protection CLB and summarize the fire protection program and commitments required by 10 CFR 50.48 using BTP Auxiliary and Power Conversion Systems Branch (APCSB) 9.5-1, ?Guidelines for Fire Protection for Nuclear Power Plants, May 1, 1976, and Appendix A to BTP APCSB 9.5-1, August 23, 1976. The staff then reviewed those components that the applicant identified as being within the scope of license renewal to verify that the applicant did not omit any passive and long-lived components that should be subject to an AMR as required by 10 CFR 54.21(a)(1). The staffs review of LRA Section 2.3.3.8 identified areas requiring additional information necessary to complete the review of the applicants scoping and screening results. The applicant responded to the staffs RAIs as discussed below. In RAI 2.3.3.8-1, dated August 15, 2006, the staff stated that LRA drawing LRA-G-191163-SH-02-0, Fire Protection System Outer Loop, shows the yard fire hydrants as out of scope (i.e., not colored in purple). The staff requested that the applicant verify whether the yard fire hydrants are in-scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal and not subject to an AMR, the staff requested that the applicant provide justification for the exclusion. 2-79

In its response, by letter dated September 20, 2006, the applicant stated: LRA drawing LRA-G-191163-SH-02-0, Fire Protection System Outer Loop shows that the yard fire hydrants are not subject to an AMR since they are not highlighted. As described in LRA Section 2.3.3.8: The fire protection-water system has no intended functions as required by 10 CFR 54.4(a)(1). The fire protection-water system intended functions as required by 10 CFR 54.4(a)(2) include the following:

• Maintain integrity of nonsafety-related components such that no physical interaction with safety-related components could prevent satisfactory accomplishment of a safety function.

The fire protection-water system intended functions as required by 10 CFR 54.4(a)(3) include the following:

• Provide the capability to extinguish fires in vital areas of the plant (10 CFR 50.48).

Therefore, the fire protection system is in-scope for license renewal. The piping in the outer loop performs a component pressure boundary intended function that supports the ability of the fire protection system to extinguish fires in vital areas of the plant serviced by the inner loop. If the outer loop failed, piping that provides water to fire systems in vital areas of the plant may not perform its intended function. The yard fire hydrants are isolable from the outer loop such that their failure would not impact the support of vital areas. Yard fire hydrants are not required to extinguish fires in vital areas of the plant and their failure cannot impact safety-related components. Therefore, the yard fire hydrants perform no intended function in support of the system intended functions and are not subject to an aging management review. In evaluating this response, the staff found that it was incomplete and that review of LRA Section 2.3.3.8 could not be completed. Yard fire hydrants are included in-scope of license and excluded from an AMR. The staff finds this contrary to the original VYNPS fire protection safety evaluation (SE) and UFSAR as the CLB. In its response, the applicant stated that the yard fire hydrants perform no intended function in support of the system intended functions and are not subject to an AMR and therefore, not credited in accordance with 10 CFR 50.48. This resulted in the staff holding a telephone conference with the applicant on November 7, 2006, to discuss information necessary to resolve the concern in RAI 2.3.3.8-1. The staff explained that the scope of SSCs required for compliance with 10 CFR 50.48 and 10 CFR 50 Appendix A, GDC 3, 2-80

goes beyond preserving the ability to maintain safe-shutdown in the event of a fire. The staff stated that the exclusion of fire protection SSCs, on the basis that the intended function is not required for the protection of safe-shutdown equipment or safety-related equipment is not acceptable, if the SSC is required from compliance with 10 CFR 50.48. By letter dated December 4, 2006, the applicant stated that the yard fire hydrants are in-scope and subject to an AMR. The hydrants are identified as component type valve body in LRA Table 2.3.3-8. Results of the AMR are provided in LRA Table 3.3.2-8 for line items valve body with carbon steel as the material and raw water as the environment. Based on its review, the staff finds the applicants response to RAI 2.3.3.8-1 acceptable because the applicant has committed to interpret yard fire hydrants as included in the valve body, which is in the scope for the license renewal and subject to an AMR. The staff is adequately assured that the yard fire hydrants used for the fire suppression will be considered appropriately during the aging management activities. Therefore, the staffs concern described is RAI 2.3.3.8-1 is resolved. In RAI 2.3.3.8-2, dated August 15, 2006, the staff stated that LRA drawing LRA-G-191163-SH-02-0, Fire Protection System Outer Loop, shows the recirculation pump motor generator set foam system colored in purple (i.e., in-scope). This drawing does not show the 150 gallon foam concentrate tank and its components (piping and valves). The staff requested that the applicant verify whether the 150 gallon foam concentrate tank and its components are in-scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal and not subject to an AMR, the staff requested applicant provide justification for the exclusion. In its response, by letter dated September 20, 2006, the applicant stated: LRA drawing LRA-G-191163-SH-01-0, Fire Protection System Inner Loop shows the recirculation pump motor generator set foam system colored in purple (i.e., subject to an AMR) at coordinates I/J-2. The associated 150 gallon foam concentrate tank (TK76-1B) and its components are in-scope and subject to an AMR as shown on the same drawing at coordinates B-8. LRA Table 3.3.2.8 includes line items for the tank and associated piping, valves, and flow nozzles with fire protection foam as the internal environment. 2-81

Based on its review, the staff found the applicant's response to RAI 2.3.3.8-2 acceptable because the recirculation pump motor generator set foam system and the 150 gallon foam concentrate tank and its components (piping and valves) were identified to be in the scope of license renewal and subject to an AMR. Therefore, the staff concludes that this recirculation pump motor generator set foam system and the associated components are correctly included in the scope of license renewal and subject to an AMR. The staffs concern described in RAI 2.3.3.8-2 is resolved. In RAI 2.3.3.8-3, dated August 15, 2006, the staff stated that NRC SE Section 3.2.2, dated January 13, 1978, approving the VYNPS fire protection program, discusses the use of flame retardant coating to protect electrical cables in trays and risers in the switchgear room to meet the requirements of 10 CFR 50.48. The LRA does not list flame retardant coating for cables. The staff requested that the applicant verify whether the flame retardant coating is in-scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If flame retardant coating is excluded from the scope of license renewal and not subject to an AMR, the staff requested applicant provide justification for the exclusion. In its response, by letter dated September 20, 2006, the applicant stated: Flame retardant (flamemastic) coatings are in-scope and subject to an AMR and are included in the line item Fire wrap in LRA Tables 2.4-6 and 3.5.2-6. Flamemastic was inadvertently omitted from the list of materials for the line item Fire wrap in LRA Table 3.5.2-6. Based on its review, the staff found the applicant's response to RAI 2.3.3.8-3 acceptable because the applicant states that the fire retardant coating Flamemastic was inadvertently omitted from the list of materials for the line item Fire wrap in LRA Table 3.5.2-6. Because the applicant has committed to interpret fire retardant coating as included in the line item Fire wrap, which is in the scope for license renewal and subject to an AMR, the staff is adequately assured that the fire retardant coating used to protect electrical cables in trays and risers will be considered appropriately during plant aging management activities. Therefore, the staffs concern described in RAI 2.3.3.8-3 is resolved. In RAI 2.3.3.8-4, dated August 15, 2006, the staff stated that SE Section 4.3.1(f) discusses a manually-operated foam maker with a permanent storage tank with fire suppression functions in the event of a fire affecting the 75,000 gallon outdoor FO storage tank, the diesel generator day tanks, or the diesel generator room located on the ground floor of the turbine building. The LRA does not list this foam maker and its associated storage tank systems and components. The staff requested that the applicant verify whether the foam maker and storage tank system and components (piping and valves) are in-scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal and not subject to an AMR, the staff requested applicant provide justification for the exclusion. In its response, by letter dated September 20, 2006, the applicant stated: As discussed in LRA Section 2.3.3.8, in the turbine building, in addition to hose stations and deluge systems, a foam fire protection agent is available that can be 2-82

used to combat fires at the FO storage tank, turbine lube oil storage tank, main and auxiliary transformers, house HBs, and the emergency diesel generators. The turbine building foam tank (TK76-1A) and associated piping and valves are in-scope and subject to an AMR as shown on LRA drawing LRA-G-191163-SH-01-0, Fire Protection System Inner Loop at coordinates E-8. This manual foam system is used by attaching a fire hose to the outlet and opening valves to enable water from the fire protection header to mix with the foam concentrate from the storage tank and flow through the hose. LRA Table 3.3.2.8 includes line items for the tank and associated piping and valves with fire protection foam as the internal environment. Fire hoses are periodically replaced and managed by the existing fire protection program, and therefore are not subject to an AMR. Based on its review, the staff found the applicant's response to RAI 2.3.3.8-4 acceptable because the manually-operated foam maker with a permanent storage tank located on the ground floor of the turbine building was identified to be in the scope of license renewal and subject to an AMR. This foam system is to be used in the event of a 75,000 gallon outdoor FO storage tank fire, or diesel generator day tank fire, or diesel generator room fire. Further, the applicant states that LRA Table 3.3.2.8 includes line items for the tank and associated piping and valves with fire protection foam as the internal environment. The applicant also states that the fire hoses associated with this foam system are outside the scope of license renewal since they are periodically replaced (short-lived components) and managed by the existing fire protection program. Therefore, the staff concludes that the turbine building foam systems and the associated components are correctly included in the scope of license renewal and subject to an AMR. The staffs concern described in RAI 2.3.3.8-4 is resolved. In RAI 2.3.3.8-5, dated August 15, 2006, the staff stated that SE Section 4.5 discusses floor drains provided in all plant areas protected with fixed water fire suppression. Are they 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). If they are excluded from the scope of license renewal and not subject to an AMR, the staff requested applicant provide justification for the exclusion. In its response, by letter dated September 20, 2006, the applicant stated: Water-filled components in the radioactive waste system (which includes the floor drain system) that could affect safety-related equipment are in-scope and require an AMR in accordance with 10 CFR 54.4(a)(2) due to potential spatial interaction. These components are subject to an AMR and are addressed in LRA Table 3.3.2-13-32. Based on its review, the staff found the applicant's response to RAI 2.3.3.8-5 acceptable. Although the SE addresses these floor drains as associated with fire suppression, it is not included in LRA Table 3.3.2-8 Fire Protection-Water System. Instead, it is included in LRA Table 3.3.2-13-32, Radwaste Liquid & Solid (RDW) Nonsafety-Related Components Affecting Safety-Related Systems, which is in the scope for license renewal and subject to an AMR. Because the applicant has committed to interpret these floor drains as included in the 2-83

radioactive waste system, which is in the scope for license renewal and subject to an AMR, the staff is adequately assured that the floor drains used for fire suppression will be considered appropriately during plant aging management activities. Therefore, the staffs concern described in RAI 2.3.3.8-5 is resolved. In RAI 2.3.3.8-6, dated August 15, 2006, the staff stated that the supplement to SE Section 3.3, dated February 20, 1980, discusses the fire protection features for the primary containment (e.g., fixed suppression systems, standpipe and hose stations, and oil collection system). The staff requested that the applicant determine whether fire protection systems and features for primary containment should be included as systems and components in-scope for license renewal and subject to an AMR. If not, the staff requested applicant explain the basis. In its response, by letter dated September 20, 2006, the applicant stated: Section 3.3 of the SE supplement dated February 20, 1980, discusses potential fire protection features for the primary containment in the event the containment is not inerted. As noted in LRA Section 3.3.2.2.7, VYNPS is a BWR with an inert containment atmosphere. Therefore, the primary containment does not have a fixed suppression system or a reactor recirculation pump oil collection system. As shown on LRA drawing LRA-G-191163-SH-01-0, Fire Protection System Inner Loop, hose stations in the reactor building that may be used for fire suppression in primary containment during non-inerted outage periods are in-scope and subject to an AMR. Based on its review, the staff found the applicant's response to RAI 2.3.3.8-6 acceptable because VYNPS is a BWR with an inert containment atmosphere and the primary containment does not have a fixed suppression system or a reactor recirculation pump oil collection system. Further, the applicant states that during non-inerted outage periods, hose stations in the reactor building, may be used for fire suppression in primary containment. Therefore, the staff concludes that the fire protection features for the primary containment (e.g., fixed suppression systems, standpipe and hose stations, and oil collection system) are correctly excluded from the scope of license renewal and are not subject to an AMR. During the refueling outage, hose stations in the reactor building may be used for fire suppression in the primary containment. This system was identified to be in the scope of license renewal and subject to an AMR. Therefore, the staffs concern described in RAI 2.3.3.8-6 is resolved. In RAI 2.3.3.8-7, dated August 15, 2006, the staff stated that the supplement to SE Section 3.3, dated October 24, 1980, discusses the deluge system used to protect the turbine building lay-down area. The staff requested that the applicant determine whether the turbine building lay-down deluge system and its components should be included as systems and components in-scope for license renewal and subject to an AMR. If not, the staff requested applicant explain the basis. 2-84

In its response, by letter dated September 20, 2006, the applicant stated: The turbine building loading bay is the area referred to in the SE supplement as the turbine building lay-down area. The sprinkler system for this area is in-scope and subject to an AMR as shown on LRA drawing LRA-G-191163-SH-01-0, Fire Protection System Inner Loop at coordinate G-9. Based on its review, the staff found the applicant's response to RAI 2.3.3.8-7 acceptable because the deluge system and its components were identified to be in the scope of license renewal and subject to an AMR. Therefore, the staff concludes that this turbine building lay-down area deluge system and its associated components are correctly included in the scope of license renewal and subject to an AMR. The staffs concern described in RAI 2.3.3.8-7 is resolved. In RAI 2.3.3.8-8, dated August 15, 2006, the staff stated that SE Section 4.3.1(e) discusses the automatic sprinkler systems used for various areas including the outdoor transformer. The LRA does not list the sprinkler systems nor associated components to protect the outdoor transformer. The staff requested that the applicant verify whether the sprinkler system and associated components are in-scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal and not subject to an AMR, the staff requested applicant provide justification for the exclusion. In its response, by letter dated September 20, 2006, the applicant stated: As described in LRA Section 2.3.3.8, the fire protection system is in the scope of license renewal in accordance with 10 CFR 54.4(a)(3) because it is credited in the Appendix R safe-shutdown analysis as required by 10 CFR 50.48. The main transformer and auxiliary transformer sprinkler fire protection subsystems do not mitigate fires in areas containing equipment important to safe operation of the plant, nor are they credited with achieving safe-shutdown in the event of a fire. These subsystems are only required to meet state, municipal, or insurance requirements. Therefore, these subsystems have no intended function and are not included in the AMR summarized in LRA Table 3.3.2-8. Since they are outdoors and away from safety-related equipment, the main transformer and auxiliary transformer sprinkler subsystems cannot affect safety-related equipment by spatial interaction and therefore, have no intended function as required by 10 CFR 54.4(a)(2). Therefore, these subsystems are not included in the AMR summarized in LRA Table 3.3.2-13-15. Based on its review, the staff found the applicant's response to RAI 2.3.3.8-8 acceptable. Although the main transformer and auxiliary transformer sprinkler systems are addressed in the SE, these systems in question are not credited to meet the requirements of Appendix R for achieving safe-shutdown in the event of a fire. In addition, the staff reviewed commitments made by the applicant to satisfy Appendix A to BTP APCSB 9.5-1, which discussed that the main transformer and auxiliary transformer are either located at least 50 feet from the building 2-85

containing safety-related equipment or the wall of the building is a 3-hour fire-rated wall. Therefore, the staff finds that the main transformer and auxiliary transformer cannot affect safety-related equipment by spatial interaction and the sprinkler systems for the main transformer and auxiliary transformer were correctly excluded from the scope of license renewal and not subject to an AMR. Therefore, the staffs concern described in RAI 2.3.3.8-8 is resolved. In RAI 2.3.3.8-9, dated August 15, 2006, the staff stated that SE Section 5.12.6 discusses the use of a 3-hour rated fire protection coating to protect the structural steel supporting the wall and ceiling of diesel generator rooms. The LRA does not list 3-hour rated fire protection coating for structural steel. The staff requested that the applicant verify whether the fire protection coating for structural steel is in-scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If fire protection coating is excluded from the scope of license renewal and not subject to an AMR, the staff requested applicant provide justification for the exclusion. In its response, by letter dated September 20, 2006, the applicant stated: Subsequent to the January 17, 1978, NRC Safety Evaluation, VYNPS notified the NRC (in letter WVY 78-85) that a protective coating with a "fire resistant rating of approximately 1-hour would be utilized for the structural steel supporting the roof and ceiling. This is based on the conclusion that a fire in one diesel generator room will not result in structural damage that could result in fire spread to the other room. The fire retardant coatings are in-scope and subject to an AMR and are included in the line item Fire proofing in LRA Tables 2.4-6 and 3.5.2-6. Based on its review, the staff found the applicant's response to RAI 2.3.3.8-9 acceptable. The SE addresses the use of a 3-hour rated fire retardant coating to protect the structural steel supporting the wall and ceiling of the diesel generator rooms. The staff has confirmed that the applicant correctly identified the actual fire resistance rating of the structural steel coating ( i.e., 1 hour). The fire resistance rating of the structural steel coating was clarified and included in the LRA Tables 2.4-6 and 3.5.2-6 and the coating is within the scope of license renewal and subject to an AMR. Therefore, the staffs concern described in RAI 2.3.3.8-9 is resolved. In RAI 2.3.3.8-10, dated August 15, 2006, the staff stated that LRA Table 2.3.3-8 excludes several types of fire protection components that appear in the SE and its supplements and/or updated UFSAR, and which also appear in the LRA drawings colored in purple. These components are listed below.

• hose stations
• hose connections
• hose racks
• pipe fittings
• pipe supports
• couplings
• threaded connections
• flexible hoses 2-86
• restricting orifices
• interface flanges
• chamber housings
• heat-actuated devices
• gauge snubbers
• tank heaters
• thermowells
• water motor alarms
• fire hydrants (casing)
• sprinkler heads
• dikes (contain oil spill)
• flame retardant coating for cables
• fire barrier penetration seals
• fire barrier walls, ceilings, floors, and slabs
• fire doors
• fire rated enclosures
• fire retardant coating for structural steel supporting walls and ceilings For each, the staff requested applicant determine whether the component should be included in Table 2.3.3.8, and if not, justify the exclusion.

In its response, by letter dated September 20, 2006, the applicant stated the following:

• hose stations - Since they support criterion (a)(3) equipment, hose stations are included in the structural AMR. They are included in the Fire hose reels line item in LRA Table 2.4-6.
• hose connections - Hose connections are included in the Piping line item in LRA Table 2.3.3-8.
• hose racks - Since they support criterion (a)(3) equipment, hose racks are included in the structural AMR. They are included in the Fire hose reels line item in LRA Table 2.4-6.
• pipe fittings - As stated in LRA Section 2.0, the term piping in component lists may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Pipe fittings are included in the Piping line item in LRA Table 2.3.3-8.
• pipe supports - Since they support criterion (a)(3) equipment, piping supports are included in the structural AMR. They are included in the Component and piping supports line item in LRA Table 2.4-6.
• couplings - As stated in LRA Section 2.0, the term piping in component lists may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Couplings are pipe fittings included in the Piping line item in LRA Table 2.3.3-8.

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• threaded connections - As stated in LRA Section 2.0, the term piping in component lists may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Threaded connections are pipe fittings included in the Piping line item in LRA Table 2.3.3-8.
• flexible hoses - Hoses are replaced on a specified periodicity and therefore, are not subject to an AMR as required by 10 CFR 54.21(a)(1)(ii).
• restricting orifices - As stated in LRA Section 2.0, the term piping in component lists may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Restricting orifices are included in the Piping line item in LRA Table 2.3.3-8.
• interface flanges - As stated in LRA Section 2.0, the term piping in component lists may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Interface flanges are pipe fittings included in the Piping line item in LRA Table 2.3.3-8.
• chamber housings - As shown on LRA drawing LRA-G-191163-SH-01-0, the turbine building lube oil room sprinkler system includes a retard chamber, piping, and valves whose purpose is to prevent false alarms due to system pressure surges and to provide a flow path to the water gong alarm during system actuation. Since failure of these components downstream of valve DV-76-200D would not prevent fire suppression capability for the lube oil room sprinkler system, they are not subject to an AMR.
• heat-actuated devices - As stated in UFSAR Section 10.11.3, the pre-action fire protection subsystems for the hydrogen seal oil area and the turbine building condenser and heater bay area have heat-actuated devices to initiate opening of the deluge valves. Heat-actuated devices are active components; not subject to an AMR.
• gauge snubbers - Gauge snubbers are integral parts of tubing runs that protect instrumentation from pressure surges. Gauge snubbers in tubing runs to instruments are included in the tubing line item in LRA Table 2.3.3-8.
• tank heaters - Neither the SE and its supplements nor the UFSAR discuss tank heaters. Tank heaters do not appear on the LRA drawings colored in purple. VYNPS does not have fire water storage tanks and the foam concentrate tanks do not have heaters. Therefore, the fire protection - water system does not have tank heaters.
• thermowells - As stated in LRA Section 2.0, the term piping in component lists may include pipe, pipe fittings (such as elbows and 2-88

reducers), flow elements, orifices, and thermowells. Thermowells are included in the Piping line item in LRA Table 2.3.3-8.

• water motor alarms - This response assumes that reviewer means water flow alarms which are provided in critical locations and annunciate in the control room to provide positive indication of fire water system operation.

Water flow alarms are active components; not subject to an AMR.

• fire hydrants (casing) - As described in response to RAI 2.3.3.8-1, the yard fire hydrants are not subject to an AMR. By letter dated December 4, 2006, the applicant stated that the yard fire hydrants are in-scope and subject to an AMR. The hydrants are identified as component type valve body in LRA Table 2.3.3-8. Results of the AMR are provided in LRA Table 3.3.2-8 for line items valve body with carbon steel as the material and raw water as the environment.
• sprinkler heads - Sprinkler heads are included in the Flow nozzle line item in LRA Table 2.3.3-8.
• dikes (contain oil spill) - Dikes are included in the structural AMR. They are included in the Flood curb line items in LRA Table 2.4-6.
• flame retardant coating for cables - As described in response to RAI 2.3.3.8-3, flame retardant (flamemastic) coatings are subject to an AMR and are included in the line item Fire wrap in LRA Table 2.4-6.

Flamemastic was inadvertently omitted from the list of materials for the line item Fire wrap in LRA Table 3.5.2-6.

• fire barrier penetration seals - Fire barrier penetration seals are included in the structural AMR. They are included in the Penetration sealant (fire, flood, radiation) line item in Table 2.4-6.
• fire barrier walls, ceilings, floor, and slabs - Fire barrier walls, ceilings, floor, and slabs are included in the structural AMR. They are included in the concrete line items in Tables 2.4-2 through 2.4-4.
• fire doors - Fire doors are included in the structural AMR. They are included in the Fire doors line item in Table 2.4-6.
• fire rated enclosures - As stated in SE Section 5.17.1, the diesel day tank for the fire pump is located in a separate 3-hour fire rated enclosure. This enclosure consists of concrete block walls in the intake structure and is included in the structural AMR. It is included in the Masonry walls line item in Table 2.4-3.

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• fire retardant coating for structural steel supporting wall and ceiling - As described in response to RAI 2.3.3.8-9, fire retardant (flamemastic) coatings are subject to an AMR and are included in the line item Fire wrap in LRA Table 2.4-6. Flamemastic was inadvertently omitted from the list of materials for the line item Fire wrap in LRA Table 3.5.2-6.

Based on its review, the staff found the applicant's response to RAI 2.3.3.8-10 acceptable. Although the applicant states that they consider these components to be included in other line items, the descriptions of the line items in the LRA do not list all these components specifically. The applicant properly identified the following components to be included in the other line items in the scope of license renewal and subject to an AMR: hose racks, pipe fittings, pipe supports, couplings, threaded connections, restricting orifices, interface flanges, gauge snubbers, thermowells, sprinkler heads, dikes, flame retardant coating for cables, fire barrier penetration seals, fire barrier walls, ceilings, floors, slabs, fire doors, fire rated enclosures, and fire retardant coating for structural steel supporting walls and ceilings. The staff is adequately assured that these components will be considered appropriately during the plant aging management activities. For each of the following components, the staff found that they were not included in the line item descriptions in the LRA: flexible hoses, chamber housings, heat-actuated devices, tank heaters, and water motor alarms. The staff recognizes the applicants interpretation of these components as active or short-lived components will result in more vigorous oversight of the condition and performance of the components. Because the applicant has interpreted that these components are active, the staff concludes that the components were correctly excluded from the scope of license renewal and are not subject to an AMR. Therefore, the staffs concern described in RAI 2.3.3.8-10 is resolved. In RAI 2.3.3.8-11, dated August 15, 2006, the staff stated that LRA Table 2.3.3-8 listed flow nozzles (flow control) as in-scope and subject to an AMR, but does not list spray nozzles (water). The staff requested applicant to explain why the water spray nozzles are not subject to an AMR. In its response, by letter dated September 20, 2006, the applicant stated: Water spray nozzles are in-scope and subject to an AMR. They are included in the line item Flow nozzles in LRA Table 2.3.3-8. Based on its review, the staff finds the applicant's response to RAI 2.3.3.8-11 acceptable because it adequately explains that the spray nozzles in question are within the scope of license renewal and subject to an AMR. Further, the applicant stated that the spray nozzles are represented in the LRA Table by the component type "Flow nozzles in LRA Table 2.3.3-8." Therefore, the staffs concern described in RAI 2.3.3.8-11 is resolved. 2.3.3.8.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the fire protection-water system 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). 2-90

2.3.3.9 Fire Protection-Carbon Dioxide 2.3.3.9.1 Summary of Technical Information in the Application LRA Section 2.3.3.9 describes the fire protection-CO2 system. The purpose of the fire protection system is to provide fire protection for the station through the use of water, CO2, dry chemicals, foam, detection and alarm systems, and rated fire barriers, doors, and dampers. The cable vault and switchgear rooms are protected by fully automatic total flooding CO2 suppression systems initiated by ionization detectors. Bottles located in the west switchgear room also may provide a backup or second shot to the cable vault if desired. The diesel fire pump FO storage tank room is protected by a total flooding CO2 suppression system initiated by heat detectors. The automatic total flooding high-pressure CO2 gas suppression systems for the cable vault and diesel fire pump FO storage tank room store high-pressure CO2 at ambient temperatures in steel CO2 tanks. Empty fixed piping systems convey CO2 from the tanks to open nozzles in the fire area. The cable vault CO2 system (automatic total flooding system with CO2 tanks in the cable vault) is cross-connected to the CO2 tanks in the west switchgear room for back-up capability for cable vault fire protection. The east and west switchgear rooms are protected by automatic total flooding low-pressure CO2 systems. Low-pressure CO2 is stored at approximately 0 EF in an outside storage tank. Empty fixed piping systems convey CO2 from the storage tank to open nozzles in the fire area. The fire protection-CO2 system performs functions that support fire protection. LRA Table 2.3.3-9 identifies the following fire protection-CO2 system component types within the scope of license renewal and subject to an AMR:

• bolting
• coil
• filter housing
• heater housing
• nozzle
• orifice
• piping
• pump casing
• siren body
• strainer
• tank
• tubing
• valve body In LRA Table 3.3.2-9, the applicant provides the results of the AMR.

The fire protection-CO2 system component intended functions within the scope of license renewal include the following:

• flow control
• filtration
• pressure boundary 2-91

2.3.3.9.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.9 and UFSAR Section 10.11 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). The staff also reviewed the approved fire protection SER, dated January 13, 1978, approving the VYNPS fire protection program and supplemental SERs listed in the VYNPS Operating License Condition g.3.F. This report is referenced directly in the VYNPS fire protection CLB and summarizes the fire protection program and commitments to requirements of 10 CFR 50.48 using BTP APCSB 9.5-1, ?Guidelines for Fire Protection for Nuclear Power Plants, May 1, 1976, and Appendix A to BTP APCSB 9.5-1, August 23, 1976. The staff then reviewed those components that the applicant identified as being within the scope of license renewal to verify that the applicant did not omit any passive and long-lived components that should be subject to an AMR as required by 10 CFR 54.21(a)(1). The staffs review of LRA Section 2.3.3.9 identified areas requiring additional information necessary to complete the review of the applicants scoping and screening results. The applicant responded to the staffs RAIs as discussed below. In RAI 2.3.3.9-1, dated August 15, 2006, the staff stated that SE Sections 3.1.5 and 4.3.2 discuss a total flooding CO2 system for the cable spreading area, battery room, and diesel driven fire water pump tank room. The LRA does not list the CO2 system for the cable spreading area, battery room, and diesel driven fire water pump tank room. The staff requested that the applicant verify whether the CO2 system and its components are in-scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal and not subject an AMR, the staff requested applicant to provide justification for the exclusion. In its response, by letter dated September 20, 2006, the applicant stated: As described in LRA Section 2.3.3.9, the cable vault and switchgear rooms are protected by fully automatic total flooding CO2 suppression systems initiated by ionization detectors. Bottles located in the west switchgear room may also provide a backup or second shot to the cable vault if desired. The diesel fire pump FO storage tank room is protected by a total flooding CO2 suppression system initiated by heat detectors. As further described in LRA Section 2.3.3.9, the fire protection-CO2 system is within the scope of license renewal and has the following intended function as required by 10 CFR 54.4(a)(3). 2-92

• Provide the capability to extinguish fires in vital areas of the plant (10 CFR 50.48).

The cable vault is the area referred to in the SE as the cable spreading area and battery room. Therefore, the CO2 systems for the cable spreading area, battery room, and diesel driven fire water pump tank room are in-scope and subject to an AMR. Based on its review, the staff found the applicant's response to RAI 2.3.3.9-1 acceptable because the total flooding CO2 systems for the cable spreading area, battery room, and diesel driven fire water pump tank room were identified to be in the scope of license renewal and subject to an AMR. Further, the applicant clarified that the cable vault is the area referred to in the SE as the cable spreading area and battery room. Therefore, the staff concludes that the total flooding CO2 systems for the cable spreading area, battery room, and diesel driven fire water pump tank room and the associated components are correctly included in the scope of license renewal and subject to an AMR. The staffs concern described in RAI 2.3.3.9-1 is resolved. In RAI 2.3.3.9-2, dated August 15, 2006, the staff stated that LRA Table 2.3.3-9 excludes several types of CO2 fire suppression system components that appear in the SE and its supplements and/or UFSAR, and which also appear in the LRA drawings colored in purple. These components are listed below.

• strainer housings
• pipe fittings
• pipe supports
• couplings
• odorizer
• threaded connections
• flexible hose
• latch door pull box
• pneumatic actuators
• CO2 bottles (CO2 storage cylinders)

For each, determine whether the component should be included in Table 2.3.3.9, and if not, the staff requested applicant justify the exclusion. In its response, by letter dated September 20, 2006, the applicant stated:

• strainer housings - The CO2 fire protection storage tank (TK-115-1) recirculation heater pump suction strainer (S-76-3) shown on LRA drawing LRA-G-191163-SH-03-0 has both filtration and pressure boundary functions. The strainer and its housing are both included in the Strainer line item in LRA Table 2.3.3-9.
• pipe fittings - As stated in LRA Section 2.0, the term piping in component lists may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Pipe fittings are 2-93

included in the Piping line item in LRA Table 2.3.3-9.

• pipe supports - Since they support criterion (a)(3) equipment, piping supports are included in the structural AMR. They are included in the Component and piping supports line item in LRA Table 2.4-6.
• couplings - As stated in LRA Section 2.0, the term piping in component lists may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Couplings are pipe fittings included in the Piping line item in LRA Table 2.3.3-9.
• odorizer - Odorizer cylinders (OC-700, 701, 702, and 703) on switchgear room discharge lines are shown on LRA drawing LRA-G-191163-SH-03-0. The odorizer cylinders are included in the Tank line item in LRA Table 2.3.3-9.
• threaded connections - As stated in LRA Section 2.0, the term piping in component lists may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Threaded connections are pipe fittings included in the Piping line item in LRA Table 2.3.3-9.
• flexible hose - Hoses are replaced on a specified schedule and therefore, are not subject to an AMR as required by 10 CFR 54.21(a)(1)(ii).
• latch door pull box - This response assumes the reviewer means emergency manual release stations to initiate CO2 flow. Manual release stations are active components; not subject to an AMR.
• pneumatic actuators - Pneumatic actuators (discharge delay timers) on deluge valves for the switchgear rooms are shown on LRA drawing LRA-G-191163-SH-03-0. Since the actuator subcomponents have a pressure boundary function, they are included in the line items for Tank, Valve body, and Tubing in Table 2.3.3-9.
• CO2 bottles (CO2 storage cylinders) - The CO2 bottles, or storage cylinders, are included in the line item Tank in Table 2.3.3-9.

Based on its review, the staff found the applicant's response to RAI 2.3.3.9-2 acceptable. Although the applicant states that they consider these components to be included in other line items, the LRA descriptions of the line items do not specifically list all these components. The applicant identified the following components to be included in other line items in the scope of license renewal and subject to an AMR: strainer housings, pipe fittings, pipe supports, couplings, odorizer, threaded connections, pneumatic actuators, and CO2 bottles. The staff is assured that the listed components will be considered appropriately during plant aging management activities. The staff found that the following components were not included in the line item descriptions in the LRA: flexible hoses and latch door pull box (emergency manual release stations to initiate CO2 flow). The staff recognizes the applicants interpretation of these components as active or short-lived components, which will result in more vigorous oversight of 2-94

the condition and performance of the components. Because the applicant has interpreted these components are active, the staff concludes that the components were correctly excluded from the scope of license renewal and are not subject to an AMR. Therefore, the staffs concern described in RAI 2.3.3.9-2 is resolved. In RAI 2.3.3.9-3, dated August 15, 2006, the staff stated that LRA Table 2.3.3-9 listed nozzles with an intended function of flow control as in-scope and subject to an AMR. Nozzles with intended functions of total flood, vent, and S nozzles are not listed. The staff requested that the applicant explain why these nozzles are not subject to an AMR. In its response, by letter dated September 20, 2006, the applicant stated: The total flood nozzles in the CO2 system are subject to an AMR, as indicated on drawings LRA-G-191163-SH-03-0 and LRA-G-191163-SH-04-0. They are included in the Nozzle line item in Table 2.3.3-9. As shown on the LRA drawings the CO2 system does not have vent or S nozzles. Based on its review, the staff finds the applicant's response to RAI 2.3.3.9-3 acceptable because it adequately explains that the flood nozzles in question are within the scope of license renewal and subject to an AMR. Further, the applicant stated that the flood nozzles are represented in the LRA Table 2.3.3-9 by the component type "Nozzles, and the CO2 system does not have vent or S nozzles. Therefore, the staffs concern described in RAI 2.3.3.9-3 is resolved. 2.3.3.9.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of License renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the fire protection-CO2 system 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). 2.3.3.10 Heating, Ventilation, and Air Conditioning 2.3.3.10.1 Summary of Technical Information in the Application LRA Section 2.3.3.10 describes the heating, ventilation, and air conditioning (HVAC) and the house HB systems. The purpose of the HVAC system is to maintain the general area environment for personnel and equipment. It consists of several ventilation systems serving ten different areas of the plant: (1) primary containment ventilation normally operates to maintain drywell ambient temperature within acceptable ranges, (2) reactor building ventilation provides filtration and controls temperature, humidity, and migration of air from clean areas to areas of higher contamination, including exhaust to the plant stack. It also purges the drywell, (3) turbine building ventilation provides filtration and controls temperature, humidity, and migration of air from clean areas to areas of higher contamination. It exhausts building air to the plant stack (normal intake and exhaust function) in a monitored release path, (4) DG room ventilation supports operation of the EDGs, (5) control building ventilation maintains the environment in the 2-95

main control room, (6) service building ventilation provides filtration, controls temperature and humidity, and exhausts potential contaminants to the plant stack. It maintains the hydrogen concentration well below 2 percent by volume in the HVAC equipment room (hydrogen is potentially generated from the AS-1 batteries), (7) radwaste building ventilation provides filtration (including filtration of exhaust sent to the plant stack) and controls temperature, humidity, and migration of air from clean areas to areas of higher contamination, (8) augmented off-gas building ventilation provides filtration (including filtration of exhaust sent to the plant stack) and temperature and humidity control, (9) intake structure ventilation maintains an environment suitable for operating personnel and equipment, including the diesel-driven fire pump, and (10) JDD building ventilation cools the JDD, which provides emergency lighting credited in the Appendix R safe shutdown capability assessment. The purpose of the HB system is to provide a source of steam for space heating and process requirements during all phases of station operation and heats the control room during normal operation. The system has two 50-percent boilers, various heaters, steam traps, valves, and piping. The HVAC and HB systems have safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related systems SSCs potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the systems perform functions that support fire protection. LRA Tables 2.3.3-10, 2.3.3-13-18, and 2.3.3-13-21 identify the following HVAC and HB system component types within the scope of license renewal and subject to an AMR:

• bolting
• compressor housing
• damper housing
• duct
• duct flexible connection
• expansion joint
• fan housing
• filter housing
• heat exchanger (fins)
• heat exchanger (housing)
• heat exchanger (shell)
• heater housing
• humidifier housing
• louver housing
• piping
• pump casing
• sight glass
• steam trap
• strainer
• strainer housing
• tank
• tubing
• valve body 2-96

The HVAC and HB system component intended functions within the scope of license renewal include the following:

• filtration
• heat transfer
• pressure boundary 2.3.3.10.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.10 and UFSAR Sections 5.2.3.7, 5.3.5, 10.7.6, and 10.12 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.10.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the HVAC and HB system 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). 2.3.3.11 Primary Containment Atmosphere Control / Containment Atmosphere Dilution 2.3.3.11.1 Summary of Technical Information in the Application LRA Section 2.3.3.11 describes the PCAC system, the containment atmosphere dilution (CAD) system, and the post-accident sampling system (PASS). The purpose of the PCAC system is to ensure that the containment atmosphere is inerted with N2 during station power operation. The PCAC system establishes and maintains the required differential pressure between the drywell and torus. System instrumentation monitors key drywell and torus parameters, including temperature, pressure, moisture, drywell to torus differential pressure, and torus water level. The CAD system limits the concentration of oxygen in the primary containment so ignition of hydrogen and oxygen from a metal-water reaction following a LOCA will not occur. The PASS is included in this evaluation. The purpose of PASS is to provide representative samples of reactor coolant indicative of the extent and development of core damage. The PCAC system, CAD system, and PASS have 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. 2-97

LRA Tables 2.3.3-11, 2.3.3-13-3, 2.3.3-13-27, and 2.3.3-13-28 identify the following PCAC system, CAD system, and PASS component types within the scope of license renewal and subject to an AMR:

• bolting
• diaphragm
• dryer
• duct
• filter housing
• heat exchanger
• orifice
• piping
• pump casing
• tank
• trap
• tubing
• valve body The component intended functions within the scope of license renewal include the following:
• flow control
• heat transfer
• pressure boundary 2.3.3.11.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.11 and UFSAR Sections 5.2.3.6, 5.2.6, 5.2.7, and 10.20 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). The staffs review of LRA Section 2.3.3.11 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staffs RAIs as discussed below. In RAI 2.3.3.11-1 dated August 16, 2006, the staff stated that license renewal drawing LRA-VY-E-75-002-0, at location K-13, penetration X209D to the H2O2 analyzers, shows a section of pipe to be within the scope of license renewal. However, this same section of pipe on drawing LRA-G-191165-0, at location E-16 from penetration X209D through the continuation to drawing LRA-VY-E-75-002-0, is not shown to be within the scope of license renewal. The staff requested that the applicant confirm that this section of pipe is within the scope of license renewal, or if not, justify its exclusion. 2-98

In its response dated September 20, 2006, the applicant stated that the section of pipe shown on license renewal drawing LRA-VY-E-75-002-0, at location K-13 at penetration X209D to the H2O2 analyzers and on drawing LRA-G-191165-0, at location E-16 from penetration X209D through the continuation to drawing LRA-VY-E-75-002-0 is within the scope of license renewal and subject to an AMR. Dashed lines (or phantom lines) on the drawings indicate that the actual line is shown on its primary system drawing. Phantom lines are not highlighted on the license renewal drawings. Based on its review, the staff found the applicants response to RAI 2.3.3.11-1 acceptable because the applicant confirmed that containment atmosphere dilution system piping 1"-VG-122-D1 connecting the H2O2 analyzers to the torus through penetration X-209D is within the scope of license renewal and subject to an AMR. Therefore, the staff concern described in RAI 2.3.3.11-1 is resolved. In RAI 2.3.3.11-2 dated August 16, 2006, the staff stated that license renewal drawing LRA-VY-E-75-002-0, at location J-9 shows a pipe section, including valve NG-16 to pipe section 20-AC-13, within the scope of license renewal. However, this same section of pipe on drawing LRA-G-191175-SH-01-0, at location K-10 is not shown within the scope of license renewal. The staff requested that the applicant confirm that this section of pipe is within the scope of license renewal, or if not, to justify its exclusion. In its response dated September 20, 2006, the applicant stated that the section of pipe shown on license renewal drawing LRA-VY-E-75-002-0, at location J-9, including valve NG-16 to pipe section 20-AC-13 and on drawing LRA-G-191175-SH-01-0, at location K-10 is within the scope of license renewal and subject to an AMR. Dashed lines (or phantom lines) on the drawings indicate that the actual line is shown on its primary system drawing. Phantom lines are not highlighted on the license renewal drawings. Based on its review, the staff found the applicant response to RAI 2.3.3.11-2 acceptable because the applicant confirmed that containment atmosphere dilution system piping from primary containment and atmosphere control system piping 20"- AC-13 to valve NG-16 (1" NG-101A-EIN2) is within the scope of license renewal and subject to an AMR. Therefore, the staff concern described in RAI 2.3.3.11-2 is resolved. In RAI 2.3.3.11-3 dated August 16, 2006, the staff stated that license renewal drawing LRA-VY-E-75-002-0, at location G-7 provides a continuation from valve VG-77 to drawing LRA-G-191165-0 (at location B-17) that is within the scope of license renewal. However, the license renewal boundary could not be located on drawing LRA-G-191165-0 (at location B-17). The staff requested that the applicant provide additional information for the continuation of this pipe section to the license renewal boundary and justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a). In its response dated September 20, 2006, the applicant stated that license renewal drawing LRA-VY-E-75-002-0, at location G-17 provides a continuation from valve VG-77 to drawing LRA-G-191165-0 that is within the scope of license renewal. The drawing references location B-17 on drawing LRA-G-191165-0. The hydrogen/oxygen analyzers are shown at location H-14 on drawing LRA-G-191165-0. Therefore, the appropriate reference location for the continuation on drawing LRA-G-191165-0 is H-14. An engineering request was submitted to correct the 2-99

discrepancy on license renewal drawing LRA-VY-E-75-002-0. The piping to VG-77 is connected to 3/4 pipe VG-109-TI prior to valve VG-20. As shown on the drawings, all of the piping and components from the primary containment air space to the analyzers and from the analyzers to the torus are within the scope of license renewal and subject to an AMR. Based on its review, the staff found the applicant response to RAI 2.3.3.11-3 acceptable because the applicant provided appropriate documentation to demonstrate that piping upstream of valve VG-77 was connected to primary containment sample system line 3/4" VG-109-T1, piping and components were correctly identified within the scope of license renewal, and license renewal boundaries were appropriately identified on the sampling system flow diagram, LRA-G-191165-0. Therefore, the staff concern described in RAI 2.3.3.11-3 is resolved. In RAI 2.3.3.11-4 dated August 16, 2006, the staff stated that license renewal drawing LRA-VY-E-75-002-0, at location J-18 shows a pipe section downstream of valve VG30A within the scope of license renewal. A drawing continuation to the license renewal boundary was not provided. The staff requested that the applicant provide additional information for the continuation of this pipe section to the license renewal boundary and justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a). In its response dated September 20, 2006, the applicant stated that license renewal drawing LRA-VY-E-75-002-0 shows hydrogen/oxygen analyzer panel SII within a dotted rectangular box at locations H-17 through J-18. Above the box, at location G-18, VG-29A is shown going to hydrogen/oxygen analyzer panel SI, which is not shown but is the same as the SII panel. Valve VG-30A, below the box at location J-18, is coming back from the SI panel. As shown on the drawing, all of the piping and components from the analyzer panels to the torus are within the scope of license renewal and subject to an AMR. Based on its review, the staff found the applicant response to RAI 2.3.3.11-4 acceptable because the applicant adequately identified the piping and components in the H2O2 analyzer SAH-VG-5A SI panel which are within the scope of license renewal and subject to an AMR. These components were identified as those corresponding to components identified in panel SII on drawing LRA-VY-E-75-002-0. Therefore, the staff concern described in RAI 2.3.3.11-4 is resolved. In RAI 2.3.3.11-5 dated August 16, 2006, the staff stated that license renewal drawing LRA-VY-191165-0, at location I-15 provides a continuation of a pipe section from the H202 analyzers to drawing LRA-VY-E-75-002-0 that is within the scope of license renewal. However, the license renewal boundary could not be located on drawing LRA-VY-E-75-002-0. The staff requested that the applicant provide additional information for the continuation of this pipe section to the license renewal boundary and justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a). In its response dated September 20, 2006, the applicant stated that an engineering request was submitted to correct the license renewal drawing discrepancies. Also, as shown on the drawings, all of the piping and components from the primary containment air space to the analyzers and from the analyzers to the torus are within the scope of license renewal and subject to an AMR. 2-100

Based on its review, the staff found the applicant response to RAI 2.3.3.11-5 acceptable because the applicant confirmed that sample system piping located on drawing LRA-G-191165-0, at location I-15 and H-14, is continued on drawing LRA-VY-E-75-002-0. Additionally, the applicant demonstrated these components and all of the piping and components from the primary containment air space to the analyzers and from the analyzers to the torus are within the scope of license renewal and subject to an AMR. Therefore, the staff concern described in RAI 2.3.3.11-5 is resolved. In RAI 2.3.3.11-6 dated August 16, 2006, the staff stated that license renewal drawing LRA-VY-191165-0, at location C-12 provides continuations to drawing LRA-G-191267 (at locations H-12 and H-5) for two pipe lines from the post-accident sampling panel that are within the scope of license renewal. The license renewal boundary could not be located on LRA-G-191267-SH-01-0. The staff requested that the applicant provide additional information for the continuation of these pipe sections to the license renewal boundary and justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a). In its response dated September 20, 2006, the applicant confirmed that the two pipe lines from the post-accident sampling panel shown on license renewal drawing LRA-VY-191165-0, at location C-12 are continued on drawing LRA-G-191267-SH-01-0 (at location H-12 and H-5). The lines are depicted as TYPICAL FOR FT63A and TYPICAL FOR FT63C with reference to FT63B and FT63D piping which are identified within dashed rectangles on drawing LRA-G-191267-SH-01-0 at the specified locations. The table on drawing LRA-G-191267-SH-02-0, at location A-16, notes the instrument root valves associated with each jet pump. Drawing LRA-G-191267-SH-01-0 identifies the piping and components from the jet pump to the instruments as being within the scope of license renewal and subject to an AMR as part of the RCS pressure boundary described in LRA Section 2.3.1.3. Drawing LRA-G-191165-0 shows piping continuing from jet pump instrument root valve V-20B (typical) to PASS valve 102 and 101 and from root valve V-20D (typical) to PASS valve 104 and 103. The applicant confirmed that components in the sample line are within the scope of license renewal and subject to an AMR as part of the post-accident sampling system as described in LRA Section 2.3.3.11. Therefore, in accordance with 10 CFR 54.4(a)(1), the entire reactor coolant pressure boundary out to the second isolation valve on the PASS sample lines is within the scope of license renewal and subject to an AMR. Based on its review, the staff found the applicant response to RAI 2.3.3.11-6 acceptable because the applicant submitted appropriate documentation acknowledging that all piping and components associated with primary containment atmosphere control and containment atmosphere dilution are within the scope of license renewal and subject to an AMR including all the reactor coolant pressure boundary up to and including the second post-accident sampling system (PASS) isolation valves. Therefore, the staff concern described in RAI 2.3.3.11-6 is resolved. 2-101

2.3.3.11.3 Conclusion The staff reviewed the LRA accompanying license renewal drawings, and RAI responses to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the PCAC system, CAD system, and PASS 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). 2.3.3.12 John Deere Diesel 2.3.3.12.1 Summary of Technical Information in the Application LRA Section 2.3.3.12 describes the JDD as a nonsafety-related skid-mounted engine powering a generator that supplies back-up electric power to plant lighting. It is located in a separate structure, the JDD building. The diesel is started electrically with batteries and does not require cooling water from other plant systems. Its license renewal purpose is to provide power to lighting panels credited as emergency lighting in the Appendix R safe shutdown capability analysis. The JDD performs functions that support fire protection. LRA Table 2.3.3-12 identifies the following JDD component types within the scope of license renewal and subject to an AMR:

• bolting
• expansion joint
• filter housing
• heat exchanger (radiator)
• heat exchanger (shell)
• heat exchanger (tubes)
• heater housing
• piping
• pump casing
• silencer
• tubing
• turbocharger The JDD component intended functions within the scope of license renewal include the following:
• heat transfer
• pressure boundary 2.3.3.12.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.12 using the Tier-2 evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

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In conducting its review, the staff evaluated the system functions described in the LRA to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). The staffs review of LRA Section 2.3.3.12 identified areas in which information provided in the LRA needed to be confirmed by the NRC Regional Inspection Team to complete the review of the applicant's scoping and screening results. Inspection Item 2.3.3.12-1 LRA Section 2.3.3.12 indicts that the John Deere Diesel is installed in compliance with 10 CFR 50, Appendix R, requirements. However, due to a lack of available drawings and/or detailed description of the diesel equipment listed in LRA Table 2.3.3-12, it is difficult to determine if any AMR category components may have been omitted from the table. It is recommended that the JDD be inspected to assure all AMR category components are included in the list of LRA Table 2.3.3-12. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components satisfy the requirements of 10 CFR 54.4(a) (3). In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team stated that the John Deere diesel system components are listed in LRA Table 2.3.3-12 and the supporting fuel oil day tank, fiberglass underground storage tank, and supply lines are listed in LRA Table 2.3.3-6, "Fuel Oil System." Based on its review, the staff found the above response acceptable because the NRC Regional Inspection Team verified that all components subject to an AMR are included in LRA Table 2.3.3-12 and LRA Table 2.3.3-6 and confirmed that no other portions of the John Deere diesel system should have been included within scope based on 10 CFR 54.4(a)(3). Therefore, the staff concern described in Inspection Item 2.3.3.12-1 is resolved. 2.3.3.12.3 Conclusion The staff reviewed the LRA and Inspection Item response to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the JDD 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). 2-103

2.3.3.13 Miscellaneous Systems In-scope as required by 10 CFR 54.4(a)(2) 2.3.3.13.1 Summary of Technical Information in the Application LRA Section 2.3.3.13 describes the miscellaneous systems within the scope of license renewal requirements of 10 CFR 54.4(a)(2). Such systems interact with safety-related systems in one of two ways: (1) a functional failure where the failure of a nonsafety-related SSC to perform its function impacts a safety function or (2) a physical failure where a safety function is impacted by the loss of structural or mechanical integrity of an SSC in physical proximity to a safety-related component. LRA Section 2.3.3.13.1 states that functional failures of nonsafety-related SSCs which could impact a safety function were identified only for systems with components supporting the main condenser and MSIV leakage pathway. Two of these systems are the augmented off-gas (AOG) and sampling systems, which are not described elsewhere in the LRA. Descriptions of these systems follow. 2.3.3.13A Augmented Off-gas 2.3.3.13A.1 Summary of Technical Information in the Application The AOG system collects, processes, and discharges radioactive gaseous wastes to the atmosphere through the plant stack during normal operation. The system reduces the released quantities of gaseous and particulate radioactive material from the site to levels as low as practical during normal operation. The AOG system has subsystems that dispose of gases from the main condenser air ejectors, the start-up vacuum pump, and the gland seal condenser. The various subsystems are monitored continuously for radiation. The failure of nonsafety-related SSCs in the AOG system could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3.13-1 identifies the following AOG system component types within the scope of license renewal and subject to an AMR:

• bolting
• filter housing
• piping
• stream trap
• tank
• tubing
• valve body The AOG system component intended function within the scope of license renewal is to provide a pressure boundary.

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2.3.3.13A.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.1 and UFSAR Section 9.4 using the Tier-2 evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). The staffs review of LRA Section 2.3.3.13.1 identified areas in which information provided in the LRA needed to be confirmed by the NRC Regional Inspection Team to complete the review of the applicant's scoping and screening results. Inspection Item 2.3.3.13a-1 The LRA states that the AOG system is within the scope of license renewal based on requirements of 10 CFR 54.4(a)(2) because of the potential for physical interaction with safety-related components described in LRA Table 2.3.3.13-A. The determination of whether a component meets the requirements of 10 CFR 54.4(a)(2) for physical interactions is based on where it is located in a building and its proximity to safety-related equipment or where a structural/seismic boundary exists. This information is not provided on license renewal drawings nor was a detailed description provided in the LRA. Consequently, any omission of AOG components subject to an AMR cannot be determined. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components meet the requirements of 10 CFR 54.4(a)(2) and all the components subject to an AMR are included in LRA Table 2.3.3-13-1. In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team noted LRA Table 2.3.3.13-B states that the portion of the AOG system associated with the plant stack loop seal is subject to an AMR based on 10 CFR 54.4(a)(2) for physical interactions. Since the boundaries for the portion of the system as described in LRA Table 2.3.3.13-B were not well defined, in its letter dated July 30, 2007, the applicant amended the table to read "portion of the system inside the plant stack." The inspector walked down the remainder of the system and confirmed that no other portions of the system should have been included based on 10 CFR 54.4(a)(2). Based on its review, the staff found the above response acceptable because the applicant amended LRA Table 2.3.3.13-B as appropriate and the NRC regional inspector walked down the remainder of the AOG system outside the plant stack and confirmed that no other portions of the system should have been included within scope based on 10 CFR 54.4(a)(2). Therefore, the staff concern described in Inspection Item 2.3.3.13a-1 is resolved. 2-105

2.3.3.13A.3 Conclusion The staff reviewed the LRA, accompanying license renewal drawings, and inspection item response to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the AOG system 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). 2.3.3.13B Sampling 2.3.3.13B.1 Summary of Technical Information in the Application The sampling system provides means for sampling and testing various process fluids in the station in centralized locations. Fluids and gases are sampled continuously or periodically from equipment or systems reflecting station performance. The failure of nonsafety-related SSCs in the sampling system could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3.13-41 identifies the following sampling system component types within the scope of license renewal and subject to an AMR:

• bolting
• piping
• stainer housing
• tubing
• valve body The sampling system component intended function within the scope of license renewal is to provide a pressure boundary.

2.3.3.13B.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.1 and UFSAR Section 10.17 using the Tier-2 evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3. The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2-106

2.3.3.13B.3 Conclusion The staff reviewed the LRA and accompanying license renewal drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the sampling system 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). Besides the augmented off-gas and sampling systems, other systems with components supporting the main condenser and MSIV leakage pathway where functional failures of nonsafety-related SSCs could impact a safety function are addressed in LRA Section 2.3.4. LRA Table 2.3.3.13-A shows systems within the scope of license renewal with potential for physical interactions with safety-related components based on the criterion of 10 CFR 54.4(a)(2). Of these systems, the applicant stated that the following are not described elsewhere in the LRA:

• circulating water
• condensate demineralizer
• demineralized water
• equipment retired in place
• feedwater
• MG lube oil
• neutron monitoring
• potable water
• radwaste, liquid and solid
• reactor water clean-up
• RWCU filter demineralizer
• stator cooling A description of each system above follows.

2.3.3.13C Condensate Demineralizer 2.3.3.13C.1 Summary of Technical Information in the Application The condensate demineralizer (CD) system maintains the required purity of feedwater supplied to the reactor. The system minimizes corrosion product in the nuclear system so it does not affect fuel performance, nuclear system component accessibility, or the capacity required of the RWCU system. The CD system protects the nuclear system against the entry of foreign material due to condenser leaks. The system uses finely ground, mixed ion-exchange resins deposited upon the tubular elements of pressure precoat type filters (the filter-demineralizer units). The CD consist of five filter-demineralizer units (including an installed spare) operating in parallel. All are normally operated but sized so four units can support operation. The failure of nonsafety-related SSCs in the CD system potentially could prevent the satisfactory accomplishment of a safety-related function. 2-107

LRA Table 2.3.3-13-4 identifies the following CD system component types within the scope of license renewal and subject to an AMR:

• bolting
• filter housing
• piping
• pump casing
• strainer housing
• tank
• tubing
• valve body The CD system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13C.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.7 using the evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13C.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the CD system 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). 2.3.3.13D RWCU Filter Demineralizer 2.3.3.13D.1 Summary of Technical Information in the Application The RWCU filter demineralizer (CUFD) system filters and cleans reactor water. The CUFD is the filter-demineralizer portion of the RWCU system and consists of the filter/demineralizer tanks, piping, and valves. The failure of nonsafety-related SSCs in the CUFD system potentially could prevent the satisfactory accomplishment of a safety-related function. 2-108

LRA Table 2.3.3-13-8 identifies the following CUFD system component types within the scope of license renewal and subject to an AMR:

• bolting
• filter housing
• orifice
• piping
• pump casing
• sight glass
• strainer housing
• tank
• tubing
• valve body The CUFD system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13D.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 4.9 using the Tier-1 evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13D.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the CUFD system 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). 2.3.3.13E Circulating Water 2.3.3.13E.1 Summary of Technical Information in the Application The circulating water (CW) system is a heat sink for steam condensation for the main condensers. Heat removal in the condensers is accomplished by a continuous supply of cooling water pumped from and returned to the Connecticut River or by recirculation flow pumped through cooling towers by three vertical circulating water pumps in the intake structure. Trash 2-109

racks and traveling water screens protect the circulating water pumps from debris. During cold weather, recirculation of water from the discharge structure to the intake structure prevents icing at the screens and intakes. Two cooling towers have the capacity to remove the total heat load from the circulating water. Three vertical circulating water booster pumps provide the necessary head for cooling tower operation and the recirculation mode. The CW system has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the CW system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-9 identifies the following CW system component types within the scope of license renewal and subject to an AMR:

• bolting
• expansion joint
• piping
• pump casing
• tank
• tubing
• valve body The CW system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13E.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2, and UFSAR Sections 10.8, 11.6, and 11.9 using the Tier-2 evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3. In conducting its review, the evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). The staffs review of LRA Section 2.3.3.13 identified areas in which information provided in the LRA needed to be confirmed by the NRC Regional Inspection Team to complete the review of the applicant's scoping and screening results. Inspection Item 2.3.3.13e-1 The LRA states that the circulating water system is within the scope of license renewal based on the potential for physical interaction with safety-related components as required by 10 CFR 54.4(a)(2) and described in LRA Table 2.3.3.13-A. The applicant did not provide drawings highlighting in-scope components required by 10 CFR 54.4(a)(2), stating that the drawings would not provide significant additional information because they do not indicate 2-110

proximity of components to safety-related equipment and do not identify structural/seismic boundaries. Without license renewal drawings and/or detailed description of the circulating water system, the omission of components subject to an AMR cannot be determined (see LRA Table 2.3.3-13-9). The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components satisfy the requirements of 10 CFR 54.4(a)(2) and all the components subject to an AMR are included in LRA Table 2.3.3-13-9. In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team stated that if any nonsafety-related portion of a fluid system is located within a building containing safety-related components, the components within the system are within the license renewal scope. Further, applicant's letter to the NRC dated July 3, 2007, LRA Amendment 27, Attachment 2 states that there are no nonsafety-related systems for which the applicant has not identified the nonsafety-related portions of systems which are attached to safety-related systems and required to be in the scope of license renewal in accordance with 10 CFR 54.4(a)(2). However, as a result of discussions with the staff during the Region I inspection (February 2007), the applicant determined that some safety-related SSCs in the VY turbine building required consideration for potential spatial impacts from nonsafety-related SSCs in accordance with 10 CFR 54.4(a)(2). Therefore, an expanded review for SSCs in the turbine building determined that additional components required an AMR. Those additional component types were added to LRA Table 2.3.3-13-9, as addressed in the applicant's letters to the staff dated July 30, 2007 and August 16, 2007. Based on its review, the staff found the above response acceptable because the applicant stated that if any nonsafety-related portion of a fluid system is located within a building containing safety-related components, the components within the system are within the license renewal scope in accordance with 10 CFR 54.4(a)(2) but that there were spatial impact concerns from nonsafety-related SSCs in the turbine building. The additional component types have been added to LRA Table 2.3.3-13-9. Therefore, the staff concern regarding components of the CW system described in Inspection Item 2.3.3.13e-1 is resolved. 2.3.3.13E.3 Conclusion The staff reviewed the LRA and the inspection item response to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the CW system 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). 2.3.3.13F Demineralized Water 2.3.3.13F.1 Summary of Technical Information in the Application The demineralized water (DW) system provides treated makeup water for such plant components as the condensate storage tank, spent fuel pool, RBCCW, and turbine building 2-111

closed cooling water systems. This supply function is not a safety function. The DW system consists of the demineralized water transfer system including the demineralized water storage tank, demineralized water transfer pumps, piping, and valves, but not including the condensate storage tank or CST system components. The failure of nonsafety-related SSCs in the DW system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-12 identifies the following DW system component types within the scope of license renewal and subject to an AMR:

• bolting
• orifice
• piping
• pump casing
• tank
• tubing
• valve body The DW system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13F.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 10.13.3 using the Tier-2 evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3. The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13F.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the DW system 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). 2-112

2.3.3.13G Feedwater 2.3.3.13G.1 Summary of Technical Information in the Application The feedwater (FW) system provides demineralized water from the condensate system to the reactor vessel at a rate sufficient to maintain adequate reactor vessel water level. The FW system consists of three reactor feedwater pumps, four high-pressure feedwater heaters (two per train), valves, and piping. The failure of nonsafety-related SSCs in the FW system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-13 identifies the following FW system component types within the scope of license renewal and subject to an AMR:

• bolting
• heat exchanger (shell)
• orifice
• piping
• pump casing
• strainer housing
• tubing
• valve body The FW system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13G.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.8 using the Tier-2 evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3. The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13G.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the FW system 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). 2-113

2.3.3.13H MG Lube Oil 2.3.3.13H.1 Summary of Technical Information in the Application The MGLO system lubricates the reactor recirculation pump motor generator set during its operation. The MGLO system has lube oil pumps, heat exchangers, piping, and valves. The failure of nonsafety-related SSCs in the MGLO system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-23 identifies the following MGLO system component types within the scope of license renewal and subject to an AMR:

• bolting
• heat exchanger (shell)
• piping
• pump casing
• tubing
• valve body The MGLO system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13H.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 7.9.4.4.1 using the evaluation methodology described in SER Section 2.3. and guidance described in SRP-LR Section 2.3. In conducting its review, the evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13H.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the MGLO system 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). 2-114

2.3.3.13I Neutron Monitoring 2.3.3.13I.1 Summary of Technical Information in the Application The neutron monitoring (NM) system indicates neutron flux, which can be correlated to thermal power level, for the entire range of flux conditions in the core. The system consists of in-core neutron detectors and out-of-core electronic monitoring equipment. The source-range and intermediate-range monitors indicate flux levels during reactor startup and lower power operation. The local-power range and average-power range monitors assess local and overall flux conditions during power range operation. Rod block monitors prevent rod withdrawal when reactor power should not be increased at the current reactor coolant flow rate. The traversing in-core probe system calibrates individual neutron monitoring sensors. The safety function of the NM system is to detect conditions in the core that threaten the overall integrity of the fuel barrier by excessive power generation and to provide signals to the reactor protection system to limit the release of radioactive material from the fuel barrier. The NM system has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the NM system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-26 identifies the following NM system component types within the scope of license renewal and subject to an AMR:

• piping
• tubing
• valve body The NM system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13I.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2, and UFSAR Sections 1.6.2.2, 1.6.4.1.3, and 7.5 using the evaluation methodology described in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3. The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2-115

2.3.3.13I.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the NM system 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). 2.3.3.13J Potable Water 2.3.3.13J.1 Summary of Technical Information in the Application The potable water (PW) system supplies treated water suitable for drinking and for sanitary purposes to lavatories, service sinks, combination emergency showers and eyewashes, kitchen sinks, bench sinks, showers, and wall hydrants. The failure of nonsafety-related SSCs in the PW system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-29 identifies the following PW system component types within the scope of license renewal and subject to an AMR:

• bolting
• filter housing
• piping
• strainer housing
• tank
• valve body The PW system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13J.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 10.15 using the Tier-1 evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2-116

2.3.3.13J.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the PW system 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). 2.3.3.13K Radwaste, Liquid and Solid 2.3.3.13K.1 Summary of Technical Information in the Application The purpose of the liquid radwaste (RDW) system is to collect potentially radioactive liquid wastes, treats them, and returns the processed radioactive liquid wastes to the station for reuse. The solid RDW system collects and processes radioactive solid wastes for temporary onsite storage and offsite shipment for permanent disposal. The RDW system monitors the drywell floor and equipment drain sump pump-out rate for reactor coolant leak detection. The liquid portion of the RDW system consists of floor and equipment drains for handling tanks, piping, pumps, process equipment, instrumentation, and auxiliaries necessary to collect, process, store, and dispose of potentially radioactive wastes. A small portion of the system connected to the RHR system maintains the RHR system pressure boundary. The RDW system has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the RDW system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-32 identifies the following RDW system component types within the scope of license renewal and subject to an AMR:

• bolting
• orifice
• piping
• pump casing
• strainer housing
• tank
• tubing
• valve body The RDW system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13K.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2, and UFSAR Sections 9.2 and 9.3 using the Tier-2 evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3. 2-117

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13K.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the RDW system 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). 2.3.3.13L Equipment Retired in Place 2.3.3.13L.1 Summary of Technical Information in the Application This system designation in the component database is for obsolete equipment. It has no safety-related components and no system intended functions; however, certain components supporting safety-related components are required to maintain structural integrity. The failure of nonsafety-related SSCs of equipment retired in place (RIP) potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-35 identifies the following component types of equipment RIP within the scope of license renewal and subject to an AMR:

• bolting
• piping
• valve body The equipment RIP component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13L.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 using the Tier-1 evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3. In conducting its review, staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2-118

2.3.3.13L.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the equipment RIP 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). 2.3.3.13M Reactor Water Clean-Up 2.3.3.13M.1 Summary of Technical Information in the Application The RWCU system maintains high reactor water purity to limit chemical and corrosive action and to remove corrosion products to limit impurities available to activate neutron flux. The RWCU system purifies the reactor coolant water by continuously removing a portion of the reactor recirculation flow from the suction side of a recirculation pump, sending the removed flow through filter-demineralizer units to undergo mechanical filtration and ion exchange processes, and returning the processed fluid back to the reactor via the feedwater line. The RWCU system has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the RWCU system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-36 identifies the following RWCU system component types within the scope of license renewal and subject to an AMR:

• bolting
• filter housing
• heat exchanger (shell)
• orifice
• piping
• pump casing
• strainer housing
• tank
• tubing
• valve body The RWCU system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13M.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 4.9 using the Tier-2 evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any 2-119

components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). The staffs review of LRA Section 2.3.3.13.2 identified an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staffs RAI as discussed below. The staff stated that license renewal drawing LRA-G-191178-SH-01-0, at location D-4, shows the common elbow differential flow element upstream piping and high side instrument lines connected to flow transmitters FT-12-1A and FT-12-1 B as not within the scope of license renewal. A failure of the flow element upstream RWCU piping or common high side instrument line could prevent the flow transmitters from detecting a high flow condition and the subsequent auto isolation of the RWCU isolation valves. The UFSAR states that the high flow auto closure of the RWCU isolation valves prevents excessive loss of reactor coolant and reduces the amount of radioactive material released from the nuclear system caused by an RWCU line break. In RAI 2.3.3.13k-1 dated August 16, 2006, the staff requested that the applicant confirm whether the RWCU high flow auto isolation will occur when negative differential pressure is caused by either failure of the flow element upstream piping or the common high side instrument line. If not, explain why the flow element upstream piping and the common high side instrument lines are not shown to be within the scope of license renewal. In its response dated September 20, 2006, the applicant stated that the flow element upstream piping and the common high side instrument lines are within the scope of license renewal based on the requirements of 10 CFR 54.4(a)(2) and thus are not shown as highlighted on the drawing. As stated in LRA Table 2.3.3.1B, "Description of Nonsafety-Related System Components Subject to Aging Management Review Based on 10 CFR 54.4(a)(2) for Physical Interactions," the nonsafety-related portion of the RWCU system located inside the reactor building is within the scope of license renewal and subject to an AMR. The common elbow differential flow element upstream piping and high side instrument lines connected to flow transmitters FT-12-1A and FT-12-1B are located inside the reactor building and are included in Table 2.3.3-13-36, "Reactor Water Clean-Up (RWCU) System Nonsafety-Related Systems and Components Affecting Safety-Related Systems Components Subject to Aging Management Review." They are listed as component types of piping, tubing and valve body. As discussed in LRA Section 2.1.2.1.3, "Mechanical System Drawings," in-scope components required by 10 CFR 54.4(a)(2) are not highlighted on the drawings. Based on its review, the staff found the applicant response to RAI 2.3.3.13k-1 acceptable because the applicant acknowledged that the flow element upstream piping and the common high side instrument lines connected to flow transmitters FT-12-1A and FT-12-1B are within the scope of license renewal and subject to an AMR based on the potential for physical interaction with safety-related systems in accordance with 10 CFR 54.4(a)(2). Therefore, the staff concern described in RAI 2.3.3.13k-1 is resolved. The staffs review of LRA Section 2.3.3.13.2 identified areas in which information provided in the LRA needed to be confirmed by the NRC Regional Inspection Team to complete the review of the applicant's scoping and screening results. 2-120

Inspection Item 2.3.3.13m-1 The LRA states that the RWCU system is within the scope of license renewal in accordance with 10 CFR 54.4(a)(2) because of the potential for physical interaction with safety-related components as described in LRA Table 2.3.3.13-A. The determination of whether a component meets the requirements of 10 CFR 54.4(a)(2) for physical interactions is based on where it is located in a building and its proximity to safety-related equipment or where a structural/seismic boundary exists. This information is not provided on license renewal drawings nor was a detailed description provided in the LRA. Consequently, any omission of RWCU components subject to an AMR cannot be determined. The staff requested that the NRC Regional Inspection Team perform an inspection to ensure that the license renewal scope boundaries for these components satisfy the requirements of 10 CFR 54.4(a)(2) and all the components subject to an AMR are included in LRA Table 2.3.3-13-36. In Inspection Report 05000271/2007006, Vermont Yankee Nuclear Power Station - NRC License Renewal Inspection Report, dated June 4, 2007, Attachment, Review of Safety Evaluation Report Confirmatory Items, the NRC Regional Inspection Team stated that if any nonsafety-related portion of a fluid system is located within a building containing safety-related components, the components within the system are within the license renewal scope. Further, the applicant's letter to the NRC dated July 3, 2007, LRA Amendment 27, Attachment 2 states that there are no nonsafety-related systems for which the applicant has not identified the nonsafety-related portions of systems which are attached to safety-related systems and required to be in the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The applicant also stated that there were no additional components that should be within scope based on 10 CFR 54.4(a) as identified during the NRC Regional Inspection and subsequent applicant reviews. Based on its review, the staff found the above response acceptable because the applicant stated that if any nonsafety-related portion of a fluid system is located within a building containing safety-related components, the components within the system are within the license renewal scope in accordance with 10 CFR 54.4(a)(2) and that there were no additional components identified that should be in-scope based on 10 CFR 54.4(a). Therefore, the staff concern regarding the components of the RWCU system described in Inspection Item 2.3.3.13m-1 is resolved. 2.3.3.13M.3 Conclusion The staff reviewed the LRA and RAI and inspection item responses to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the RWCU system 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). 2-121

2.3.3.13N Stator Cooling 2.3.3.13N.1 Summary of Technical Information in the Application The stator cooling system cools the stator winding of the main generator. The system permits generator load changes with minimum variation of stator winding temperature. The stator copper is in direct contact with low-conductivity water of automatically-controlled temperature and pressure; therefore, average copper temperature can be kept essentially constant, practically eliminating thermal stress cycling of the insulation. The failure of nonsafety-related SSCs in the stator cooling system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-39 identifies the following stator cooling system component types within the scope of license renewal and subject to an AMR:

• bolting
• cooler
• filter housing
• heat exchanger (shell)
• piping
• pump casing
• strainer housing
• tank
• tubing
• valve body The stator cooling system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13N.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 8.2.3.11.2 using the Tier-1 evaluation methodology described in SER Section 2.3. and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13N.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant 2-122

has adequately identified the stator cooling system 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). 2.3.3.13O HD & HV Instruments 2.3.3.13O.1 Summary of Technical Information in the Application The heater drain (HD) and the heater vent (HV) instruments system provides indication, alarm and control functions for associated systems (heater drains and heater vents). The failure of nonsafety-related SSCs in the HD & HV instruments system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-43 identifies the following HD & HV instruments system component types within the scope of license renewal and subject to an AMR:

• bolting
• piping
• tubing
• valve body The HD & HV instruments system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13O.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 using the Tier-1 evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13O.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the HD & HV instruments system 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). 2-123

2.3.3.13P Air Evacuation 2.3.3.13P.1 Summary of Technical Information in the Application The air evacuation (AE) system evacuates gases from the main turbine and main condenser during startup and maintains them free of noncondensible gases during operation. The failure of nonsafety-related SSCs in the AE system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-44 identifies the following AE system component types within the scope of license renewal and subject to an AMR:

• bolting
• filter housing
• heat exchanger (shell)
• piping
• pump casing
• rupture disk
• strainer housing
• trap
• tubing
• valve body The AE system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13P.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.4 using the Tier-1 evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13P.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the AE system 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). 2-124

2.3.3.13Q Building (Drainage System Components) 2.3.3.13Q.1 Summary of Technical Information in the Application The building (BLD) system removes operational waste fluids from their points of origin in a controlled manner and delivers them to a suitable disposal system. The BLD system includes floor drains and the site sewers. This system classification also includes buildings and structures which are evaluated in LRA Section 2.4. The failure of nonsafety-related SSCs in the BLD system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-46 identifies the following BLD system component types within the scope of license renewal and subject to an AMR:

• bolting
• piping The BLD component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13Q.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 10.16 using the Tier-1 evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13Q.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the BLD system 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). 2.3.3.13R Circulating Water Priming 2.3.3.13R.1 Summary of Technical Information in the Application The circulating water priming (CWP) system provides air evacuation from the discharge side of the main condenser. The system ensures that air will not hinder circulating water flow by 2-125

collecting in the upper portions of the condenser water boxes or in the upper portion of the circulating water discharge piping. The failure of nonsafety-related SSCs in the CWP system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-47 identifies the following CWP system component types within the scope of license renewal and subject to an AMR:

• bolting
• piping
• pump casing
• tank
• trap
• tubing
• valve body The CWP system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13R.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.63 using the Tier-1 evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13R.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the CWP system 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). 2.3.3.13S Extraction Steam 2.3.3.13S.1 Summary of Technical Information in the Application The extraction steam (ES) system supplies steam to the shell side of various feedwater heaters for condensate and feedwater heating. Extraction steam is piped from the main turbine casing and cross-around piping to the shells of two parallel strings of reactor feedwater heaters. 2-126

The failure of nonsafety-related SSCs in the ES system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-48 identifies the following ES system component types within the scope of license renewal and subject to an AMR:

• bolting
• expansion joint
• orifice
• piping
• tubing
• valve body The ES system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13S.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.5.4.3 using the Tier-1 evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13S.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the ES system 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). 2.3.3.13T Heater Drain 2.3.3.13T.1 Summary of Technical Information in the Application The heater drain (HD) system provides proper level and control for the moisture separator and feedwater heaters by providing drain capability to the main condenser. Condensate drainage from the drain coolers of each feedwater heater flows to the next lower pressure heater by means of pressure differential between successive heaters. Condensate flow may be aided by a heater drain pump between the two lowest pressure heaters in each string. 2-127

The failure of nonsafety-related SSCs in the HD system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-49 identifies the following HD system component types within the scope of license renewal and subject to an AMR:

• bolting
• piping
• pump casing
• tank
• tubing
• valve body The HD system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13T.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.8.3.2 using the Tier-1 evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13T.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the HD system 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). 2.3.3.13U Heater Vent 2.3.3.13U.1 Summary of Technical Information in the Application The heater vent (HV) system provides venting of non-condensable gases back to the main condenser. The failure of nonsafety-related SSCs in the HV system potentially could prevent the satisfactory accomplishment of a safety-related function. 2-128

LRA Table 2.3.3-13-50 identifies the following HV system component types within the scope of license renewal and subject to an AMR:

• bolting
• orifice
• piping
• tank
• tubing
• valve body The HV system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13U.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2, the Tier-1 evaluation methodology described in SER Section 2.3, and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13U.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the HV system 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). 2.3.3.13V Make-up Demineralizer 2.3.3.13V.1 Summary of Technical Information in the Application The make-up demineralizer (MUD) system provides a supply of treated water that may be used as make-up for the station and reactor cycles. The MUD system consists of one train that consists of a cation, anion, and a mixed bed ion exchanger. The failure of nonsafety-related SSCs in the MUD system potentially could prevent the satisfactory accomplishment of a safety-related function. 2-129

LRA Table 2.3.3-13-53 identifies the following MUD system component types within the scope of license renewal and subject to an AMR:

• bolting
• filter housing
• piping
• pump casing
• tank
• tubing
• valve body The MUD system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13V.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 10.13 using the Tier-1 evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13V.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the MUD system 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). 2.3.3.13W Seal Oil 2.3.3.13W.1 Summary of Technical Information in the Application The seal oil (SO) system provides shaft sealing for the main generator. The failure of nonsafety-related SSCs in the SO system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-55 identifies the following SO system component types within the scope of license renewal and subject to an AMR:

• bolting 2-130
• filter housing
• piping
• pump casing
• sight glass
• tank
• tubing
• valve body The SO system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13W.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.23 using the Tier-1 evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13W.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the SO system 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). 2.3.3.13X Turbine Building Closed Cooling Water 2.3.3.13X.1 Summary of Technical Information in the Application The turbine building closed cooling water (TBCCW) system supplies demineralized water to cool various nonsafety-related auxiliary equipment located in the turbine building in support of power generation. The system consists of two pumps, two 100 percent capacity heat exchangers and the necessary controls, piping, and instrumentation. Station service water provides the cooling medium for the TBCCW heat exchangers, however, it is automatically isolated if service water pressure drops to a present value which could occur under a condition of concurrent loss-of-coolant accident and loss of offsite power. No essential equipment is cooled by the TBCCW system. The failure of nonsafety-related SSCs in the TBCCW system potentially could prevent the satisfactory accomplishment of a safety-related function. 2-131

LRA Table 2.3.3-13-56 identifies the following TBCCW system component types within the scope of license renewal and subject to an AMR:

• bolting
• heat exchanger (shell)
• piping
• pump casing
• tank
• tubing
• valve body The TBCCW system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13X.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 10.10 using the Tier-1 evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13X.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the TBCCW system 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). 2.3.3.13Y Main Turbine Generator 2.3.3.13Y.1 Summary of Technical Information in the Application The main turbine generator (TG) system converts the thermodynamic energy of steam into electrical energy for use on the transmission network and the station auxiliary busses. The failure of nonsafety-related SSCs in the TG system potentially could prevent the satisfactory accomplishment of a safety-related function. 2-132

LRA Table 2.3.3-13-57 identifies the following TG system component types within the scope of license renewal and subject to an AMR:

• bolting
• filter housing
• piping
• pump casing
• turbine casing
• tubing
• valve body The TG system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13Y.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.2 using the Tier-1 evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13Y.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the TG system 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). 2.3.3.13Z Turbine Lube Oil 2.3.3.13Z.1 Summary of Technical Information in the Application The turbine lube oil (TLO) system provides lube oil for lubrication of the main turbine. The failure of nonsafety-related SSCs in the TLO system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-58 identifies the following TLO system component types within the scope of license renewal and subject to an AMR:

• bolting
• filter housing 2-133
• heat exchanger (shell)
• piping
• pump casing
• strainer casing
• tank
• tubing
• valve body The TLO system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13Z.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Section 11.2.3 using the Tier-1 evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13Z.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the TLO system 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). 2.3.3.13AA Hydrogen Water Chemistry 2.3.3.13AA.1 Summary of Technical Information in the Application The hydrogen water chemistry (HWC) system mitigates the chemical conditions that allow IGSCC in the recirculation piping and reactor vessels internals. The HWC system injects hydrogen into the reactor feedwater at the suction of the feedwater pumps. The failure of nonsafety-related SSCs in the HWC system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-13-51 identifies the following HWC system component types within the scope of license renewal and subject to an AMR:

• bolting
• piping 2-134
• tubing
• valve body The HWC system component intended function within the scope of license renewal is to provide pressure boundary.

2.3.3.13AA.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13.2 and UFSAR Sections 4.2.5, 11.8.3.1 and K.4.7. using the evaluation methodology described in SER Section 2.3 and the guidance described in SRP-LR Section 2.3. In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.3.13AA.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the HWC system 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 remaining systems shown in LRA Table 2.3.3.13-A as within the scope of license renewal with potential for physical interaction with safety-related components are addressed elsewhere in other LRA sections listed here:

• 2.3.1 CRD
• 2.3.1 HCUs
• 2.3.1 NB
• 2.3.2.1 RHR
• 2.3.2.2 CS
• 2.3.2.4 HPCI
• 2.3.2.5 CST
• 2.3.2.5 RCIC
• 2.3.2.6 SBGT
• 2.3.3.1 SLC
• 2.3.3.2 SW
• 2.3.3.2 RHRSW
• 2.3.3.3 RBCCW
• 2.3.3.4 DG and auxiliaries
• 2.3.3.4 DLO
• 2.3.3.5 FPC
• 2.3.3.5 FPC filter demineralizer 2-135
• 2.3.3.5 SBFPC
• 2.3.3.6 FO
• 2.3.3.7 IA
• 2.3.3.7 N2
• 2.3.3.8 fire protection
• 2.3.3.10 HB
• 2.3.3.10 HVAC
• 2.3.3.11 containment air dilution
• 2.3.3.11 PASS
• 2.3.3.11 PCAC
• 2.3.4.2 condensate 2.3.4 Steam and Power Conversion Systems In LRA Section 2.3.4, the applicant identified the SCs of the steam and power conversion systems that are subject to an AMR for license renewal.

The applicant described the supporting SCs of the steam and power conversion systems in the following LRA Sections:

• 2.3.4.1 auxiliary steam
• 2.3.4.2 condensate
• 2.3.4.3 main steam
• 2.3.4.4 101 (main steam, extraction steam, and auxiliary steam instruments)

The staffs review findings regarding LRA Sections 2.3.4.1 - 2.3.4.4 are presented in SER Sections 2.3.4.1 - 2.3.4.4, respectively. 2.3.4.1 Auxiliary Steam 2.3.4.1.1 Summary of Technical Information in the Application LRA Section 2.3.4.1 describes the auxiliary steam (AS) system, which provides steam from MS piping to the steam jet air ejector to maintain main condenser vacuum. The AS system consists of the steam jet air ejector and associated equipment. The failure of nonsafety-related SSCs in the AS system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Tables 2.3.4-1and 2.3.3-13-45 identify the AS system component types within the scope of license renewal and subject to an AMR:

• bolting
• condenser
• expansion joint
• heat exchanger (shell)
• heat exchanger (tubes)
• piping
• orifice 2-136
• strainer housing
• steam trap
• thermowell
• tubing
• valve body The AS system component intended functions within the scope of license renewal include the following:
• pressure boundary
• holdup and plateout of fission products 2.3.4.1.2 Staff Evaluation The staff reviewed LRA Section 2.3.4.1 and UFSAR Section 11.4 using the Tier-2 evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.4.1.3 Conclusion The staff reviewed the LRA and accompanying license renewal drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the AS system 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). 2.3.4.2 Condensate 2.3.4.2.1 Summary of Technical Information in the Application LRA Section 2.3.4.2 describes the condensate system, which receives condensed steam from the condenser and supplies it to the reactor feedwater system as well as such other components and systems as the air ejector condensers, steam packing exhausters, and CRD pumps. The condensate system consists of a single train with three parallel pumps drawing condensate from the two main condenser hotwells and includes the main condenser. During normal operation, all three pumps provide sufficient condensate flow capacity and net positive suction head to the reactor feedwater pumps during full power operation. Condensate flow to the reactor feed pumps passes through two parallel low-pressure feedwater heater strings, each with three heaters. Condensate flow exiting the low-pressure heaters is provided to a common reactor feed pump suction header. 2-137

The failure of nonsafety-related SSCs in the condensate system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Tables 2.3.4-1 and 2.3.3-13-2 identify the following condensate component types within the scope of license renewal and subject to an AMR:

• bolting
• condenser
• expansion joint
• heat exchanger (shell)
• heat exchanger (tubes)
• orifice
• piping
• pump casing
• steam trap
• strainer housing
• tank
• thermowell
• tubing
• valve body The condensate system component intended functions within the scope of license renewal include the following:
• pressure boundary
• holdup and plateout of fission products 2.3.4.2.2 Staff Evaluation The staff reviewed LRA Sections 2.3.4.2 and 2.3.3.13, and UFSAR Section 11.8 using the Tier-2 evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.4.2.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the condensate system 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). 2-138

2.3.4.3 Main Steam 2.3.4.3.1 Summary of Technical Information in the Application LRA Section 2.3.4.3 describes the MS system, which completes the transmission of steam from the seismic Class I steam piping to the main turbine at a controlled pressure during normal operation. The MS system consists of nonsafety-related components. (The nuclear boiler system contains the seismic Class I portion of the MS system which extends from the reactor vessel to the restraint at the second MS isolation valve. The system consists of the non-seismic Class I components beyond this point.) The MS system includes the turbine stop and control valves. A low-point drain line is downstream of each turbine control valve continuously draining the steam line low points through an orificed header to the condenser hotwell. The MS system has the ability to bypass the turbine when necessary. The main turbine bypass system has two valve chests, each with five automatically operated regulating bypass valves proportionally controlled by the turbine pressure regulator and control system. The bypass system opens whenever the amount of steam admitted into the turbine is less than that generated by the reactor. The MS system provides main turbine sealing steam. The failure of nonsafety-related SSCs in the MS system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Tables 2.3.4-1and 2.3.3-13-52 identify the following MS system component types within the scope of license renewal and subject to an AMR:

• bolting
• condenser
• expansion joint
• heat exchanger (shell)
• heat exchanger (tubes)
• orifice
• piping
• steam trap
• strainer housing
• thermowell
• tubing
• valve body The MS system component intended functions within the scope of license renewal include the following:
• pressure boundary
• holdup and plateout of fission products 2-139

2.3.4.3.2 Staff Evaluation The staff reviewed LRA Section 2.3.4.3 and UFSAR Sections 11.4 and 11.5 using the Tier-2 evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. In conducting its review, staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.4.3.3 Conclusion The staff reviewed the LRA and accompanying license renewal drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the MS system 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). 2.3.4.4 101 (Main Steam, Extraction Steam, and Auxiliary Steam Instruments) 2.3.4.4.1 Summary of Technical Information in the Application LRA Section 2.3.4.4 describes the 101 system (main steam, extraction steam, and auxiliary steam instruments), which provides indication, alarm, and control functions for its associated systems. This system code includes various instrumentation components for main steam, extraction steam, and auxiliary steam. Although the 101 system consists mainly of EIC components, certain mechanical instrumentation components are included as well. The failure of nonsafety-related SSCs in the 101 system (main steam, extraction steam, and auxiliary steam instruments) potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.4-1 identifies the following 101 system (main steam, extraction steam, and auxiliary steam instruments) component types within the scope of license renewal and subject to an AMR:

• bolting
• condenser
• orifice
• expansion joint
• heat exchanger (tubes)
• piping
• strainer housing
• thermowell
• steam trap 2-140
• tubing
• valve body The 101 (main steam, extraction steam, and auxiliary steam instruments) component intended functions within the scope of license renewal include the following:
• pressure boundary
• holdup and plateout of fission products 2.3.4.4.2 Staff Evaluation The staff reviewed LRA Section 2.3.4.4 using the Tier-1evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.3.4.4.3 Conclusion The staff reviewed the LRA and accompanying license renewal drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the 101 (main steam, extraction steam, and auxiliary steam instruments) 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). 2.4 Scoping and Screening Results: Structures This section documents the staffs review of the applicants scoping and screening results for structures. Specifically, this section discusses:

• primary containment
• reactor building
• intake structure
• process facilities
• yard structures
• bulk commodities 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 staffs review focused on the implementation results. This focus allowed the staff to confirm that there were no omissions of SCs that meet the scoping criteria and are subject to an AMR.

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The staffs evaluation of the information in the LRA was the same for all structures. The objective was to determine whether the applicant has identified, in accordance with 10 CFR 54.4, components and supporting structures for structures that appear to meet the license renewal scoping criteria. Similarly, the staff evaluated the applicants screening results to verify that all passive, long-lived components were subject to an AMR as required by 10 CFR 54.21(a)(1). In its scoping evaluation, the staff reviewed the applicable LRA sections and component drawings, focusing on components that have 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 whether the applicant has omitted from the scope of license renewal components with intended functions as required by 10 CFR 54.4(a). The staff also reviewed the licensing basis documents to determine whether the LRA specified all intended functions as required by 10 CFR 54.4(a). The staff requested additional information to resolve any omissions or discrepancies identified. After its review of the scoping results, the staff evaluated the applicants screening results. For those SCs with intended functions, the staff sought to determine whether: (1) the functions are performed with moving parts or a change in configuration or properties or (2) the SCs are subject to replacement after a qualified life or specified time period, as required by 10 CFR 54.21(a)(1). For those meeting neither of these criteria, the staff sought to confirm that these SCs were subject to an AMR, as required by 10 CFR 54.21(a)(1). The staff requested additional information to resolve any omissions or discrepancies identified. 2.4.1 Primary Containment 2.4.1.1 Summary of Technical Information in the Application LRA Section 2.4.1 describes the primary containment, which limits the release of fission products in postulated design basis accidents so offsite doses do not exceed the values specified in 10 CFR 50.67. Located inside the reactor building, the primary containment is a General Electric Mark I containment with a drywell (which encloses the reactor vessel and recirculation system), a pressure suppression chamber (commonly known as the torus), and a connecting vent system. When operating at power, the containment is flooded with N2 to preclude the availability of oxygen. The drywell surrounds the reactor vessel and primary systems. The torus, containing water, is below the drywell and the vent system connecting it to the drywell terminates below the water surface. Access to the drywell is by its steel drywell head and personnel hatch as well as a double door air lock, equipment hatch, and one CRD access hatch. Access to the torus is by two personnel hatches. The primary containment components include the drywell, the torus, the reactor vessel and drywell bellows, and the shield wall. The drywell is a carbon steel structure that houses the reactor pressure vessel and its components. A reinforced concrete support structure, founded on bedrock, is part of the drywell support system. The torus is a toroid-shaped carbon steel pressure vessel below and encircling the drywell. The reactor vessel refueling bulkhead has two stainless steel bellows with backing plates, spring seals, and removable guard rings. The drywell to reactor building bellows assembly is similar to that of the reactor vessel refueling bulkhead. The shield wall (also known as the sacrificial shield wall) is a high-density, steel-reinforced, concrete cylindrical structure surrounding the vessel. The concrete is contained by inner and outer steel liner plates that also 2-142

attach various system supports. The sacrificial shield wall provides lateral support for the reactor vessel to accommodate both seismic forces and jet forces from the breakage of any pipe attached to the vessel. The primary containment has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related primary containment SSCs potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the primary containment performs functions that support fire protection. LRA Table 2.4-1 identifies the following primary containment component types within the scope of license renewal and subject to an AMR:

• steel and other metals
• concrete
• elastomers and other materials
• fluoropolymers and lubrite sliding surfaces The primary containment component intended functions within the scope of license renewal include the following:
• shelter or protection to safety-related equipment, including radiation shielding and pipe whip restraint
• protective barrier for flood events
• heat sink during SBO or DBAs
• missile barrier
• pressure boundary
• structural or functional support for safety-related equipment 2.4.1.2 Staff Evaluation The staff reviewed LRA Section 2.4.1 and UFSAR Sections 5.1.2 and 5.2 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4, Scoping and Screening Results: Structures.

The staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.4.1.3 Conclusion The staff reviewed the LRA and related structural components to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. 2-143

The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the primary containment 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). 2.4.2 Reactor Building 2.4.2.1 Summary of Technical Information in the Application LRA Section 2.4.2 describes the reactor building, which in design basis accidents contains leakage of airborne fission products to the environment within the dose limits specified in 10 CFR 50.67 and supports and protects the reactor and its systems. The reactor building completely encloses the primary containment and houses the refueling and reactor servicing equipment (platforms and cranes), new and spent fuel storage facilities, reactor core isolation cooling system, SBGT system, reactor cleanup demineralizer system, SLC system, CRD system equipment, reactor core and containment cooling systems, and electrical equipment components. The seismic Class I reactor building is constructed of monolithic reinforced concrete floors and walls up to the refueling level and of steel framing covered by insulated sealed siding and roof decking above. The siding and roofing can withstand limited internal overpressure before it is relieved by venting through blowout panels. A biological shield wall, part of the reactor building, encircles the primary containment, protects the containment vessel and the reactor system against potential external missiles, and shields personnel to reduce dose. The reactor building bridge crane, which services the reactor and the refueling area, is designed seismic Class II with supports designed seismic Class I. The crane bridge and trolley wheels have seismic holddown lugs for crane stability in a hypothetical maximum earthquake. The new fuel storage vault, part of the seismic Class I reactor building, houses new fuel storage racks, each designed as seismic Class I while loaded with fuel. The spent fuel storage pool in the reactor building is lined with stainless steel. The pool liner is seam-welded ASTM-A240 Type 304 stainless steel with pipe sleeves welded to both sides of the liner plate. The spent fuel storage racks are assemblies of individual storage cells consisting of Type 304L stainless steel boxes welded together. The seismic Class I refueling platform, the principal means of transporting fuel assemblies back and forth, travels on tracks extending along each side between the reactor well and the storage pool. The reactor building has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related reactor building SSCs potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the reactor building performs functions that support fire protection, ATWS, and SBO. LRA Table 2.4-2 identifies the following reactor building component types within the scope of license renewal and subject to an AMR:

• steel and other metals
• concrete 2-144

The reactor building component intended functions within the scope of license renewal include the following:

• shelter or protection to safety-related equipment, including radiation shielding and pipe whip restraint
• rated fire barrier to confine or retard a fire from spreading
• protective barrier for flood events
• missile barrier
• pressure boundary
• structural or functional support to nonsafety-related equipment the failure of which could impact safety-related equipment
• structural or functional support for safety-related equipment 2.4.2.2 Staff Evaluation The staff reviewed LRA Section 2.4.2 and UFSAR Sections 5.3, 10.4, and 12.2.2 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

The staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2.4.2.3 Conclusion The staff reviewed the LRA and related structural components to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the reactor building 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). 2.4.3 Intake Structure 2.4.3.1 Summary of Technical Information in the Application LRA Section 2.4.3 describes the intake structure, which supports and protects equipment that draws water from the intake canal, located east of the station on the riverbank and divided into two rooms: the SW pump room (which also contains the diesel and electric fire pumps) and the circulating water pump room. The room housing the SW pumps is seismic Class I; the other is seismic Class II. The reinforced concrete and steel intake structure is founded entirely on bedrock. It has three pump bays for the vertical circulating water pumps, two SW bays for four SW pumps and two fire water pumps, three roller gates, and one sluice gate. Recirculation of 2-145

warm discharge water by a concrete pipe connecting the discharge structure to the intake structure keeps the intake bays and SW bays free of ice. All bays have trash racks and stop log guides, traveling screens, and fine screen guides. Interconnection of the three pump bays is by removal of stop logs in center walls. The intake structure has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related intake structure SSCs potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the intake structure performs functions that support fire protection. LRA Table 2.4-3 identifies the following intake structure component types within the scope of license renewal and subject to an AMR:

• steel and other metals
• concrete The intake structure component intended functions within the scope of license renewal include the following:
• shelter or protection to safety-related equipment, including radiation shielding and pipe whip restraint
• rated fire barrier to confine or retard a fire from spreading
• protective barrier for flood events
• missile barrier
• structural or functional support to nonsafety-related equipment the failure of which could impact safety-related equipment
• structural or functional support for equipment required to meet fire protection, environmental qualification, pressurized thermal shock (PTS), ATWS, or SBO regulations
• structural or functional support for safety-related equipment 2.4.3.2 Staff Evaluation The staff reviewed LRA Section 2.4.3 and UFSAR Sections 10.6.5, 10.11.3, and 12.2.6 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

The staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2-146

In RAI 2.4.3-1 dated August 3, 2006, the staff stated that Table 2.4.3 does not include the sluice gate, roller gates, trash racks, stop log guides, traveling screens, and fine screen guides within the intake structure, and the concrete pipe that connects the intake structure to the discharge structure. The staff requested that the applicant provide justification for not including them within the scope of license renewal. In its response dated September 5, 2006, the applicant provided the following response: Sluice gates and roller gates The roller gates isolate the circulating water bays from the river and have no license renewal intended function. The sluice gate is used for de-icing. De-icing supports normal plant operation and is not credited for emergency operation, since warm circulating water flow would not be available with a loss of offsite power. The gates have no license renewal intended function and are not included in LRA Table 2.4-3. Trash racks and traveling screens The trash racks and traveling screens remove debris from the circulating and SW system flow path to prevent plugging of the condenser water box inlets and loss of SW flow. The circulating water bays and the SW bays have separate flow paths sharing a common wall. The trash racks prevent the high circulating water velocity from drawing large debris into the circulating water bays during normal plant operation. However, during emergency operations, the circulating water pumps are unnecessary and, in fact, may be unavailable due to a loss of offsite power. For normal and emergency operations, the SW pumps draw a much lower volume of water through the SW bays. The lower flow rates of the SW system are insufficient to transport large debris that could prevent the traveling screens from passing adequate flow to the SW pumps to allow for safe shutdown. Therefore, trash racks do not provide a license renewal intended function as required by 10 CFR 54.4(a)(1), (a)(2) or (a)(3). The structural supports for the traveling screens are part of the screen-house structure, which is within the scope of license renewal and subject to an AMR. The traveling screens themselves perform their function with moving parts and a change in configuration and are therefore, not subject to an AMR in accordance with 10 CFR 54.21 (a)(l)(i), and are not included in LRA Table 2.4-3. Stop log guides and fine screen guides The stop log guides and fine screen guides do not perform a license renewal intended function. The purpose of the stop log guides is to hold temporary stop logs in place to allow inspections or maintenance. The fine screen guides do not perform a license renewal intended function because a fine screen is not utilized at VYNPS. Therefore, the stop log and fine screen guides do not provide a license renewal intended function as required by 10 CFR 54.4(a)(1), (a)(2) or (a)(3). 2-147

Concrete pipe The concrete pipe connecting the intake structure to the discharge structure provides recirculation of warm condenser circulating water to keep the circulating water intake bays and SW bays free of ice. De-icing supports normal plant operation and is not credited for emergency operation, since warm circulating water flow would not be available with a loss of offsite power. Therefore, the concrete pipe does not provide a license renewal intended function as required by 10 CFR 54.4(a)(1), (a)(2) or (a)(3). Based on its review, the staff finds the applicants response to RAI 2.4.3-1 acceptable because the applicant has provided sufficient explanations for the function of the sluice gate, roller gates, trash racks, stop log guides, traveling screens and fine screen guides within the intake structure, and the concrete pipe that connects the intake structure to the discharge structure, and the basis of their exclusion from the license renewal intended function requirements of 10 CFR 54.4(a)(1), (2) or (3). The staffs concern described in RAI 2.4.3-1 is resolved. 2.4.3.3 Conclusion The staff reviewed the LRA and related structural components to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the intake structure 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). 2.4.4 Process Facilities 2.4.4.1 Summary of Technical Information in the Application LRA Section 2.4.4 describes the process facilities, buildings or structures designated as either seismic Class I or II for power generation and supporting processes with concrete floor slabs, structural steel floors, and platforms as required supported by concrete or structural steel columns, base slabs, and walls. Process facilities include alternate cooling cells and the cooling tower No. 2 deep basin, the control building, the plant stack, and the turbine building. Alternate cooling cell No. 2-1 and the cooling tower No. 2 deep basin provide a heat sink to remove decay heat and sensible heat from the primary system so the reactor can be shut down safely when the SW pumps are not available. Alternate cooling cell No. 2-1, adjoining cooling cell 2-2, and the cooling tower No. 2 deep basin, support and protect structures necessary for the heat sink. The control building houses instrumentation and switches required for station operation with major instrumentation in the main control room. The cable vault and east and west switchgear rooms occupy the lower levels of the building. The plant stack (or main stack) discharges gases to the atmosphere from portions of the turbine building, reactor building, RDW building, SBGT system, and advanced off-gas system. The height of the stack ensures an elevated release and 2-148

an enclosure at its base contains monitoring equipment. The turbine building houses the TG and auxiliaries including the condensate, feedwater, DG, and water treatment systems. Portions of the turbine building support and protect the EDGs and FO day tank areas. The process facilities have safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related process facility SSCs potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the process facilities perform functions that support fire protection. LRA Table 2.4-4 identifies the following process facilities component types within the scope of license renewal and subject to an AMR:

• steel and other metals
• concrete
• elastomer and other materials The process facilities component intended functions within the scope of license renewal include the following:
• shelter or protection to safety-related equipment, including radiation shielding and pipe whip restraint
• rated fire barrier to confine or retard a fire from spreading
• protective barrier for flood events
• heat sink during SBO or DBAs
• missile barrier
• pressure boundary
• structural or functional support to nonsafety-related equipment the failure of which could impact safety-related equipment
• structural or functional support for equipment required to meet fire protection, environmental qualification, PTS, ATWS, or SBO regulations
• structural or functional support for safety-related equipment 2.4.4.2 Staff Evaluation The staff reviewed LRA Section 2.4.4 and UFSAR Sections 10.8, 11.9, 12.2.3, 12.2.4, 12.2.5, and 12.2.6.4 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

The staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). 2-149

In RAI 2.4.4-1 dated August 3, 2006, the staff stated that Table 2.4-4 lists "Structural steel" as a component, and "Structural steel: beams, columns, plates as another component. The staff requested that the applicant provide clarification for the two different components. In its response dated September 5, 2006, the applicant provided the following response: Table 2.4.4 lists these two different components.

        "Structural steel: beams, columns, plates" is defined as:

• substructure or superstructure steel that is part of the primary structural support function of a building or structure, such as structural columns, support girders, beams, plates, connections, roofing joists, purlins, and wind bracing.

        "Structural steel" is defined as:

• steel which does not perform a primary structural integrity function for a building but does provide secondary structural support for equipment or components within the building, or it may provide protection around openings in floors or walls and metal decking on the bottom of reinforced concrete floor slabs. Structural steel includes items such as grating, grating supports, embedded channels, angles, frames, and embedded inserts such as UnistrutTM.

Based on its review, the staff finds the applicants response to RAI 2.4.4-1 acceptable because it distinguishes the primary structural support function from a secondary structural support function of steel members. The staffs concern described in RAI 2.4.4-1 is resolved. In Table 2.4-4, cooling tower cell No. 2-1, cooling tower cell No. 2-2, and foundation (cooling tower No. 2 deep basin) are listed as subject to an aging management review. On August 21, 2007, a portion of cooling tower cell No. 2-4 collapsed. The staff required verification as to whether the affected cells should be in the scope of license renewal and whether scoping for license renewal has been appropriately conducted with respect to the cooling towers. In RAI 2.4.4-2 dated August 29, 2007, the staff requested that the applicant provide the results of the review performed to determine the impact of the circulating water piping, pipe supports, and west cooling tower cell (2-4) failures on license renewal scoping, screening, and applicable aging management programs. The staff also requested the applicant to include the following information: A. A conclusion and basis as to whether the scoping results documented in the LRA, which initially determined that 9 of the11 west cooling tower cells were not within the scope of license renewal, are still valid. B. If found that the west cooling tower cells (2-3 through 2-11) are within the scope of license renewal, provide the following: 2-150

I. The potential effect of a circulating water piping, pipe supports, or structural failure of the nonsafety-related west cooling tower cells (2-3 through 2-11), which were not included within the scope of license renewal, on safety-related systems, structures, and components (in accordance with 10 CFR 54.4(a)(2)). Include the potential effect of debris entering the deep basin beneath the cooling tower. II. The details of any age related degradation which caused the failure of the circulating water piping, pipe supports, and west cooling tower cell. Include the results of the piping and pipe supports inspection related to the current failure and any previously performed, and a description of the identified aging mechanism(s). C. Any impact on the aging management programs for circulating water piping, pipe supports, or cooling tower cells. In letters dated September 27 and October 18, 2007, the applicant provided the following response: Cooling Tower Background Information VYNPS utilizes once-through condenser cooling from the Connecticut River supplemented by two forced draft cooling towers. Each tower consists of eleven cells, each cell equipped with its own forced draft fan. One cell in the west cooling tower, CT 2-1, provides a safety related function as the heat sink for the Residual Heat Removal Service Water system (RHRSW) in the Alternate Cooling System (ACS) mode and is constructed as a Seismic Class I structure. The adjacent cell, CT 2-2, is also designed and constructed as a Seismic Class I structure to prevent adversely impacting the structural integrity of CT 2-1 during a seismic event. CT 2-1 and CT 2-2 structures have similar construction as the other cooling tower cells for dead weight loads, but a more robust bracing system to withstand wind and seismic loading. They are constructed from high quality timber and use stainless steel hardware for all bolted connections. The structural columns were refurbished during the 1980s, followed by end wall refurbishment between 2002 and 2007. As required for activities associated with any safety-related and Seismic Class I systems, structures, and components (SSCs), the inspections and repairs on cooling tower cells CT 2-1 and CT 2-2 receive additional oversight by the site Engineering, Maintenance, and Quality Assurance (QA) groups.

• Different design. Safety-related Cell CT 2-1 and Seismic Class I Cell CT 2-2 design includes additional 4x4 cross-bracing to withstand wind and seismic loading. In CT 2-1, some of the additional bracing is heavier 4 x 6 material.
• Different material specifications. Hardware for CT 2-1 and CT 2-2 is stainless steel, while the other towers may use carbon or galvanized 2-151

steel. The stainless steel hardware minimizes potential iron salt attack at the bolted structural connections.

• Different level of quality. CT 2-1 and CT 2-2 are subject to the higher levels of oversight afforded to safety-related and Seismic Class I structures. The higher level of quality results in application of the station corrective action program to evaluate deficiencies and effect appropriate corrective actions.
• Different maintenance history. Because of their safety significance and higher level of quality, CT 2-1 and CT 2-2 have had more refurbishment during the past ten years than the other tower cells. During this period, the end wall of CT 2-1 and the partition walls of CT 2-1 and CT 2-2 have been replaced, including the vertical columns and structural hardware.

The original end walls and partition walls remain in many of the non-Seismic Class I cells. Response to Part A: Cooling tower cells CT 2-1 and CT 2-2 are the only cells in the scope of license renewal. Failures of the other cells will not prevent satisfactory accomplishment of a safety function identified in 10 CFR 54.4(a)(1). The scoping results documented in the LRA remain valid. See the response to part B for further discussion of potential failures. Cooling tower cell CT 2-1, which is part of the circulating water system, has the 10 CFR 54.4(a)(1) and (a)(3) intended function to support operation of the alternate cooling system by providing an alternate means of heat removal in the unlikely event that the service water pumps become inoperable. Therefore, CT 2-1 is in the scope of license renewal and subject to aging management review. Cell CT 2-1 itself and associated components of the residual heat removal service water (RHRSW) system fulfill the intended function. The credited RHRSW system components in CT 2-1 are the 24 carbon steel suction piping located in the RHRSW suction pit and the 16 and 20 carbon steel distribution piping that discharges water into the cooling tower from the RHRSW pumps. Aging management review results for RHRSW system components at CT 2-1 are provided in LRA Table 3.3.2-2. Circulating water piping is not relied on to perform the license renewal intended function of supporting alternate cooling system operation. The circulating water system piping has no other system intended functions in scope for 54.4(a)(1) or (a)(3). It does have a 54.4(a)(2) intended function to maintain integrity of nonsafety-related components such that no physical interaction with safety-related components could prevent satisfactory accomplishment of a safety function. 2-152

Response to Part B Subpart I: As indicated in the LRA and in response to Part A, west cooling tower cells CT 2-1 and CT 2-2 are within the scope of license renewal. The failure of cooling tower cell CT 2-4 or any other of the cooling tower cells, along with the associated circulating water piping and pipe supports, has no impact on the ability of the in-scope cooling tower cells and the Cooling Tower No. 2 (west cooling tower) deep basin to accomplish safety functions under design basis conditions. Cooling tower cells CT 2-1 and CT 2-2 are seismically designed to ensure that they are not adversely affected by a seismic event or by failure of other cooling tower cells. This design includes "breakaway" connections to the remaining cooling tower cells. These breakaway connections ..... are constructed by cutting the major wooden structural members connecting CT 2-2 to CT 2-3 and splicing them together with weaker materials that will separate in the event of significant seismic loading. For cooling tower cell CT 2-1, the portion of the circulating water system piping that is in scope for 54.4(a)(2) is the carbon steel piping outside the tower that supplies water to the tower. This portion of the piping has the potential for spatial interaction with safety-related electrical equipment due to spray or leakage. This carbon steel piping is subject to aging management review as shown in Tables 2.3.3.13-B and 3.3.2.13-9. This carbon steel circulating water system piping transitions to fiberglass upon entering CT 2-1. The fiberglass circulating water piping has no license renewal intended function as discussed below. Therefore, fiberglass circulating water piping is not included in the LRA Section 3.3 tables. The fiberglass circulating water piping is nonsafety-related and supports no system intended functions for 54.4(a)(1) or (a)(3). Pipe supports on this piping are part of the wooden tower structure and are subject to aging management review and included in the Structures Monitoring Program to ensure the piping cannot physically impact safety-related equipment. Following onset of the recent partial failure of CT 2-4, two lengths of the circulating water piping separated at a connecting joint. Failure of vertical wooden structural columns caused the piping to sag and separate at the joint. Managing the effects of aging on the wooden tower structure will prevent a similar piping separation at the joints in CT 2-1. The seismic analysis shows that the pipe stays intact during a seismic event. No other credible failure mechanisms can cause wholesale failure of the fiberglass piping. Postulated failures involving minor leakage from piping joints could spray or leak water on internal Cell CT 2-1 components. These components are designed for a wetted environment during normal cooling tower operation and as such would not be adversely impacted. As a result, the fiberglass piping cannot prevent satisfactory accomplishment of any of the functions identified in 10 CFR 54.4(a)(1) due to spatial interaction from spray or leakage, and is not in scope and subject to aging management review under 54.4(a)(2). 2-153

If the fiberglass piping were subject to aging management review, the aging management review results would be that there are no aging effects requiring management due to the high corrosion resistance of fiberglass which is composed of glass fibers. This is consistent with NUREG-1801, Volume 2, Line V.F-8 that lists no aging effects for glass piping elements in raw water. The cooling tower basin has a storage capacity of 1.45 million gallons that is sufficient for seven days of ACS operation. The available capacity assumes that cooling tower cells CT 2-3 through CT 2-9 collapse during a seismic event resulting in an estimated 170,427 gallons of water (equivalent to the volume of all material in these cells) being displaced (lost). The evaluation does not credit the volume of water in basin below cooling tower cells CT 2-10 and CT 2-11. The basin below these two cells is shallow and the small volume of water is conservatively not credited for available capacity. Because the volume of the basin beneath cells CT2-10 and CT2-11 is not credited, a postulated collapse of the wooden structure of these two cells displaces no credited volume. The potential for debris blockage of the ACS suction following an event involving collapse of cooling tower cells CT 2-3 through CT 2-11 has also been evaluated. The velocity through the suction grating at an ACS flow rate of 8000 gpm is 0.25 ft/sec which is 10% of the velocity required to keep sediment in suspension. This low velocity coupled with the tower cross bracing in two directions will prevent migration of debris to the ACS suction. The RHRSW system takes suction from a pit in the northwest corner of CT 2-1. The pit is approximately 60 feet from the nearest non-Seismic Class I cell. The suction pit is covered by steel grating. During alternate cooling system operation, RHRSW system flow is recirculated through CT 2-1. The only flow into CT 2-1 from the basin below the remaining cells is the flow required to make up for normal operating losses, such as, evaporation and drift. The flow rate from adjacent cells into CT 2-1 is low with a resulting velocity of less than a tenth of the 0.25 ft/sec velocity .... for flow through the grating over the suction pit. Failure of cooling tower cells CT 2-3 through CT 2-11 (9 of 11 cells) and associated components has no impact on safety-related cooling tower cell CT 2-1. Subpart II: As identified in the VYNPS LRA, the aging effects on the cooling tower wooden structures are: (a) change in material properties, (b) cracking, and (c) loss of material. The aging mechanisms associated with the partial failure of CT 2-4 are: (a) iron salt attack (formation of iron salts in the wood where ferrous hardware contacts the lumber and degrades the wood cells), 2-154

(b) fungal attack (wood destroying microscopic organism called decay fungi that forms in wood exposed to suitable temperature 40oF-140oF in moist environment), and (c) repeated wetting and drying cycles causing wood checking and physical damage which reduces wood strength. The circulating water piping within the cooling tower is made of fiberglass and is secured in wooden support saddles. The piping separation event resulted from the distribution deck sag that caused the bell/spigot joint to separate. It did not result from the effects of aging on the fiberglass piping. The wooden saddles supporting the distribution header were found in good condition with no significant degradation. The supporting columns for the circulating water header experienced a reduction in strength due to iron salt attack and fungal attack at the upper spliced joints that caused cracking. This caused the initial failure of several support columns that led to deck sag and separation of the fiberglass circulating water piping joint, thereby increasing the local water loading, causing the additional column failures that lead to the partial failure of CT 2-4. Response to Part C: The circulating water piping separated due to the initial CT 2-4 column failure, rather than due to the effects of aging. This failure does not indicate a need to change the aging management programs for the circulating water piping. Thus, there is no impact on the aging management programs for circulating water piping. Aging effects identified in the VYNPS LRA for the cooling tower structural elements are; loss of material, cracking and change in material properties. These aging effects are consistent with those associated with the failure of CT 2-

4. The LRA identifies a need for enhancing the Structures Monitoring Program to add guidance for performing examinations of the wood cooling tower elements as appropriate to identify a loss of material, cracking, or change in material properties. This enhancement will include details for the examination and acceptance criteria for wood structures and structural components (i.e., columns and circulating water pipe supports) to ensure aging effects are identified and corrected prior to a loss of intended function. To detect a change in material properties, the enhancement will entail inspections that are more involved than remote visual surface inspections. Lessons learned from review of the failure of CT 2-4 will be considered in implementation of the enhancement identified for the Structures Monitoring Program.

The staff determined that the applicant has appropriately included cooling tower cells CT 2-1 and CT 2-2 within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(1) and (a)(2), respectively, and has committed (Commitment #21) to enhance and apply the Structures Monitoring Program to the cooling towers. In addition, the applicant has articulated the significant differences in design, material specifications, level of quality 2-155

assurance oversight and maintenance between cooling tower cells CT 2-1 through CT 2-2 and those of cooling tower cell CT 2-3 through CT 2-11. These features, along with the execution of the Structures Monitoring Program, would preclude cooling tower cells CT 2-1 and CT 2-2 from failing in the manner of cooling tower cell CT 2-4. The additional information provided by the applicant demonstrated that cooling tower cells CT 2-3 through CT 2-11 do not meet the criteria of 10 CFR 54.4(a) for inclusion within the scope of license renewal in that they do not perform an intended function as defined by 10 CFR 54.4(a)(1) or (a)(3). Also, with the aid of the breakaway connections design, their failure would not prevent a safety-related SSC from performing its intended function as defined by 10 CFR 54.4(a)(2). Based on a review of the additional information provided by the applicant, the staff finds the applicants response to RAI 2.4.4-2 acceptable. 2.4.4.3 Conclusion The staff reviewed the LRA and related structural components to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the process facilities 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). 2.4.5 Yard Structures 2.4.5.1 Summary of Technical Information in the Application LRA Section 2.4.5 describes the yard structures, structures not contained within the primary containment, reactor building, intake structure, or process facilities. Yard structures include the condensate storage tank foundation and enclosure structure, FO storage tank foundation and transfer pump house, N2 storage tank foundation and enclosure, low-pressure CO2 tank foundation and enclosure, JDD building, startup transformer foundation, switchyard relay house, trenches, manholes, duct banks, Vernon tie transformer foundation, Vernon Dam and hydroelectric station, and transmission towers. The condensate storage tank is near the southeast corner of the turbine building. The carbon steel enclosure houses safety-related equipment of the CST system. The FO storage tank holds make-up fuel for the EDG day tanks. A FO transfer pump house contains the FO pumps. The liquid N2 storage tank enclosure is a seismic Class I structure designed so no instantaneous introduction of a high concentration of N2 gas into the DG air intake occurs if the storage tank fails. A restraining wall around the base of the tank collects liquid N2 and minimizes surface area to limit the boil-off rate of spilled N2. The tank, located adjacent to the east side of the reactor building, is supported by a reinforced concrete foundation and structural steel support columns to meet seismic design requirements. The reinforced concrete CO2 tank (TK-115-1) foundation is adjacent to the northeast corner of the switchgear room. A metal enclosure houses and protects electrical and mechanical equipment for the tank against the environment. The JDD powers emergency lighting credited for alternate shutdown in the safe shutdown capability analysis. The start-up transformers (T-3A & B) on the west side of the turbine building are supported by reinforced concrete pedestals raised above a crushed rock bed. The startup transformers provide power during recovery from SBO. The switchyard control house, also 2-156

known as the switchyard relay house, a single-story structure in the main switchyard, houses relays that control the offsite 115 kV lines. The trenches, manholes and duct banks throughout the VYNPS site, support and protect plant equipment. Those that support or protect equipment within the scope of license renewal are also in-scope. Duct banks route electrical cables between buildings and in the switchyard area. The Vernon tie transformer is on a reinforced concrete slab located approximately 50 feet northwest of the west cooling tower and formed on a gravel and sand base to minimize frost heaving. The Vernon tie transformer is credited for SBO. Vernon Dam on the Connecticut River is constructed of concrete and steel and used for hydro-electric generation as an alternate source of AC power in an SBO. The dam and powerhouse are founded on compact rock and the power block superstructure is comprised of reinforced concrete, masonry brick, and structural steel. The dam is not a site structure owned by the applicant. Transmission towers are constructed of galvanized steel reinforced concrete foundations. In-scope towers are the 115 kV tower in the 115 kV switchyard, the 115KV angle tower located west of the turbine building, and the 115/345 kV shared tower in the 345 kV switchyard. The yard structures have safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related yard structure SSCs potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the yard structures perform functions that support fire protection and SBO. LRA Table 2.4-5 identifies the following yard structures component types within the scope of license renewal and subject to an AMR:

• steel and other metals
• concrete The yard structures component intended functions within the scope of license renewal include the following:
• shelter or protection to safety-related equipment, including radiation shielding and pipe whip restraint
• protective barrier for flood events
• missile barrier
• structural or functional support to nonsafety-related equipment the failure of which could impact safety-related equipment
• structural or functional support for equipment required to meet fire protection, environmental qualification, PTS, ATWS, or SBO regulations
• structural or functional support for safety-related equipment 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.

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The staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). In RAI 2.4.5-1 dated August 3, 2006, the staff stated that Table 2.4.5 lists "Vernon Dam external walls above/below grade" as a component, and "Vernon Dam external walls, floor slabs and interior walls as another component. The staff requested that the applicant provide clarification for the two different components. In its response dated September 5, 2006, the applicant provided the following response: In Table 2.4.5, item "Vernon Dam external walls above/below grade" refers to the outside surface of the exterior walls and the second line item "Vernon Dam external walls, floor slabs and interior walls" refers to the interior surface of the exterior walls along with floors and interior walls. This distinction is consistent with the treatment of each of these as having separate environments as shown in Table 3.5.2-5. Based on its review, the staff finds the applicants response to RAI 2.4.5-1 acceptable because it distinguishes the exterior surface of the Vernon Dam wall from the interior surface of the wall, which are subjected to different environments. The staffs concern described in RAI 2.4.5-1 is resolved. 2.4.5.3 Conclusion The staff reviewed the LRA and related structural components to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the yard structures 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). 2.4.6 Bulk Commodities 2.4.6.1 Summary of Technical Information in the Application LRA Section 2.4.6 describes the bulk commodities, structural components or commodities that perform or support intended functions of in-scope SSCs. Bulk commodities unique to specific structures are included in the reviews for those structures (SER Sections 2.4.1 through 2.4.5). This section addresses bulk commodities common to in-scope SSCs (e.g., anchors, embedments, pipe and equipment supports, instrument panels and racks, cable trays, and conduits). The bulk commodities have safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related bulk commodity SSCs potentially could 2-158

prevent the satisfactory accomplishment of a safety-related function. In addition, the bulk commodities perform functions that support fire protection, ATWS, SBO, and environmental qualification. LRA Table 2.4-6 identifies the following bulk commodity component types within the scope of license renewal and subject to an AMR:

• steel and other metals
• concrete
• elastomers and other materials
• fluoropolymers and lubrite sliding surfaces The bulk commodity component intended functions within the scope of license renewal include the following:
• shelter or protection to safety-related equipment, including radiation shielding and pipe whip restraint
• rated fire barrier to confine or retard a fire from spreading
• protective barrier for flood events
• insulation
• missile barrier
• pressure boundary
• structural or functional support to nonsafety-related equipment the failure of which could impact safety-related equipment
• structural or functional support for equipment required to meet fire protection, Environmental qualification, PTS, ATWS, or SBO regulations
• structural or functional support for safety-related equipment 2.4.6.2 Staff Evaluation The staff reviewed LRA Section 2.4.6 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

The staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR as required by 10 CFR 54.21(a)(1). In RAI 2.4.6-1 dated August 3, 2006, the staff stated that Table 2.4.6 lists "Flood curbs" as a component with intended functions for flood barrier and shelter or protection, and another component "Flood curbs with an intended function for flood barrier. The staff requested that the applicant provide clarification for the two different components. 2-159

In its response dated September 5, 2006, the applicant provided the following response: For VYNPS, flood curbs constructed of either concrete or steel perform the same intended function, which is to provide shelter or protection by serving as flood barriers. In essence, flood barrier and shelter or protection are the same function and both entries for flood curbs fulfill the same function. Based on its review, the staff finds the applicants response to RAI 2.4.6-1 acceptable because the applicant explained that the two entries for flood curbs perform the same intended function. The staffs concern described in RAI 2.4.6-1 is resolved. 2.4.6.3 Conclusion The staff reviewed the LRA and related structural components to determine whether the applicant failed to identify any SSCs within the scope of license renewal or subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the bulk commodities 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). 2.5 Scoping and Screening Results: Electrical and Instrumentation and Control Systems This section documents the staffs review of the applicants scoping and screening results for electrical and instrumentation and control (EIC) 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 staffs review focused on the implementation results. This focus allowed the staff to confirm that there were no omissions of EIC system components that meet the scoping criteria and subject to an AMR. The staffs evaluation of the information in the LRA was the same for all EIC systems. The objective was to determine whether the applicant has identified, as required by 10 CFR 54.4, components and supporting structures for EIC systems that appear to meet the license renewal scoping criteria. Similarly, the staff evaluated the applicants screening results to verify that all passive, long-lived components were subject to an AMR as required by 10 CFR 54.21(a)(1). In its scoping evaluation, the staff reviewed the applicable LRA sections and component drawings, focusing on components that have not been identified as within the scope of license renewal. The staff reviewed relevant licensing basis documents, including the UFSAR, for each EIC system to determine whether the applicant has omitted from the scope of license renewal components with intended functions as required by 10 CFR 54.4(a). The staff also reviewed the licensing basis documents to determine whether the LRA specified all intended functions as required by 10 CFR 54.4(a). The staff requested additional information to resolve any omissions or discrepancies identified. 2-160

Once the staff completed its review of the scoping results, the staff evaluated the applicants screening results. For those SCs with intended functions, the staff sought to determine: (1) if the functions are performed with moving parts or a change in configuration or properties, or (2) if they are subject to replacement based on a qualified life or specified time period, as required by 10 CFR 54.21(a)(1). For those that did not meet either of these criteria, the staff sought to confirm that these SCs were subject to an AMR, as required by 10 CFR 54.21(a)(1). If discrepancies were identified, the staff requested additional information to resolve them. 2.5.1 Summary of Technical Information in the Application LRA Section 2.5 describes the EIC systems. Plant EIC systems are included within the scope of license renewal as are EIC components in mechanical systems. The default inclusion of plant EIC systems within the scope of license renewal reflects the method for IPAs of electrical systems. This method differs from those used for IPAs of mechanical systems and structures. VYNPS electrical commodity groups correspond to two of the commodity groups identified in NEI 95-10: (1) high-voltage insulators and (2) cables and connections, busses, and electrical portions of EIC penetration assemblies. The IPA eliminated commodity groups and specific plant systems from further review as the intended functions of commodity groups were examined. In addition to the plant electrical systems, certain switchyard components required to restore offsite power following a SBO were conservatively included within the scope of license renewal although they are not relied on in safety analyses or plant evaluations to perform functions for compliance with SBO regulations. The offsite power system provides the electrical interconnection between the generator and the offsite transmission network and between the offsite network and the auxiliary buses as well as other buildings and facilities. The EIC systems perform functions that support SBO. LRA Table 2.5-1 identifies the following EIC systems component types within the scope of license renewal and subject to an AMR:

• cable connections (metallic parts)
• electrical cables, connections, and fuse holders (insulation) not subject to 10 CFR 50.49 Environmental qualification requirements
• electrical cables not subject to 10 CFR 50.49 Environmental qualification requirements used in instrumentation circuits
• fuse holders (insulation material)
• high-voltage insulators
• inaccessible medium-voltage (4.16 kV to 22 kV) cables (e.g., installed underground in conduit or direct buried) not subject to 10 CFR 50.49 Environmental qualification requirements
• switchyard bus
• transmission conductors 2-161

The EIC systems component intended functions within the scope of license renewal include the following:

• provide electrical connections to specified sections of an electrical circuit to deliver voltage, current, or signals
• insulate and support electrical conductor 2.5.2 Staff Evaluation The staff reviewed LRA Section 2.5 and UFSAR Sections 7 and 8 using the evaluation methodology described in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5, Scoping and Screening Results: Electrical and Instrumentation and Controls Systems. The staff reviewed the scoping methodology of the applicant, and considered it to be acceptable in accordance with the Plant Spaces approach method in NUREG-1800, Revision 1, Table 2.5.1. This approach eliminates the need for unique identification of every component and its specific location. This assures components are not excluded from an AMR.

As documented in SER, Section 3.6.2.3.1, the staff determined that uninsulated ground conductors are not in the scope of licence renewal and do not require an AMR. In RAI 2.5-1, the staff requested the applicant to provide brief descriptions of the systems, listed in LRA Table 2.2-1b, explaining how each system serves one or more functions listed in 10 CFR 54.4(a). In its response dated September 5, 2006, the applicant stated that: As described in LRA Section 2.5, all plant electrical and Instrumentation and Control (EIC) systems are included in the scope of license renewal. EIC equipment in mechanical systems is included in the scope of license renewal, regardless of whether the mechanical system is included in-scope. Including components beyond those actually required is referred to as an encompassing review. This method eliminates the need for unique identification of each system and its specific function. This assures components are not improperly excluded from the scope of license renewal. Based on its review, the staff finds the above response to the RAI 2.5-1 acceptable because when used with Plant Spacesapproach, this method eliminates the need for unique identification of each system and its specific function. The staffs concern described in RAI 2.5-1 is resolved. In RAI 2.5-2, the staff requested the applicant to provide details of Vermont Yankee Nuclear Power Stations alternate alternating current (AAC) source, and also describe the offsite power recovery paths from switchyard to the onsite distribution which are in the license renewal scope to satisfy the requirements of 10 CFR 50.63. In its response dated September 5, 2006, the applicant stated that: 2-162

The parts of the AAC that are subject to AMR are explained in the response to RAI 3.6.2.2-N-08. The offsite power recovery paths from switchyard to the onsite distribution system which are in the license renewal scope are the source fed through the start-up transformers and a delayed access circuit from the 345 kV switchyard through the main and auxiliary transformers via the isophase bus. Specifically, the start-up transformer path includes; the 115 kV switchyard circuit breaker feeding the start-up transformers, the start-up transformers, the circuit breaker-to-transformers and transformer-to-onsite electrical distribution interconnections, and the associated control circuits and structures. The delayed access circuit is made available by opening the generator no-load disconnect switch and establishing a feed from the 345kV switchyard through the main and auxiliary transformers via the isophase bus. The staff reviewed the applicant response to RAI 3.6.2.2-N-08, provided in the letter dated July 14, 2006, in which it stated that the VHS is the AAC source credited for Vermont Yankee Nuclear Power Station (VYNPS) to demonstrate compliance with 10 CFR 50.63, loss of all alternating current power (the station blackout rule). As such, all VHS structures, systems, and components (SSCs) are in the scope of license renewal. Based on its review of the response to RAI 3.6.2.2-N-08, and further clarifications provided by the applicant in its letter dated January 4, 2007, Attachment 4, the staff finds the applicants response to RAI 2.5-2 acceptable because the applicant has included all necessary components of the AAC source in the scope of license renewal. The staffs concern described in RAI 2.5-2 is resolved. The applicant initially excluded metal-enclosed bus connections, and bus enclosure assemblies and insulators from the AMR. However, in its response dated September 5, 2006 to the staffs RAI 2.5-3, the applicant clarified that the metal-enclosed isophase bus is now included in the AMR. This isophase bus is part of the delayed access circuit (to support SBO recovery actions) from the 345 kV switchyard through the main generator step-up transformer and unit auxiliary transformer. The applicant stated that the VYNPS Metal Enclosed Bus Program will manage the effects of aging of the isophase bus and will be consistent with the GALL Report aging management program X1.E4 (NUREG-1801, Volume 2, Rev 1). Based on above response provided by the applicant in its letter dated September 5, 2006, the staff considers that the applicant has included necessary components of the metal-enclosed bus connections, bus enclosure assemblies and insulators subject to an AMR. The RAI 2.5-3 response is considered acceptable. The staffs concern described in RAI 2.5-3 is resolved. In RAI 2.5-4, the staff asked the applicant to provide justification, in detail, why the cable connections (metallic portion) was not included in the scope of an AMR although the GALL Report aging management program XI.E6, "Electrical Cable Connections not Subject to 10 CFR 50.49 Environmental Qualification Requirements," recommended such an aging managing program. In its letter dated September 5, 2006, the licensee provided the following justification: 2-163

Metallic parts of electrical cable connections that are exposed to thermal cycling and ohmic heating are those carrying significant current in power supply circuits. VYNPS power cables are in a continuous run from the supply to the load. The connections to the supply and to the load are parts of active components that are not subject to aging management review in accordance with 10 CFR 54.21. As discussed in the statement of considerations for the license renewal rule, maintenance rule activities are credited with managing the effects of aging on active components. The fast action of circuit protective devices at high currents mitigates stresses associated with electrical faults and transients. In addition, mechanical stress associated with electrical faults is not a credible aging mechanism because of the low frequency of occurrence for electrical faults. Therefore, electrical transients are not aging mechanisms. Metallic parts of electrical cable connections exposed to vibration are those associated with active components that cause vibration. Active components are not subject to aging management review in accordance with 10 CFR 54.21. As discussed in the statement of considerations for the license renewal rule, maintenance rule activities are credited with managing the effects of aging on active components. Corrosive chemicals are not stored in most areas of the plant. Routine releases of corrosive chemicals to areas inside plant buildings do not occur during plant operation and corrosive chemicals are not a normal environment for electrical connections. Contamination of electrical connections causes rapid degradation independent of the age of the connection components. Corrosion due to contamination is due to the contamination event rather than aging. Therefore, chemical contamination is not an aging mechanism for electrical connections. Corrosion and oxidation occur in the presence of moisture or contamination such as industrial pollutants and salt deposits. Enclosures and splice materials protect metal connections from moisture and contamination. Therefore, oxidation and corrosion are not applicable aging mechanisms. Electrical cable connections at VYNPS are inspected in accordance with the maintenance rule program as directed by plant procedures. The maintenance rule program, based on industry guidance provided in NUMARC 93-01 and Reg. Guide 1.160, complies with 10 CFR 50.65. The maintenance rule program includes performance monitoring and trending. Monitoring and trending includes normal plant maintenance activities. Maintenance includes activities associated with identifying and correcting actual or potential degraded conditions (e.g., repair, surveillance, diagnostic examinations, and preventive measures). Thermography is used to detect potential degraded conditions. Thermography can detect "hot spots" in cable connections that are indicative of a high resistance connection. As a part of the maintenance rule program, periodic assessments are performed. A periodic assessment is performed to evaluate the effectiveness of 2-164

maintenance activities. This assessment is performed at least every operating cycle, not to exceed 24 months. Plant operating experience has shown that the maintenance rule program has been effective at detecting, evaluating and repairing electrical cable connection degradation. The maintenance rule program includes scoping, performance monitoring, trending and periodic assessments. This program provides reasonable assurance that electrical cable connections will remain capable of performing their intended functions through the period of extended operation. No aging management program (AMP) for license renewal is required at VYNPS since the regulatory mandated maintenance rule program effectively maintains electrical cable connections. Subsequent to above response, on November 30, 2006, NEI held a meeting with NRC. Based on this meeting, XI.E6 program was revised to be a one-time inspection of a representative sample of cable connections subject to aging management review. In its letter dated January 4, 2007, Attachment 7, the applicant agreed to a plant-specific Bolted Cable Connection Program. Based on licensee agreement to implement a Bolted Cable Connection Program as detailed in its letter dated January 4, 2007, the staff considers the issue raised in RAI 2.5-4 resolved. 2.5.3 Conclusion The staff reviewed the LRA Section 2.5, the UFSAR, and the supplemental information provided by the applicant in its letters dated September 5, 2006, and January 4, 2007, to determine whether any SSCs that should be within the scope of license renewal or subject to an AMR had not been identified by the applicant. No omissions were identified. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant had adequately identified the electrical commodity group components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that are 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 applicants scoping and screening methodology was consistent with the requirements of 10 CFR 54.21(a)(1) and the staffs positions on the treatment of safety-related and nonsafety-related SSCs within the scope of license renewal and on SCs subject to an AMR is consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1). On the basis of its review, the staff concludes, pending resolution of Confirmatory Items 2.3.3.2a-1, 2.3.3.2a-2, 2.3.3.12-1, 2.3.3.13a-1, 2.3.3.13e-1, and 2.3.3.13m-1, 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). 2-165

The staff concludes that there is reasonable assurance that the applicant will continue to conduct the activities authorized by the renewed license in accordance with the CLB and any changes to the CLB in order to comply with 10 CFR 54.21(a)(1), in accordance with the Atomic Energy Act of 1954, as amended, and NRC regulations. 2-166

SECTION 3 AGING MANAGEMENT REVIEW RESULTS This section of the safety evaluation report (SER) evaluates aging management programs (AMPs) and aging management reviews (AMRs) for Vermont Yankee Nuclear Power Station (VYNPS), by the staff of the United States (US) Nuclear Regulatory Commission (NRC) (the staff). In Appendix B of its license renewal application (LRA), Entergy Nuclear Operations, Inc. (ENO or the applicant) described the 36 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 US NRC NUREG-1801, Volume 2, 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 indicate 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 purpose of the GALL Report is to provide 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, the time, effort, and resources for LRA review will be greatly reduced, improving 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 AMPs and activities that the staff determines will adequately manage or monitor aging during the period of extended operation. The GALL Report identifies: (1) systems, structures, and components (SSCs), (2) SC materials, (3) environments to which the SCs are exposed, (4) the aging effects of the materials and environments, (5) the AMPs credited with managing or monitoring the aging effects, and (6) recommendations for further applicant evaluations of aging management for certain component types. To determine whether use of the GALL Report would improve the efficiency of LRA review, the staff conducted a demonstration of the GALL Report process in order to model the format and content of safety evaluations (SEs) based on it. The results of the demonstration project confirmed that the GALL Report process will improve the efficiency and effectiveness of LRA review, while maintaining the staff's focus on public health and safety. NUREG-1800, 3-1

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 staffs review was in accordance with Title 10, Part 54, of the Code of Federal Regulations (10 CFR 54), Requirements for Renewal of Operating Licenses for Nuclear Power Plants, and 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 selected AMRs and associated AMPs, during the weeks of April 17-21, 2006, May 15-19, 2006 and June 26-28, 2006. The staff documented the results of its audit and review in Audit and Review Report for Plant Aging Management Reviews and Programs, Vermont Yankee Nuclear Power Station (Audit and Review Report). The onsite audits and reviews are designed for maximum efficiency of the staffs LRA review. The applicant can respond to questions, the staff can readily evaluate the applicant's responses, and the need for formal correspondence between the staff and the applicant is reduced, resulting in 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 to by the staff and the Nuclear Energy Institute (NEI) agreed by letter dated April 7, 2003 (ML030990052). This revised LRA format incorporates lessons learned from the staff's reviews of the previous five LRAs, which used a format developed from information gained during a staff-NEI demonstration project conducted 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 VYNPS application is essentially the same. The intent of the revised format of the LRA was to modify the tables in LRA Section 3 to provide additional information that would assist in the staffs review. In its Table 1s, the applicant summarized the portions of the application that it considered to be consistent with the GALL Report. In its Table 2s, the applicant identified the linkage between the scoping and screening results in LRA Section 2 and the AMRs in LRA Section 3. 3-2

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 through 6 in the GALL Report, except that the Type column has been replaced by an Item Number column and the Item Number in GALL column has been replaced by a Discussion column. The Item Number column 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 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 so that the consistency can be checked easily. 3.0.1.2 Overview of Table 2s Each Table 2 provides the detailed results of the AMRs for components identified in LRA Section 2 as subject to an AMR. The LRA has a Table 2 for each of the systems or structures within a specific system grouping (e.g., reactor coolant systems, engineered safety features (ESF), auxiliary systems, etc.). For example, the ESF group has tables specific to the core spray system (CSS), high pressure coolant injection system (HPCIS), and residual heat removal system (RHRS). Each Table 2 consists of 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. Internal and external service environments are indicated with a list of these environments in LRA Tables 3.0-1, 3.0-2, and 3.0-3. (5) Aging Effect Requiring Management - The fifth column lists aging effects requiring management (AERM). As part of the AMR process, the applicant determined any AERMs for each combination of material and environment. 3-3

(6) Aging Management Programs - The sixth column lists the AMPs that the applicant uses to manage the identified aging effects. (7) NUREG-1801 Volume 2 Item - The seventh column lists the GALL Report item(s) identified in the LRA as similar to the AMR results. The applicant compares 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 in order to identify the AMR results in the LRA tables corresponding to the items in the GALL Report tables. (8) Table 1 Item - The eighth column lists the corresponding summary item number from LRA Table 1. If the applicant identifies in each LRA Table 2 AMR results consistent with the GALL Report, the associated Table 1 line item summary number should be listed in LRA Table 2. If there is no corresponding item in the GALL Report, column eight is left blank. In this manner, the information from the two tables can be correlated. (9) Notes - The ninth column lists the corresponding notes used to identify how the information in each Table 2 aligns with the information in the GALL Report. The notes, identified by letters, were developed by an NEI work group and will be used in future LRAs. 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 such 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 such consistency. In addition, the staff conducted either an audit or a technical review of the applicant's technical justifications for the exceptions or the adequacy of the enhancements. The SRP-LR states that an applicant may take one or more exceptions to specific GALL AMP elements; however, any deviation from or exception to the GALL AMP should be described and justified. Therefore, the staff considers exceptions as being portions of the GALL 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 AMP. However, the applicant may make a commitment to augment the existing program to satisfy the GALL AMP prior to 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. 3-4

Staff audits and technical reviews of the applicants AMPs and AMRs determine whether the effects of aging on SCs can be adequately managed to maintain their intended function(s) consistent with the plants current licensing basis (CLB) for the period of extended operation, as required by 10 CFR Part 54. 3.0.2.1 Review of AMPs For AMPs for which the applicant claimed consistency with the GALL 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 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/one-time inspections to ensure timely detection of aging effects. (5) Monitoring and Trending - Monitoring and trending should provide predictability of the extent of degradation, as well as timely corrective or mitigative actions. (6) Acceptance Criteria - Acceptance criteria, against which the need for corrective action will be evaluated, should ensure that the structure or component intended function(s) are maintained in accordance with all CLB design conditions during the period of extended operation. (7) Corrective Actions - Corrective actions, including root cause determination and prevention of recurrence, should be timely. (8) Confirmation Process - Confirmation process should ensure that preventive actions are adequate and that appropriate corrective actions have been completed and are effective. (9) Administrative Controls - Administrative controls should provide 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 so that the SC intended function(s) will be maintained during the period of extended operation. 3-5

Details of the staffs audit evaluation of program elements (1) through (6) are documented in SER Section 3.0.3. 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. The staff reviewed the information on the operating experience program element and documented its evaluation in SER Section 3.0.3. The staff reviewed the Updated Final Safety Analysis Report (UFSAR) Supplement for each AMP to determine if it provided an adequate description of the program or activity, as required by 10 CFR 54.21(d). 3.0.2.2 Review of AMR Results Each LRA Table 2 contains information concerning whether or not the AMRs identified 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 LRA column seven, GALL Report Volume 2 Item, correlates 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. 3.0.2.3 UFSAR Supplement Consistent with the SRP-LR for the AMRs and AMPs that it reviewed, the staff also reviewed the UFSAR supplement, which summarizes the applicants programs and activities for managing the effects of aging for the period of extended operation, as required by 10 CFR 54.21(d). 3.0.2.4 Documentation and Documents Reviewed In its review, the staff used the LRA, LRA supplements, the SRP-LR, and the GALL Report. During the onsite audit, the staff also examined the applicants justifications to verify that the applicants activities and programs will adequately manage the effects of aging on SCs. The staff also conducted detailed discussions and interviews with the applicants license renewal project personnel and others with technical expertise relevant to aging management. 3-6

3.0.3 Aging Management Programs SER Table 3.0.3-1 presents the AMPs credited by the applicant and described in LRA Appendix B and subsequent LRA supplements. The table also indicates the SSCs that credit the AMPs and the GALL AMP with which the applicant claimed consistency and shows the SER section in which the staffs evaluation of the program is documented. Table 3.0.3-1 VYNPS Aging Management Programs VYNPS AMP GALL Report GALL Report LRA Systems or Structures Staff's (LRA Section) Comparison AMPs That Credit the AMP SER Section Existing AMPs Bolting Integrity Consistent with XI.M18 reactor vessel, internals, and 3.0.3.2.19 Program (B.1.31) enhancement reactor coolant system; ESF systems; auxiliary systems; steam and power conversion systems; SC supports Buried Piping Consistent with XI.M34 ESF systems / auxiliary 3.0.3.2.1 Inspection Program exceptions and systems (B.1.1) enhancements BWR CRD Return Line Consistent with XI.M6 reactor vessel, internals, and 3.0.3.2.2 Nozzle Program exception reactor coolant system (B.1.2) BWR Feedwater Consistent with XI.M5 reactor vessel, internals, and 3.0.3.2.3 Nozzle Program exception reactor coolant system (B.1.3) BWR Penetrations Consistent with XI.M8 reactor vessel, internals, and 3.0.3.2.4 Program exceptions reactor coolant system (B.1.4) BWR Stress Corrosion Consistent with XI.M7 reactor vessel, internals, and 3.0.3.2.5 Cracking Program exception reactor coolant system (B.1.5) BWR Vessel Inside Consistent with XI.M4 reactor vessel, internals, and 3.0.3.2.6 Diameter Attachment exception reactor coolant system Welds Program (B.1.6) BWR Vessel Internals Consistent with XI.M9 reactor vessel, internals, and 3.0.3.2.7 Program exceptions and reactor coolant system (B.1.7) enhancements Containment Leak Consistent with XI.S4 ESF systems / SC supports 3.0.3.2.8 Rate Program exception (B.1.8) Diesel Fuel Monitoring Consistent with XI.M30 auxiliary systems 3.0.3.2.9 Program exceptions and (B.1.9) enhancements 3-7

VYNPS AMP GALL Report GALL Report LRA Systems or Structures Staff's (LRA Section) Comparison AMPs That Credit the AMP SER Section Environmental Consistent X.E1 electrical and instrumentation 3.0.3.1.1 Qualification of Electric and controls Components Program (B.1.10) Fatigue Monitoring Consistent with X.M1 reactor vessel, internals, and 3.0.3.2.10 Program exceptions and reactor coolant system / ESF (B.1.11) enhancements systems / auxiliary systems / steam and power conversion systems / SC supports Fire Protection Consistent with XI.M26 auxiliary systems / SC 3.0.3.2.11 Program exceptions and supports (B.1.12.1) enhancements Fire Water System Consistent with XI.M27 auxiliary systems 3.0.3.2.12 Program exception and (B.1.12.2) enhancements Flow-Accelerated Consistent XI.M17 reactor vessel, internals, and 3.0.3.1.2 Corrosion Program reactor coolant system / ESF (B.1.13) systems / auxiliary systems / steam and power conversion systems Containment Inservice Plant-specific NA SC supports 3.0.3.3.2 Inspection Program (B.1.15.1) Inservice Inspection Plant-specific NA reactor vessel, internals, and 3.0.3.3.3 Program reactor coolant system / SC (B.1.15.2) supports Instrument Air Quality Plant-specific NA auxiliary systems 3.0.3.3.4 Program (B.1.16) Oil Analysis Program Consistent with XI.M39 ESF systems / auxiliary 3.0.3.2.13 (B.1.20) exception systems Periodic Surveillance Plant-specific NA ESF systems / auxiliary 3.0.3.3.5 and Preventive systems / SC supports Maintenance Program (B.1.22) Reactor Head Closure Consistent XI.M3 reactor vessel, internals, and 3.0.3.2.14 Studs Program reactor coolant system (B.1.23) Reactor Vessel Consistent with XI.M31 reactor vessel, internals, and 3.0.3.2.15 Surveillance Program enhancement reactor coolant system (B.1.24) Service Water Integrity Consistent with XI.M20 ESF systems / auxiliary 3.0.3.2.16 Program exceptions and systems (B.1.26) enhancement. 3-8

VYNPS AMP GALL Report GALL Report LRA Systems or Structures Staff's (LRA Section) Comparison AMPs That Credit the AMP SER Section Masonry Wall Program Consistent XI.S5 SC supports 3.0.3.1.8 (B.1.27.1) Structures Monitoring Consistent with XI.S6 SC supports 3.0.3.2.17 Program enhancements (B.1.27.2) Vernon Dam FERC Plant-specific NA SC supports 3.0.3.3.6 Inspection (B.1.27.3) System Walkdown Consistent XI.M36 reactor vessel, internals, and 3.0.3.1.9 Program reactor coolant system / ESF (B.1.28) systems / auxiliary systems / steam and power conversion systems Water Chemistry Plant-specific NA ESF systems / auxiliary 3.0.3.3.7 Control - Auxiliary systems Systems Program (B.1.30.1) Water Chemistry Consistent XI.M2 reactor vessel, internals, and 3.0.3.1.11 Control - BWR reactor coolant system / ESF Program systems / auxiliary systems / (B.1.30.2) steam and power conversion systems / SC supports Water Chemistry Consistent with XI.M21 reactor vessel, internals, and 3.0.3.2.18 Control - Closed exception reactor coolant system / ESF Cooling Water systems / auxiliary systems / Program steam and power conversion (B.1.30.3) systems New AMPs Heat Exchanger Plant-specific NA ESF systems / auxiliary 3.0.3.3.1 Monitoring Program systems (B.1.14) Non-Environmental Consistent XI.E3 electrical and instrumentation 3.0.3.1.3 Qualification and controls Inaccessible Medium-Voltage Cable Program (B.1.17) Non-Environmental Consistent XI.E2 electrical and instrumentation 3.0.3.1.4 Qualification and controls Instrumentation Circuits Test Review Program (B.1.18) 3-9

VYNPS AMP GALL Report GALL Report LRA Systems or Structures Staff's (LRA Section) Comparison AMPs That Credit the AMP SER Section Non-Environmental Consistent XI.E1 electrical and instrumentation 3.0.3.1.5 Qualification Insulated and controls Cables and Connections Program (B.1.19) One-Time Inspection Consistent XI.M32 reactor vessel, internals, and 3.0.3.1.6 Program XI.M35 reactor coolant system / ESF (B.1.21) systems / auxiliary systems

                                                         /steam and power conversion systems Selective Leaching      Consistent         XI.M33        ESF systems / auxiliary        3.0.3.1.7 Program                                                  systems (B.1.25)

Thermal Aging and Consistent XI.M13 reactor vessel, internals, and 3.0.3.1.10 Neutron Irradiation reactor coolant system Embrittlement of Cast Austenitic Stainless Steel Program (B.1.29) Metal-Enclosed Bus Consistent with XI.E4 electrical and instrumentation 3.0.3.2.20 Inspection Program exceptions and controls (B.1.32) Bolted Cable Plant-specific NA electrical and instrumentation 3.0.3.3.8 Connections Program and controls (B.1.33) 3.0.3.1 AMPs Consistent with the GALL Report In LRA Appendix B, the applicant identified the following AMPs as consistent with the GALL Report:

• Environmental Qualification of Electric Components Program
• Flow-Accelerated Corrosion Program
• Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program
• Non-Environmental Qualification Instrumentation Circuits Test Review Program
• Non-Environmental Qualification Insulated Cables and Connections Program
• One-Time Inspection Program
• Selective Leaching Program
• Masonry Wall Program 3-10
• System Walkdown Program
• Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program
• Water Chemistry Control - BWR Program 3.0.3.1.1 Environmental Qualification of Electric Components Program Summary of Technical Information in the Application. LRA Section B.1.10 describes the existing Environmental Qualification of Electric Components Program as consistent with GALL AMP X.E1, Environmental Qualification of Electric Components.

The Environmental Qualification of Electric Components Program manages component thermal, radiation, and cyclical aging by aging evaluations based on 10 CFR 50.49(f) qualification methods. As required by 10 CFR 50.49, environmental qualification components not qualified for the current license term are refurbished or replaced or their qualifications are extended prior to reaching the aging limits established in the evaluation. Aging evaluations for environmental qualification components are considered time-limited aging analyses (TLAAs) for license renewal. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The Audit and Review Report documents the details of the staff's evaluation of this AMP. The staff noted that the results of electrical equipment in LRA Section 4.4 indicate that the aging effects of the Environmental qualification electrical equipment identified as a TLAA will be managed during the extended period of operation in accordance with 10 CFR 54.21(c)(1)(iii). However, no information is provided on the attributes of a re-analysis of aging evaluation to extend the qualification life of electrical equipment identified as TLAA. The important attributes of a re-analysis are the analytical methods, the data collection, the reduction methods, the underlying assumptions, the acceptance criteria, and corrective actions. The staff asked the applicant to provide information on these important attributes of re-analysis of an aging evaluation of electrical equipment identified in the TLAA to extend the qualification in accordance with 10 CFR 50.49(e). In its response, the applicant stated that it would supplement VYNPS AMP B.1.10 to include the Environmental Qualification Component Re-analysis Attributes specified in GALL AMP X.E1 as follows: Environmental Qualification Component Re-analysis Attributes: The re-analysis of an aging evaluation is normally performed to extend the qualification by reducing excess conservatism incorporated in the prior evaluation. Re-analysis of an aging evaluation to extend the qualification of a component is performed on a routine basis in accordance with 10 CFR 50.49(e) as part of an Environmental Qualification program. While a component life limiting condition may be due to thermal, radiation, or cyclical aging, the vast majority of component aging limits are based on thermal conditions. Conservatism may exist in aging evaluation parameters, such as the assumed ambient temperature of the component, an unrealistically low activation energy, 3-11

or in the application of a component (de-energized versus energized). The re-analysis of an aging evaluation is documented according to the station's quality assurance program requirements, which requires verification of assumptions and conclusions. As already noted, important attributes of a re-analysis include analytical methods, data collection and reduction methods, underlying assumptions, acceptance criteria, and corrective actions (if acceptance criteria are not met). These attributes are discussed below. Analytical Methods: The analytical models used in the re-analysis of an aging evaluation are the same as those previously applied during the prior evaluation. The Arrhenius methodology is an acceptable model for performing a thermal aging evaluation. The analytical method used for a radiation aging evaluation demonstrates qualification for the total integrated dose (that is, normal radiation dose for the projected installed life plus accident radiation dose). For license renewal, one acceptable method of establishing the 60-year normal radiation dose is to multiply the 40-year normal radiation dose by 1.5 (that is 60 years/40 years). The result is added to the accident radiation dose to obtain the total integrated dose for the component. For cyclical aging, a similar approach may be used. Other methods may be justified on a case-by-case basis. Data Collection and Reduction Methods: Reducing excess conservatism in the component service conditions (for example, temperature, radiation, cycles) used in the prior aging evaluation is the chief method used for a re-analysis. Temperature data used in an aging evaluation is to be conservative and based on plant design temperatures or on actual plant temperature data. When used, plant temperature data can be obtained in several ways, including monitors used for technical specification compliance, other installed monitors, measurement made by plant operators during rounds, and temperature sensors on large motors (while the motor is not running). A representative number of temperature measurement are conservatively evaluated to establish the temperatures used in an aging evaluation. Plant temperature data may be used in an aging evaluation in different ways, such as (a) directly applying the plant temperature data in the evaluation, or (b) using the plant temperature data to demonstrate conservatism when using plant design temperature for an evaluation. Any changes to material activation energy values as part of a re-analysis are to be justified on a plant-specific basis. Similar methods of reducing excess conservatism in the component service conditions used in prior aging evaluation can be used for radiation and cyclical aging. Underlying Assumption: Environmental qualification component aging evaluation contain sufficient conservatism to account for most environmental changes occurring due to plant modifications and events. When unexpected adverse conditions are identified during operational or maintenance activities that affect the normal operating environment of a qualified component, the affected environmental qualification component is evaluated and appropriate corrective actions are taken, which may include changes to the qualification bases and conclusions. 3-12

Acceptance Criteria and Corrective Actions: The re-analysis of an aging evaluation could extend the qualification of the component. If the qualification cannot be extended by re-analysis, the component is to be refurbished, replaced, or re-qualified prior to exceeding the period for which the current qualification remains valid. A re-analysis is to be performed in a timely manner (that is, sufficient time is available to refurbish, replace, or re-qualify the component if the re-analysis is unsuccessful. The staff finds the applicant's response acceptable because a re-analysis of the attributes, which is consistent with the attribute recommended in the GALL Report. In a letter dated January 4, 2007, the applicant revised VYNPS AMP B.1.10 to include the Environmental Qualification Component Re-Analysis Attributes as described above. The staff also asked the applicant to address how it will analyze and evaluate the equipment in the Environmental Qualification of Electric Components Program for 60 years per 10 CFR 54.21. The staff asked the applicant to address in its response whether the environmental conditions (both ambient and accident) resulting from the extended power uprate (EPU) will be used as the basis for the analysis and evaluation going forward. In addition, the staff asked the applicant to confirm that the approach described in the response to this question is consistent with its LRA. In its response, the applicant stated that VYNPS will continue to use the analysis and evaluation techniques described in 10 CFR 50.49 and Institute of Electrical and Electronics Engineers (IEEE) 323 during the renewal period. The equipment in the Environmental Qualification of Electric Components Program is both active and passive. The equipment in the Environmental Qualification of Electric Components Program documentation has recently been updated to reflect the normal and accident environments in accordance with EPU conditions. The program considers equipment degradation from EPU radiation dose, normal and accident (loss of coolant accident (LOCA), high energy line break) temperatures as well as cycling, pressure, humidity, etc. For the period of extended operation, the Environmental Qualification of Electric Components Program requires VYNPS to update the environmental qualification document to reflect the additional life. The environmental conditions (both ambient and accident) resulting from EPU are the basis for evaluations and analysis going forward. This is consistent with the description of the Environmental Qualification of Electric Components Program in the LRA. The staff finds the applicant's response acceptable because the Environmental Qualification of Electric Components Program is an existing program established to meet VYNPS commitments in accordance with 10 CFR 50.49. The program considers equipment degradation from EPU radiation dose, normal and accident (LOCA, high energy line break) temperatures as well as cycling, pressure, humidity, etc. Compliance with 10 CFR 50.49 provides reasonable assurance that components can perform their intended functions during accident conditions after experience the effects of inservice aging. The staff reviewed those portions of the applicants Environmental Qualification of Electric Components Program for which the applicant claimed consistency with GALL AMP X.E1 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicants Environmental Qualification of Electric Components Program provided assurance that the applicants environmental qualification program provided assurance of aging management of thermal, radiation, and cyclical for electrical equipment, 3-13

important to safety and located in harsh environments. The staff finds the applicants Environmental Qualification of Electric Components Program acceptable because it conformed to the recommended GALL AMP X.E1, Environmental Qualification of Electric Components. Operating Experience. LRA Section B.1.10 states that Licensee Event Report 97-20 notified the staff of significant program deficiencies including nonconservative analytical methods. Supplementary and confirmatory analyses were completed because the environmental qualification analyses were determined to be nonconservative. This operating experience demonstrates that the corrective action process documents program deficiencies and tracks corrective actions when necessary. QA audits in 2000 and 2002 identified deficiencies in maintenance and content of program documentation. However, a 2004 QA audit and engineering program health report determined that the program is effective and that its administration and maintenance meet regulatory requirements and commitments. The applicant further states that the VYNPS program is in compliance with 10 CFR 50.49. Therefore, the VYNPS program is effective at managing aging effects for electric components. The staff reviewed the operating experience provided in the LRA and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. On the basis of its review of the operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicants Environmental Qualification of Electric Components Program will adequately manage the aging effects that are identified in the LRA for which this AMP is credited. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.10, the applicant provided the UFSAR supplement for the Environmental Qualification of Electric Components Program. The staff reviewed this section and 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 Environmental Qualification of Electric 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). 3-14

3.0.3.1.2 Flow-Accelerated Corrosion Program Summary of Technical Information in the Application. LRA Section B.1.13 describes the existing Flow-Accelerated Corrosion Program as consistent with GALL AMP XI.M17, Flow-Accelerated Corrosion. This program applies to safety-related and nonsafety-related carbon steel components in systems carrying two phase or single phase high energy fluid greater than or equal to two percent of plant operating time. The program, based on Electric Power Research Institute (EPRI) Report NSAC-202L-R2 recommendations for an effective flow-accelerated corrosion program, predicts, detects, and monitors Flow-accelerated corrosion in plant piping and other pressure-retaining components. This program includes (a) an evaluation to determine critical locations, (b) initial operational inspections to determine the extent of thinning at these locations, and (c) followup inspections to confirm predictions or repair or replace components as necessary. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP. The staff reviewed the VYNPS Flow-accelerated corrosion procedures and noted that VYNPS performs wall thickness examinations in areas adjacent to those locations where the detected wall thickness was less than predicted, and in similar locations in parallel trains, as recommended by EPRI Report NSAC-202L-R2. The staff noted that VYNPS had performed calculations to determine the required minimum wall thickness for all classes of piping, safety-related and nonsafety-related, and applied the results to its Flow-accelerated corrosion procedure acceptance criteria. The impact of the 20 percent increased power level on Flow-accelerated corrosion was evaluated in the SER for the EPU license amendment. In the staffs SER for EPU dated March 2, 2006, the staff found that the CHECWORKS modeling would be updated to account for uprated power conditions. The staff also noted that VYNPS calculates the number of operating cycles remaining before each component reaches its minimum allowable wall thickness, as recommended by CHECWORKS. In a letter dated January 31, 2004, VYNPS provided information on typical expected wall thickness changes due to Flow-accelerated corrosion in the main steam drains, moisture separator drains, and turbine across around piping subsequent to power uprate. In this letter, the applicant provided its expected changes to its Flow-Accelerated Corrosion Program. The applicant described the changes to criteria for the selection of piping components for inspection and sample expansion guidelines. The staff noted that the selection criteria were based on CHECWORKS database, Vermont Yankee operation, and industry operating experience on pipe wall thinning. Computer programs, such as CHECWORKS, used to predict and track pipe wall thicknesses as a result of Flow-accelerated corrosion are benchmarked against a general range of plant parameters including flow rate. The staff reviewed the changes to the Flow-Accelerated Corrosion Program and finds that after change the parameters remain in the range that was benchmarked. The staff concluded that, with the changes, the applicant will be able to reestablish the wear rate for those piping which may be impacted by power uprate. On this basis, the staff found the applicants modified Flow-Accelerated Corrosion Program acceptable. 3-15

The staff reviewed those portions of the applicants Flow-Accelerated Corrosion Program for which the applicant claimed consistency with GALL AMP XI.M17 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicants Flow-Accelerated Corrosion Program provided assurance that the aging effects due to Flow-accelerated corrosion will be adequately managed during the period of extended operation. The staff finds the applicants Flow-Accelerated Corrosion Program acceptable because it conformed to the recommended GALL AMP XI.M17, Flow-Accelerated Corrosion. Operating Experience. LRA Section B.1.13 states that recent inspection results (refueling outage (RFO) 23) revealed that repairs or replacements were not necessary. Turbine cross-around piping inspections found that 1995 repairs mitigated the rate of erosion and that wall thickness is acceptable. Absence of loss of material due to Flow-Accelerated Corrosion Program proves that the program is effective for managing loss of material for carbon steel lines containing high-energy fluids. Past repairs, replacements, and modifications also have been effective in mitigating Flow-Accelerated Corrosion Program. QA surveillances and self-assessments from 1999 to 2004 revealed no issues or findings that could impact program effectiveness. The applicant also stated that its has a comprehensive operating experience program that monitors industry events and issues, and assesses them for applicability to its own operations. In addition, VYNPS has a corrective action program (CAP) that is used to track, trend, and evaluate significant plant issues and events. Those issues and events, whether from the industry or plant-specific, that are potentially significant to the Flow-Accelerated Corrosion Program at VYNPS are evaluated. The Flow-Accelerated Corrosion Program is augmented, as appropriate, when these evaluations show that changes to this program will enhance its effectiveness. In addition, the applicant stated that NRC inspection reports, audits, self assessments, and the CAP for VYNPS were reviewed for pertinent information; however, no findings indicating that the Flow-Accelerated Corrosion Program was ineffective were identified. Some findings identified Flow-Accelerated Corrosion Program weaknesses, which resulted in corrective actions and program enhancements. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the applicants Flow-Accelerated Corrosion Program, with the corrective actions and enhancements mentioned above, has been effective in identifying, monitoring, and correcting the effects of Flow-accelerated corrosion and can be expected to ensure that piping wall thickness will be maintained above the minimum required by design. On the basis of its review of the operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicants Flow-Accelerated Corrosion Program will adequately manage the aging effects that are identified in the LRA for which this AMP is credited. 3-16

The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.14, the applicant provided the UFSAR supplement for the Flow-Accelerated Corrosion Program. The staff reviewed this section and 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 Flow-Accelerated 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). 3.0.3.1.3 Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program Summary of Technical Information in the Application. LRA Section B.1.17 describes the new Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program as consistent with GALL AMP XI.E3, Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements. In this program, periodic actions like inspecting for water collection in cable manholes and conduit and draining water as needed will be taken to prevent cable exposure to significant moisture. In-scope medium-voltage cables exposed to significant moisture and voltage will be tested for an indication of the condition of the conductor insulation. The specific type of test will be determined prior to the initial test. The program will be implemented prior to the period of extended operation. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP. The staff noted that GALL AMP XI.E3, in accordance with the detection of aging effects program element, recommends that the inspection for water collection should be performed based on actual plant experience with water accumulation in the manhole. However, the inspection frequency should be at least once every two years. In the program basis document, in accordance with the same attribute, VYNPS requires inspection for water collection in cable manholes and conduit at least once every two years. It was not clear to the staff that actual plant experience would be considered in the manhole inspection frequency. The staff asked the 3-17

applicant to explain how actual plant experience was considered in the manhole inspection frequency, as consistent with the GALL Report's recommendation. In its response, the applicant stated that Non-EQ Inaccessible Medium-Voltage Cable Program will be revised to include the following: VYNPS inspection for water accumulation in manholes is conducted by a plant procedure. An evaluation per the Corrective Action Process will be used to determine the need to revise manhole inspection frequency based on inspection results. The staff finds the applicants response acceptable because actual plant operating experience will be used to determine the manhole inspection frequency. However, the inspection frequency should be at least once every two years. This is consistent with GALL AMP XI.E3. In a letter dated July 14, 2006, the applicant revised LRA Section B.1.17 as described above. The staff also noted that GALL AMP XI.E3, in accordance with the program description, recommends, in part, that periodic actions be taken such as inspecting for water collection in cable manholes and draining water, as needed, to prevent cables from being exposed to significant moisture. The above actions are not sufficient to assure water is not trapped elsewhere in the raceways. In addition to the periodic actions, in-scope inaccessible medium-voltage cables are tested to verify the condition of the conductor insulation. In the program basis document, in accordance with the same attribute, VYNPS stated that periodic actions will be taken to prevent cables from being exposed to significant moisture, such as inspecting for water collection in cable manholes and draining water, as needed. In-scope medium-voltage cables exposed to significant moisture and voltage will be tested to provide an indication of the condition of the conductor insulation. It was not clear to the staff if periodic action would be used to preclude cable testings. The staff asked the applicant to confirm that the intent of its Non-EQ Inaccessible Medium-Voltage Cable Program is to test in-scope cables and inspect water accumulation regardless of whether or not water accumulates in the manholes. In its response, the applicant stated that the intent of its Non-EQ Inaccessible Medium-Voltage Cable Program is to inspect for water in manholes and to test in-scope medium voltage cables. The staff finds the applicants response acceptable. In addition, the staff noted that GALL AMP XI.E3 recommends testing of all non-environmental qualification inaccessible medium-voltage cables within the scope of license renewal. The staff asked the applicant to confirm that all inaccessible medium-voltage cables within the scope of license renewal are tested. The applicant responded that all of the in-scope medium-voltage cables will be subject to testing per the program requirements. The staff finds the applicants response acceptable because it is consistent with the GALL Report's recommendation. Further, the staff noted that GALL AMP XI.E3, in accordance with the parameters monitored/inspected program element, recommends that the specific type of test performed will be determined prior to the initial test. Moreover, that it is a proven test for detecting deterioration of the insulation system due to wetting such as power factor, partial discharge test, or polarization index, as described in an EPRI technical report, or other test that is state-of-the-art 3-18

at the time the test is performed. In the program basis document, in accordance with the same attribute, the applicant stated that the specific type of test performed will be determined prior to initial test. The staff asked the applicant to revise its program basis document to be consistent with the GALL Report or explain how it ensured that the test to be performed will be in accordance with industry guidelines. In its response, the applicant stated that it would revise the LRA to replace the last sentence in the Program Description with: The specific type of test to be performed will be determined prior to the initial test and is to be a proven test for detecting deterioration of the insulation system due to wetting as described in the EPRI technical report or other testing that is state-of-the-art at the time the test is performed. The staff finds the applicants response acceptable because it is consistent with the GALL Report in that the type of test will be in accordance with industrial guidelines as described in EPRI technical report or another test that is state-of-the-art at the time the test is performed. In a letter dated July 14, 2006, the applicant revised LRA Section B.1.17 as described above. Finally, the staff noted that GALL AMP XI.E3 defines a medium-voltage cable as having a voltage level from 2kV to 35kV. The applicants Non-EQ Inaccessible Medium-Voltage Cable Program defines a medium-voltage cable as having a voltage level from 2kV to 15kV. The staff asked the applicant to revise the scope of inaccessible medium-voltage levels to be consistent with the GALL Report or provide a technical basis of why the water tree phenomenon is not applicable to a voltage level greater than 15kV. In its response, the applicant stated that VYNPS does not have any in-scope medium-voltage cable that is greater than 15kV. The applicant also stated that they would revise LRA Section B.1.17 to state medium-voltage cables include cables with operating voltage level from 2kV to 35kV. The staff finds the applicants response acceptable because the scope of the program would be consistent with the GALL Report. In a letter dated July 14, 2006, the applicant revised LRA Section B.1.17 as described above. The underground power lines, which run from the adjacent Vernon Hydroelectric Station (VHS) to station switchgear, have been designated as the station blackout (SBO) alternate ac (AAC) source. Thus, they are used to meet SBO requirements 10 CFR 50.63. During the audit and review, the staff asked the applicant if all of these cables were included within the scope of VYNPS AMP B.1.17. The applicant replied that the underground power lines that run from the Vernon Dam switchyard to VYNPS safety-related buses are included in VYNPS AMP B.1.17. The staff noted that there are other underground medium-voltage cables which run from VHS generators to the Vernon Dam switchyard that are not included within the scope of the applicants Non-EQ Inaccessible Medium-Voltage Cable Program. The staff issued RAI 3.6.2.2-N-08-3 to address this concern, which is evaluated in SER Section 3.6.2.3.2. The staff reviewed those portions of the applicant's Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program for which the applicant claimed consistency with GALL AMP XI.E3 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicant's Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program provided assurance of aging management of conductor insulation due to significant moisture while energized. The staff finds the applicant's Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program acceptable 3-19

because it conforms to the recommended GALL AMP XI.E3, Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements. Operating Experience. LRA Section B.1.17 states that there is no operating experience for the new Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program. During the audit and review, the staff noted that GALL AMP X1.E3, in accordance with operating experience, has shown that cross-linked polyethylene or high molecular weight polyethylene insulation materials are most susceptible to water tree formation. The formation and growth of water trees varies directly with operating voltage. Also, minimizing exposure to moisture minimizes the potential for the development of water treeing. As additional operating experience is obtained, lessons learned can be used to adjust the program, as needed. In VYNPS AMP B.1.17, the applicant stated that its Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program is a new program for which there is no operating experience. The staff asked the applicant to address industrial and plant-specific operating experience and confirm that the review did not reveal any degradation not bound by industrial experience. In its response, the applicant stated that it would replace the operating experience discussion in LRA Section B.1.17 with the following: This program is a new AMP. Industry experience that forms the basis for the program is described in the operating experience element of NUREG-1801 program description. VYNPS plant-specific operating has been reviewed against the industry operating experience identified in NUREG-1801. Although VYNPS has not experienced all of the aging effects listed in NUREG-1801, the VYNPS program will manage all of the aging effects identified in the operating experience section of NUREG-1801. The program is based on the program description in NUREG-1801, which in turn is based on relevant industry operating experience. As such, this program will provide assurance that effects of aging will be managed such that applicable components will continue to perform their intended functions consistent with the CLB for the period of extended operation. As additional operating experience is obtained, lessons learned can be used to adjust the program, as needed. The staff finds the applicant's response acceptable because the applicant reviewed the plant-specific operating experience against the industry experience identified in the GALL Report. As additional operating experience is obtained, lessons learned can be used to adjust the program elements. In a letter dated July 14, 2006, the applicant revised LRA Section B.1.17 in accordance with operating experience as described above. The applicant also stated that operating experience at VYNPS is controlled by its operating experience program procedure. VYNPS plant-specific operating experience was reviewed in the applicable program basis document, as documented in the Audit and Review Report, and the results showed that VYNPS has had operating experience that is consistent with industry experience or with the GALL Report aging mechanisms. No new aging mechanism or operating experience was found that is not consistent with industry experience and the GALL Report. 3-20

The operating experience program procedure includes the following components: Operating experience - Information received from various industry sources that describes events, issues, equipment failures, that may represent opportunities to apply lessons learned to avoid negative consequences or to recreate positive experience as applicable. Internal operating experience - Operating experience that originates as a condition report or request from plant personnel which warrants consideration for possible Entergy-wide distribution. Internal operating experience can originate from any Entergy plant or headquarters. Impact Evaluation - Analysis of an operating experience event or problem that requires additional information and research to determine impact or potential impact, as it relates to plant condition and/or configuration. Impact evaluations are typically documented with a condition report. Condition report action items and corrective actions are used to confirm program effectiveness and to modify the program as needed. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. In addition, the staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.19, the applicant provided the UFSAR supplement for the Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program. The applicant committed (Commitment #13) to implement its Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program by March 21, 2012. The staff reviewed LRA A.2.1.19 and determined that, upon the implementation of Commitment

1. 13, 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 Non-Environmental Qualification Inaccessible Medium-Voltage Cable 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). 3-21

3.0.3.1.4 Non-Environmental Qualification Instrumentation Circuits Test Review Program Summary of Technical Information in the Application. LRA Section B.1.18 describes the new Non-Environmental Qualification Instrumentation Circuits Test Review Program as consistent with GALL AMP XI.E2, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits. The Non-Environmental Qualification Instrumentation Circuits Test Review Program will assure maintenance of the intended functions of instrument cables exposed to adverse environments of heat, radiation, and moisture consistent with the CLB through the period of extended operation. An adverse environment is significantly more severe than the service environment specified for the cable. This program will consider the technical information and guidance of NUREG/CR-5643, Institute of Electrical and Electronics Engineers Std. P1205, SAND96-0344, and EPRI TR-109619. The program will start prior to the period of extended operation. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP. The staff noted that GALL AMP XI.E2 recommends that in cases where the calibration or surveillance program does not include a cabling system in the testing circuit (cables disconnected during instrument calibration), the cable testing frequency shall be determined by the applicant based on an engineering evaluation, but the test frequency shall be at least one every ten years. LRA Section A.2.1.20 stated that for cable disconnected during instrument calibration, testing is performed at least once every 10 years. As documented in the Audit and Review Report, the staff asked the applicant to explain how an engineering evaluation is considered in the test frequency; in order to be consistent with the GALL Report's recommendation. In its response, the applicant stated that it would revise LRA Section B.1.18 as follows: The first test of neutron monitoring system cables that are disconnected during instrument calibration shall be completed before the period of extended operation and subsequent tests will occur at least every 10 years. In accordance with the CAP, an engineering evaluation will be performed when test acceptance criteria are not met and corrective actions, including modified inspection frequency, will be implemented to ensure that the intended functions of the cables can be maintained consistent with the CLB for the period of extended operation. The staff finds the applicants response acceptable because an engineering evaluation will be considered in the test frequency to ensure that the intended function of in-scope cables is maintained. This is consistent with GALL AMP XI.E2. In a letter dated July 14, 2006, the applicant revised LRA Section B.1.18 as described above. 3-22

The staff also noted that GALL AMP XI.E2, in accordance with the corrective actions program element, recommends that an evaluation is to consider the significance of the test results, the operability of the component, the reportability of the event, the extent of the concern, the potential root causes for not meeting the test acceptance criteria, the corrective actions required, and likelihood of recurrence, in addition to 10 CFR Part 50, Appendix B requirements. The applicable program basis document, in accordance with the same program element, only referred to requirements of 10 CFR Part 50 Appendix B to address the corrective actions. The staff asked the applicant to revise the corrective actions program element to be consistent with the GALL Report or provide a justification of why such specific actions were not necessary. The applicant responded that VYNPS AMP B.1.18, in accordance with the CAP element, stated that an engineering evaluation will be performed when the test acceptance criteria are not met in order to ensure that the intended functions of the electrical cables can be maintained consistent with current license basis. This evaluation is performed in accordance with the Entergy corrective action process procedure. This procedure provides the stated elements to consider including the extent of the concern, the potential root causes for not meeting the test acceptance criteria, the corrective action required, and likelihood of recurrence. The staff finds the applicant's response acceptable because corrective actions per the corrective action process procedure will require specific actions consistent with to the GALL AMP XI.E2 corrective actions. In addition, GALL AMP XI.E2, in accordance with the scope of program element, stated that this program applies to electrical cables and connections used in circuits with sensitive, high-voltage, low-level signal (i.e., radiation monitoring), and nuclear instrumentation that are subject to an AMR. As documented in the Audit and Review Report, the applicable program basis document, in accordance with the same program element, did not include the high-range radiation monitoring cables. The staff asked the applicant to clarify why high-range radiation monitor cables were not included within the scope of its Non-EQ Instrumentation Circuits Test Review Program. The applicant responded, as documented in the Audit and Review Report, that cables and connections in the high-range reactor building area monitoring system, support a license renewal intended function. However, the entire length of these cables are environmental qualified and do not require aging management since they are subject to replacement based on a qualified life. The staff reviewed the applicants response and finds the applicants response acceptable because the entire length of high-range radiation monitoring cables are environmentally qualified, subject to 10 CFR 50.49 requirements, and do not require an AMR. Furthermore, GALL AMP XI.E2, in accordance with the parameters monitored/inspected program element, stated that the parameters monitored are determined from the specific calibration, surveillance, or testing performed and are based on the specific instrumentation in accordance with surveillance or being calibrated as documented in plant procedures. As documented in the Audit and Review Report, the applicable program basis document, in accordance with the same attribute, stated that the results from calibration or surveillance of components within the scope of license renewal will be reviewed. The parameters reviewed will be based on the specific instrumentation circuit in accordance with surveillance or being calibrated, as documented in the plant calibration or surveillance procedures. The staff asked the applicant to explain why the review of calibration results belong to the parameters monitored/inspected attribute and why the parameter for cable testing was not mentioned. The staff also asked the applicant to confirm that cable testing will be performed on in-scope cables disconnected during instrument calibration. In its response, the applicant stated that its Non-EQ 3-23

Instrumentation Circuits Test Review Program basis document will be revised in accordance with the parameters monitored/inspected program element to state that the parameters monitored are determined from the specific calibration, surveillance or testing performed and are based on the specific instrumentation circuit in accordance with surveillance or being calibrated, as documented in plant procedures. Cable testing is performed by plant procedures on cables within the scope of GALL AMP XI.E2 that are disconnected during instrument calibration. The staff verified, as documented in the Audit and Review Report, that the applicant incorporated this change in the program basis document. The staff finds the applicant's response acceptable because the revised parameters monitored/inspected program element is consistent with GALL AMP XI.E2. The staff reviewed those portions of the applicant's Non-Environmental Qualification Instrumentation Circuits Test Review Program for which the applicant claimed consistency with GALL AMP XI.E2 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicant's Non-Environmental Qualification Instrumentation Circuits Test Review Program provided assurance of aging management of conductor insulation due to heat, radiation, or moisture for electrical cables used in instrumentation circuits. The staff finds the applicant's Non-Environmental Qualification Instrumentation Circuits Test Review Program acceptable because it conformed to the recommended GALL AMP XI.E2. Operating Experience. LRA Section B.1.18 states that there is no operating experience for the new Non-Environmental Qualification Instrumentation Circuits Tests Review Program. Industry and plant-specific operating experience will be considered in the development of this program, and future operating experience will be incorporated into the program appropriately. During the audit and review, the staff noted that GALL AMP XI.E2, in accordance with the operating experience, stated that 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. Changes in instrument calibration can be caused by degradation of the circuit cable and are a possible indication of electrical cable degradation. The vast majority of site specific and industry wide operating experience regarding neutron flux instrumentation circuits is related to cable/connector issues inside containment near the reactor vessel. The staff asked the applicant to address industrial and plant-specific operating experience and confirm that plant-specific operating experience did not reveal any degradation not bound by industry experience. In its response, the applicant stated that operating experience discussion in LRA Section B.1.18 would be replaced with the following: This program is a new AMP. Industry experience that forms the basis for the program is described in the operating experience element of NUREG-1801s program description. VYNPS plant-specific operating have been reviewed against the industry operating experience identified in NUREG-1801. Although VYNPS has not experienced all of the aging effects listed in NUREG-1801, the VYNPS program will manage all of the aging effects identified in the Operating Experience section of NUREG-1801. The program is based on the program description in NUREG-1801, which in turn is based on relevant industry operating experience. As such, this program will provide assurance that effects of aging will be managed such that applicable components will continue to perform their intended functions consistent with the CLB for the period of extended operation. 3-24

As additional operating experience is obtained, lessons learned can be used to adjust the program, as needed. The staff finds the applicant's response acceptable because the applicant reviewed the plant-specific operating experience against the industry experience identified in the GALL Report. As additional operating experience is obtained, lessons learned can be used to adjust the program elements. In a letter dated July 14, 2006, the applicant revised LRA Section B.1.18 in accordance with operating experience as described above. The applicant also stated that operating experience at VYNPS is controlled by its operating experience program procedure. The staff reviewed the plant-specific operating experience in the applicable program basis document and the results showed that VYNPS has had operating experience that is consistent with industry experience or with the GALL Report aging mechanisms. No new aging mechanism or operating experience was found that is not consistent with industry experience and the GALL Report. The operating experience program procedure includes the following components: Operating experience - Information received from various industry sources that describes events, issues, equipment failures, that may represent opportunities to apply lessons learned to avoid negative consequences or to recreate positive experience as applicable. Internal operating experience - Operating experience that originates as a condition report or request from plant personnel which warrants consideration for possible Entergy-wide distribution. Internal operating experience can originate from any Entergy plant or headquarters. Impact Evaluation - Analysis of an operating experience event or problem that requires additional information and research to determine impact or potential impact, as it relates to plant condition and/or configuration. Impact evaluation are typically documented with a condition report. Condition report action items and corrective actions are used to confirm program effectiveness and to modify the program as needed. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.20, the applicant provided the UFSAR supplement for the Non-Environmental Qualification Instrumentation Circuits Test Review Program. 3-25

The applicant committed (Commitment #14) to implement its Non-Environmental Qualification Instrumentation Circuits Test Review Program by March 21, 2012. The staff reviewed LRA Section A.2.1.20 and determined that, upon the implementation of Commitment #14, the information in the UFSAR supplement is an adequate summary of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Non-Environmental Qualification Instrumentation Circuits Test Review Program, the staff finds all program elements consistent with the GALL Report with the addition of Commitment #14. 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). 3.0.3.1.5 Non-Environmental Qualification Insulated Cables and Connections Program Summary of Technical Information in the Application. LRA Section B.1.19 describes the new Non-Environmental Qualification Insulated Cables and Connections Program as consistent with GALL AMP XI.E1, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements. The Non-Environmental Qualification Insulated Cables and Connections Program will assure maintenance of the intended functions of insulated cables and connections exposed to adverse environments of heat, radiation, and moisture consistent with the CLB through the period of extended operation. An adverse environment is significantly more severe than the service environment specified for the insulated cable or connection. A representative sample of accessible insulated cables and connections within the scope of license renewal will be inspected visually for such cable and connection jacket surface anomalies as embrittlement, discoloration, cracking, or surface contamination. The technical basis for sampling will be determined in accordance with EPRI TR-109619, Guideline for the Management of Adverse Localized Equipment Environments. The program will start prior to the period of extended operation. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP. The staff noted that, in accordance with the program description, GALL AMP XI.E1, stated that the program described herein is written specifically to address cables and connections at plants whose configuration is such that most (if not all) cables and connections installed in adverse localized environments are accessible. This program, as described, can be thought of as a sampling program. Selected cables and connections from accessible areas (the inspection sample) are inspected and represent, with assurance, all cables and connections in the adverse localized environments. If an unacceptable condition or situation is identified for a cable or connection in the inspection sample, a determination is made as to whether the same condition or situation is applicable to other accessible or inaccessible cables or connections. In the 3-26

Non-EQ Insulated Cables and Connections Program in accordance with the same element, the applicant stated that a representative sample of accessible insulated cables and connections, within the scope of license renewal, will be visually inspected for cable and connection jacket surface anomalies such as embrittlement, discoloration, cracking or surface contamination. The technical basis for sampling will be determined using an EPRI technical report document. The staff asked the applicant to explain the technical basis for cable sampling to be consistent with the GALL Report's program description. In its response, the applicant stated that to clarify the technical basis for sampling, the sampling discussion in LRA Section B.1.19 for the Non-Environmental Qualification Insulated Cables and Connections Program would be revised to read as follows: This program addresses cables and connections at plants whose configuration is such that most cables and connections installed in adverse localized environments are accessible. This program can be thought of as a sampling program. Selected cables and connections from accessible areas will be inspected and represent, with assurance, all cables and connections in the adverse localized environments. If an unacceptable condition or situation is identified for a cable or connection in the inspecting sample, a determination will be made as to whether the same condition or situation is applicable to other accessible cables or connections. The sample size will be increased on an evaluation per the plant Corrective Action Process procedure. The staff finds the applicant's response acceptable because it provided the technical basis for cable sampling; these basis are consistent with the GALL Report's program description. In a letter dated July 14, 2006, the applicant revised LRA Section B.1.19 as described above. In addition, GALL AMP XI.E1, in accordance with the scope of program element, stated that the inspection program applies to accessible electrical cables and connections within the scope of license renewal that are installed in adverse localized environment caused by heat or radiation in the presence of oxygen. The Non-EQ Insulated Cables and Connections Program program basis document, in accordance with the same element, stated that this program will include accessible insulated cables and connections installed in structures within the scope of license renewal and prone to adverse localized environments. It was not clear to the staff if the scope of the program only included insulated cables and connections installed in-scope structures located in adverse localized environment or insulated cables and connections within the scope of license renewal that are installed in adverse localized environments. The staff asked the applicant to clarify the scope of the program, as appropriate. In its response, the applicant stated that in a structure meant inside the plant, not outside. It would revise LRA Section B.1.19 Program Description to include the following: The program applies to accessible electrical cables and connections within the scope of license renewal that are installed in adverse localized environments caused by heat or radiation in the presence of oxygen. The staff finds the applicant's response acceptable because the scope of VYNPS AMP B.1.19 will be consistent with the scope of GALL AMP XI.E1 and it will remove the confusion as described above. In a letter dated July 14, 2006, the applicant revised the program description in LRA Section B.1.19 as described above. 3-27

The staff reviewed those portions of the applicant's Non-Environmental Qualification Insulated Cables and Connections Program for which the applicant claimed consistency with GALL AMP XI.E1 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicant's Non-Environmental Qualification Insulated Cables and Connections Program provided assurance of aging management of cables and connectors within the scope of license renewal exposed to adverse localized temperature, moisture, or radiation environments with the presence of oxygen. The staff finds the applicant's Non-Environmental Qualification Insulated Cables and Connections Program acceptable because it conformed to the recommended GALL AMP XI.E1. Operating Experience. LRA Section B.1.19 states that there is no operating experience for the new Non-Environmental Qualification Insulated Cables and Connections Program. During the audit and review, the staff noted that GALL AMP XI.E1 stated that operating experience has shown that adverse localized environments caused by heat or radiation for electrical cables and connections may exist next to or above (within 3 feet of) steam generators, pressurizers or hot process pipes, such as feedwater (FW) lines. These adverse localized environments have been found to cause degradation of the insulating materials on electrical cables and connections that are visually observable, such as color changes or surface cracking. These visual indications can be used as indicators of degradation. The staff asked the applicant to provide industrial and plant operating experience for this program and confirm that the review of plant operating experience did not reveal any degradation not bound by industry experience. In its response, the applicant stated that it would replace the operating experience discussion in LRA Section B.1.19 with the following: This program is a new aging management program. Industry experience that forms the basis for the program is described in the operating experience element of NUREG-1801 program description. VYNPS plant-specific operating experience has been reviewed against the industry operating experience identified in NUREG-1801. Although VYNPS has not experienced all of the aging effects listed in NUREG-1801, the VYNPS program will manage all of the aging effects identified in the Operating Experience section of NUREG-1801. The program is based on the program description in NUREG-1801, which in turn is based on relevant industry operating experience. As such, this program will provide assurance that effects of aging will be managed such that applicable components will continue to perform their intended functions consistent with the CLB for the period of extended operation. As additional operating experience is obtained, lessons learned can be used to adjust the program, as needed. The staff finds the applicant's response acceptable because the applicant reviewed the plant-specific operating experience against the industry experience identified in the GALL Report. As additional operating experience is obtained, lessons learned will be used to adjust the program elements as needed. In a letter dated July 14, 2006, the applicant revised LRA Section B.1.19 in accordance with operating experience as described above. The applicant also stated that operating experience at VYNPS is controlled by its operating experience program procedure. VYNPS plant-specific operating experience was reviewed in the 3-28

applicable program basis document, as documented in the Audit and Review Report, and the results showed that VYNPS has had operating experience that is consistent with industry experience or with the GALL Report aging mechanisms. No new aging mechanism or operating experience was found that is not consistent with industry experience and the GALL Report. Operating experience at VYNPS is controlled by an operating experience program procedure. The program includes the following components: Operating experience - Information received from various industry sources that describes events, issues, equipment failures, that may represent opportunities to apply lessons learned to avoid negative consequences or to recreate positive experience as applicable. Internal operating experience - Operating experience that originates as a condition report or request from plant personnel which warrants consideration for possible Entergy-wide distribution. Internal operating experience can originate from any Entergy plant or headquarters. Impact Evaluation - Analysis of an operating experience event or problem that requires additional information and research to determine impact or potential impact, as it relates to plant condition and/or configuration. Impact evaluation are typically documented with a condition report. Condition report action items and corrective actions are used to confirm program effectiveness and to modify the program as needed. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. In addition, the staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.21, the applicant provided the UFSAR supplement for the Non-Environmental Qualification Insulated Cables and Connections Program. The applicant committed (Commitment #15) to implement its Non-EQ Insulated Cables and Connections Program by March 21, 2012. The staff reviewed LRA Section A.2.1.21 and determined that, upon the implementation of Commitment #15, the information in the UFSAR supplement is an adequate summary of the program, as required by 10 CFR 54.21(d). 3-29

Conclusion. On the basis of its audit and review of the applicant's Non-Environmental Qualification Insulated Cables and Connections Program, the staff finds all program elements consistent with the GALL Report with the addition of Commitment #15. 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). 3.0.3.1.6 One-Time Inspection Program Summary of Technical Information in the Application. LRA Section B.1.21 and subsequent LRA supplements describe the new One-Time Inspection Program as consistent with GALL AMPs XI.M32, One-Time Inspection, and XI.M35, One-Time Inspection of ASME Code Class 1 Small-Bore Piping. The One-Time Inspection Program will be implemented prior to the period of extended operation. The one-time inspection activity for small-bore piping in the reactor coolant system and associated systems that form the reactor coolant pressure boundary (RCPB) will be comparable to GALL AMP XI.M35. The program will verify AMP effectiveness and confirm the absence of aging effects for the following:

• water chemistry control programs
• internal carbon steel surfaces exposed to indoor air in the standby gas treatment system
• diesel fuel monitoring program
• non-piping components without metal fatigue analysis
• oil analysis program
• carbon steel retired in place system components in the area around containment penetration X-21
• small bore piping in the reactor coolant system and associated systems that form the reactor coolant pressure boundary
• reactor vessel flange leakoff lines
• main steam flow restrictors (cast austenitic stainless steel)

The elements of the program include (a) determination of the sample size based on an assessment of materials of fabrication, environment, plausible aging effects, and operating experience; (b) identification of the inspection locations in the system or component based on the aging effect; (c) determination of the examination technique, including acceptance criteria that would be effective in managing the aging effect for which the component is examined; and (d) evaluation of the need for followup examinations to monitor the progression of any aging degradation. 3-30

Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP. The staff asked the applicant to clarify how VYNPS does volumetric examinations of small bore piping socket welds. In a letter dated July 6, 2006, the applicant committed (Commitment # 16) to include an addition to its One-Time Inspection Program. Specifically, the applicant committed to a destructive or non-destructive examination of one (1) socket welded connection using techniques proven by past industry experience to be effective for the identification of cracking in small bore socket welds. Furthermore, the applicant committed that, should an inspection opportunity not occur (e.g., socket weld failure or socket weld replacement), a susceptible small-bore socket weld will be examined either destructively or non-destructively prior to entering the period of extended operation. Since small-bore piping socket weld connection will be either destructively or non-destructively examined at least once, the staff found the applicants response acceptable. Upon further discussions, the staff concluded that the destructive or non-destructive examination of one or more socket welds would not contribute significant additional information on the condition of the socket welds. Socket welds fail by vibrational fatigue with cracks initiating from their inside surfaces. The time required for fatigue crack initiation is very long compared to the time to propagate through a wall. Therefore, a surface examination or destructive examination of a socket weld is unlikely to detect problems. In addition, there is no history of significant socket weld failures. In its letter dated March 12, 2007, the applicant revised Commitment #16 to remove references to socket welds. In addition, as discussed further in SER Sections 3.2.2.1.3 and 3.3.2.1.9, the applicant provided an amendment to its LRA in a letter dated July 14, 2007, to state that its One-Time Inspection Program will verify the effectiveness of the Oil Analysis Program, and the Diesel Fuel Monitoring Program by confirming the absence of loss of material, cracking and fouling, where applicable. The applicant also stated in the LRA that when evidence of an aging effect is revealed by a one-time inspection, routine evaluation of the inspection results will identify appropriate corrective actions. The inspection will be performed within the 10 years prior to the period of extended operation. The staff reviewed those portions of the applicants One-Time Inspection Program for which the applicant claimed consistency with GALL AMP XI.M32 and GALL AMP XI.M35 and found that they are consistent with these GALL AMPs. On the basis of its review, the staff concludes that the applicants One-Time Inspection Program provided assurance that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly as not to affect the intended function of the component or structure. The staff finds the applicants One-Time Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M32, One-Time Inspection and GALL AMP XI.M35, One-Time Inspection of ASME Code Class 1 Small-Bore Piping. 3-31

Operating Experience. LRA Section B.1.21 states that there is no operating experience for the new One-Time Inspection Program. Industry and plant-specific operating experience will be considered in the development of this program, as appropriate. The staff confirmed that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.23, the applicant provided the UFSAR supplement for the One-Time Inspection Program. In addition, the applicant stated in a letter dated January 4, 2007, that a one-time inspection activity is used to verify the effectiveness of the water chemistry control programs by confirming that unacceptable cracking, loss of material, and fouling is not occurring on components within systems covered by water chemistry control programs [LRA Sections A.2.1.34, A.2.1.35, and A.2.1.36]. The applicant committed (Commitment #16) to implement its One-Time Inspection Program by March 21, 2012. The staff reviewed LRA Section A.2.1.23 and determined that, upon the implementation of Commitment #16, the information in the UFSAR supplement is an adequate summary 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 finds all program elements consistent with the GALL Report with the addition of Commitment #16. 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 Selective Leaching Program Summary of Technical Information in the Application. LRA Section B.1.25 describes the new Selective Leaching Program as consistent with GALL AMP XI.M33, Selective Leaching of Materials. The Selective Leaching Program will ensure the integrity of components made of cast iron, bronze, brass, and other alloys exposed to raw water, treated water, or groundwater that may cause selective leaching. The program will include a one-time visual inspection and hardness measurement of selected components that may be susceptible to determine whether loss of material due to selective leaching occurs and whether the loss will affect the ability of the 3-32

components to perform their intended function for the period of extended operation. The program will start prior to the period of extended operation. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The Audit and Review Report documents the details of the staff's evaluation of this AMP. The staff reviewed those portions of the applicants Selective Leaching Program for which the applicant claimed consistency with GALL AMP XI.M33 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicants Selective Leaching Program provided assurance that this aging effect will be adequately managed during the period of extended operation. The staff finds the applicants Selective Leaching Program acceptable because it conforms to the recommended GALL AMP XI.M33, Selective Leaching of Materials. Operating Experience. LRA Section B.1.25 states that there is no operating experience for the new Selective Leaching Program. The staff audited VYNPS maintenance data for evidence of this aging mechanism and reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. In addition, the staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirms that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.27, the applicant provided the UFSAR supplement for the Selective Leaching Program. The applicant committed (Commitment #19) to implement its Selective Leaching Program by March 21, 2012. The staff reviewed LRA Section A.2.1.27 and determined that, upon the implementation of Commitment #19, the information in the UFSAR supplement is an adequate summary 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 Program, the staff finds all program elements consistent with the GALL Report with the addition of Commitment #19. 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). 3-33

3.0.3.1.8 Masonry Wall Program Summary of Technical Information in the Application. LRA Section B.1.27.1 describes the existing Masonry Wall Program as consistent with GALL AMP XI.S5, Masonry Wall Program. The objective of the Masonry Wall Program is to manage aging effects so that the evaluation basis established for each masonry wall within the scope of license renewal remains valid through the period of extended operation. The program includes all masonry walls performing intended functions in accordance with 10 CFR 54.4. The included walls are the 10 CFR 50.48-required walls and masonry walls in the reactor building, intake structure, control room building, and turbine building. Masonry walls are visually examined at a frequency ensuring no loss of intended function between inspections. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP. During the audit and review, the staff noted that GALL AMP XI.S5, Masonry Wall Program, in accordance with the detection of aging effects program element, has the following statement: The frequency of inspection is selected to ensure there is no loss of intended function between inspections. The inspection frequency may vary from wall to wall, depending on the significance of cracking in the evaluation basis. Unreinforced masonry walls, which have not been contained by bracing warrant the most frequent inspection, because the development of cracks may invalidate the existing evaluation basis. The staff asked the applicant to explain if the inspection frequency varies from wall to wall. The applicant stated that the inspection of masonry walls which are within the scope of license renewal, are performed each refueling outage. Upon the completion of six successive surveillance intervals during a ten -year period, the sequence of the inspections revert back to the initial sequence interval. In addition, the applicant stated that due to the lack of aging effects (new cracking) for the masonry walls through the current life of the program, no individual masonry walls receive more frequent inspections over others. However, if significant new cracking was discovered on a particular masonry wall, part of the corrective action would entail more frequent inspections. The staff finds the applicants response acceptable. A review of the applicants operating experience did not reveal a history of masonry wall aging effects. For VYNPS, due to a history of no masonry wall aging effects, the CAP is an adequate method to determine if more frequent inspections should be performed on individual masonry walls beyond the programs current 10-year cycle. The staff reviewed those portions of the applicants Structures Monitoring-Masonry Wall Program for which the applicant claimed consistency with GALL AMP XI.S5 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicants Structures Monitoring-Masonry Wall Program demonstrated that the effects of aging 3-34

of masonry block walls will be properly managed for the period of extended operation. The staff finds the applicants Structures Monitoring-Masonry Wall Program acceptable because it conformed to the recommended GALL AMP XI.S5, Masonry Wall Program. Operating Experience. LRA Section B.1.27.1 states that recent inspections (2002 and 2004) revealed no cracking of masonry walls within the scope of license renewal potentially affecting wall qualification, proving that the program is effective in managing cracking for masonry and block walls. QA surveillance and self-assessment in 2002 and 2004 revealed no issues or findings that could impact program effectiveness. The listed operating experience in which inspections revealed no cracking which could potentially affect wall qualification demonstrated that the VYNPS Masonry Wall Program is effective in ensuring that age related deterioration of masonry walls within the scope of license renewal is adequately managed to ensure that these masonry walls maintain their ability to perform their intended function. The staff reviewed a sampling of drawings for masonry walls within the scope of license renewal and finds the drawings to be of high quality. Components attached to the walls were well documented with respect to component identification, overall dimensions and relative wall location. Any identified cracks were also well mapped out on the drawings as far as relative location and width. The high quality of the masonry drawings will ensure that any aging effects (new cracks) will be identified during the inspections performed in accordance with the program. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. In addition, the staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.29, the applicant provided the UFSAR supplement for the Masonry Wall Program. The staff reviewed this section and 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 Masonry Wall 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). 3-35

3.0.3.1.9 System Walkdown Program Summary of Technical Information in the Application. LRA Section B.1.28 describes the existing System Walkdown Program as consistent with GALL AMP XI.M36, External Surfaces Monitoring. This program entails inspections of external surfaces of components subject to an AMR. The program is also credited with managing loss of material from internal surfaces where internal and external material-environment combinations are the same and external surface conditions represent internal surface conditions. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP. The staff noted that, the applicants System Walkdown procedure, one of the specific purposes of which was to observe and report system conditions, did not adequately address material degradation and leakage. Specifically, the procedure did not address the loss of material due to corrosion or material wastage, or surface or coating deterioration/degradation. Also, the procedure did not adequately address leakage or evidence of leakage from or onto surfaces. The applicant agreed that the procedure should be enhanced to include periodic system engineer inspections which are aging management oriented. The applicant added that an additional enhancement would be provided to examiners who perform the system walkdowns using the recent guidance provided in the EPRI Aging Management Field Guide document. The staff reviewed the guide and noted that it provided photos and detailed descriptions of the AERMs on the materials and in the environments that are found at nuclear power plants, and agreed that it would be a useful tool to the examiners. As discussed in SER Section 3.0.3.2.11, the applicant also committed to revise the System Walkdown Program to specify CO2 system inspections every six months. The staff reviewed those portions of the applicants System Walkdown Program for which the applicant claimed consistency with GALL AMP XI.M36 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicants System Walkdown Program provided assurance that the program will manage aging effects, e.g., the loss of material and leakage, of the external surfaces of components. The staff finds the applicants System Walkdown Program acceptable because it conformed to the recommended GALL AMP XI.M36, External Surfaces Monitoring. Operating Experience. LRA Section B.1.28 states that in 1999 a self-assessment determined that corrective actions for deficient conditions detected during system walkdowns had been effective and had received timely closeouts, assuring that the program will manage component loss of material. Peer assessment found that system engineering management had not used metrics sufficient for monitoring core functions of the department. In accordance with new oversight standards supervisors perform walkdowns with system engineers to satisfy quality expectations. Program oversight was increased during 2003, providing assurance that the program will manage component loss of material. Recent system walkdowns (2003 and 2004) of the circulating water (CW), standby liquid control (SLC), and reactor building heating, ventilation, 3-36

and air-conditioning (HVAC) systems have detected leakage or degradation prior to loss of intended function, proving that the program is effective for managing component loss of material. The applicant stated, during the audit and review, that VYNPS has a comprehensive operating experience program that monitors industry events and issues, and assesses them for applicability to its own operations. In addition, VYNPS has a CAP that is used to track, trend, and evaluate significant plant issues and events. Those issues and events, whether from the industry or plant-specific, that are potentially significant to the System Walkdown Program are evaluated. The System Walkdown Program is augmented, as appropriate, when these evaluations show that changes to this program will enhance its effectiveness. The staff reviewed a representative sample of system walkdowns. These system walkdowns indicated a higher than average number of reports dealing with the condenser and the SLC system. The applicant agreed that these were areas of concern. The staff noted that this program included thermography of plant instrumentation and the electrical components in the switchyard. The staff also reviewed the operating experience provided to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the applicant reviewed all applicable operating experience and used this experience to modify the System Walkdown Program appropriately. This should help ensure that the System Walkdown Program will manage the effects of aging in the systems and components for which the program is credited. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.32, the applicant provided the UFSAR supplement for the System Walkdown Program. The applicant committed (Commitment #24) to have the System Walkdown guidance document enhanced to perform periodic system engineer inspections of systems in-scope and subject to an AMR for license renewal in accordance with 10 CFR 54.4(a)(1) and (a)(3). Inspections shall include areas surrounding the subject systems to identify hazards to those systems. Inspections of nearby systems that could impact the subject system will include SSCs that are in-scope and subjected to an AMR for license renewal in accordance with 10 CFR 54.4 (a)(2). The applicant also committed (Commitment #35) to provide within the System Walkdown Training Program a process to document biennial refresher training of Engineers to demonstrate inclusion of the methodology for aging management of plant equipment as described in the EPRI Aging Assessment Field Guide or comparable instructional guide, by March 21, 2012. The applicant also committed (Commitment #30) to revise the System Walkdown Program to specify CO2 system inspections every six months; by March 21, 2012. 3-37

The staff reviewed LRA Section A.2.1.32 and determined that, upon the implementation of (Commitments #24, #30 and #35), the information in the UFSAR supplement is an adequate summary of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's System Walkdown Program, the staff finds all program elements consistent with the GALL Report with the addition of Commitments #24, #30, and #35. 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). 3.0.3.1.10 Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program Summary of Technical Information in the Application. LRA Section B.1.29 describes the new Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program as consistent with GALL AMP XI.M13, Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS). The purpose of the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program is to make sure that reduction of fracture toughness due to thermal aging and radiation embrittlement will not result in loss of intended function. This program will evaluate CASS components in the reactor vessel internals and require nondestructive examinations (NDEs) as appropriate. EPRI, the BWR Owners Group, and other industry groups focus on reactor vessel internals to better understand aging effects. Future Boiling Water Reactor Vessel Internals Project (BWRVIP) reports, EPRI reports, and other industry operating experience will be additional bases for evaluations and inspections in accordance with this program. This program will supplement reactor vessel internals inspections required by the BWR Vessel Internals Program for assurance that aging effects do not result in loss of the intended functions of reactor vessel internals during the period of extended operation. The program will start prior to the period of extended operation. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP. The staff reviewed those portions of the applicants Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program for which the applicant claims consistency with GALL AMP XI.M13 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicants Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program will adequately maintain the integrity of CASS components during period of extended operation. The staff finds the applicants Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program conforms to the recommended GALL AMP XI.M13, Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS). 3-38

Operating Experience. LRA Section B.1.29 states that there is no operating experience for the new Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program. The staff reviewed the operating experience provided in the program basis document, and interviewed the applicant's technical personnel to conclude that no industry operating experience with thermal aging and embrittlement of CASS has emerged. The staff finds the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.33, the applicant provided the UFSAR supplement for the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program. The applicant committed (Commitment #25) to implement its Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program by March 21, 2012. The staff reviewed LRA Section A.2.1.33 and determined that, upon the implementation of Commitment #25, the information in the UFSAR supplement is an adequate summary of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program, the staff finds all program elements consistent with the GALL Report with the addition of Commitment #25. 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 Water Chemistry Control - BWR Program Summary of Technical Information in the Application. LRA Section B.1.30.2 describes the existing Water Chemistry Control - BWR Program as consistent with GALL AMP XI.M2, Water Chemistry. The objective of this program is to manage aging effects caused by corrosion and cracking mechanisms. The program monitors and controls water chemistry in accordance with EPRI Report 1008192 (BWRVIP-130), which has three sets of guidelines for primary water, for condensate and FW, and for control rod drive (CRD) mechanism cooling water. EPRI guidelines in BWRVIP-130 also include recommendations for controlling water chemistry in the torus, condensate storage tanks, demineralized water storage tanks, and spent fuel pool. The Water 3-39

Chemistry Control - BWR Program optimizes the primary water chemistry to minimize the potential for loss of material and cracking by limiting the levels of contaminants in the reactor coolant system that could cause loss of material and cracking. Additionally, the applicant has instituted hydrogen water chemistry for the reduction of dissolved oxygen in the treated water to limit the potential for intergranular stress corrosion cracking (IGSCC) through the reduction of dissolved oxygen in the treated water. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The Audit and Review Report details the staff's evaluation of this AMP. The staff reviewed those portions of the applicants Water Chemistry Control-BWR Program for which the applicant claimed consistency with GALL AMP XI.M2 and found that they are consistent with this GALL AMP. On the basis of its review, the staff concludes that the applicants Water Chemistry Control-BWR Program provided assurance that this program will help mitigate degradation caused by corrosion and stress corrosion cracking (SCC) in components exposed to reactor or treated water. The staff finds the applicants Water Chemistry Control-BWR Program acceptable because it conformed to the recommended GALL AMP XI.M2, Water Chemistry. Operating Experience. LRA Section B.1.30.2 states that for the first 158 operating days of Cycle 24 (May - November 2004), sulfate and chloride levels in the reactor water, while within EPRI guideline acceptance criteria, were significantly higher than they had been during Cycle 23. An engineering and chemistry evaluation determined the most probable sources of chloride and sulfate ingress and the causes contributing to the extended time required to reduce reactor water chemistry to normal low levels. Corrective actions included enhanced control of chemical ingress, increased condensate and FW cleaning, and enhanced demineralizer filter replacement procedures. Resolution of higher than normal reactor water sulfate and chloride levels before they exceed EPRI guideline acceptance criteria is assurance that the program will ensure adequate water quality to preclude component loss of material, cracking, and fouling. A QA audit in 2003 revealed no issues or findings that could impact program effectiveness. The staff reviewed a chemistry audit report for April 2005 from an independent external organization and verified that it identified areas of improvement for the FW and condensate system to maintain the performance quality of the Water Chemistry Control - BWR Program. The staff also reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. 3-40

UFSAR Supplement. In LRA Section A.2.1.35, the applicant provided the UFSAR supplement for the Water Chemistry Control - BWR Program. The staff reviewed this section and determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). In addition, in a letter dated January 4, 2007, the applicant provided a revision to its LRA to explicitly state the One-Time Inspection Program activities will confirm the effectiveness of the Water Chemistry Control - BWR Program. Conclusion. On the basis of its audit and review of the applicant's Water Chemistry Control - BWR 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 AMPs Consistent with the GALL Report with Exceptions and/or Enhancements In LRA Appendix B, the applicant stated the following AMPs that are, or will be, consistent with the GALL Report, with exceptions or enhancements:

• Buried Piping Inspection Program
• BWR Control Rod Drive Return Line Nozzle Program
• BWR Feedwater Nozzle Program
• BWR Penetrations Program
• BWR Stress Corrosion Cracking Program
• BWR Vessel Inside Diameter Attachment Welds Program
• BWR Vessel Internals Program
• Containment Leak Rate Program
• Diesel Fuel Monitoring Program
• Fatigue Monitoring Program
• Fire Protection Program
• Fire Water System Program
• Oil Analysis Program
• Reactor Head Closure Studs Program
• Reactor Vessel Surveillance Program
• Service Water Integrity Program
• Structures Monitoring Program
• Water Chemistry Control - Closed Cooling Water Program
• Bolting Integrity Program
• Metal Enclosed Bus Inspection Program 3-41

For AMPs that the applicant claimed are consistent with the GALL Report, with exception(s) and/or enhancement(s), the staff performed an audit and review to confirm that program attributes or features for which the applicant claimed consistency were indeed consistent. The staff also reviewed the exception(s) and/or enhancement(s) to the GALL Report to determine whether they were acceptable and adequate. The results of the staffs audits and reviews are documented in the following sections. 3.0.3.2.1 Buried Piping Inspection Program Summary of Technical Information in the Application. LRA Section B.1.1 and LRA supplement dated March 23, 2007, describe the existing Buried Piping Inspection Program as consistent, with exceptions and enhancements, with GALL AMP XI.M34, Buried Piping and Tanks Inspection. This program includes: (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried carbon steel, stainless steel, and gray cast iron components. Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings. Buried components are inspected when excavated during maintenance. Prior to the period of extended operation, plant operating experience will be reviewed to verify that there had been an inspection within the previous ten years. There will be a focused inspection within the first 10 years of the period of extended operation unless an opportunistic inspection (or an inspection of pipe condition without excavation) occurs within this ten-year period. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions and enhancements to determine whether the AMP, with the exceptions and enhancements, remained adequate to manage the aging effects for which it is credited. The staff reviewed those portions of the Buried Piping Inspection Program for which the applicant claimed consistency with GALL AMP XI.M34 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicants Buried Piping Inspection Program provided assurance that the program will manage aging effects on the external surfaces of buried steel piping. The staff finds the applicants Buried Piping Inspection Program acceptable because it conformed to the recommended GALL AMP XI.M34, Buried Piping and Tanks Inspection, with exceptions and an enhancements. Exception 1. In LRA Section B.1.1, the applicant stated an exception to the GALL Report program element scope of program. Specifically, the exception states that: The GALL Report refers to buried steel piping and tanks. The VYNPS program does not inspect tanks. There are no buried steel tanks subject to an AMR. In addition, the applicant stated in the LRA, that preventive measures are taken at VYNPS that are in accordance with standard industry practices. The staff asked the applicant to describe the tanks at VYNPS. The applicant responded that the only below-grade tank at VYNPS that is below grade is the diesel fire pump tank, which is in a 3-42

vault, so it is not exposed to a soil environment. The only buried tank at VYNPS is the John Deere Diesel tank, which is fiberglass. The GALL Report does not identify fiberglass as a material that is subject to an AERM. These tanks are monitored by the Diesel Fuel Monitoring Program. The staff reviewed the applicants response. The applicant clarified that the only buried tank at VYNPS is fiberglass, which is not subject to the aging mechanisms identified in the GALL Report. On the basis that fiberglass is a material not subject to a loss of material and the tanks are monitored by the applicants Diesel Fuel Monitoring Program, the staff found this exception acceptable. Exception 2. In LRA Section B.1.1, the applicant stated an exception to the GALL Report program element detection of aging effects. Specifically, the exception states: Inspections via methods that allow assessment of pipe condition without excavation may be substituted for inspections requiring excavation solely for the purpose of inspection. Methods such as phased array ultrasonic testing (UT) technology provide indication of wall thickness for buried piping without excavation. Use of such methods to identify the effects of aging is preferable to excavation for visual inspection, which could result in damage to coatings or wrappings. The LRA also states that, as an alternative to examination methods that require excavation to examine buried piping, examination methods that do not require excavation may be substituted. The LRA identifies phased array UT to determine wall thickness as one such alternative. The staff asked the applicant to provide technical justification of the phased array UT examination technique and other examination methods that VYNPS planned to perform as an exception. The applicant explained that robotic crawlers that can perform phased array UT examinations are available. These UT examinations can perform piping wall thickness measurements, which provide an indication of the condition of the exterior surface of the piping being examined. While these alternative examination methods are planned to be performed to obviate the need for excavation, in the event that they detect wall thinning sufficient to indicate that the exterior piping surface is corroded or damaged, excavation will be performed in order to better evaluate the exterior surface condition, and to repair or to replace the piping, as needed. When the staff asked the applicant how buried piping would be examined when it cannot be examined by UT, due to size or material, the applicant responded that excavation and examination would be performed, as normal. On the basis that either UT or excavation will be performed to determine wall thickness of buried piping, the staff finds this exception acceptable. Enhancement 1. In LRA Section B.1.1, the applicant stated the following enhancement in meeting the GALL Report program element parameters monitored/inspected. Specifically, the enhancement stated (Commitment # 1): Guidance for performing examinations of buried piping will be enhanced to specify that coating degradation and corrosion are attributes to be evaluated. 3-43

The applicant further stated, in the LRA, that this program included examinations to detect and manage the effects of corrosion on the pressure-retaining capability of buried piping. The staff noted that a VYNPS program procedure required a general visual examination for obvious signs of settlement, joint separation, cracks (concrete pipe), obvious misalignment, etc. of buried piping. Also, the staff noted that the program procedure was very general rather than focused on coating or wrapping integrity. The staff determines that this procedure did not adequately address the GALL Report recommendation in that the average examiner would not be able to read the procedure requirements and find evidence of age-related damage to piping surfaces or coverings. The applicant will enhance plant procedure 7030 (PP 7030), Structures Monitoring Program Procedures, to provide additional guidelines for the examination of buried piping and underground structures. The enhancements include an improved definition of the scope of buried piping examinations; a requirement to define the condition of the coatings to be examined, including adhesion and discontinuities; a requirement to inspect piping underneath failed coatings; additional acceptance criteria, including rust and wall thickness; and instructions to notify engineering to perform an opportunistic examination of any buried structure uncovered during the excavation of piping. The staff finds this commitment to be acceptable, since the enhanced procedure will address the recommendations of the GALL Report. On this basis, the staff finds this enhancement acceptable since when the enhancement is implemented the Buried Piping Inspection Program will be consistent with GALL AMP XI.M34 and will provide additional assurance that the effects of aging will be adequately managed. Enhancement 2. In LRA supplement dated March 23, 2007, the applicant stated the following enhancement in meeting the GALL Report program element detection of aging effects. Specifically, the enhancement stated: Program guidance will be revised to include the following. A focused inspection will be performed within the first 10 years of the period of extended operation, unless an opportunistic inspection (or an inspection via a method that allows an assessment of pipe condition without excavation) occurs within this ten-year period. The staff reviewed the enhancement and its evaluation is documented in the VYNPS - NRC License Renewal Inspection Report 05000271/2007006. The staff determined that a focused inspection within the first 10 years of th period of extended operation is acceptable. On this basis, the staff finds this enhancement acceptable since when the enhancement is implemented the Buried Piping Inspection Program will be consistent with GALL AMP XI.M34 and will provide additional assurance that the effects of aging will be adequately managed. Operating Experience. LRA Section B.1.1, states that steel piping was excavated and inspected on several occasions during the past seven years. These inspections revealed no loss of material due to external surface corrosion. Therefore, this operating experience proves that the program manages loss of material caused by corrosion of the external surfaces of buried components. 3-44

The applicant stated, during the audit and review, that VYNPS has a comprehensive operating experience program that monitors industry events and issues, and assesses them for applicability to its own operations. In addition, VYNPS has a CAP that is used to track, trend, and evaluate significant plant issues and events. Those issues and events, whether from the industry or plant-specific, that are potentially significant to the Buried Piping Inspection Program are evaluated. The Buried Piping Inspection Program is augmented, as appropriate, when these evaluations show that changes to this program will enhance its effectiveness. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. In addition, the staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.1, the applicant provided the UFSAR supplement for the Buried Piping Inspection Program. In LRA Section A.2.1.1, the applicant stated that its Buried Piping Inspection Program included preventive measures to mitigate corrosion and inspections to manage the effects of corrosion on the pressure-retaining capability of buried carbon steel, stainless steel, and gray cast iron components. Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings. Buried components are inspected when excavated during maintenance. If trending within the CAP identified susceptible locations, the areas with a history of corrosion problems are evaluated for the need for additional inspection, alternate coating, or replacement. A focused inspection will be performed within the first 10 years of the period of extended operation, unless an opportunistic inspection (or an inspection via a method that allows an assessment of pipe condition without excavation) occurs within this ten-year period. (Commitment #44). During the audit and review, the staff asked the applicant to clarify its buried piping examination plans during the ten-year periods before and during the period of extended operation. The applicant responded to say that buried piping was last examined in 2003, which is within the final ten-year period before the period of extended operation. Therefore, even if no other buried piping is examined until the end of the current operating license, VYNPS has followed staff guidance regarding the examination of buried piping through the end of the current operating license. Regarding the period of extended operation, the applicant stated, in the LRA and the UFSAR, that a focused examination of buried piping will be performed within the first ten years of the period of extended operation, unless an opportunistic examination or an examination by an examination method that allows an assessment of the buried piping surface condition without excavation, occurs within that ten-year period. 3-45

The applicant committed (Commitment #1) to enhance guidance for performing examinations of buried piping to specify that coating degradation and corrosion are attributes to be evaluated for its Buried Piping Program by March 21, 2012. The staff reviewed LRA Section A.2.1.1, and determined that, upon the implementation of Commitment #1 and Commitment #44, the information in the UFSAR supplement is an adequate summary 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 Inspection Program, the staff determines that the AMP, with the exceptions, is adequate to manage the aging effects for which it is credited. Also, the staff reviewed the enhancements (Commitments

1. 1 and #44) and confirmed that their implementation prior to the period of extended operation would make the existing AMP consistent with the GALL 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).

3.0.3.2.2 BWR CRD Return Line Nozzle Program Summary of Technical Information in the Application. LRA Section B.1.2 describes the existing BWR CRD Return Line Nozzle Program as consistent, with exception, with GALL AMP XI.M6, BWR Control Rod Drive Return Line Nozzle. In accordance with this program, the applicant has rerouted the CRD return flow to the reactor water cleanup (RWCU) system with the rerouted line flow valved open and capped the CRD return line vessel nozzle to mitigate cracking. Inservice Inspection (ISI) examinations monitor the effects of crack initiation and growth on the intended function of the CRD return line nozzle and cap. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effects for which it is credited. The staff reviewed those portions of the BWR CRD Return Line Nozzle Program for which the applicant claimed consistency with GALL AMP XI.M6 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicants BWR CRD Return Line Nozzle Program provides assurance that aging effects within the scope of license renewal are adequately managed. The staff finds the applicants BWR CRD Return Line Nozzle Program acceptable because it conforms to the recommended GALL AMP XI.M6, BWR Control Rod Drive Return Line Nozzle, with exceptions. Exception. In LRA Section B.1.2, the applicant stated exception to the GALL Report program elements parameters monitored/inspected, detection of aging effects, and monitoring and trending. Specifically, the exception states: 3-46

VYNPS does not inspect the welded connection between the CRD return line and the RWCU system piping during each refueling outage. The applicant stated that in its SE of BWR FW and CRD return line modifications at VYNPS, NRC accepted VYNPS commitment to inspect the CRD return line to RWCU joint, by UT methods, for three consecutive refuel outages, then to reassess the inspection frequency based upon the inspection results. Inspection of the three CRD return line to RWCU welds confirmed there were no indications; and the VYNPS assessment concluded that further inspections are not required. The staff reviewed this assessment and determines that it was acceptable. In the LRA, the applicant asserted that is reasonable to maintain this exception for the period of extended operation since the CRD return line now ties into the RWCU system in a section of piping that is nonsafety-related (no license renewal function) and is not subject to an AMR. The applicant further stated that the BWR CRD Return Line Nozzle Program monitors the effects of cracking on the intended function of the CRD return line nozzle by performing ultrasonic inspection of the nozzle inner radius, nozzle to vessel weld, and nozzle to cap weld in accordance with the American Society of Mechanical Engineers (ASME) Code, Section XI, Subsection IWB. The staff noted that the inspections identified in NUREG-0619, BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking: Resolution of Generic Technical Activity A-10, for the rerouted return line are not addressed by the BWR CRD Return Line Program, and this had been appropriately identified as an exception to the referenced GALL Report program. Considering that the return line welds had been subject to enhanced inspection, that the results had been reviewed by the staff, and that the welds are in a system that is not subject to an AMR, the staff finds this exception to be acceptable. Operating Experience. LRA Section B.1.2 states that the CRD return line nozzle ultrasonic examination in October 2002 found no indications of cracking. The staff reviewed plant records of the examinations identified in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.2, the applicant provided the UFSAR supplement for the BWR CRD Return Line Nozzle Program. The staff reviewed this section and 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 BWR CRD Return Line Nozzle Program, the staff determines that those program elements for which the applicant claimed 3-47

consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justification and determines that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. 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 BWR Feedwater Nozzle Program Summary of Technical Information in the Application. LRA Section B.1.3 describes the existing BWR Feedwater Nozzle Program as consistent, with exception, with GALL AMP XI.M5, BWR Feedwater Nozzle. In accordance with this program, the applicant has replaced the original low flow control valve with a drag-type valve with improved flow characteristics, replaced the FW spargers with interference-fit thermal sleeve spargers, and installed a thermal sleeve bypass leak detection system to mitigate cracking. This program continues enhanced ISI of the FW nozzles in accordance with the requirements of ASME Code, Section XI, Subsection IWB and the recommendation of General Electric (GE) NE-523-A71-0594 to monitor the effects of cracking on the intended function of the FW nozzles. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effects for which it is credited. The staff reviewed those portions of the BWR Feedwater Nozzle Program for which the applicant claimed consistency with GALL AMP XI.M5 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicants BWR Feedwater Nozzle Program provides assurance that aging of the FW nozzles will be adequately managed. The staff finds the applicants BWR Feedwater Nozzle Program acceptable because it conforms to the recommended GALL AMP XI.M5, BWR Feedwater Nozzle, with an exception. Exception. In LRA Section B.1.3, the applicant stated an exception to the GALL Report program element preventive actions. Specifically, the exception states: Stainless steel cladding was not removed, a low-flow controller was not installed and the RWCU system was not rerouted. The LRA further states that VYNPS performs the enhanced ISI recommended by a GE guidance document to monitor the effects of cracking on the intended function of the FW nozzles and has performed system modifications to mitigate cracking. The staff reviewed the applicable portions of the program procedures for VYNPS inservice inspection and a VYNPS calculation on crack growth for the FW nozzles. In addition, the staff reviewed NVY 84-144, in which the staff provided its SE of BWR FW modifications at VYNPS 3-48

and determined that the intent of the requirements of NUREG-0619 and NEDE-21821-A had been satisfied by the modifications performed. The staff finds that FW nozzle cracking continues to be adequately managed by the existing program. On this basis, the staff finds this exception to be acceptable. Operating Experience. Section B.1.3, states that inspections following FW system modifications show no new cracking of the FW nozzle, indicating that plant modifications to reduce thermal stresses have been effective in resolving the FW nozzle cracking issue. Ultrasonic testing of the FW nozzle in October 2002 resulted in no recordable indications. Absence of recordable indications proves that the program is effective for managing FW nozzle cracking. QA assessments in 2002 and 2004 revealed no issues or findings that could impact program effectiveness. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. Data from the bypass leakage detection system continues to be used appropriately to ensure adequate conservatism in modeling the aging of the interference-fit thermal sleeve. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.3, the applicant provided the UFSAR supplement for the BWR Feedwater Nozzle Program. The staff reviewed this section and 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 BWR Feedwater Nozzle 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 its justifications and determined that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. 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 BWR Penetrations Program Summary of Technical Information in the Application. LRA Section B.1.4 describes the existing BWR Penetrations Program as consistent, with exceptions, with GALL AMP XI.M8, BWR Penetrations. 3-49

The program includes: (a) inspection and flaw evaluation conforming to the guidelines of staff-approved documents BWRVIP-27 and BWRVIP-49 and (b) monitoring and control of reactor coolant water chemistry in accordance with guidelines to ensure the long-term integrity of vessel penetrations and nozzles. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions to determine whether the AMP, with the exceptions, remained adequate to manage the aging effects for which it is credited. The GALL Report, in the preventive actions program element for GALL AMP XI.M8, stated that maintaining high water purity reduces susceptibility to SCC or intergranular stress-corrosion cracking (IGSCC) and reactor coolant water chemistry is monitored and maintained in accordance with the guidelines in BWRVIP-29. The applicant stated, in the LRA, that the applicant's reactor water chemistry is monitored and maintained in accordance with the guidelines of BWRVIP-130 to ensure the long-term integrity of vessel penetrations and nozzles. The staff reviewed the Water Chemistry Control-BWR Program and concludes that it is acceptable. The acceptance of the applicants Water Chemistry Control-BWR Program is addressed in SER Section 3.0.3.1.11. The staff reviewed those portions of the BWR Penetrations Program for which the applicant claimed consistency with GALL AMP XI.M8 and finds that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicants BWR Penetrations Program provided assurance that the applicants BWR Penetrations Program will adequately manage the aging effects. The staff finds the applicants BWR Penetrations Program acceptable because it conformed to the recommended GALL AMP XI.M8, BWR Penetrations, with exceptions. Exception 1. In LRA Section B.1.4, the applicant stated exception to the GALL Report program elements parameters monitored/inspected and detection of aging effects. Specifically, the exception states: Table IWB-2500-1 from the 1998 Edition with 2000 Addenda of ASME Code, Section XI is used to specify SLC nozzle inspections, while the GALL Report specifies the 2001 Edition with 2002 and 2003 Addenda. The applicant further stated, in the LRA, that Since ASME Code, Section XI through the 2003 Addenda has been accepted by reference in 10 CFR 50.55a, paragraph (b)(2), without modification or limitation on use of Table IWB-2500-1 from the 1998 Edition with 2000 Addenda for BWR components, use of this version is appropriate to assure that components crediting this program can perform their intended function consistent with the CLB during the period of extended operation. The staff reviewed inspection requirements and finds that there is no change for the penetration inspection requirements in IWB-2500 for the ASME Code Edition/Addendum identified in this exception. On this basis, the staff finds this acceptable. 3-50

Exception 2. In LRA Section B.1.4, the applicant stated exception to the GALL Report program element detection of aging effects. Specifically, the exception states: VYNPS examines 1/2 inch of the volume next to the widest part of the N10 nozzle to vessel weld, rather than half of the vessel wall thickness. The applicant stated, in the LRA, that Extending the examination volume into the base metal as required by ASME Code, Section XI, 1998 Edition, 2000 Addenda, Figure IWB-2500-7(b) prolongs the examination time significantly and results in no net increase in safety. The extra volume is base metal region which is not prone to inservice cracking and has been extensively examined before the vessel was put into service and during the first, second and third interval examinations. The staff asked the applicant to provide additional justification instead of referencing examination results from previous intervals. The applicant stated the inspection of the vessel penetrations to 1/2 inch versus 1/2 vessel wall thickness was consistent with ASME Code Case N-613-1 which has been endorsed by the NRC as documented in Regulatory Guide 1.147, Revision 14. As the applicants inspections are consistent with the NRC-approved ASME Code Case N-613-1, the staff finds this exception acceptable. Operating Experience. LRA Section B.1.4 states that enhanced leakage inspection (with insulation removed) of the SLC nozzle in October 2002 resulted in no recordable indications. Absence of recordable indications proves that the program is effective for managing SLC nozzle cracking. Liquid penetrant examination of instrument penetration nozzles in May 2001 resulted in no recordable indications. Absence of recordable indications proves that the program is effective for managing instrument penetration nozzle cracking. The applicant, as a participant in the BWRVIP, is committed to incorporate lessons learned from operating experience of the entire BWR fleet. The applicant evaluates BWRVIP inspection criteria and industry operating experience to determine whether the existing program should be modified. The staff reviewed the operating experience provided in the LRA and industry operating experience documented in related BWRVIP reports, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation the criterion defined in the GALL Report and in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.4, the applicant provided the UFSAR supplement for the BWR Penetrations Program. The staff reviewed this section and determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). 3-51

Conclusion. On the basis of its audit and review of the applicant's BWR Penetrations 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 it is credited. 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). 3.0.3.2.5 BWR Stress Corrosion Cracking Program Summary of Technical Information in the Application. LRA Section B.1.5 describes the existing BWR Stress Corrosion Cracking Program as consistent, with exception, with GALL AMP XI.M7, BWR Stress Corrosion Cracking. The program includes: (a) preventive measures to mitigate IGSCC and (b) inspection and flaw evaluation to monitor IGSCC and its effects on RCPB components made of stainless steel, CASS, or nickel alloy. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effects for which it is credited. The GALL Report, in the preventive actions program element for GALL AMP XI.M7, stated that maintaining high water purity reduces susceptibility to SCC or IGSCC and reactor coolant water chemistry is monitored and maintained in accordance with the guidelines in BWRVIP-29. The applicant's reactor water chemistry is monitored and maintained in accordance with the guidelines of BWRVIP-130. The staff reviewed the Water Chemistry Control-BWR Program, and concludes that it is acceptable. The acceptance of the Water Chemistry Control-BWR Program is addressed in SER Section 3.0.3.1.11. The applicant stated, that extensive piping replacement and mitigating treatments were applied throughout the austenitic piping system during the decade from 1977 to 1986 and the result of these actions is that nearly all piping, nozzles, and welds in the austenitic system are composed of resistant materials. The staff finds this meets the GALL Reports recommendation. The staff reviewed those portions of the BWR Stress Corrosion Cracking Program for which the applicant claimed consistency with GALL AMP XI.M7 and finds that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicants BWR Stress Corrosion Cracking Program provides assurance that IGSCC will be adequately managed and the intended function of the pressure boundary piping made of susceptible material will be maintained consistent with the CLB for the period of extended operation. The staff finds the applicants BWR Stress Corrosion Cracking Program acceptable because it conforms to the recommended GALL AMP XI.M7, BWR Stress Corrosion Cracking, with an exception. 3-52

Exception. In LRA Section B.1.5, the applicant stated an exception to the GALL Report program element acceptance criteria. Specifically, the exception states: The 1998 Edition with 2000 Addenda of ASME Code, Section XI, Subsection IWB-3600 is used for flaw evaluation, while the GALL Report specifies the 1986 Edition of ASME Code, Section XI, Subsection IWB-3600 for flaw evaluation. The applicant stated, in the LRA, that Since ASME Section XI through the 2003 Addenda has been accepted by the NRC in 10 CFR 50.55a, paragraph (b)(2), without modification or limitation on use of Subsection IWB-3600 from the 1998 Edition with 2000 Addenda, use of this version for flaw evaluation is appropriate to assure that components crediting this program can perform their intended function consistent with the CLB during the period of extended operation. The staff reviewed the Inservice Inspection Program, and concludes that it is acceptable. The acceptance of the applicants Inservice Inspection Program is addressed in SER Section 3.0.3.3.3. ASME Code, Section XI, Subsection IWB-3600 is part of the Inservice Inspection Program. On this basis, the staff finds this exception acceptable. Operating Experience. LRA Section B.1.5 states that liquid penetrant and ultrasonic examinations of Generic Letter (GL) 88-01 nozzle safe end welds in May 2001 and October 2002 resulted in no recordable indications. Absence of recordable indications on the nozzle safe end welds proves that the program is effective for managing cracking of austenitic stainless steel piping and components. Preventive measures to mitigate cracking, including replacement and modification of austenitic piping and components, have been approved by the staff as part of an effective SCC mitigation strategy. QA assessment in 2001 revealed no issues or findings that could impact program effectiveness. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.5, the applicant provided the UFSAR supplement for the BWR Stress Corrosion Cracking Program. The staff reviewed this section and 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 BWR Stress Corrosion Cracking 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 its justifications and determines that the AMP, with the exception, is adequate to 3-53

manage the aging effects for which it is credited. 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). 3.0.3.2.6 BWR Vessel ID Attachment Welds Program Summary of Technical Information in the Application. LRA Section B.1.6 describes the existing BWR Vessel ID Attachment Welds Program as consistent, with exception, with GALL AMP XI.M4, BWR Vessel ID Attachment Welds. The program includes: (a) inspection and flaw evaluation in accordance with the guidelines of staff-approved BWRVIP-48 and (b) monitoring and control of reactor coolant water chemistry in accordance with the guidelines of BWRVIP-130 (EPRI Report 1008192) to ensure the long-term integrity and safe operation of reactor vessel inside diameter (ID) attachment welds and support pads. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effects for which it is credited. The GALL Report, in the preventive actions program element for GALL AMP XI.M4, stated that maintaining high water purity reduces susceptibility to SCC or IGSCC and reactor coolant water chemistry is monitored and maintained in accordance with the guidelines in BWRVIP-29. The applicant stated, in the LRA, that the applicant's reactor water chemistry is monitored and maintained in accordance with the guidelines of BWRVIP-130. The staff reviewed the Water Chemistry Control-BWR Program and concluded that it is acceptable. The acceptance of the applicants Water Chemistry Control-BWR Program is addressed in Section 3.0.3.1.11 of this SER. BWRVIP-48 requires that steam dry support and feedwater sparger bracket attachment welds which use furnace-sensitized stainless steel (E 308/309 or 308L/309L) or Alloy 600 material be examined by modified VT-1 inspection. The staff asked the applicant to clarify the inspection requirements for those attachments. The applicant responded that the program procedure states clearly that these brackets are examined as if they are furnace-sensitized. The staff reviewed the applicable program procedures and determined this position is consistent with the GALL Reports recommendation. The staff reviewed those portions of the BWR Vessel ID Attachment Welds Program for which the applicant claimed consistency with GALL AMP XI.M4 and finds that they are consistent with the GALL Report AMP. Furthermore, the staff concludes that the applicants BWR Vessel ID Attachment Welds Program provides assurance that cracking will be adequately managed and the intended function of the vessel ID attachments will be maintained consistent with the current licensing basis for the period of extended operation. The staff found the applicants BWR Vessel 3-54

ID Attachment Welds Program acceptable because it conforms to the recommended GALL AMP XI.M4, BWR Vessel ID Attachment Welds, with an exception. Exception. In LRA Section B.1.6, the applicant stated an exception to the GALL Report program element parameters monitored/inspected. Specifically, the exception states: Table IWB-2500-1 from the 1998 Edition with 2000 Addenda of ASME Section XI is used, while the GALL Report specifies the 2001 Edition with 2002 and 2003 Addenda. The applicant further stated, in the LRA, that Since ASME Section XI through the 2003 Addenda has been accepted by reference in 10 CFR 50.55a paragraph (b)(2) without modification or limitation on use of Table IWB-2500-1 from the 1998 Edition with 2000 Addenda for BWR components, use of this version is appropriate to assure that components crediting this program can perform their intended function consistent with the current licensing basis during the period of extended operation. The staff reviewed the Inservice Inspection Program and concluded that it is acceptable. The acceptance of the applicants Inservice Inspection Program is addressed in Section 3.0.3.3.3 of this SER. On this basis, the staff found this exception acceptable. Operating Experience. LRA Section B.1.6 states that visual inspections of vessel ID attachment welds in October 2002 recorded no indications. Absence of recordable indications proves that the program is effective for managing cracking of vessel attachment welds. Staff inspections in 2002 and 2004 and a self-assessment in 2002 revealed no issues or findings that could impact program effectiveness. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.6, the applicant provided the UFSAR supplement for the BWR Vessel ID Attachment Welds Program. The staff reviewed this section and 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 BWR Vessel ID Attachment Welds 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 its justifications and determines that the AMP, with the exception, is adequate to 3-55

manage the aging effects for which it is credited. 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 BWR Vessel Internals Program Summary of Technical Information in the Application. LRA Section B.1.7 describes the existing BWR Vessel Internals Program as consistent, with exceptions and enhancement, with GALL AMP XI.M9, BWR Vessel Internals. The program includes (a) inspection, flaw evaluation, and repair in conformance with applicable, staff-approved, BWRVIP documents and (b) monitoring and control of reactor coolant water chemistry in accordance with the guidelines of BWRVIP-130 to ensure the long-term integrity of vessel internal components. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions and enhancement to determine whether the AMP, with the exceptions and enhancement, remained adequate to manage the aging effects for which it is credited. The staff noted that the BWR Vessel Internals Program was credited to manage the steam dryer in LRA Section 3.1. The staff noted that the BWR Vessel Internals Program does not address steam dryer in the AMP and asked the applicant to address this item. In a letter dated August 22, 2006, the applicant committed (Commitment #37) to continue inspections in accordance with the VYNPS steam dryer monitoring plan, Revision 3. These inspections incorporate the guidelines of GE-SIL-644, Revision 1 in accordance with existing procedures. The applicant will evaluate BWRVIP-139 upon approval by the staff and either include its recommendations in the BWR Vessel Internals Program or inform the staff of exceptions to that document. The GALL Report, in the preventive actions program element for GALL AMP XI.M7, stated that maintaining high water purity reduces susceptibility to SCC or IGSCC and reactor coolant water chemistry is monitored and maintained in accordance with the guidelines in BWRVIP-29 (EPRI TR-103515). The applicant's reactor water chemistry is monitored and maintained in accordance with the guidelines of BWRVIP-130. The staff reviewed the Water Chemistry Control-BWR Program, and concludes that it is acceptable. The acceptance of the applicants Water Chemistry Control Program is addressed in SER Section 3.0.3.1.11. On this basis, the staff finds this difference acceptable. The staff reviewed those portions of the BWR Vessel Internals Program for which the applicant claimed consistency with GALL AMP XI.M9 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicants BWR Vessel Internals Program 3-56

provided assurance that aging effects for vessel internals will be managed so that the systems and components within the scope of this program will continue to perform their intended functions consistent with the CLB through the period of extended operation. The staff finds the applicants BWR Vessel Internals Program acceptable because it conformed to the recommended GALL AMP XI.M9, BWR Vessel Internals, with the exceptions and enhancement. Exception 1. In LRA Section B.1.7, the applicant stated an exception to the GALL Report program elements scope of program and detection of aging effects. Specifically, the exception states: Core Shroud - For shroud horizontal welds H1, H2 and H3, VYNPS inspects 18 inches in length in each of the four quadrants from the outside diameter using EVT-1 methods. If cracks are found in a quadrant, the length is expanded in that quadrant to detect 18 inches of unflawed weld. Thus, VYNPS does not meet the BWRVIP-76 requirement to inspect both the outside and inside diameter of the welds and does not meet the requirement to inspect 100 percent of the length of the welds. Exception Note: The applicant stated, in the LRA, that The CS spargers cover H1 and H2, and grating covers the periphery of the top guide. Therefore, access to the shroud inside diameter would be through vacated fuel cells, which would result in the camera being too distant from the inspection surfaces to perform an adequate EVT-1 of H1, H2, or H3. Although no BWRVIP guidance is given for one-sided visual examinations of horizontal welds, they are inspected on a six-year frequency following the BWRVIP guidance for a one-sided EVT-1 of vertical welds. The excellent results obtained in the 1995 ultrasonic examination of welds H1, H2, and H3 (very limited indications) and the 1996 ultrasonic examination of the vertical and ring segment welds (no indications) provide additional assurance that a one sided EVT-1 is acceptable. The staff noted that the proposed outside diameter inspection cannot detect cracks initiated from the inside diameter and industry operating experience indicated that cracks have been initiated from the inside diameter. The applicant responded that one-sided EVT-1 will not be used and will follow BWRVIP-76's recommendation. In a letter dated January 4, 2007, the applicant provided an amendment to its LRA to delete the exception related to the core shroud. Specifically, the applicant revised the BWR Vessel Internals Program as follows:

1. Delete the exception to the BWR Vessel Internal Program related to the core shroud (page B-27)

2. Delete exception Note #1 on page B-29.

On the basis that this exception is deleted and the applicant will follow BWRVIP-76's recommendation, consistent with the GALL Report recommendation, the staff finds this acceptable. 3-57

Exception 2. In LRA Section B.1.7, the applicant stated exception to the GALL Report program elements scope of program and detection of aging effects. Specifically, the exception states that: Core Plate - VYNPS performs VT-3 inspection of 50 percent (15) of the top of the core plate rim hold-down bolts every other refueling outage. If access to the lower plenum becomes available, VYNPS plans to perform a VT-3 inspection of accessible rim hold-down bolt bottom locking engagement and accessible aligner pin assemblies. Thus, VYNPS does not meet the BWRVIP-25 requirement to perform enhanced VT-1 from below the core plate of 50 percent of the hold-down bolts. The applicant also stated that A baseline VT-3 examination of the tops of all 30 bolted connections was performed in 1996. Followup VT-3 examinations of tops of 50 percent of the bolted connections were performed in 1999, 2000 and 2001. None of the exams found evidence of cracking or bolting disassembly. Since the lower bolted connections are similar to the top, and there are no failed connections in the sample that is inspected, it is unlikely that a significant number of failed connections could exist in the remainder of the population. Therefore, the VYNPS inspection plan is adequate for ensuring the structural integrity of the core plate configuration to resist sliding against shear loads. The staff noted that VT-3 cannot detect cracking and asked the applicant for further justification. The staff also asked the applicant to provide the plant-specific TLAA analysis as identified in the applicants action item of BWRVIP-25. The applicant responded that there is no TLAA to support an inspection sample of 50 percent of the bolts with none cracked to assure the integrity of a critical number of bolts. In a letter dated July 6, 2006, the applicant provided Commitment #2 and Commitment #29 to address this exception. In this letter, the applicant stated that VYNPS will either install core plate wedge or complete a plant-specific analysis to determine acceptance criteria for continued inspection for core plate hold down bolting in accordance with BWRVIP-25. Since the applicant committed to either install a core plate wedge or complete a plant-specific analysis to determine acceptance criteria for continued inspection for core plate hold down bolting in accordance with BWRVIP-25, the staff finds this exception acceptable. Exception 3. In LRA Section B.1.7, the applicant stated an exception to the GALL Report program elements scope of program and detection of aging effects. Specifically, the exception states that: Core Spray - VYNPS defers inspection of the three inaccessible welds inside each of the two CS nozzles, and the P9 welds inside the CS shroud collars, until a delivery system for ultrasonic testing of the hidden welds is developed. Thus, VYNPS does not meet the BWRVIP-18 requirement to perform an ultrasonic inspection of a full target weld set every other refueling outage. 3-58

The applicant stated, in the LRA, that The three CS thermal sleeve welds in each of the two CS nozzles are full penetration butt welds, which decreases the likelihood of cracking. Inspections of similar CS piping welds, such as junction box-to-pipe and upper elbow welds, showed no indication of cracking. Integrity of the P9 welds must be considered because indications have been recorded during ultrasonic examination of collar-to-shroud welds at VYNPS. The P9 welds are creviced. All other creviced CS welds at VYNPS - the junction box cover plate welds, P1 welds and downcomer sleeve welds - show no indications of cracking. Therefore, deferral of inspection of the inaccessible welds is justified. The staff noted that BWRVIP-18 states that inspection technique development needed for the inaccessible (thermal sleeve) welds is being addressed by the BWRVIP inspection committee as a high priority item (since 1996). The staff asked the applicant to provide justification to address this exception. In a letter dated July 6, 2006, the applicant provided Commitment #36 to address this item. In this letter, the applicant stated that If technology to inspect the hidden jet pump thermal sleeve and CS thermal sleeve welds has not been developed and approved by the NRC at least two years prior to the period of extended operation, VYNPS will initiate a plant-specific action to resolve this issue. That plant-specific action may be justification that the welds do not require inspection. The staff finds this commitment to be acceptable, since the enhanced procedure will address the recommendations of the GALL Report. On the basis of this commitment, the staff finds this exception acceptable. Exception 4. In the LRA Section B.1.7, the applicant stated an exception to the GALL Report program elements scope of program and detection of aging effects. Specifically, the exception states that: Jet Pump Assembly - VYNPS uses EVT-1 inspection of six jet pump welds with UT indications. Thus, VYNPS does not meet guidance implied in BWRVIP-41 that when flaws are identified, subsequent examinations should use the same technique that originally found the flaw. VYNPS defers inspection of jet pump inaccessible welds, until a delivery system for ultrasonic testing of the hidden welds is developed. Thus, VYNPS does not meet the BWRVIP-41 requirement to perform a modified VT-1 of 100 percent of these welds over two 6-year inspection cycles and 25 percent per inspection cycle thereafter. The applicant noted that: The hidden jet pump welds are far enough into the nozzle that failure at these welds would not result in the thermal sleeve disengaging from the nozzle before the riser contacted the shroud. If the jet pump thermal sleeve or riser piping severed, it would be detected through jet pump monitoring, which alarms if the riser pipe moves more than 10 percent while at or above a core flow of 42 Mlb/hr. Therefore, deferral of inspection of the inaccessible welds is justified. 3-59

For jet pump welds, BWRVIP-41 finds EVT-1 or UT to be acceptable examination techniques. In 1996, VYNPS performed UT examinations and recorded indications in six jet pump welds. All six welds were reinspected by UT after two cycles of operation and there were no new indications or growth of existing indications. Since the reinspection demonstrated that there is no active cracking in these welds, and EVT-1 inspection will reveal cracking prior to encroachment on the weld structural integrity limit, performing subsequent inspections using the EVT-1 technique is acceptable. VYNPS will perform the EVT-1 inspections every two cycles until three successive inspections confirm no new indications or growth of existing indications, at which time VYNPS will revert to the six-year inspection interval specified in BWRVIP-41. The staff noted that the SER for BWRVIP-41 states that an AMR of the nozzle thermal sleeve (jet pump inaccessible welds) will be provided by individual applicants and asked the applicant to provide plant-specific justification/commitment to demonstrate that the weld will be adequately managed during the period of extend operation. In a letter dated July 6, 2006, the applicant provided Commitment #36 to address this item. In this letter, the applicant stated that If technology to inspect the hidden jet pump thermal sleeve and CS thermal sleeve welds has not been developed and approved by the NRC at least two years prior to the period of extended operation, VYNPS will initiate plant-specific action to resolve this issue. That plant-specific action may be justification that the welds do not require inspection. The staff finds this commitment to be acceptable, since the enhanced procedure will address the recommendations of the GALL Report. On the basis of this commitment, the staff finds this exception acceptable. The staff also noted that EVT-1 inspection cannot detect the depth of the flaw and there is no way to identify the flaw propagation with EVT-1. The staff asked the applicant to provide further justification for using EVT-1 technique. The applicant gave three reasons why there was no change in the size of the indications. The first was that the indications are not relevant and are caused by either geometry, transducer lift off or are related to metallurgical interfaces, which it states is unlikely. The second possibility is that the indications are fabrication flaws. The applicant thinks that the fabrication flaws would not have been identified since all that is required during fabrication was a PT exam. The third possibility is that the cracks are IGSCC but, the cracks are not growing. The applicant stated that the BWRVIP has stated that EVT-1 and UT are equivalent. The staff has accepted this position. The applicant also stated that before integrity of the welds was compromised, the EVT-1 examinations would be able to identify the flaws because they would be long, through-wall circumferential flaws. Furthermore, the applicant stated that flaw propagation can be confirmed through three successive examinations which is consistent with the rules in ASME Code Section XI. Finally, the applicant stated that, in addition to the above reasons, VYNPS Technical Specifications (TS) require that jet pump integrity and operability be checked daily. The staff finds that reverting to the six -year inspection frequency using the EVT-1 technique is acceptable. On this basis, the staff finds this exception acceptable. 3-60

Exception 5. In LRA Section B.1.7, the applicant stated an exception to the GALL Report program elements scope of program and detection of aging effects. Specifically, the exception states that: Control Rod Drive Housing - VYNPS performed less than 5 percent of the CRD guide tube weld exams within the first six-year interval. Thus, VYNPS does not meet the BWRVIP-47 requirement to inspect 5 percent of the CRD guide tube welds within the first six years. The applicant stated, in the LRA, that To meet the BWRVIP-47 requirement to inspect 5 percent of the CRD guide tube welds within the first six years, VYNPS would have to inspect five guide tubes. Four CRD guide tube assemblies were inspected during the first six-year period, for a total of 4.5 percent of the welds. The inspections began in RFO 22 (2001), when four guide tube assemblies were inspected, and were expected to be completed during RFO 23 (2002). Control blade change-out allows access to the interior of the CRD guide tube and, typically, there are between three and ten blade change-outs each outage. However, no control blades were changed during RFO 23. Inspecting one guide tube during RFO 23 to attain the five percent sample level would have required vacating an additional fuel cell (more fuel moves) and an added three hours for disassembly and reassembly (not counting inspection time). This hardship is not justified in terms of safety in order to raise the inspection sample from 4.5 percent to 5 percent. The BWRVIP-47 requirement to inspect 10 percent of the CRD guide tubes over the first twelve years will be met. The staff noted that the program basis document indicated VT-3 inspections were performed and asked the applicant to clarify whether EVT-1 inspection was performed to meet the baseline inspection requirements. The applicant responded that the EVT-1 inspections are conducted on control rod guide tube (CRGT)-2 and CRGT-3 in accordance with BWRVIP-47. On the basis that the inspection meets the BWRVIP-47 guidelines of 10 percent of the CRGT over the 12 years, the staff finds this exception acceptable. Exception 6. In LRA Section B.1.7, the applicant stated an exception to the GALL Report program element parameters monitored/inspected. Specifically, the exception states that: Table IWB-2500-1 from the 1998 Edition with 2000 Addenda of ASME Code, Section XI is used, while the GALL Report specifies the 2001 Edition with 2002 and 2003 Addenda. The applicant stated, in the LRA, that Since ASME Code, Section XI through the 2003 Addenda has been accepted by reference in 10 CFR 50.55a, paragraph (b)(2), without modification or limitation on use of Table IWB-2500-1 from the 1998 Edition with 2000 Addenda for BWR components, use of this version is appropriate to assure that components crediting this program can perform their intended function consistent with the CLB during the period of extended operation. 3-61

The staff reviewed the Inservice Inspection Program and concludes that it is acceptable. The acceptance of the applicants Inservice Inspection Program is addressed in SER Section 3.0.3.3.3. ASME Code, Section XI, Subsection IWB-2500 from the 1998 Edition with 2000 Addenda is part of the Inservice Inspection Program. On this basis, the staff finds this exception acceptable. Enhancement. In LRA Section B.1.7, the applicant stated the following enhancement in meeting the program element scope of program. Specifically, the enhancement states: The VYNPS top guide fluence is projected to exceed the threshold for irradiation-assisted stress corrosion cracking (IASCC) (5x1020 n/cm2) prior to the period of extended operation. Therefore, 10 percent of the top guide locations will be inspected using enhanced visual inspection technique, EVT-1, within the first 12 years of the period of extended operation, with one-half of the inspections (50 percent of locations) to be completed within the first six years of the period of extended operation. Locations selected for examination will be areas that have exceeded the neutron fluence threshold. During the audit and review, the staff noted that the applicants enhancement addresses the first 12 years of the period of extended operation and does not address the remaining period of extended operation. The staff asked the applicant to clarify the reinspection requirement. In a letter dated July 6, 2006, the applicant provided its LRA amendment to address this issue. In its letter, the applicant stated that an inspection requirement will be applied to the remaining period of extended operation. On this basis, the staff finds this enhancement acceptable since when the enhancement is implemented, the BWR Vessel Internals Program will be consistent with GALL AMP XI.M9 and will provide additional assurance that the effects of aging will be adequately managed. Operating Experience. LRA Section B.1.7 states that cracking of jet pump riser welding (RS-1) was detected during 1998 inspections. Subsequent inspections detected no new indications or growth of existing indications. Potential CS piping weld flaws also were detected during ultrasonic examination in 2001. Indications evaluated in accordance with BWRVIP-18 evaluation criteria were found acceptable. This operating experience shows that the program is effective at managing the effects of component cracking on the intended function. Visual inspections of reactor vessel internals in 2004 detected no new age-related indications. Absence of new indications shows that the program is effective at managing component aging effects on intended function. Staff inspections, self-assessments, QA audits, and evaluations of industry operating experience from 1999 through 2004 revealed no issues or findings that could impact program effectiveness. The staffs review of plant-specific operating experience revealed conditions discovered by BWR Vessel Internals Program examinations similar to those identified elsewhere in the BWR fleet. In each case, indications were evaluated and either found acceptable for further service or appropriately repaired. The BWR Vessel Internals Program is continually adjusted to account for industry experience and research. The staff finds this acceptable. 3-62

The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.7, the applicant provided the UFSAR supplement for the BWR Vessel Internals Program. The applicant committed (Commitment #37) to continue inspections in accordance with the steam dryer monitoring plan, Revision 3, in the event that the BWRVIP-139 is not approved prior to the period of extended operation; by March 21, 2012. The applicant also committed (Commitment #29), by March 21, 2012, to perform one of the following:

1. Install core plate wedges, or,

2. Complete a plant-specific analysis to determine acceptance criteria for continued inspection of core plate holddown bolting in accordance with BWRVIP-25 and submit the inspection plan to the NRC two years prior to the period of extended operation for NRC review and approval.

The applicant made a commitment (Commitment #36) that by March 12, 2012, if technology to inspect the hidden jet pump thermal sleeve and CS thermal sleeve welds has not been developed and approved by the NRC at least two years prior to the period of extended operation, VYNPS will initiate plant-specific action to resolve this issue. That plant-specific action may be justification that the welds do not require inspection. The applicant committed (Commitment #2), to inspect 15 percent of the top guide locations using enhanced visual inspection technique, EVT-1, within the first 18 years of the period of extended operation, with at least one-third of the inspections to be completed within the first 6 years and at least two-thirds within the first 12 years of the period of extended operation. Locations selected for the examination will be areas that have exceeded the neutron fluence threshold. The staff reviewed LRA Section A.2.1.7 and determines that, upon the implementation of Commitments #2, #29, #36 and #37, the information in the UFSAR supplement is an adequate summary of the program, as required by 10 CFR 54.21(d). 3-63

Conclusion. On the basis of its audit and review of the applicant's BWR Vessel Internals Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent with the addition of Commitments #2, #29, #36 and #37. 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 it is credited. Also, the staff reviewed the enhancement and confirmed that their implementation prior to the period of extended operation would make the existing AMP consistent with the GALL 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). 3.0.3.2.8 Containment Leak Rate Program Summary of Technical Information in the Application. LRA Section B.1.8 and LRA supplement dated March 23, 2007, describe the existing Containment Leak Rate Program as consistent, with exceptions, with GALL AMP XI.S4, 10 CFR 50, Appendix J. Containment leak rate tests are required for assurance that: (a) leakage through the primary reactor containment and systems and components penetrating primary containment does not exceed allowable limits in technical specifications or associated bases and (b) periodic surveillance of reactor containment penetrations and isolation valves is performed so that proper maintenance and repairs are made during the service life of the primary containment and penetrating systems and components. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exceptions, remained adequate to manage the aging effects for which it is credited. The staff reviewed those portions of the Containment Leak Rate Program for which the applicant claimed consistency with GALL AMP XI.S4 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicants Containment Leak Rate Program provided assurance that aging management and other deterioration of the containment leakage limiting boundary is appropriately managed to ensure that postulated post-accident releases are limited to an acceptable level during the period of extended operation. The staff finds the applicants Containment Leak Rate Program acceptable because it conformed to the recommended GALL AMP XI.S4, 10 CFR 50, Appendix J, with exceptions. Exception 1. In LRA Section B.1.8, the applicant stated an exception to the GALL Report program element monitoring and trending. Specifically, the exception states: The first Type A test after the April 1995 Type A test shall be performed no later than April 2010. This is a one-time extension of the NEI 94-01, 10-year Type A test interval to 15 years. NRC approved Amendment 227 to Facility Operating License DPR-28 for VYNPS to extend the primary containment integrated leak rate testing interval from 10 years to no longer than 15 years on a one-time basis. 3-64

The staff reviewed Amendment 227 to Facility Operating License DPR-28 for VYNPS, which extends the primary containment integrated leak rate testing interval from 10 years to no longer than 15 years. The staff determines that this one-time extension to the current operating license does not cover all subsequent Type A tests which must be performed at ten -year intervals. On this basis, the staff finds this exception acceptable. Exception 2. In the supplement to LRA Section B.1.8, the applicant stated an exception to the GALL Report program element acceptance criteria. Specifically, the exception states: Main steam leakage pathway contributions (leakage through all four main steam lines and the main steam drain line) are excluded from the overall integrated leakage rate Type A test measurement and from the sum of the leakage rates from Type b and Type c tests. The applicant also stated that the NRC approved Amendment 223 to Facility Operating license DPR-28 allowing this exemption from the requirements of Sections III.A and III.B of 10 CFR 50 appendix J, Option B because a separate radiological consequence term has been provided for these pathways. The revised design basis radiological consequences analyses address leakage through these pathways as individual factors, exclusive of the primary containment leakage. The staff reviewed the exception and its evaluation is documented in the VYNPS - NRC License Renewal Inspection Report 05000271/2007006. The staff determines that the requirements of Amendment 223 are being followed with the exception, On this basis, the staff finds the exception acceptable. Operating Experience. LRA Section B.1.8 states that during the most recent integrated leakage testing of primary containment, as-found and as-left test data met all applicable acceptance criteria, indicating that the program is effective at managing the effects of loss of material and cracking on primary containment components. A QA audit in 2001 revealed latent noncompliance with station administrative and requirements of 10 CFR Part 50, Appendix J. An administrative procedure noncompliance created the potential for untimely review of industry operating experience relative to the program. These issues could impact program effectiveness. However, actions to preclude recurrence of the identified conditions were implemented in accordance with the CAP and subsequent QA audits, QA surveillances, and engineering program health assessments (2003 and 2004) revealed no issues or findings that could impact program effectiveness. During the audit and review, the applicant stated that VYNPS has a comprehensive operating experience program that monitors industry events and issues, and assesses them for applicability to its own operations. In addition, VYNPS has a CAP that is used to track, to trend, and to evaluate significant plant issues and events. Those issues and events, whether industry or plant-specific, that are potentially significant to the Containment Leak Rate Program at VYNPS are evaluated. The Containment Leak Rate Program is augmented, as appropriate, when these evaluations show that changes to this program will enhance its effectiveness. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures 3-65

internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.8, the applicant provided the UFSAR supplement for the Containment Leak Rate Program. The staff reviewed this section and 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 Containment Leak Rate 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 its justifications and determines that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. 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). 3.0.3.2.9 Diesel Fuel Monitoring Program Summary of Technical Information in the Application. LRA Section B.1.9 and LRA supplement dated March 23, 2007, describe the existing Diesel Fuel Monitoring Program as consistent, with exceptions and enhancements, with GALL AMP XI.M30, Fuel Oil Chemistry. The program samples diesel fuel to maintain adequate quality to prevent corrosion of fuel systems. Exposure to such fuel oil contaminants as water and microbiological organisms is minimized by periodic draining and cleaning of selected tanks and by verifying the quality of new oil before its introduction into storage tanks. Sampling and analysis activities are in accordance with technical specifications on fuel oil purity and the guidelines of American Society for Testing and Materials (ASTM) Standards D4057-88 and D975-02 (or later revisions of these standards). Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions and enhancements to determine whether the AMP, with the exceptions and enhancements, remained adequate to manage the aging effects for which it is credited. The staff reviewed those portions of the Diesel Fuel Monitoring Program for which the applicant claimed consistency with GALL AMP XI.M30 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicants Diesel Fuel Monitoring Program provided assurance that the loss of material due to corrosion is adequately managed by monitoring and controlling conditions that would cause this aging effect and by monitoring the effectiveness of the program through surveillance and testing. The staff finds the applicants 3-66

Diesel Fuel Monitoring Program acceptable because it conformed to the recommended GALL AMP XI.M30, Fuel Oil Chemistry, with exceptions and enhancements. Exception 1. In LRA Section B.1.9, the applicant stated an exception to the GALL Report program elements scope of program and acceptance criteria. Specifically, the exception states: The guidelines of ASTM Standard D6217 are not used along with those of D2276 for determination of particulates. The applicant also stated, in the LRA, that the program uses only the guidance provided in ASTM D2276 for the determination of particulates and not both ASTM D2276 and ASTM D6217. In the LRA, the applicant further stated that the use of ASTM D2276 is consistent with the guidance provided in ASTM D975 which is specified in the VYNPS technical specifications. The staff finds that the applicant is using one of the methods (ASTM D2276) which is recommended by the GALL Report. During the audit and review, the applicant stated that the ASTM D6217 provides guidance on determining particulate contamination by sample filtration at an offsite laboratory. However, the use of ASTM D2276 provides for guidance on determining particulate contamination using a field monitor which provides for rapid assessment of changes in contamination. In addition, the applicant stated that the acceptance criteria for ASTM D2276 is more stringent than for ASTM D6217, namely 10 mg/ml versus 24 mg/ml. The staff finds the use of only ASTM D2276 to be conservative. The staff finds this exception acceptable based on using the more stringent of the ASTM standards recommended by the GALL Report with the added advantage of the quick assessment of contamination changes. Exception 2. In LRA Section B.1.9, the applicant stated exception to the GALL Report program element preventive actions. Specifically, the exception states: No additives are used beyond what the refiner adds during production. The applicant also stated, in the LRA, that VYNPS does not add biocides, stabilizers, or corrosion inhibitors to the diesel fuel. Plant-specific operating experience has not indicated significant problems related to microbiologically-influenced corrosion. Since water contamination in the diesel fuel storage tanks is minimized, the potential for MIC is limited. The applicant stated that for the past 10 years VYNPS has been buying high quality fuel oil from the same supplier. The diesel fuel is tested before delivery and then the diesel fuel in the storage tank is tested monthly. There have been no indications of diesel fuel deterioration or the presence of water or sediment. Since mold and bacteria grow in the water fuel oil interface, the applicant stated during the audit and review that based on the test results there is no need to add biocides. The staff reviewed the operating experience and sample results, and determines that MIC and breakdown of the diesel fuel have not been issues that necessitated the use of fuel additives. 3-67

Furthermore, the Diesel Fuel Monitoring Program provides for routine monitoring of the diesel fuel through monthly surveillance and trending which ensures that the presence of contamination will not go undetected. On this basis, the staff finds this exception acceptable. Exception 3. In LRA Section B.1.9, the applicant stated exception to the GALL Report program elements parameters monitored/inspected and acceptance criteria. Specifically, the exception states: Only ASTM Standard D1796 is used for determination of water and sediment, rather than Standards D1796 and D2709. The applicant also stated, in the LRA, that ASTM Standards D1796 and D2709 are used for determination of water and sediment. However, these standards describe the determination of water and sediment for oils with different viscosities. Either standard is applicable to the #2 diesel fuel oil used at VYNPS. VYNPS uses ASTM Standard D1796 for determination of water and sediment. The GALL Report recommends both ASTM Standards D1796 and D2709 for determining the water and sediment contamination in diesel fuel. Both of these standards are applicable to the diesel fuel used at VYNPS. The ASTM Standard D1796 is the method referenced in ASTM D975 which VYNPS is using in the plant technical specifications. Since either standard would be appropriate for the VYNPS diesel fuel, the staff accepted the use of ASTM D1796 to determine the water and sediment in the diesel fuel. On this basis, the staff finds this exception acceptable. Exception 4. In LRA Section B.1.9, the applicant stated an exception to the GALL Report program elements parameters monitored/inspected and acceptance criteria. Specifically, the exception states: Determination of particulates may be according to ASTM Standard D2276, rather than modified ASTM D2276 Method A. The applicant also stated, in the LRA, that the determination of particulates is based on ASTM D2276 and not the modified Method A version of D2276. The VYNPS determination of the presence of unacceptable levels of particulates is based on using a filter with a pore size of 0.8 µm which is recommended in ASTM D2276. The modified Method A version of ASTM D2276 uses a filter pore size of 3.0 µm. The staff determines that the use of a filter size of 0.8 µm instead of 3.0 µm when monitoring the presence of particulates in the diesel fuel is judged to be conservative. Based on the use of the conservative filter pore size, the staff finds the testing provides results that are equivalent or superior to those obtained using a 3.0 µm pore size as recommended in the GALL Report. On this basis, the staff finds this exception acceptable. Enhancement 1. In the supplement to LRA Section B.1.9, the applicant stated the following enhancement in meeting the program element detection of aging effects. Specifically, the enhancement states: 3-68

Ultrasonic thickness measurement of the fuel oil storage and fire pump diesel storage (day) tank bottom surfaces will be performed every 10 years during tank cleaning and inspection. The staff determines that the monthly testing of the diesel fuel quality and for the presence of water and sediment augmented by the ultrasonic thickness measurement of the diesel fuel storage tank bottom every 10 years when the tank is cleaned and inspected will ensure that significant degradation of the tank bottom surface will not go undetected. On this basis, the staff finds this enhancement acceptable since when the enhancement is implemented, Diesel Fuel Monitoring Program, will be consistent with GALL AMP XI.M30 and will provide additional assurance that the effects of aging will be adequately managed. Enhancement 2. In the supplement to LRA Section B.1.9, the applicant stated the following enhancement in meeting the program element acceptance criteria. Specifically, the enhancement stated: UT measurements of fuel oil storage and fire pump diesel storage (day) tank bottom surfaces will have acceptance criterion $ 60 percent Tnom. The applicant also stated, in the LRA, that for the ultrasonic measurements of the diesel fuel storage tank bottom thickness an acceptance criteria of 60 percent of the nominal thickness will be used. The GALL Report does not provide an acceptance criterion for the bottom surface thickness of the diesel fuel storage tank. The fuel oil tank is not pressurized so the staff judged the use of 60 percent of the nominal wall thickness provides sufficient margin to be an acceptable criterion for the ultrasonic thickness measurements. The use of this acceptance criterion will provide additional assurance that the effects of aging will be detected before the loss of intended function. On this basis, the staff finds this enhancement acceptable since when the enhancement is implemented, Diesel Fuel Monitoring Program, will be consistent with GALL AMP XI.M30 and will provide additional assurance that the effects of aging will be adequately managed. Enhancement 3. In the supplement to LRA Section B.1.9, the applicant stated the following enhancement in meeting the program element parameters monitored/inspected. Specifically, the enhancement stated: Fuel oil in the fire pump diesel storage (day) tank will be analyzed according to ASTM D975-02 and for particulates per ASTM D2276. The staff reviewed the enhancement and its evaluation is documented in the VYNPS - NRC License Renewal Inspection Report 05000271/2007006. The staff determines that performing periodic fuel oil sampling and analysis in accordance with the guidelines of the ASTM Standards is acceptable. On this basis, the staff finds this enhancement acceptable since when the enhancement is implemented, Diesel Fuel Monitoring Program, will be consistent with 3-69

GALL AMP XI.M30 and will provide additional assurance that the effects of aging will be adequately managed. Enhancement 4. In the supplement to LRA Section B.1.9, the applicant stated the following enhancement in meeting the program element parameters monitored/inspected. Specifically, the enhancement stated: Fuel oil in the john Deere diesel storage tank will be analyzed for particulates per ASTM D2276. The staff reviewed the enhancement and its evaluation is documented in the VYNPS - NRC License Renewal Inspection Report 05000271/2007006. The staff determines that performing periodic fuel oil sampling and analysis in accordance with the guidelines of the ASTM Standards is acceptable. On this basis, the staff finds this enhancement acceptable since when the enhancement is implemented, Diesel Fuel Monitoring Program, will be consistent with GALL AMP XI.M30 and will provide additional assurance that the effects of aging will be adequately managed. Enhancement 5. In the supplement to LRA Section B.1.9, the applicant stated the following enhancement in meeting the program element parameters monitored/inspected. Specifically, the enhancement stated: Fuel oil in the common portable fuel oil storage tank will be analyzed according to ASTM D975-02, per ASTM D2276 for particulates, and ASTM D1796 for water and sediment. The staff reviewed the enhancement and its evaluation is documented in the VYNPS - NRC License Renewal Inspection Report 05000271/2007006. The staff determines that performing periodic fuel oil sampling and analysis in accordance with the guidelines of the ASTM Standards is acceptable. On this basis, the staff finds this enhancement acceptable since when the enhancement is implemented, Diesel Fuel Monitoring Program, will be consistent with GALL AMP XI.M30 and will provide additional assurance that the effects of aging will be adequately managed. Operating Experience. LRA Section B.1.9 states that fuel oil sampling results from 2000, 2001, 2002, and 2003 reveal fuel oil quality maintained in compliance with acceptance criteria. A 1996 visual inspection of the fuel oil storage tank internals revealed no degradation. A 1996 ultrasonic thickness measurement of the tank bottom surface also revealed no significant degradation. Continuous confirmation of diesel fuel quality and absence of degradation in the fuel oil storage tank prove that the program is effective in preventing loss of material and cracking of fuel system components. QA surveillance in 1999 found an issue that could impact program effectiveness. However, corrective action was taken to update the program to the 2002 version of ASTM D975. There have been no other significant findings. The staff reviewed a sample of the monthly diesel fuel test data from the data highlighted in the LRA. The staff confirmed that the test results were within the acceptance criteria. Also, during the audit and review, the staff confirmed that based on a review of the plant operating experience, there were no component failures related to the quality of the diesel fuel which led to 3-70

the loss of intended function of any component. Finally, the staff reviewed VYNPS work orders. From this review the staff confirmed that a visual inspection was performed in 1996 of the fuel oil tank which revealed no degradation. In addition during this review the staff confirmed that the ultrasonic measurement in 1996 of the tank bottom surface revealed no degradation. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.9, the applicant provided the UFSAR supplement for the Diesel Fuel Monitoring Program. The applicant committed (Commitment #3) to implement the enhancement to the Diesel Fuel Monitoring Program to ensure ultrasonic thickness measurement of the tank bottom surface will be performed every 10 years during tank cleaning and inspection by March 21, 2012. The applicant committed (Commitment #4) to implement the enhancement to the Diesel Fuel Monitoring Program to specify UT measurements of TK-40-1A bottom surface will have acceptance criterion greater or equal to 60 percent Tnom by March 21, 2012. The applicant committed (Commitment #46) to implement the enhancement to the Diesel Fuel Monitoring Program to specify that fuel oil in the fire pump diesel storage (day) tank will be analyzed in accordance with ASTM D975-02 and for particulates per ASTM D2276, and fuel oil in the John Deere diesel storage tank will be analyzed for particulates per ASTM D2276 by March 21, 2012. The applicant committed (Commitment #47) to implement the enhancement to the Diesel Fuel Monitoring Program to specify fuel oil in the common portable fuel oil storage tank will be analyzed in accordance with ASTM D975-02, per ASTM D2276 for particulates, and ASTM D1796 for water and sediment by March 21, 2012. The staff reviewed LRA Section A.2.1.9 and determined that, upon the implementation of Commitments #3, #4, #46, and #47, the information in the UFSAR supplement is an adequate summary of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Diesel Fuel Monitoring Program, the staff determines that the AMP, with the exceptions and their justifications, is adequate to manage the aging effects for which it is credited. Also, the staff reviewed the enhancements (Commitments #3, #4, #46, and #47) and confirmed that their implementation, prior to the period of extended operation would make the existing AMP consistent with the GALL 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). 3-71

3.0.3.2.10 Fatigue Monitoring Program Summary of Technical Information in the Application. LRA Section B.1.11 describes the existing Fatigue Monitoring Program as consistent, with exceptions and enhancements, with GALL AMP X.M1, Metal Fatigue of Reactor Coolant Pressure Boundary. The Fatigue Monitoring Program tracks the number of critical thermal and pressure transients for selected reactor coolant system components so they do not exceed design limit on fatigue usage. The program validates analyses that explicitly assume a specified number of thermal and pressure fatigue transients by assuring that the actual effective number of transients is not exceeded. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions and enhancements to determine whether the AMP, with the exceptions and enhancements, remained adequate to manage the aging effects for which it is credited. The staff reviewed those portions of the Fatigue Monitoring Program for which the applicant claimed consistency with GALL AMP X.M1 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicants Fatigue Monitoring Program provided assurance that fatigue damage will be adequately managed. The staff finds the applicants Fatigue Monitoring Program acceptable because it conformed to the recommended GALL AMP X.M1, Metal Fatigue of Reactor Coolant Pressure Boundary, with exceptions and enhancements. Exception 1. In LRA Section B.1.11, the applicant stated an exception to the GALL Report program element preventive actions. Specifically, the exception states that: The Fatigue Monitoring Program only involves tracking the number of transient cycles and does not include assessment of the impact of reactor water environment on critical components. In the LRA, the applicant stated that the effect of the reactor water environment on fatigue [damage] is addressed as a TLAA (as described in Section 4.3.3) as opposed to being implemented within the Fatigue Monitoring Program. In its letter dated September 17, 2007, the applicant stated that the program will include assessment of the impact of reactor water environment on critical components and removed this exception from the LRA. The staff finds the removal of this exception acceptable. Exception 2. In LRA Section B.1.11, the applicant stated an exception to the GALL Report program element detection of aging effects. Specifically, the exception states that: The VYNPS program does not provide for periodic update of the fatigue usage calculations. 3-72

The applicant further stated that the VYNPS program provides for periodic assessment of the number of accumulated cycles, and that if a design cycle assumption is approached, corrective action is taken. In its letter dated September 17, 2007, the applicant stated that the program will include periodic review of accumulated transient cycles and associated updates of fatigue usage calculation, if necessary, and removed this exception from the LRA. The staff finds the removal of this exception acceptable. Enhancement 1. In LRA Section B.1.11, the applicant stated the following enhancement in meeting the program element detection of aging effects. Specifically, the enhancement stated: The VYNPS program will be modified to either require periodic update of cumulative fatigue usage factors (CUFs), or to require update of CUFs if the number of accumulated cycles approaches the number assumed in the design calculation. The staff finds this enhancement acceptable. If the first alternative is adopted, Fatigue Monitoring Program, will be consistent with GALL AMP X.M1. If the second alternative is adopted, together with the commitment to implement the use of a computerized monitoring program (which entails the establishment of a new baseline and then determines CUFs directly), an acceptable method to ensure that the effects of aging will be adequately managed is provided. Enhancement 2. In LRA Section B.1.11, the applicant stated the following enhancement in meeting the program element monitoring and trending. Specifically, the enhancement states: A computerized monitoring program (e.g., FatiguePro) will be used to directly determine CUFs for locations of interest. The staff reviewed a sample of CUF calculations and associated reports and VYNPS technical personnel confirmed that the NUREG/CR-6260 locations were among the locations of interest to be monitored. On the basis that CUFs will be determined directly on an ongoing basis, the staff finds that this enhancement will provide an acceptable method for monitoring and trending fatigue damage. The staff finds that when the enhancement is implemented, the applicants Fatigue Monitoring Program will be consistent with GALL AMP X.M1 and will provide additional assurance that the effects of aging will be adequately managed. Enhancement 3. In LRA Section B.1.11, the applicant stated the following enhancement in meeting the program element acceptance criteria. Specifically, the enhancement stated: The allowable number of effective transients will be established for monitored transients. This will allow quantitative projection of future margin. 3-73

The staff finds this enhancement acceptable since when the enhancement is implemented, the applicants Fatigue Monitoring Program will be consistent with GALL AMP X.M1 and will provide additional assurance that the effects of aging will be adequately managed. Operating Experience. In LRA Section B.1.11, the applicant stated that the condition reporting process documented the discovery of a previously unrecognized fatigue cycle applicable to reactor vessel FW nozzles. Corrective actions included revision of the cycle tracking procedure and of FW nozzle fatigue analysis calculations. This operating experience demonstrates that the corrective action process documents program deficiencies and tracks corrective actions when necessary. For recent reactor shutdowns and startups, cycle limitations did not trend toward exceeding the allowable number of cycles. This operating experience demonstrates that the program continues to monitor plant transients and to track the accumulation of these transients. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no degradation beyond industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. UFSAR Supplement. In LRA Section A.2.1.11, the applicant provided the UFSAR supplement for the Fatigue Monitoring Program. The applicant committed (Commitment #5) to modified the Fatigue Monitoring Program to require periodic update of cumulative fatigue usage factors (CUFs), or to require update of CUFs if the number of accumulated cycles approaches the number assumed in the design calculation by March 21, 2012. The applicant committed (Commitment #6) to use a computerized monitoring program (e.g., FatiguePro) will be used to directly determine CUFs for locations of interest for the Fatigue Monitoring Program by March 21, 2012. The applicant committed (Commitment #7) to established the allowable number of effective transients for monitored transients. This will allow quantitative projection of future margin for the Fatigue Monitoring Program, by March 21, 2012. The staff reviewed LRA Section A.2.1.11 and determines that, upon implementation of Commitments #5, #6, and #7, the information in the UFSAR supplement provided an adequate summary description of the program, as required by 10 CFR 54.21(d). The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. Conclusion. On the basis of its audit and review of the applicant's Fatigue Monitoring Program, the staff determines that the AMP, with the exceptions and the associated justifications, is adequate to manage the aging effects for which it is credited. Also, the staff reviewed the enhancements and confirmed that the implementation of the enhancements (Commitments #5, 3-74

1. 6, and #7) prior to the period of extended operation would result in the existing AMP being consistent with the GALL 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).

3.0.3.2.11 Fire Protection Program Summary of Technical Information in the Application. In LRA Section B.1.12.1, the applicant stated that Fire Protection Program, is an existing plant program that is consistent with GALL AMP XI.M26, Fire Protection, with exceptions and enhancements. The Fire Protection Program includes a fire barrier inspection and a diesel-driven fire pump inspection. The fire barrier inspection requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests of fire-rated doors to ensure that their operability is maintained. The diesel-driven fire pump inspection requires that the pump be periodically tested to ensure that the fuel supply line can perform its intended function. Corrective actions, confirmation process, and administrative controls in accordance with the requirements of 10 CFR 50 Appendix B are applied to the Fire Protection Program. Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. The Audit and Review Report details the staff's audit evaluation of this AMP. The staff reviewed the exceptions and enhancements and the associated justifications to determine whether the AMP, with the exceptions and enhancements, remains adequate to manage the aging effects for which it is credited. The GALL Report recommends that inspection results are acceptable if there are no visual indications (outside those allowed by approved penetration seal configuration) of cracking, separation of seals from walls and components, separation of layers of material, or ruptures or punctures of seals; no visual indications of concrete cracking, spalling and loss of material of fire barrier walls, ceilings and floors; no visual indications of missing parts, holes, and wear; and no deficiencies in the functional tests of fire doors. The staff reviewed the applicants procedure acceptance criteria and noted that they allow cracks in poured concrete barriers, fire barriers, concrete block walls, drywall, plaster, silicone foam, pyrocrete, and smoke/gas seals. The staff asked the applicant to justify the plant-specific acceptance criterias variance from that recommended by the GALL Report. The applicant responded that this acceptance criteria procedure would be revised to require that any recordable indication be identified and entered into the CAP for evaluation and subsequent action, as described below in the discussion of Enhancement 1. The GALL Report recommends that visual inspection by fire protection qualified inspectors of penetration seals in walkdowns be performed at least once every refueling cycle. The staff reviewed VYNPS procedure, examination requirements and noted that it did not address inspector qualifications. The staff asked the applicant to explain the inspector qualifications. The 3-75

applicant responded that its qualification program was being developed and will include acceptance criteria, personnel training, and qualification as a fire protection qualified individual in accordance with the standards of ANSI 45.2.6. The staff reviewed those portions of the Fire Protection Program for which the applicant claimed consistency with GALL AMP XI.M26 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicants Fire Protection Program provides assurance that the aging of fire protection components through detailed fire barrier examinations of fire barrier penetration seals, fire barrier walls, ceilings and walls, and through periodic examinations and functional tests of fire-rated doors, will be adequately managed. The Fire Protection Program also manages the aging of the diesel-driven fire pump through periodic testing, and the carbon dioxide fire suppression system through periodic examinations and testing. The staff finds the applicants Fire Protection Program acceptable because it conformes to the recommended GALL AMP XI.M26, Fire Protection, with exceptions and enhancements. Exception 1. In LRA Section B.1.12.1, the applicant stated an exception to the GALL Report program element scope of program. Specifically, the exception states that: This program is not necessary to manage aging effects for halon fire protection system components. The applicant also noted that the Halon 1301 suppression system is not subject to an AMR. Aging effects for components in the CO2 system are managed by the System Walkdown Program. The staff asked the applicant to explain statement regarding the halon fire suppression system. The applicant responded that there was no halon fire suppression system within the scope of license renewal, or that was brought in-scope resulting from requirements of 10 CFR 54.4(a)(2). The applicant explained that there is a halon fire suppression system for the computer room only, but that there are no UFSAR, TS, or 10 CFR 50, Appendix R, requirements associated with that system. The applicant further explained that VYNPS uses water spray to protect most areas that are typically protected with halon or CO2 at other nuclear power plants, except that VYNPS will limit water in areas where there is potential for water to spread radioactive contamination. In those areas, the applicant stated that fires would be fought primarily with portable dry chemical or CO2 fire extinguishers. Since there is no halon fire suppression system within the scope of license renewal, the Fire Protection Program does not discuss aging management of a halon fire suppression system. The staff asked the applicant to explain the statement regarding the CO2 fire suppression system. The applicant responded that the CO2 fire suppression system had historically been placed in the System Walkdown Program vice the Fire Protection Program. As with the halon fire suppression system, the applicant stated that there were no UFSAR TS or 10 CFR 50, Appendix R, requirements associated with the CO2 fire suppression system. The staff reviewed the applicants procedure and determines that it adequately addressed AERM as identified in the GALL Report. According to this procedure, VYNPS performs visual examinations during periodic formal walkdowns on either monthly or a six-month frequency, depending on the system; and informal walkdown results can be recorded and evaluated at any time. VYNPS has committed (Commitment #30) to revise the System Walkdown Program to specify CO2 system inspections 3-76

every six months. In its letter, dated March 23, 2007, the applicant revised its LRA to include functional testing of the CO2 system in accordance with Technical Requirements Manual (TRM) 4.13.D surveillance requirements. The staff reviewed the applicants response and concludes that there is no halon fire suppression system within the scope of license renewal and that the applicant adequately addresses the aging management of the CO2 fire suppression system with the System Walkdown Program and functional testing in accordance with their TRM 4.13.D surveillance requirements. On this basis, the staff finds this exception to be acceptable. Exception 2. In LRA Section B.1.12.1, the applicant stated an exception to the GALL Report program element detection of aging. Specifically, the exception states that: The GALL Report program stated that 10 percent of each type of penetration seal should be visually inspected at least once every refueling outage. The VYNPS program specifies inspection of approximately 25 percent of the seals (regardless of seal type) each operating cycle, with all accessible fire barrier penetration seals being inspected at least once every four operating cycles. The applicant also stated that since aging effects are typically manifested over several years, this variation in inspection frequency is insignificant. The staff asked the applicant to explain the rationale for the inspection frequency of the penetration seals. The applicant responded that the examination frequency is conservative. The staff asked the applicant to explain how it addressed inaccessible penetration seals. The applicant responded that the environment to which the inaccessible penetrations seals are exposed is similar, if not identical, to that of the accessible penetrations seals, and that it considered the condition of accessible penetration seals to be representative of the inaccessible penetration seals. Thus, inaccessible seals would not necessarily be included in any inspection expansion, when recordable indications are detected during the performance of an inspection, but would be included in replacement of accessible penetration seals, as determined by engineering evaluation. The staff evaluated the applicants response and determined that it was unacceptable to consider the inspection of accessible seals representative of inaccessible seals. In its letter, dated March 13, 2007, the applicant revised the VYNPS fire barrier penetration seal inspection program to remove the word accessible from the exception. Both GALL AMP XI.M26 and the applicants proposed program inspect a sample of each type of seal every refueling outage. By inspecting approximately 25 percent of the seals each refueling outage, the VYNPS fire barrier seal inspection program will accomplish inspection of 100 percent of the penetration seals in 6 years or four refueling outage (VYNPS refueling outage is every 18-month). GALL AMP XI.M26 recommends inspection of 100 percent of the penetration seals over 20 years. The staff evaluated the applicants program and determined that overall it meets or exceeds the penetration seal inspection frequency recommended in the GALL Report and it adequately addresses the aging mechanism requiring management of fire barrier penetration seals. On the basis of its review, the staff concludes that the VYNPS fire barrier penetration seal inspection program is effective in finding signs of penetration seal degradation during the period of 3-77

extended operation. The staff is adequately assured that the fire barrier penetration seals will be considered appropriately during plant aging management activities and will continue to perform applicable intended functions consistent with the CLB for the period of extended operation. Enhancement 1. In LRA Section B.1.12.1, the applicant stated the following enhancement in meeting the program elements parameters monitored/inspected and acceptance criteria. Specifically, the enhancement states: Procedures will be enhanced to specify that fire damper frames in fire barriers shall be inspected for corrosion. Acceptance criteria will be enhanced to verify no significant corrosion. The staff asked the applicant to explain this enhancement (Commitment #8). The applicant responded that, in the course of an evaluation conducted in preparation for license renewal, this procedure had been determined not to adequately address the concerns associated with all the AERMs, as recommended in the GALL Report. The staff reviewed the pertinent procedure and agrees that the procedure instructions and acceptance criteria did not adequately address the aging effect of corrosion. The fire dampers are in the ventilation ducts and are considered to be susceptible to corrosion. The staff also asked the applicant to clarify the stated objective of no significant corrosion. The applicant responded that any recordable indication would be forwarded to the CAP for evaluation and subsequent action. The staff reviewed the applicants response and determines that it adequately addresses the issue of corrosion of the dampers. The staff determines that the applicants response is appropriate. The staff finds this enhancement acceptable because, when the enhancement is implemented, the Fire Protection Program, will be consistent with GALL AMP XI.M26 in that it will address all AERMs, and will provide additional assurance that the effects of aging will be adequately managed. Enhancement 2. In LRA Section B.1.12.1, the applicant stated the following enhancement in meeting the program elements parameters monitored/inspected and acceptance criteria. Specifically, the enhancement stated: Procedures will be enhanced to state that the diesel engine subsystems (including the fuel supply line) shall be observed while the pump is running. Acceptance criteria will be enhanced to verify that the diesel engine did not exhibit signs of degradation while it was running; such as fuel oil, lube oil, coolant, or exhaust gas leakage. The staff asked the applicant to explain this enhancement. The applicant responded that, in the course of an evaluation conducted in preparation for license renewal, this procedure had been determined not to adequately address the concerns associated with all the AERMs, as recommended in the GALL Report. The staff reviewed the pertinent procedure and determined that the procedure instructions and acceptance criteria did not adequately address all the AERMs, as recommended in the GALL Report, and noted that the fuel supply line was not mentioned. When the staff asked the applicant about the absence of the fuel supply line, the applicant stated that evidence of corrosion inside the fuel supply line would appear as corrosion products in the fuel filter, which would result in a condition report and an evaluation. The 3-78

applicant added that the fuel condition is monitored by the Diesel Fuel Oil Monitoring Program. The applicant agreed that the procedure enhancement would be expanded to include detection of degradation of the fuel supply line (Commitment #9). The staff reviewed the applicants response and finds this enhancement acceptable. When the enhancement is implemented the Fire Protection Program, will be consistent with GALL AMP XI.M26 and will provide additional assurance that the effects of aging will be adequately managed. Operating Experience. In LRA Section B.1.12.1, the applicant stated that numerous condition reports of minor degradation of penetration seals and fire barriers show that periodic inspections effectively monitor for AERM, identify aging effects, and appropriately resolve them. QA surveillances, QA audits, and staff integrated and triennial inspections since 1999 revealed no issues or findings with impact on program effectiveness. The applicant stated that VYNPS has a comprehensive operating experience program that monitors industry events and issues, and assesses them for applicability to its own operations. In addition, VYNPS has a CAP that is used to track, trend, and evaluate significant plant issues and events. Those issues and events, whether industry or plant-specific, that are potentially significant to the Fire Protection Program are evaluated. The Fire Protection Program is augmented, as appropriate, when these evaluations show that changes to this program will enhance its effectiveness. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.12, the applicant provided the UFSAR supplement for the Fire Protection Program. The applicant committed (Commitment #8) to enhance the procedures for the Fire Protection Program to specify that fire damper frames in fire barriers shall be inspected for corrosion and to enhance the acceptance criteria to verify no significant corrosion by March 21, 2012. The applicant committed (Commitment #9) to enhance the procedures for the Fire Protection Program to state that the diesel engine subsystems (including the fuel supply line) shall be observed while the pump is running and to enhance the acceptance criteria to verify that the diesel engine did not exhibit signs of degradation while it was running; such as fuel oil, lube oil, coolant, or exhaust gas leakage, documented as Commitment #9, as described in VYNPS AMP B.1.12.1 by March 21, 2012. 3-79

The applicant committed (Commitment #30) to revise the System Walkdown Program to specify CO2 system inspections every six months by March 21, 2012. The staff reviewed LRA Section A.2.1.12 and determined that, upon implementation of Commitments #8, #9, and #30, the information in the UFSAR supplement provided 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 Fire Protection Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent with the addition of Commitments #8, #9, and #30. 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 it is credited. Also, the staff reviewed the enhancements and confirmed that their implementation prior to the period of extended operation would make the existing AMP consistent with the GALL 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). 3.0.3.2.12 Fire Water System Program Summary of Technical Information in the Application. LRA Section B.1.12.2 describes the existing Fire Water System Program as consistent, with exception and enhancements, with GALL AMP XI.M27, Fire Water System. This program applies to water-based fire protection systems consisting of sprinklers, nozzles, fittings, valves, hydrants, hose stations, standpipes, and above-ground and underground piping and components tested in accordance with applicable National Fire Protection Association (NFPA) codes and standards. Such testing assures system functionality. Many of these systems normally are maintained at required operating pressure and monitored to immediately detect leakage causing loss of system pressure and to initiate corrective actions. In addition, a sample of sprinkler heads will be inspected in accordance with the guidance of NFPA 25 (2002 Edition) Section 5.3.1.1.1, which states that, where sprinklers have been in place for 50 years, they shall be replaced or representative samples from one or more sample areas shall be submitted to a recognized testing laboratory for field service testing. NFPA 25 also provides guidance for this sampling every 10 years after initial field service testing. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception and enhancements to determine whether the AMP, with the exception and enhancements, remained adequate to manage the aging effects for which it is credited. The staff reviewed those portions of the Fire Water System Program for which the applicant claims consistency with GALL AMP XI.M27 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicants Fire Water System Program provided assurance that the aging effects for the components in the scope of its Fire Water System Program are adequately managed. The staff finds the applicants Fire Water System Program 3-80

acceptable because it conforms to the recommended GALL AMP XI.M27, Fire Water System, with exceptions and enhancements. Exception 1. In LRA Section B.1.12.2, the applicant stated an exception to the GALL Report program element detection of aging effects. Specifically, the exception states that: NUREG-1801 specifies annual fire hydrant hose hydrostatic tests. In accordance with the VYNPS program, hydrostatic test of outside hoses occurs once per 24 months; and hydrostatic test of inside hoses occurs once per three years. The staff asked the applicant to provide justification for the exception. The applicant was asked whether the 24 or 36 months is part of their CLB. In response, the applicant provided its TRM of the current licensing requirements. The staff determined that the exception was inconsistent with the TRM. In its letter, dated March 12, 2007, the applicant revised the exception to specify that fire hydrant hoses will be tested, inspected, and replaced, if necessary, in accordance with NFPA standards (Commitment #49). On the basis that this exception is revised and the applicant will perform the fire hydrant hose test, inspections, and replacement, consistent with its TRM, the staff finds this acceptable. Exception 2. In LRA Section B.1.12.2, the applicant stated an exception to the GALL Report program element detection of aging effects. Specifically, the exception states that: NUREG-1801 specifies annual gasket inspections. In accordance with the VYNPS program, visual inspection, re-racking and replacement of gaskets in couplings occurs at least once per 18 months. The staff asked the applicant to explain this exception. The applicant responded that the aging effects of gaskets are manifest over the period of several years, and that minor differences in inspection and testing frequencies are insignificant. In addition, the applicant stated that a review of the operating experience did not reveal age-related failures of the fire water system components that led to loss of intended function. However, in a letter dated January 4, 2007, the applicant provided a revision to its LRA to delete this exception and to specify that inspections of the fire hydrant gasket will be performed annually (Commitment #31). On the basis that this exception is deleted and the applicant will perform the fire hydrant gasket inspection annually, consistent with the GALL Report recommendation, the staff finds this acceptable. Exception 3. In LRA Section B.1.12.2, the applicant stated an exception to the GALL Report program element detection of aging effects. Specifically, the exception states that: NUREG-1801specifies annual fire hydrant flow tests. In accordance with the VYNPS program, verification of operability and of no flow blockage occurs at least once every three years. 3-81

The staff asked the applicant to justify the extension of the fire hydrant flow test from one year, as recommended by the GALL Report, to three years. The applicant responded that it had always performed the fire hydrant flow test on a three -year frequency, which was supported by VYNPS operational experience, that is, there was no justification for the extension. However, in a letter dated January 4, 2007, the applicant provided a revision to its LRA to delete this exception and specify that the fire hydrant flow tests will be performed annually (Commitment

1. 31).

On the basis that this exception is deleted and the applicant will perform the fire hydrant flow tests annually, consistent with the GALL Report recommendation, the staff finds this acceptable. Exception 4. In LRA Section B.1.12.2, the applicant stated an exception to the GALL Report program element detection of aging effects. Specifically, the exception states that: NUREG-1801specifies sprinkler systems inspections once every refueling outage. In accordance with the VYNPS program, visual inspection of deluge and pre-action system piping to verify their integrity occurs at least once per 24 months. Since aging effects are typically manifested over several years, differences in inspection and testing frequencies are insignificant. The staff asked the applicant to justify the extension of the visual inspection frequency from once every refueling outage (20 months), in accordance with the recommendation of the GALL Report, to 24 months. The applicant responded that the aging effects of sprinkler heads are manifest over the period of several years, and that minor differences in inspection and testing frequencies (four months) are insignificant. The staff reviewed the applicants response and operating experience. The staff finds that a loss of intended function of the sprinkler heads due to age-related failures is not likely to occur over the four additional months. On this basis, the staff finds this exception acceptable. Enhancement 1. In LRA Section B.1.12.2, the applicant stated the following enhancement in meeting the program element detection of aging effects. Specifically, the enhancement stated: A sample of sprinkler heads will be inspected using guidance of NFPA 25 (2002 Edition) Section 5.3.1.1.1. NFPA 25 also contains guidance to repeat this sampling every 10 years after initial field service testing. The staff asked the applicant to provide an explanation as to why this enhancement will provide additional assurance that the effects of aging will be adequately managed. The applicant responded that this enhancement to the LRA is written in accordance with the NFPA guidance, rather than the GALL Report recommendation; however, the applicant added that the NFPA guidance for this enhancement is essentially identical to the GALL Report recommendation. The staff reviewed the fire water system procedures and noted that VYNPS followed NFPA guidance in all aspects of sprinkler head examination. The staff finds this enhancement acceptable since when the enhancement is implemented the Fire Water System Program, will be consistent with GALL AMP XI.M27 and will provide additional assurance that the effects of aging will be adequately managed. 3-82

Enhancement 2. In LRA Section B.1.12.2, the applicant stated the following enhancement in meeting the program element detection of aging effects. Specifically, the enhancement states: Wall thickness evaluations of fire protection piping will be performed on system components using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion. These inspections will be performed before the end of the current operating term and at intervals thereafter during the period of extended operation. Results of the initial evaluations will be used to determine the appropriate inspection interval to ensure aging effects are identified prior to loss of intended function. The staff asked the applicant to provide an explanation as to why this enhancement would provide additional assurance that the effects of aging on fire water system piping would be adequately managed. The applicant responded that fire water system piping is flow tested in accordance with NFPA guidelines every three years. The applicant further responded that the recommendation to monitor wall thinning was a recommendation of the GALL Report, and that VYNPS included this enhancement to this attribute to perform wall thickness examinations of fire water system piping using volumetric examinations to identify the loss of material due to corrosion. The applicant stated that these examinations would be performed before the end of the current operating term and at intervals during the period of extended operation on an appropriate frequency that would be determined based on the initial examination results. The staff reviewed the applicants response and agrees that it adequately addresses the recommendations of the GALL Report. On this basis, the staff finds this enhancement acceptable since when the enhancement is implemented, Fire Water System Program, will be consistent with GALL AMP XI.M27 and will provide additional assurance that the effects of aging will be adequately managed. Operating Experience. LRA Section B.1.12.2 states that in 2003 open-head deluge nozzles were verified to be free of damage and free of obstructions that could inhibit the spray pattern. Absence of loss of material from the deluge nozzles proves that the program is effective for managing loss of material for water suppression fire protection system components. QA audits and staff integrated and triennial inspections from 2001 to 2004 revealed no issues or findings that could impact program effectiveness. The applicant stated, during the audit and review, that VYNPS has a comprehensive operating experience program that monitors industry events and issues, and assesses them for applicability to its own operations. In addition, VYNPS has a CAP that is used to track, trend, and evaluate significant plant issues and events. Those issues and events, whether industry or plant-specific, that are potentially significant to the Fire Water System Program are evaluated. The Fire Water System Program is augmented, as appropriate, when these evaluations show that changes to this program will enhance its effectiveness. 3-83

The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.13, the applicant provided the UFSAR supplement for the Fire Water System Program. The applicant committed (Commitment #10) to implement the enhancement to the Fire Water System Program to inspect a sample of sprinkler heads using guidance of NFPA 25 (2002 Edition) Section 5.3.1.1.1 by March 21, 2012. When sprinklers have been in place for 50 years a representative sample of sprinkler heads will be submitted to a recognized testing laboratory for field service testing1. This sample will be repeated every 10 years, by March 21, 2012. The applicant committed in (Commitment #11) to implement the enhancement to the Fire Water System Program to specify that wall thickness evaluations of fire protection piping will be performed on system components using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion by March 21, 2012. These inspections will be performed before the end of the current operating term and at intervals thereafter during the period of extended operation. Results of the initial evaluations will be used to determine the appropriate inspection interval to ensure aging effects are identified prior to loss of intended function, by March 21, 2012. The applicant committed (Commitment #31) to revise the Fire Water System Program to specify annual fire hydrant gasket inspections and flow tests by March 21, 2012. The applicant committed (Commitment #49) to revise the Fire Water System Program to specify that fire hydrant hoses will be tested, inspected, and replaced, if necessary, in accordance with NFPA standards by March 21, 2012. The staff reviewed this section and determined that, upon implementation of Commitments #10,

1. 11, #31, and #49, the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).

1 NFPA 25 requires that sprinkler heads be replaced or representative samples from one or more sample areas be submitted to a recognized testing laboratory for field services testing. In the VYNPS program a representative sample of sprinkler heads will be submitted to a recognized testing laboratory for services testing. The Staff notes that the VYNPS sprinkler heads inspection program appears to eliminate the option to just replace a sprinkler head after 50 years service unless it first undergoes laboratory testing. This implies that, if a sprinkler head is obviously corroded and requires replacement, the VYNPS may first have to send that sprinkler head to a testing laboratory before replacing it, a seemingly unnecessary burden. 3-84

Conclusion. On the basis of its audit and 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 with the addition of Commitments #10, #11, #31, and #49. In addition, the staff reviewed the exception and their justifications and determines that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. Also, the staff reviewed the enhancements and confirmed that their implementation prior to the period of extended operation would make the existing AMP consistent with the GALL 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). 3.0.3.2.13 Oil Analysis Program Summary of Technical Information in the Application. LRA Section B.1.20 describes the existing Oil Analysis Program as consistent, with exception, with GALL AMP XI.M39, Lubricating Oil Analysis. The Oil Analysis Program maintains oil systems free of contaminants (primarily water and particulates), preserving an environment not conducive to loss of material, cracking, or fouling. Sampling frequencies are based on vendor recommendations, accessibility during plant operation, equipment importance to plant operation, and previous test results. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effects for which it is credited. The staff reviewed those portions of the Oil Analysis Program for which the applicant claimed consistency with GALL AMP XI.M39 and finds that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicants Oil Analysis Program provided assurance that oil systems are free of contaminants which preserves an environment that is not conducive to loss of material, cracking or fouling. The staff finds the applicants Oil Analysis Program acceptable because it conformed to the recommended GALL AMP XI.M39, Lubricating Oil Analysis, with an exception. Exception. In LRA Section B.1.20, the applicant stated an exception to the GALL Report program element parameters monitored/inspected. Specifically, the exception states that: Flash point is not determined for sampled oil. The applicant also stated, that analyses of filter residue or particle count, viscosity, total acid/base (neutralization number), water content, and metals content are performed on the sampled oil, but the flash point of the oil is not determined. 3-85

The applicant indicated that extensive testing and analyses is performed on all of the sampled oil to verify that the oil is suitable for continued use. However, determination of the oil flash point is not performed as part of the program. The applicant also stated that it performs a fuel dilution test in lieu of performing flash point testing on the emergency diesel generators (EDGs), diesel driven fire pump, and the John Deere Diesel generator. This test accomplishes the same goal as the flash point test but is more prescriptive. The fuel dilution test determines the percent by volume of both fuel and water, the analysis can determine the cause of the change in flash point without having to conduct additional tests and corrective actions, and if required, could be implemented on a timelier basis. On the basis that the fuel dilution test is more prescriptive and timely, the staff finds this exception acceptable. Operating Experience. LRA Section B.1.20 states that a negative trend was noted in the lube oil analysis report for the P-40-1A diesel fire pump. Oil was drained, flushed, and refilled. A lube oil sample taken on the B EDG indicated a temporary abnormally high non-abrasive silicon level caused by gasket sealant materials used during the last EDG overhaul. Although acceptance criteria do not include an upper threshold for silicon, re-sampling confirmed that the silicon level had gone down. Corrective action following negative trends and abnormal samples proves that the program is effective at preserving an environment not conducive to loss of material, cracking, or fouling. Recent QA surveillance and self-assessment revealed no issues or findings that could impact program effectiveness. The staff reviewed an assessment of the maintenance programs which was performed by the Quality Assurance Group and the Component Engineering assessment of the Predictive Maintenance Programs. This review confirmed that the lube Oil Analysis Program effectively had implemented the programmatic and regulatory requirements at that point in time. The review of these reports confirmed that the Oil Analysis Program was effectively monitoring the lube oil and was trending the data to allow the appropriate actions to be taken. In addition, the staff confirmed that there have been no component failures to date at VYNPS related to lube oil contamination. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.22, the applicant provided the UFSAR supplement for the Oil Analysis Program. The staff reviewed this section and determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). 3-86

Conclusion. On the basis of its audit and review of the applicant's Oil Analysis 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 its justifications and determines that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. 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). 3.0.3.2.14 Reactor Head Closure Studs Program Summary of Technical Information in the Application. LRA Section B.1.23 describes the existing Reactor Head Closure Studs Program as consistent, with exception, with GALL AMP XI.M3, Reactor Head Closure Studs. This program includes ISI in conformance with the requirements of ASME Code, Section XI, Subsection IWB, and preventive measures (e.g., rust inhibitors, stable lubricants, appropriate materials) to mitigate cracking and loss of material of reactor head closure studs, nuts, washers, and bushings. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effects for which it is credited. The staff reviewed those portions of the Reactor Head Closure Studs Program for which the applicant claimed consistency with GALL AMP XI.M3 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicants Reactor Head Closure Studs Program provided assurance that the effects of cracking due to SCC/IGSCC and loss of material due to wear will be adequately managed so that the intended functions of components within the scope of license renewal will be maintained during the period of extended operation. The staff finds the applicants Reactor Head Closure Studs Program acceptable because it conformed to the recommended GALL AMP XI.M3, Reactor Head Closure Studs, with an exception. Exception. In LRA Section B.1.23, the applicant stated an exception to the GALL Report program element detection of aging effects. Specifically, the exception states that: When reactor head closure studs are removed for examination, either a surface or volumetric examination is allowed. The applicant noted that cracking initiates on the outside surfaces of bolts and studs. Therefore, a qualified surface examination meeting the acceptance standards of IWB-3515 provides at least the sensitivity for flaw detection that an end shot ultrasonic examination provides on bolts or studs. Thus, when reactor head closure studs are removed for examination, either a surface or volumetric examination is allowed. The applicant stated that its detection of aging effects is consistent with ASME Section XI Code Case N-652 which allows surface examination to be substituted for volumetric examination 3-87

when bolting is removed for examination. Code Case N-652 has been endorsed by the NRC per Table 1 in RG 1.147, Revision 14. In accordance with Code Case N-652, future examinations will be visual only. The staff determines that either a surface or volumetric examination can reliably reveal cracking and loss of material due to corrosion or wear. On this basis, the staff finds that this is not an exception to the GALL Report. In its letter dated July 14, 2006, the applicant deleted this exception from the LRA. Operating Experience. LRA Section B.1.23 states that recent (2002 and 2004) visual and ultrasonic inspections of reactor vessel studs, nuts, bushings, and washers revealed no recordable indications. Absence of recordable indications proves that the program is effective for managing loss of material and cracking for applicable components. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.25, the applicant provided the UFSAR supplement for the Reactor Head Closure Studs Program. The staff reviewed this section and 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 Reactor Head Closure Studs 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 its justifications and determines that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. 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). 3-88

3.0.3.2.15 Reactor Vessel Surveillance Program Summary of Technical Information in the Application. LRA Section B.1.24 describes the existing Reactor Vessel Surveillance Program as consistent, with enhancement, with GALL AMP XI.M31, Reactor Vessel Surveillance. This program manages reduction in fracture toughness of reactor vessel beltline materials to maintain the pressure boundary function of the reactor pressure vessel (RPV) for the period of extended operation. The applicant participates in the BWRVIP Integrated Surveillance Program (ISP) as approved by License Amendment 218. This program monitors changes in the fracture toughness properties of ferritic materials in the RPV beltline region. As BWRVIP-ISP capsule test reports for representative RPV materials become available the actual shift in the reference temperature for nil-ductility transition of the vessel material may be updated. In accordance with 10 CFR Part 50, Appendix H, the applicant reviews relevant test reports for compliance with fracture toughness requirements and pressure-temperature limits. BWRVIP-116, BWR Vessel and Internals Project Integrated Surveillance Program (ISP) Implementation for License Renewal, describes the design and implementation of the ISP during the period of extended operation. BWRVIP-116 identifies additional capsules, their withdrawal schedule, and contingencies to ensure that the requirements of 10 CFR Part 50 Appendix H are met for the period of extended operation. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the enhancement, remained adequate to manage the aging effects for which it is credited. In LRA Appendix B, Reactor Vessel Surveillance Program, the applicant described its AMP to manage irradiation embrittlement of the RPV through testing that monitors RPV beltline materials. The LRA stated that the RPV surveillance program will be enhanced by making it consistent with the BWRVIP ISP for the period of extended operation prior to the VYNPS entering its period of extended operation. The applicant has implemented the BWRVIP ISP which is based on the BWRVIP-78 report, BWR Integrated Surveillance Program Plan, and the BWRVIP-86-A report, BWR Vessel and Internals Project, BWR Integrated Surveillance Program Implementation. These reports are consistent with the GALL AMP XI.M31, Reactor Vessel Surveillance, for the period of the current VYNPS license. The staff concludes that the BWRVIP ISP in the BWRVIP-78 and BWRVIP-86-A reports is acceptable for BWR applicant implementation provided that all participating applicants use one or more compatible neutron fluence methodologies acceptable to the staff for determining surveillance capsule and RPV neutron fluences. The staffs acceptance of the BWRVIP ISP for the current term at VYNPS is documented in the staffs SE dated March 29, 2004, which is addressed in VYNPS Amendment 218. The BWRVIP developed an updated version of the ISP in the BWRVIP-116 report, BWR Vessel And Internals Project, Integrated Surveillance Program Implementation For License Renewal, which provides guidelines for an ISP to monitor neutron irradiation embrittlement of the limiting RPV beltline materials for all U.S. BWR power plants for the period of extended operation. The 3-89

applicant stated in the Reactor Vessel Surveillance Program, and in the Updated Final Safety Analysis Report (UFSAR) supplement Section A.2.1.26, Reactor Vessel Surveillance Program, that it will implement the ISP specified in the BWRVIP-116 report. The staff reviewed the UFSAR Supplement Section A.2.1.26 to determine whether it provides an adequate description of the program. In RAI B.1.24-1, by letter dated August 16, 2006, the staff requested that the applicant commit to the following in the Reactor Vessel Surveillance Program and in UFSAR Supplement (LRA Section A.2.1.26): The BWRVIP-116 report which was approved by the staff will be implemented at VYNPS with the conditions documented in Sections 3 and 4 of the staffs final SE for the BWRVIP-116 report dated March 1, 2006. In response to RAI B.1.24-1, by letter dated September 20, 2006, the applicant stated that it would update UFSAR Supplement Section A.2.1.26 and the Reactor Vessel Surveillance Program to include the aforementioned commitment (Commitment #38) proposed by the staff. The staff finds that its concern described in RAI B.1.24-1 is resolved. An ISP used as a basis for a facilitys RPV surveillance program must be reviewed and approved by the staff as required by 10 CFR 50, Appendix H. The ISP to be used by the applicant is a program that was developed by the BWRVIP and the applicant will apply the BWRVIP ISP as the method by which the VYNPS will comply with the requirements of 10 CFR Part 50, Appendix H. The BWRVIP ISP identifies capsules that must be tested to monitor neutron radiation embrittlement for all applicants participating in the ISP and identifies capsules that need not be tested (standby capsules). Table 3-3 of the BWRVIP-116 report indicates that the remaining capsule from VYNPS is not to be tested. This untested capsule was originally part of the applicant's plant-specific surveillance program and has received significant amounts of neutron radiation. In RAI B.1.24-2, by letter dated August 16, 2006, the staff requested that the applicant commit to include the following in the UFSAR Supplement (LRA Section A.2.1.26): If the VYNPS standby capsule is removed from the RPV without the intent to test it, the capsule will be stored in a manner which maintains it in a condition which would permit its future use, including during the period of extended operation, if necessary. In response to RAI B.1.24-2, by letter dated September 20, 2006, the applicant stated that it would incorporate the staffs aforementioned commitment (Commitment #39) in UFSAR Supplement Section A.2.1.26. The staff finds that the concern described in RAI B.1.24-2 is resolved. On the basis of its review, the staff finds that the applicant has demonstrated that the effects of aging due to loss of fracture toughness of the RPV beltline region will be adequately managed, so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). 3-90

Operating Experience. LRA Section B.1.24 states that the applicant participates in the BWRVIP ISP as incorporated into the plant technical specifications by Amendment 218. The fact that it participates in the BWRVIP ISP means future operating experience from all participating BWRs will be factored into this program. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff concludes that this program element is acceptable. UFSAR Supplement. The applicant described the reactor materials surveillance program as an existing program in LRA Section A.2.1.26. The program uses periodic testing of metallurgical surveillance samples to monitor the loss of fracture toughness of the RPV beltline region materials consistent with the requirements of 10 CFR Part 50, Appendix H. The applicant further stated that it will implement the staff-approved BWRVIP-116 report for the period of extended operation. The BWRVIP-116 report was approved by the staff and, as described in the staff evaluation section. The applicant made a commitment (Commitment #38) to include the following statement in the UFSAR Supplement (LRA Section A.2.1.26) by March 21, 2012: The BWRVIP-116 report which was approved by the staff will be implemented at VYNPS with the conditions documented in Sections 3 and 4 of the staffs final SE for the BWRVIP-116 report dated March 1, 2006. As to the status of the remaining VYNPS standby capsule, the applicant made a commitment (Commitment #39) to incorporate the following statement in the UFSAR Supplement (LRA Section A.2.1.26) by March 21, 2012: If the VYNPS standby capsule is removed from the RPV without the intent to test it, the capsule will be stored in manner which would permit its future use, if necessary. The staff reviewed the applicants proposed revision to UFSAR Supplement Section A.2.1.26 and determines that by committing to implement the most recent staff-approved version of the BWRVIP-116 report, the applicant demonstrated its compliance with the requirements of 10 CFR Part 50, Appendix H. The staffs review determined that the following license condition will be required to ensure that changes in the withdrawal schedule for the capsule that is specified in the BWRVIP-116 report will be submitted for staff review and approval: All capsules placed in storage must be maintained for future insertion. Any changes to storage requirements must be approved by the NRC, as required by 10 CFR Part 50, Appendix H. The staff concluded that the information provided in the UFSAR Supplement for the aging management of systems and components discussed above is equivalent to the information in NUREG-1801 and therefore provides an adequate summary of program activities (pending incorporation of Commitments #38 and #39) as required by 10 CFR 54.21(d). 3-91

Conclusion. On the basis of its audit and review of the applicant's Reactor Vessel Surveillance Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent with the addition of Commitments #38 and #39. Also, the staff reviewed the enhancement and confirmed that their implementation prior to the period of extended operation would make the existing AMP consistent with the GALL 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). 3.0.3.2.16 Service Water Integrity Program Summary of Technical Information in the Application. LRA Section B.1.26 and LRA supplement dated March 23, 2007, describes the existing Service Water Integrity Program as consistent, with exceptions and an enhancement, with GALL AMP XI.M20, Open-Cycle Cooling Water System. This program implements the recommendations of GL 89-13 to manage aging effects on the service water systems (SWS) for the period of extended operation. The SWS include the service water (SW), residual heat removal service water (RHRSW), and alternate cooling systems. The program includes surveillance and control techniques to manage aging effects in the SWS or SCs they serve. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions to determine whether the AMP, with the exceptions, remained adequate to manage the aging effects for which it is credited. The staff reviewed those portions of the Service Water Integrity Program for which the applicant claimed consistency with GALL AMP XI.M20 and finds that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicants Service Water Integrity Program demonstrated that the aging of the SWS will be properly managed for the period of extended operation. However, due to a history of aggressive aging effects, the applicant stated that future proper management of the SWS may include major components replaced with components made of materials less susceptible to aging in raw water. The staff finds the applicants Service Water Integrity Program acceptable because it conformed to the recommended GALL AMP XI.M20, Open-Cycle Cooling Water System, with exceptions. Exception 1. In LRA Section B.1.26, the applicant stated an exception to the GALL Report program element preventive actions. Specifically, the exception states that: The GALL Report stated that system components are lined or coated. Components are lined or coated only where necessary to protect the underlying metal surfaces. The applicant noted that the GALL Report stated that system components are constructed of appropriate materials and lined or coated to protect the underlying metal surfaces from being 3-92

exposed to aggressive cooling water environments. Not all VYNPS system components are lined or coated. Components are lined or coated only where necessary to protect the underlying metal surfaces. The applicant was asked to provide the original (or current if pipe has been replaced) material and lining specification for the buried piping which is part of the SWS, including the alternate cooling system. The applicant stated that no piping had been replaced and provided the original VYNPS piping specification, which showed the piping for the SW and alternate cooling water systems piping to be carbon steel material and not internally lined or coated. The applicant further stated that the only coated components in the SWS are a few valve body internals and heat exchanger heads that are currently and will continue to be inspected as part of the Service Water Integrity Program. The staff reviewed the SWS piping specifications and determined that the system piping is not internally lined or coated. VYNPS operating experience demonstrates that the lack of internal linings or coatings has resulted in the system experiencing aggressive aging effects. The applicant stated that to address the aggressive aging effects on the system due to the lack of protective internal linings or coatings, changes have been made at VYNPS in accordance with the Service Water Integrity Program. The applicant stated during the audit and review that changes have been made to the sampling and chemical treatment process. New chemical addition pumps were installed and sampling implemented for SW components during inspections However, VYNPS is limited in accordance with environmental controls to no more than two hours a day of chemical treatment to the SWS. VYNPS has also begun chemical treatment of SW lines not normally inservice. VYNPS also inspects the system every refueling outage. The applicant stated that one method being considered to manage aging is system piping replacement with materials less susceptible to the aging effects of raw water. The staff finds that VYNPS is taking measures with inspections and chemical treatments in accordance with the Service Water Integrity Program to compensate for the SWS components in general not having internal protective linings or coatings. On this basis, the staff finds this exception acceptable. Exception 2. In LRA Section B.1.26, the applicant stated an exception to the GALL Report program element monitoring and trending. Specifically, the exception states that: The GALL Report stated that testing and inspections are performed annually and during refueling outages. The VYNPS program requires tests and inspections each refueling outage. The applicant noted that the GALL Report program entails testing and inspections performed annually and during refueling outages. The VYNPS program requires tests and inspections each refueling outage, but not annually. Since aging effects are typically manifested over several years, the difference in inspection and testing frequency is insignificant. 3-93

The applicant stated, in the LRA, that its Service Water Integrity Program requires tests and inspections each refueling outage. The applicant stated in its program basis document that inspection scope, method, and testing frequencies are in accordance with VYNPS commitments in accordance with GL 89-13. Tests and inspections are done during refueling outages and other outages as necessary. The staff finds VYNPS is in compliance with its commitment in accordance with GL 89-13 to inspect and perform testing on the SWS each refueling outage. Outages at VYNPS are generally performed on an eighteen month cycle. The staff also determines that since aging effects typically manifest over several years, the difference in inspection and testing frequency is not significant. On this basis, the staff finds this exception acceptable. Enhancement. In the LRA supplement dated March 23, 2007, the applicant stated the following enhancement in meeting the GALL Report program element scope of program. Specifically, the enhancement stated: Enhance the Service Water Integrity Program to require a periodic visual inspection of the RHRSW pump motor cooling coil internal surface for loss of material. The staff reviewed the enhancement and its evaluation is documented in the VYNPS - NRC License Renewal Inspection Report 05000271/2007006. The staff determines that performing periodic visual inspection of the RHRSW pump motor cooling coil internal surface is acceptable. On the basis, the staff finds this enhancement acceptable since when the enhancement is implemented the Service Water Integrity Program will be consistent with GALl AMP XI.M20 and will provide additional assurance that the effects of aging will be adequately managed. Operating Experience. LRA Section B.1.26 states that recent performance test and inspection results (2004) prove that the program is effective for managing component aging effects, For example, SW-cooled diesel generator heat exchanger performance testing revealed no significant performance degradation, RHR heat exchanger inspection revealed no loss of material, cracking or fouling, a SW check valve internal visual inspection revealed no loss of material, and internal visual inspection of a SW pipe by fiber optics revealed no loss of material. Ultrasonic wall thickness measurements taken in October 2003 and January 2004 in the vicinity of known wall-thinning in a SW pipe revealed that the pipe wall thickness had not changed and that the structural integrity of the piping would be maintained until the pipe section could be replaced in September 2004. Accelerated monitoring in the vicinity of an indication is assurance that the program is effective for managing component loss of material. A staff inspection of the SWS in 2002 determines that mitigation of MIC buildup had not been effective as evidenced by more than 20 SWS leaks. A self-assessment, including independent evaluation by industry experts, was completed on December 20, 2002. Protocols for use of biocides to mitigate MIC were revised and the processes for analysis, trending, and interpretation of results were enhanced. Resolution of this issue is assurance that the program will manage component aging effects. The staff finds the listed operating experience up through 2002 indicates that VYNPS had performed inadequately in managing the aging effects of raw water on the SWS. The staff determines that mitigation of MIC buildup had not been effective as indicated by the more than 3-94

20 SWS leaks. During the audit and review discussions/interviews, the applicant stated that no biocides to mitigate MIC had been used in the SWS for many years after initial plant operation. The lack of aging management for the system manifested itself in 2002 with 20 leaks. The applicant performed a self-assessment of the aging management of the system, including the use of independent industry experts. This resulted in the criteria for the use of biocides to mitigate MIC being revised and the processes for analysis, trending, and interpretation of results being enhanced. The applicant further stated that the improved performance by VYNPS in managing the aging effects on the SWS after 2002 is demonstrated by the more recent operating experience. Recent SWS performance test and inspection results from 2004 demonstrated that the program has become more effective in managing aging effects for applicable components. The staff reviewed a sampling of inspection reports and performance testing results for the SWS components and found the documentation to be very detailed and thorough. Since 2002 VYNPS has taken a much more aggressive and pro-active approach to managing the aging effects of the SWS components as indicated by the most recent operating experience where no severe aging was found. The staff finds by VYNPS demonstrating a more pro-active approach to managing aging on the SWS, the type of aggressive aging effects discovered in 2002 will be better managed going forward. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.28, the applicant provided the UFSAR supplement for the Service Water Integrity Program. The applicant committed (Commitment #45) to implement the enhancement to the Service Water Integrity Program to require a periodic visual inspection of the RHRSW pump motor cooling coil internal surface for loss of material by March 21, 2012. The staff reviewed this section and determines that, upon the implementation of Commitment

1. 45, 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 Service Water 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, enhancement, and their justifications and determined that the AMP, with the exceptions and enhancement, is adequate to manage the aging effects for which it is credited. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately 3-95

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). 3.0.3.2.17 Structures Monitoring Program Summary of Technical Information in the Application. LRA Section B.1.27.2 describes the existing Structures Monitoring Program as consistent, with enhancements, with GALL AMP XI.S6, Structures Monitoring Program. Structures monitoring in accordance with 10 CFR 50.65 (Maintenance Rule) is addressed in RG 1.160 and NUMARC 93-01. These two documents provide guidance for development of applicant-specific programs to monitor the condition of structures and structural components within the scope of the Maintenance Rule so there is no loss of structure or structural component intended function. Since protective coatings do not manage aging effects for structures included in the Structures Monitoring Program, the program does not address protective coating monitoring and maintenance. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancements to determine whether the AMP, with the enhancements, remained adequate to manage the aging effects for which it is credited. The staff asked the applicant to explain why the inspection of crane rails and girders is not included under a program that is consistent with GALL AMP XI.M23, Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems. The applicant stated that its Periodic Surveillance and Preventive Maintenance Program and the Structures Monitoring Program adequately manage aging effects for cranes and girders. Therefore, a separate program (i.e., inspection of overhead heavy load and light load handling system) is not necessary. The staff finds the applicants response acceptable. The staff asked the applicant to explain if VYNPS has any porous concrete subfoundations and a site dewatering system. In addition, the applicant was asked to explain if the Structures Monitoring Program required periodic sampling and testing of groundwater to determine and confirm that the below grade water chemistry/soil is non-aggressive to concrete structures below grade. The applicant stated that VYNPS does not have porous concrete subfoundations or a site dewatering system. The results of the two most recent reported groundwater samples as submitted to the State of Vermont were made available to the staff. These samples are currently obtained twice yearly, primarily around the plant septic systems with some of the sampling wells near plant structures. The results of these samples are provided to the State of Vermont in accordance with the Indirect Discharge Permit. The Structures Monitoring Program will be enhanced to ensure an engineering evaluation is made on a periodic basis of groundwater samples to assess for evidence of groundwater being aggressive to concrete. Historically, VYNPS groundwater samples have shown some level of seasonality in that the wells adjacent to roadways have slightly higher levels of chlorides due to salt treatment of roadways in the winter. 3-96

In a letter dated July 14, 2006, the applicant stated by amendment to the application that LRA Section B.1.27.2 for the Structures Monitoring Program is revised to include an enhancement to perform, at least once every five years, an engineering evaluation of groundwater samples to assess for groundwater being aggressive to concrete. The staff reviewed the applicants response and finds the applicants response acceptable. The applicant has committed (Commitment #33) to enhancing the VYNPS Structures Monitoring Program to ensure an engineering evaluation is made on a periodic basis of groundwater samples. A five -year periodicity for performing an engineering evaluation of groundwater samples to assess for groundwater being aggressive to concrete has previously been accepted by the staff in other applicant LRAs and therefore on this basis the staff finds the maximum five -year periodicity acceptable. The staff also asked the applicant to explain if VYNPS will take advantage of inspection opportunities for structures required for license renewal and identified as inaccessible. The applicant stated that VYNPS will take advantage of inspection opportunities for underground structures that become accessible by excavation. This inspection is already part of the Structures Monitoring Program. The staff finds the applicants response acceptable. The applicant will take advantage of inspection opportunities for structures required for license renewal and identified as inaccessible. The staff asked the applicant to explain if the inspection acceptance criteria for its Structures Monitoring Program was based on American Concrete Institute (ACI) standard, ACI 349.3R-96, and if not, to provide the industry codes, standards and guidelines that the acceptance criteria is based on. In addition, the applicant was asked to explain the basis of the acceptance criteria for crane rail/girder inspections. The applicant stated that the VYNPS Structures Monitoring Program is controlled by plant procedure, as documented in the Audit and Review Report. The standards used to develop and conduct the program are listed in the procedure. The specific standard used to develop inspection requirements for this procedure is NEI 96-03, Nuclear Energy Institute, Industry Guideline for Monitoring the Condition of Structures at Nuclear Power Plants, Section 3.3, Examination Guidance. Inspection requirements of commodities taken from NEI-96-03 are delineated in the program procedure. The following comparison of the relevant guidelines for concrete structural components in the program procedure, with the guidelines of ACI 349.3 Chapter 5 Evaluation Criteria indicates general consistency:

1) Both documents specify visual inspection methods for the examination of structures.

2) Both documents provide guidance for the inspections for the following parameters and conditions:

• Concrete components: spalling, cracking, delamination, honey combs, water in-leakage, chemical leaching, peeling paint, or discoloration
• Structure Settlement: excessive total or differential settlement 3-97
• Structural/seismic gap: insufficient space for structural movement during a seismic event (i.e., exclusion of foreign objects or debris); deteriorated elastomer type filler.

3) ACI 349.3R-96 Chapter 5 provides acceptable limits beyond which further evaluation is required. PP 7030 Section 4.8 conservatively requires evaluation of identified degradation.

Based upon this comparison, the applicant concluded that the guidance for inspections provided in PP 7030 is consistent with the guidelines in ACI 349.3R-96. The acceptance criteria for crane rail/girder inspections are contained in the preventive maintenance tasks for the crane inspection. A plant procedure provides the inspection and acceptance criteria for crane rail/girders. The procedure criteria is based on the following codes and standards of ANSI B30.2-83 Overhead and Gantry Cranes and NUREG-0612, Control of Heavy Loads at Nuclear Power Plants. The staff reviewed the applicants response and finds the response acceptable. The applicant has made a comparison of the VYNPS relevant guidelines for concrete inspection acceptance criteria with the guidelines of ACI 349.3R-96 Chapter 5, and found general consistency. In addition, the applicant stated that the acceptance criteria for crane rail/girder inspections are based on codes and standards of ANSI B30.2-83 and NUREG-0612. The staff noted that the program description in the LRA for the Structures Monitoring Program makes no reference to GALL AMP XI.S7, RG 1.127, Inspection of Water-Control Structures Associated With Nuclear Power Plants. GALL AMP XI.S7 stated that for plants not committed to RG 1.127, Revision 1, aging management of water-control structures may be included in the Structures Monitoring Program. However, details pertaining to water-control structures are to incorporate the attributes of GALL AMP XI.S7. During the audit and review, the staff asked the applicant to explain if VYNPS is committed to RG 1.127, Revision 1 for inspection of its water control structures (such as intake structure). If VYNPS is not committed to RG 1.127, Revision 1, explain how the 10 program elements of GALL AMP XI.S7 are incorporated into the VYNPS Structures Monitoring Program. The applicant stated that the water-control structure at VYNPS is the intake structure. There are no earthen water control structures at VYNPS. The program elements of GALL AMP XI.S7 applicable to the intake structure are incorporated in the VYNPS Structures Monitoring Program as described below. Program elements of GALL AMP XI.S7 that are not incorporated in the Structures Monitoring Program primarily apply to earthen structures.

1) Scope - The scope of the GALL AMP XI.S7 program applicable to VYNPS is the intake structure. The intake structure is included in the scope of the Structures Monitoring Program as delineated in LRA Table 3.5.2-3.

2) Preventive Actions - The GALL AMP XI.S7 program includes no preventive actions.

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3) Parameters Monitored - The AERM for concrete structural components of the intake structure is loss of material which is consistent with the GALL Report, Volume 2 Item II.A6-7. The parameters monitored from the GALL AMP XI.S7 program applicable to loss of material are consistent with those monitored by the Structures Monitoring Program. The guidance for inspections of concrete in RG 1.127, Section C.2, is consistent with the guidance in ACI 349.3R-96 used in the Structures Monitoring Program.

4) Detection of Aging - GALL AMP XI.S7 identifies visual inspection methods as the primary method used to detect aging. The Structures Monitoring similarly uses visual inspection methods as the primary method used to detect aging in concrete structural components. GALL AMP XI.S7 identifies inspection intervals of five years. The Structures Monitoring Program identifies similar inspection intervals of three years for accessible areas, ten years for inaccessible areas and opportunistic inspections for buried components.

5) Monitoring and Trending - Monitoring is by periodic inspection for both the GALL AMP XI.S7 and Structures Monitoring Programs.

6) Acceptance Criteria - Acceptance criteria is not identified in RG 1.127, however appropriate guidance is provided in the Structures Monitoring Program to ensure corrective measures are identified prior to loss of intended function.

7-9) The corrective actions, confirmation process and administrative control attributes of the Structures Monitoring Program and the GALL AMP XI.S7 program are consistent.

10) Operating Experience - The operating experience relevant to the effectiveness of the Structures Monitoring Program is presented in Appendix B of the application and is consistent with the operating experience described in GALL AMP XI.S7.

The staff reviewed the applicants response and finds the applicants response acceptable. The staff determines that the applicant has verified that the program elements of GALL AMP XI.S7 pertaining to VYNPS water control structures have been incorporated within the Structures Monitoring Program. The staff reviewed those portions of the Structures Monitoring Program for which the applicant claimed consistency with GALL AMP XI.S6 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicants Structures Monitoring Program provides assurance that the aging of materials of construction, which include structural steel, concrete, roof materials, wood, polyvinyl chloride (PVC), and sealing materials, for structures within the scope of license renewal will be properly managed for the period of extended 3-99

operation. The staff finds the applicants Structures Monitoring Program acceptable because it conformed to the recommended GALL AMP XI.S6, Structures Monitoring Program, with enhancements. Enhancement 1. In LRA Section B.1.27.2, the applicant stated the following enhancement in meeting the program element scope of program. Specifically, the enhancement states: The Structures Monitoring Program will be enhanced to specify that process facility crane rails and girders, condensate storage tank (CST) enclosure, CO2 tank enclosure, N2 tank enclosure and restraining wall, CST pipe trench, diesel generator cable trench, fuel oil pump house, SW pipe trench, drywell floor liner seal, manway seals and gaskets, and hatch seals and gaskets are included in the program. By letter dated July 14, 2006, as discussed in SER Section 3.0.3.2.17.2, the applicant removed the drywell floor liner seal from scope of its Structures Monitoring Program since drywell floor liner seal (moisture barrier) is examined in accordance with the its Containment Inservice Inspection-IWE Program. The staff finds that with the addition of the above SCs, the applicants Structures Monitoring Program will meet the recommendation of the program described in GALL AMP XI.S6. The applicant identified commitments to the NRC associated with this enhancement relative to GALL AMP XI.S6. On this basis, the staff finds this enhancement (Commitment #20) acceptable since when the enhancement is implemented, the Structures Monitoring Program will be consistent with GALL AMP XI.S6 and will provide additional assurance that the effects of aging will be adequately managed. Enhancement 2. In LRA Section B.1.27.2, the applicant stated the following enhancement in meeting the program element detection of aging effects. Specifically, the enhancement states: Guidance for performing structural examinations of wood to identify loss of material, cracking, and change in material properties will be added to the Structures Monitoring Program. On this basis, the staff finds this enhancement (Commitment #21) acceptable since when the enhancement is implemented, the Structures Monitoring Program will be consistent with GALL AMP XI.S6 and will provide additional assurance that the effects of aging will be adequately managed. Enhancement 3. In LRA Section B.1.27.2, the applicant stated the following enhancement in meeting the program element detection of aging effects. Specifically, the enhancement states: Guidance for performing structural examinations of elastomers (Drywell floor liner seal, seals, and gaskets) to identify cracking and change in material properties (cracking when manually flexed) will be enhanced in the Structures Monitoring Program procedure. 3-100

On this basis, the staff finds this enhancement (Commitment #22) acceptable since when the enhancement is implemented, the Structures Monitoring Program will be consistent with GALL AMP XI.S6 and will provide additional assurance that the effects of aging will be adequately managed. The drywell floor liner seal is to be removed from scope of the Structures Monitoring Program as discussed in in Enhancement 1. Enhancement 4. In LRA Section B.1.27.2, the applicant stated the following enhancement in meeting the program element detection of aging effects. Specifically, the enhancement states: Guidance for performing structural examinations of PVC cooling tower fill to identify cracking and change in material properties will be added to the Structures Monitoring Program procedure. On this basis, the staff finds this enhancement (Commitment #23) acceptable since when the enhancement is implemented, Structures Monitoring Program, will be consistent with GALL AMP XI.S6 and will provide additional assurance that the effects of aging will be adequately managed. The staff determines that these three enhancements, described above, will provide the inspection methods for SCs that are in-scope of license renewal, to ensure that aging degradation will be detected and quantified before there is loss of intended functions. The staff finds that with the addition of the above guidance for performing structural examinations of wood, elastomers, and PVC cooling tower fill to the Structures Monitoring Program, all the inspection methods for each structure/aging effect combination within the scope of license renewal in accordance with this AMP is provided. The additional guidance provided sufficient detail to ensure that aging degradation will be detected and quantified before there is loss of intended functions. Operating Experience. LRA Section B.1.27.2 states that the concrete pad above John Deere diesel generator day tank was sinking and cracking. The pad was repaired with steel bollards installed to prevent future sinking and cracking. Cooling tower inspections detected degradation of a structural column, cracking of a wooden structural member. The degraded column and associated splice connection were replaced. Resolution of these issues proves that the program is effective for managing cracking of structural components. Recent performance test and inspection results (2002 and 2003) show that the program is effective for managing component aging effects. For example, inspection of the turbine building crane and of the reactor building overhead crane in 2002 revealed no findings; and inspection of the reactor building airlock door seal revealed no cracking, dry rot, bulging, or separation of the seal. The most recent structures monitoring inspection found the overall condition of structures very good. Inspections were conducted in 2004 in the reactor building, turbine building, diesel generator rooms, fuel oil day tank room, control building, plant stack, switch yard, discharge structure, intake structure, and John Deere diesel building. Absence of significant findings during these inspections proves that the program is effective for managing loss of material, cracking, and change in material properties for structural components. 3-101

The staff reviewed the summary of specific operating experience for the Structures Monitoring Program. The staff also reviewed the operating experience for a concrete pad sinking and cracking and degradation of a structural wooden column and found that the applicants existing Structures Monitoring Program was effective in identifying deterioration of plant SCs within its scope. The deficiencies were placed in the CAP for VYNPS and dispositioned for repair. The listed operating experience demonstrated that the VYNPS Structures Monitoring Program is effective in ensuring that age related deterioration of plant SCs within the scope of license renewal is adequately managed to ensure that these SCs maintain their ability to perform their intended function. On the basis of its review, the staff finds that the applicants Structures Monitoring Program is effective in identifying age-related degradation, implementing repairs, and maintaining the structural integrity of the structures and associated components within the scope of license renewal. The staff also reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.30, the applicant provided the UFSAR supplement for the Structures Monitoring Program. The applicant committed (Commitment #20) to enhance the Structures Monitoring Program to specify that process facility crane rails and girders, CST enclosure, CO2 tank enclosure, N2 tank enclosure and restraining wall, CST pipe trench, diesel generator cable trench, fuel oil pump house, SW pipe trench, manway seals and gaskets, and hatch seals and gaskets are included in the program by March 21, 2012. The applicant committed (Commitment #21) to enhance the Structures Monitoring Program to add guidance for performing structural examinations of wood to identify loss of material, cracking, and change in material, by March 21, 2012. The applicant committed (Commitment #22) in to enhance the Structures Monitoring Program to add guidance for performing structural examinations of elastomers (seals and gaskets) to identify cracking and change in material properties (cracking when manually flexed) by March 21, 2012. The applicant committed (Commitment #23) to enhance the Structures Monitoring Program to add guidance for performing structural examinations of PVC cooling tower fill to identify cracking and change in material properties by March 21, 2012. 3-102

The applicant committed (Commitment #33) to include in the Structures Monitoring Program provisions that will ensure an engineering evaluation is made on a periodic basis (at least once every five years) of groundwater samples to assess aggressiveness of groundwater to concrete. Samples will be monitored for sulfates, pH and chlorides, by March 21, 2012. The staff reviewed this section and determined that, upon the implementation of Commitments

1. 20, #21, #22, #23, and #33, 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 Structures Monitoring Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent with the addition of Commitments #20, #21,

1. 22, #23, and #33. Also, the staff reviewed the enhancements and confirmed that their implementation prior to the period of extended operation would make the existing AMP consistent with the GALL 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).

3.0.3.2.18 Water Chemistry Control - Closed Cooling Water Program Summary of Technical Information in the Application. LRA Section B.1.30.3 describes the existing Water Chemistry Control - Closed Cooling Water Program as consistent, with exception, with GALL AMP XI.M21, Closed-Cycle Cooling Water System. This program includes preventive measures that manage loss of material, cracking, and fouling for closed cooling water systems (CCWS) (reactor building closed cooling water (CCW), turbine building CCW, augmented off-gas (AOG) CCW, EDG CCW, AOG refrigerant skid water, and chilled water). These chemistry activities monitor and control CCW chemistry using plant-specific procedures and processes based on EPRI guidance for CCW chemistry. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effects for which it is credited. The staff reviewed those portions of the Water Chemistry Control-Closed Cooling Water Program for which the applicant claimed consistency with GALL AMP XI.M21 and found that they are consistent with the GALL AMP. Furthermore, the staff concludes that the applicants Water Chemistry Control-Closed Cooling Water Program provided assurance that this program will manage loss of material, cracking, and fouling for the following CCWSs:

• Reactor Building Closed Cooling Water
• Augmented Off-Gas Closed Cooling Water 3-103
• Augmented Off-Gas Refrigerant Skid Water and Chilled Water
• Emergency Diesel Generator Closed Cooling Water
• Turbine Building Closed Cooling Water The staff finds the applicants Water Chemistry Control-Closed Cooling Water Program acceptable because it conformed to the recommended GALL AMP XI.M21, Closed-Cycle Cooling Water System, with an exception.

Exception 1. In LRA Section B.1.30.3, the applicant stated an exception to the GALL Report program element detection of aging effects. Specifically, the exception states that: The VYNPS Water Chemistry Control-Closed Cooling Water Program does not include performance and functional testing. Exception Note. While GALL AMP XI.M21, Closed-Cycle Cooling Water System endorses EPRI Report TR-107396 for performance and functional testing guidance, EPRI Report TR-107396 does not recommend that equipment performance and functional testing be part of a Water Chemistry Control Program. This appears appropriate since monitoring pump performance parameters is of little value in managing effects of aging on long-lived, passive CCWS components. Rather, EPRI Report TR-107396 stated in Section 5.7 (Section 8.4 in EPRI Report 1007820) that performance monitoring is typically part of an engineering program, which would not be part of water chemistry. In most cases, functional and performance testing verifies that component active functions can be accomplished and as such would be included as part of Maintenance Rule (10 CFR 50.65). Passive intended functions of pumps, heat exchangers and other components will be adequately managed by the Closed Cooling Water Chemistry Program through monitoring and control of water chemistry parameters. The staff discussed technical issues related to this exception with the applicant. The applicant stated that aging of CCWS components relies on monitoring and control of CCWS chemistry. The applicant stated that the effectiveness of the Closed Cooling Water Chemistry Program will be verified by a one-time inspection of the CCWS. The applicant was asked to confirm that the one-time inspection would consider representative sampling of low-flow and stagnant water areas of the listed CCWSs. In its response, the applicant stated that sampling of the entire system, including the piping and fittings, thermowells, and valve bodies in the various systems, would be selected. The staff determines that the applicant would select representative samples from the low-flow and stagnant flow areas of the listed CCWSs in the One-Time Inspection Program, which will provide assurance that the aging effects for this system will be adequately managed. On this basis, the staff finds this exception acceptable. Operating Experience. LRA Section B.1.30.3 states that monthly sample results from January 2003 through January 2005 showed CCWS chemistry parameters are maintained within EPRI acceptance criteria. Self-assessments in 2000 and 2002 found the program effective at maintaining low levels of contaminants in the water. One reactor building CCW reading for 3-104

molybdate corrosion inhibitor was within the EPRI action Level 1 range; the reading was slightly low, molybdate was added, and the reading returned to normal at the next sample. First and second quarter 2004 reports stated that, the chemistry of the major CCWSs remains very good and within specification. Sample results within acceptance criteria indicate that the program is effective for managing component loss of material, cracking, and fouling. In addition, self-assessment in 2000 revealed that low triazole concentrations during 1999 were resolved by the addition of pure 10 percent triazole to CCWSs when molybdate corrosion inhibitor was high and triazole was low. Timely correction of low triazole concentrations provides assurance that the program will ensure adequate water quality to preclude loss of material, cracking, and fouling of applicable components. Self-assessment in 2000 revealed three instances of CCW chemistry outside administrative limits without corrective action taken or planned. Procedural changes and trending process revisions resolved the issue and provide assurance that the program will ensure adequate water quality to preclude component loss of material, cracking, and fouling. A QA audit of program implementation in 2003 found it effective. QA auditors also confirmed implementation of improvements recommended during previous program audits. A self-assessment in 2002 and a QA audit in 2003 revealed no issues or findings that could impact program effectiveness. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.36, the applicant provided the UFSAR supplement for the Water Chemistry Control - Closed Cooling Water Program. The staff reviewed this section and determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). In addition, in a letter dated January 14, 2007, the applicant provided an amendment to its LRA to explicitly state that the One-Time Inspection Program activities will confirm the effectiveness of the Water Chemistry Control - Closed Cooling Water Program. Conclusion. On the basis of its audit and review of the applicant's Water Chemistry Control-Closed Cooling Water Program, the staff determines that those program elements, for which the applicant claimed consistency with the GALL Report, are consistent with the GALL Report. In addition, the staff reviewed the exception and the associated justifications, and determines that the AMP, with the exception, is adequate to manage the aging effects for which 3-105

it is credited. 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). 3.0.3.2.19 Bolting Integrity Program Summary of Technical Information in the Application. In a letter dated October 17, 2006, the applicant revised its LRA. The applicant submitted its Appendix B, Section B.1.31, Bolting Integrity Program, and stated its Bolting Integrity Program is a new plant program that is consistent with GALL AMP XI.M18, Bolting Integrity, with an enhancement. By letter dated January 4, 2007, the applicant provided additional clarification stated: The Bolting Integrity Program applies to bolting and torquing practices of safety-related and nonsafety-related bolting for pressure retaining components, nuclear steam supply system (NSSS) support components, and structural joints. The program addresses all bolting regardless of size (except the reactor vessel closure studs which are addressed by the Reactor Vessel Closures Stud Program). The applicant stated that this program relies on recommendations for a comprehensive bolting integrity program as delineated in NUREG-1339, Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants, and industry recommendations as delineated in the EPRI NP-5769, with the exceptions noted in NUREG-1339 for safety-related bolting. The program relies on industry recommendations for comprehensive bolting maintenance as delineated in EPRI TR-104213 for pressure-retaining bolting and structural bolting. The applicant stated that this program covers bolting within the scope of license renewal, including: (1) safety-related bolting, (2) bolting for NSSS component supports, (3) bolting for other pressure-retaining components including nonsafety-related bolting, and (4) structural bolting (actual measured yield strength is less than or equal to 150 ksi). The aging management of reactor head closure studs is addressed by GALL AMP XI.M3 and is not included in this program. The staffs 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 industrys technical basis for the program for safety-related bolting and guidelines for material selection and testing, bolting preload control, ISI, plant operation and maintenance, and evaluation of the structural integrity of bolted joints is outlined in EPRI NP-5769, with the exceptions noted in NUREG-1339. For other bolting, this information is set forth in EPRI TR-104213. The applicant also stated that its Bolting Integrity Program applies to bolting and torquing practices of safety-related and nonsafety-related bolting for pressure-retaining components, NSSS component supports, and structural joints. The program addresses all bolting regardless of size. Guidance for the program is contained in NUREG-1339, which refers to EPRI NP-5769 and EPRI NP-5067 for technical bases. For other (structural) bolting, the guidelines of EPRI TR-104213 are followed. 3-106

Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. The Audit and Review Report details the staff's audit evaluation of this AMP. The staff reviewed the exception and the associated justifications to determine whether the AMP, with the exception, remains adequate to manage the aging effects for which it is credited. The staff reviewed those portions of the Bolting Integrity Program for which the applicant claims consistency with GALL AMP XI.M18 and found that they are consistent with the GALL AMP. On the basis of its review, the staff concludes that the applicants Bolting Integrity Program will adequately manage the aging effects associated with the bolting. The staff finds the applicants Bolting Integrity Program conforms to the recommended GALL AMP XI.E4, "Bolting Integrity, with the enhancement as described below. Enhancement. The applicant stated the following enhancement in meeting the program element preventive actions. Specifically, the enhancement states: Enhance procedures to clarify that actual yield strength is used in selecting materials for low susceptibility to SCC. The staff finds that this enhancement ensures that the recommendations in the referenced documents are properly implemented. On this basis, the staff finds this enhancement acceptable since when the enhancement is implemented, the Bolting Integrity Program will be consistent with GALL AMP XI.M18, and will provide additional assurance that the effects of aging will be adequately managed. Operating Experience. The applicant stated that operating experience reviews did not identify cracking or loss of preload as AERMs for pressure boundary bolting. Although cracking and loss of preload are not AERMs for the plant equipment operator, plant procedures implement the recommendations of NUREG-1339, Resolution to Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants, for pressure boundary bolting in the scope of license renewal. Plant procedures address material and lubricant selection, design standards, and good bolting maintenance practices in accordance with EPRI 5067, Good Bolting Practices. The staff reviewed the operating experience provided in the LRA supplement and interviewed the applicants technical personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. 3-107

UFSAR Supplement. The applicant provided the UFSAR supplement for the Bolting Integrity Program. The applicant committed (Commitment #34) to implement the Bolting Integrity Program by March 21, 2012. The staff reviewed the UFSAR Supplement section and determines that, upon implementation of Commitment #34, the information in the UFSAR supplement provided 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 with the addition of Commitment # 34. Also, the staff reviewed the enhancement and confirmed that the implementation of the enhancements prior to the period of extended operation would result in the existing AMP being consistent with the GALL 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 Metal-Enclosed Bus Inspection Program Summary of Technical Information in the Application. In a letter dated October 17, 2006, the applicant revised its LRA. The applicant submitted its Appendix B, Section B.1.32, and stated that the Metal-Enclosed Bus Inspection Program is a new program that will be comparable to GALL AMP XI.E4, "Metal-Enclosed Bus," with exceptions. The applicant stated that in accordance with Metal-Enclosed Bus Inspection Program, internal portions of the isophase bus which runs between the main transformer and the unit auxiliary transformer are inspected for cracks, corrosion, foreign debris, excessive dust buildup, and evidence of water intrusion. Internal bus supports are inspected for structural integrity and signs of cracks. Enclosure assemblies are visually inspected for evidence of loss of material and, where applicable, enclosure assembly elastomers are inspected to manage cracking and change in material properties. Staff Evaluation. The staff confirmed the applicants claim of consistency with the GALL Report. The Audit and Review Report details the staff's audit evaluation of this AMP. The staff reviewed the enhancements and the associated justifications to determine whether the AMP, with the exceptions, remains adequate to manage the aging effects for which it is credited. The staff reviewed those portions of the applicants Metal-Enclosed Bus Inspection Program for which the applicant claims comparable with GALL AMP XI.E4 and found that they are consistent with the GALL Report AMP. On the basis of its review, the staff concludes that the applicants Metal-Enclosed Bus Inspection Program will adequately manage the aging effects associated with the metal-enclosed bus (MEB). The staff finds the applicants Metal-Enclosed Bus Inspection Program conforms to the recommended GALL AMP XI.E4, "Metal-Enclosed Bus, with the exceptions. 3-108

Exception 1. In the revised LRA Section B.1.32, the applicant stated an exception to the GALL Report program elements parameters monitored/inspected and detection of aging effects. Specifically, the exception states that: MEB enclosure assemblies will be inspected in addition to internal surfaces. The applicant stated that MEB enclosure assemblies will be inspected in addition to internal surfaces. The applicant also stated that, in accordance with Exception Note 1, that inspection of MEB enclosure assemblies in accordance with its Metal Enclosure Bus Inspection Program assures that effects of aging will be identified prior to loss of intended functions. The staff reviewed the applicants Metal Enclosure Bus Program and found that the inspection proposed by the applicant is consistent with the inspection portion of GALL AMP XI.S6. The applicant will inspect the external surfaces of MEB enclosure assemblies, including enclosure assembly elastomers, for cracking and change in material properties. On this basis, the staff finds this exception acceptable. Exception 2. In revised LRA Section B.1.32, the applicant stated an exception to the GALL Report program elements parameters monitored/inspected and detection of aging effects. Specifically, the exception states that: Bus insulation will not be inspected or monitored since the isophase bus which runs between the main transformer and the unit auxiliary transformer does not have bus insulation. The staff reviewed the applicants Metal-Enclosed Bus Inspection Program. The staff finds that since the design of VYNPS isophase bus is different from non-segregated phase bus in that it does not have insulation material on the isophase bus, there is no need for inspecting or monitoring bus insulation. On this basis, the staff finds this exception acceptable. Operating Experience. In the revised LRA, the applicant stated that its Metal-Enclosed Bus Inspection Program is a new program. The program is based on the program described in NUREG-1801 which in turn is based on industry operating experience. Industry operating experience and plant operating experience will be considered during program implementation. The staff reviewed the operating experience at VYNPS and finds that operating experience at VYNPS is controlled by procedure. The program includes the following components: (1) Operating Experience - Information received from various industry sources that describes events, issues, equipment failures, that may represent opportunities to apply lessons learned to avoid negative consequences or to recreate positive experience as applicable; (2) Internal Operating Experience - Operating experience (OE) that originates as a condition report or request from plant personnel which warrants consideration for possible Entergy-wide distribution. Internal operating experience can originate from any Entergy plant or headquarters; and (3) Impact Evaluation - Analysis of an operating experience event or problem that requires additional information and research to determine impact or potential impact, as it relates to plant condition and/or configuration. An impact evaluation is typically documented with a condition report. Condition report action items and corrective actions are used to confirm program effectiveness and to modify the program as needed. 3-109

The staff reviewed the operating experience provided in the revised LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. UFSAR Supplement. In revised LRA Section A.2.1.38, the applicant provided the UFSAR supplement for the Meta-Enclosed Bus Inspection Program. The applicant committed (Commitment #32) to implement the Metal-Enclosed Bus Program by March 21, 2012. The staff reviewed LRA Section A.2.1.38 and determines that, upon implementation Commitment #32, the information in the UFSAR supplement provided 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 Metal-Enclosed Bus Inspection Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent with the addition of Commitment # 32. In addition, the staff reviewed the exceptions and the associated justifications, and determines that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. 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). 3.0.3.3 AMPs Not Consistent with or Not Addressed in the GALL Report In LRA Appendix B, the applicant identified the following AMPs as plant-specific:

• Heat Exchanger Monitoring Program
• Containment Inservice Inspection Program
• Inservice Inspection Program
• Instrument Air Quality Program
• Periodic Surveillance and Preventive Maintenance Program
• Vernon Dam Federal Energy Regulatory Commission Inspection
• Water Chemistry Control - Auxiliary Systems 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 staffs review of these plant-specific AMPs is documented in the following sections.

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3.0.3.3.1 Heat Exchanger Monitoring Program Summary of Technical Information in the Application. LRA Section B.1.14 describes the Heat Exchanger Monitoring Program as a new, plant-specific program. The Heat Exchanger Monitoring Program will inspect heat exchangers for degradation and, if found, evaluate its effects on the heat exchanger's design functions, including ability to withstand a seismic event. Representative tubes within the sample population of heat exchangers will be eddy current-tested at a frequency determined by plant-specific and industry operating experience to identify aging effects prior to loss of intended function. With each eddy current test, visual inspections on accessible heat exchanger heads, covers and tube sheets will monitor surface conditions for indications of loss of material. The sample population of heat exchangers includes the high-pressure coolant injection (HPCI) gland seal condenser (GSC), HPCI lube oil cooler, reactor core isolation coolant lube oil cooler, condensate storage and transfer steam reheat coil, drywell atmospheric cooling units (RRU-1, 2, 3, and 4), reactor recirculation pump (RRP) seal water coolers, RRP motor upper and lower bearing oil coolers, and RRP motor air coolers. The program will be implemented prior to the period of extended operation. Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.1.14 on the applicant's demonstration of the Heat Exchanger Monitoring Program to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff reviewed the Heat Exchanger Monitoring Program against the AMP elements found in the GALL Report, in SRP-LR Appendix A.1.2.3, and in SRP-LR Table A.1-1, focusing on how the program manages aging effects through the effective incorporation of 10 elements (i.e., scope of the program, preventive actions, parameters monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, administrative controls, and operating experience). The applicant indicated that the corrective actions, confirmation process, and administrative controls program elements are parts of the site-controlled QA program. The staff's evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven elements follows: (1) Scope of Program - LRA Section B.1.14 states that this program will manage aging effects on selected heat exchangers in various systems as identified in AMRs. In the program description for this program in the LRA, the applicant listed the specific components that are managed by this program. The staff confirmed that the specific components for which the program manages aging effects are identified by the applicant, which satisfies the criterion as defined in SRP-LR Appendix A.1.2.3.1. On this basis, the staff finds that the applicants proposed program scope acceptable. The staff confirmed that the scope of the program program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.1. The staff finds this program element acceptable. 3-111

(2) Preventive Actions - LRA Section B.1.14 states that this program is an inspection program and no actions are taken as part of this program to prevent degradation. The staff confirmed that the preventive actions program element satisfied the criteria defined in SRP-LR Appendix A.1.2.3.2. The staff finds it acceptable because this is an inspection program and there is no need for preventive actions. On this basis, the staff finds that the applicant's preventive actions acceptable. The staff confirmed that the preventive actions program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.2. The staff finds this program element acceptable. (3) Parameters Monitored or Inspected - LRA Section B.1.14 states that this program where practical, eddy current inspections of shell-and-tube heat exchanger tubes may be performed to determine tube wall thickness. Visual inspections will be performed on heat exchanger heads, covers and tube sheets where accessible to monitor surface condition for indications of loss of material. The staff confirmed that the preventive actions program element satisfied the criteria defined in SRP-LR Appendix A.1.2.3.3. In the LRA, the applicant stated that this AMP is credited to manage the aging effect of loss of material on the pressure boundary intended function for the components for which this AMP is credited. Visual inspection of the heat exchanger heads, covers and tube sheets is capable of detecting indications of loss of material. The use of eddy current testing of the shell-and-tube heat exchanger tubes to determine changes in tube wall thickness will detect the loss of material on the tubes. On this basis, the staff finds that the applicant's description of the parameters monitored/inspected is acceptable. The staff confirmed that the parameters monitored or inspected program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.3. The staff finds this program element acceptable. (4) Detection of Aging Effects - LRA Section B.1.14 states that loss of material is the aging effect managed by this program. Representative tubes within the sample population of heat exchangers will be eddy current tested at a frequency determined by internal and external operating experience to ensure that effects of aging are identified prior to loss of intended function. Visual inspections of accessible heat exchangers will be performed on the same frequency as eddy current inspections. In addition, as stated in the LRA, supplement dated March 23, 2007, an appropriate sample population of heat exchangers will be determined based on operating experience prior to inspections. The sample population of heat exchangers will be determined based on materials of construction of the heat exchanger tubes and the associated environments as well as the type of heat exchanger (for example, shell and tube type). At least one heat exchanger of each type, material and environment combination will be included in the sample population. Inspection can reveal loss of material that could result in degradation of the heat exchangers. Fouling is not addressed by this program. 3-112

The LRA supplement also stated that testing frequency will be established using baseline eddy current testing in accordance with industry best practices and EPRI recommendations. The results of these baseline tests will be used to determine the frequency of future inspections and the number of tubes to be sampled. Additional examination methods (e.g., ultrasonic thickness measurements or radiography) may be used if as-found conditions warrant. The results of these inspections will be used to establish the frequency of future inspections. As documented in the Audit and Review Report, the applicant clarified that all heat exchangers in the program are inspected. The population of tubes for eddy-current testing is sampled using a standard industry methodology. The applicant also indicated that the heat transfer intended function is managed in accordance with another program for those heat exchangers for which this function is required. The inspection for the aging effect of loss of material is directly related to the pressure boundary intended function. All of the heat exchangers in the program are to be inspected and any sampling of the tubes to be selected for eddy-current testing is based on an industry standard methodology. The sample population of tubes will be eddy-current tested at a frequency based on internal and external operating experience. On this basis, the staff finds that the applicant's description of the detection of aging effects is acceptable. The staff confirmed that the detection of aging effects program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.4. The staff finds this program element acceptable. (5) Monitoring and Trending - LRA Section B.1.14 states that results of this program will be evaluated against established acceptance criteria and an assessment will be made regarding the applicable degradation mechanism, degradation rate and allowable degradation level. This information will be used to develop future inspection scope and to modify inspection frequency, if appropriate. Wall thickness will be trended and projected to the next inspection. Corrective actions will be taken if projections indicate that the acceptance criteria may not be met at the next inspection. The staff confirmed that the monitoring and trending program element satisfied the criteria defined in SRP-LR Appendix A.1.2.3.5. The program described above provides for monitoring and trending the eddy-current thickness data. In addition, the applicant stated that the condition of the surfaces based on visual inspections of the heat exchanger heads, covers and tube sheets will be trended. This information will allow the applicant to take the appropriate corrective actions before the loss of intended function. On this basis, the staff finds that the applicant's description of monitoring and trending is acceptable. The staff confirmed that the monitoring and trending program element satisfies recommendation defined in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.5. The staff finds this program element acceptable. 3-113

(6) Acceptance Criteria - LRA Section B.1.14 states that the minimum acceptable tube wall thickness for each heat exchanger to be eddy current inspected will be established based upon a component-specific engineering evaluation that considers industry best practices and EPRI recommendations. Wall thickness will be acceptable if greater than the minimum wall thickness for the component. In addition, as stated in the LRA, the acceptance criterion for visual inspections of heat exchanger heads, covers and tubesheets will be no evidence of degradation that could lead to loss of intended function. If degradation that could lead to loss of intended function is detected, a condition report will be written and the issue resolved in accordance with the site CAP. The staff confirmed that the acceptance criteria program element satisfied the criteria defined in SRP-LR Appendix A.1.2.3.6. The staff finds the use of specific criteria for the minimum wall thickness for each component based on a component-specific engineering evaluation to be acceptable for the eddy-current testing. On this basis, the staff finds that the applicant's description of the acceptance criteria is acceptable. The staff confirmed that the acceptance criteria program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.6. The staff finds this program element acceptable. (10) Operating Experience - LRA Section B.1.14 states that there is no operating experience for the new Heat Exchanger Monitoring Program. The staff recognized that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation defined in the GALL Report and in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.15, the applicant provided the UFSAR supplement for the Heat Exchanger Monitoring Program. The applicant committed to implement the Heat Exchanger Monitoring Program, documented as Commitment #12, as described in VYNPS AMP B.1.14, by March 21, 2012. The staff reviewed this section and determined that, upon the implementation of Commitment

1. 12, 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 technical review of the applicant's Heat Exchanger Monitoring Program with the addition of Commitment #12, 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 3-114

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 Containment Inservice Inspection Program Summary of Technical Information in the Application. LRA Section B.1.15.1 describes the Containment Inservice Inspection Program, as an existing, plant-specific program. Section 50.55a of 10 CFR imposes ASME Code, Section XI, ISI requirements for Classes 1, 2, and 3 pressure-retaining components and their attachments in light-water cooled power plants. Additionally, 10 CFR 50.55a imposes ASME Code, Section XI, ISI requirements for Class MC and Class CC containment structures. Subsection IWE provides inspection requirements for Class MC metal containments and Class CC concrete containments. The scope of Subsection IWE includes steel liners for concrete containment and their attachments, containment hatches and airlocks, moisture barriers, and pressure-retaining bolting. The program uses NDE techniques to detect and characterize flaws. Three different types of examinations are volumetric, surface, and visual. Volumetric examinations are the most extensive, using methods such as radiographic, ultrasonic or eddy current examinations to locate surface and subsurface flaws. Surface examinations, such as magnetic particle or dye penetrant testing, are used to locate surface flaws. Three levels of visual examinations are specified: VT-1, VT-2, and VT-3. The Containment Inservice Inspection Program encompasses the requirements for the inspection of Class MC pressure-retaining components (primary containment) and their integral attachments in accordance with the requirements of 10 CFR 50.55a(b)(2) and the 1998 Edition of ASME Code, Section XI with 2000 Addenda, Inspection Program B. Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.1.15.1 on the applicant's demonstration of the Containment Inservice Inspection Program to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff reviewed the Containment Inservice Inspection Program against the AMP elements finds in the GALL Report, in SRP-LR Appendix A.1.2.3, and in SRP-LR Table A.1-1, focusing on how the program manages aging effects through the effective incorporation of 10 elements (i.e., scope of the program, preventive actions, parameters monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, administrative controls, and operating experience). During the audit and review, the staff asked the applicant to explain why its Containment Inservice Inspection Program was a plant-specific program instead of an existing plant program that is consistent with GALL AMP XI.S1, ASME Code, Section XI, Subsection IWE, with exceptions. The applicant stated that VYNPS chose to describe its Containment Inservice Inspection Program as plant-specific rather than comparing it to the corresponding GALL Report program because the GALL Report program contains many ASME Code, Section XI tables and section numbers which change with different versions of the code. Because of this, comparison with the GALL Report program would have generated many exceptions and explanations which 3-115

would have detracted from the objective of the comparison. Therefore, the Inservice Inspection - Containment Inservice Inspection Program was presented as a plant-specific program so that it could be evaluated on its own merit without numerous explanations of code revision. The staff finds VYNPSs classification of its Containment Inservice Inspection Program as plant-specific an acceptable alternative to characterizing it as consistent with GALL AMP XI.S1, with exceptions. The staffs evaluation of the 10 program element are provided below. The staff's evaluation of the applicants QA program is discussed in SER Section 3.0.4. (1) Scope of Program - LRA Section B.1.15.1 states that this program, in accordance with ASME Code, Section XI Subsection IWE, manages loss of material and cracking for the primary containment and its integral attachments. The primary containment is a GE Mark I pressure suppression containment system. The system consists of a drywell (housing the reactor vessel and reactor coolant recirculation loops), a pressure suppression chamber (housing a water pool), and the connecting vent system between the drywell and the water pool, isolation valves, and containment cooling systems. The code of construction for the containment structure is the ASME Code, Section III,1965, with winter addenda. The staff confirmed that the specific components for which the program manages aging effects are identified by the applicant, which satisfied the criterion as defined in SRP-LR Appendix A.1.2.3.1. On this basis, the staff finds that the applicants proposed program scope acceptable. The staff confirmed that the scope of the program program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.1. The staff finds this program element acceptable. (2) Preventive Actions - LRA Section B.1.15.1 states that this program is a monitoring program that does not include preventive actions. The staff confirmed that the preventive actions program element satisfied the criteria defined in SRP-LR Appendix A.1.2.3.2. The staff finds that the applicants Containment Inservice Inspection Program is only an inspection program and the inspections performed in accordance with this program will only monitor the condition of the primary containment and its integral attachments and will not perform any preventive or mitigating action for aging effects/mechanisms. On this basis, the staff finds the applicant's preventive actions acceptable. The staff confirmed that the preventive actions program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.2. The staff finds this program element acceptable. (3) Parameters Monitored or Inspected - LRA Section B.1.15.1 states that the primary containment and its attachments are inspected for evidence of cracks, wear, and corrosion. 3-116

The staff asked the applicant to explain why VYNPS did not have a Service Level I Protective Coating Monitoring and Maintenance Program to prevent coating failure that could adversely affect the operation of post-accident fluid systems emergency core cooling systems (ECCS) and thereby impair safe shutdown. The applicant had already stated in the LRA that coatings are not relied on for managing aging effects for license renewal which the staff finds acceptable. The applicant stated in detail during the audit and review its response to GL 98-04, Potential for Degradation of the Emergency Core Cooling System and Containment Spray System After a Loss of Coolant Accident Because of Construction and Protective Coating Deficiencies and Foreign Material in Containment, dated July 14, 1998, that the impact of debris loading on the ECCS strainers at VYNPS is discussed. As discussed in the GL response, in response to NRC Bulletin 96-03, new large passive ECCS strainers have been installed at VYNPS. The applicant stated that the new VYNPS torus strainers were designed to accept 100 percent of the coatings within the LOCA pipe break steam/water jet zone of influence. The approach velocity of materials entrained in the torus water is extremely low due to the sizing of the ECCS strainers and also any coating debris would quickly settle to the bottom of the suppression pool after the initial turbulence subsided. The NRC has previously accepted VYNPSs response to GL 98-04 which indicated that the coatings of the containment will not affect the operation of the ECCS strainers during a LOCA. Since coatings are not relied upon to manage aging effects and not an ECCS strainer blockage concern, the staff finds the applicants response acceptable for not requiring a Service Level I Protective Coating Monitoring and Maintenance Program in accordance with license renewal. The staff confirmed that the parameters monitored/inspected program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.3. The staff finds that the applicant has identified the parameters of the primary containment and its attachments which need to be inspected by general visual examination to determine if aging effects/mechanisms have occurred and to the extent that detailed visual examinations need to be performed. In accordance with IWE requirements, if detailed IWE visual examinations are required of certain areas, the areas shall be examined for evidence of cracking, discoloration, wear, pitting, excessive corrosion, gouges, surface discontinuities, dents, and other signs of surface irregularities. On this basis, the staff finds that the applicant's description of the parameters monitored or inspected acceptable. The staff confirmed that the parameters monitored or inspected program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.3. The staff finds this program element acceptable. 3-117

(4) Detection of Aging Effects - LRA Section B.1.15.1 states that this program manages loss of material for the primary containment and its integral attachments. In addition, as stated in the LRA, the primary inspection method for the primary containment and its integral attachments is visual examination. Visual examinations are performed either directly or remotely with sufficient illumination and resolution suitable for the local environment to assess general conditions that may affect either the containment structural integrity or leak tightness of the pressure retaining component. The program includes augmented ultrasonic exams to measure wall thickness of the containment structure. The staff confirmed that this program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.4. Although not stated in accordance with this element, the staff finds that the applicant has identified the frequency of inspections in accordance with the program description. In accordance with the program description, it is stated that VYNPS uses Inspection Program B of ASME Code, Section XI Subsection IWE. This inspection program consists of sequential 10-year inspection intervals with three partial inspection periods within the interval. All accessible areas of the primary containment and its integral attachments will be inspected every 10 years. An initial visual examination is an adequate method to gather data on the condition of the primary containment and its integral attachments. Should flaws or areas of degradation be found which exceed the acceptance standards, ultrasonic examinations are also an adequate method to determine remaining component thickness. On this basis, the staff finds that the applicant's description of the detection of aging effects acceptable. The staff confirmed that the detection of aging effects program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.4. The staff finds this program element acceptable. (5) Monitoring and Trending - LRA Section B.1.15.1 states that program results are compared, as appropriate, to baseline data and other previous test results. If indications are accepted for continued use by analytical evaluation, the areas containing such flaws are monitored during successive inspection periods. The staff confirmed that for visual inspection, this program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.5. The staff finds that the applicant will retain all inspection results and records in accordance with its Inservice Inspection - Containment Inservice Inspection Program. As appropriate, reviews of previous inspection results and records will be done for areas containing flaws so that long-term degradation can be trended. The applicant will continue to monitor areas containing flaws during successive inspection periods even if the flaws are accepted for continued use by analytical evaluation. On this basis, the staff finds that the applicant's description of the monitoring and trending acceptable. The staff confirmed that the monitoring and trending program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.5. The staff finds this program element acceptable. 3-118

(6) Acceptance Criteria - LRA Section B.1.15.1 states that program results are compared, as appropriate, to baseline data, other previous test results, and acceptance criteria of the ASME Code, Section XI, Subsection IWE for evaluation of any evidence of degradation. The staff confirmed that the acceptance criteria program element satisfied the criteria defined in SRP-LR Appendix A.1.2.3.6. The staff finds that the applicant compared all primary containment and its integral attachments inspection findings, as appropriate, to baseline data, other previous test results, and acceptance criteria of the ASME Code, Section XI, Subsection IWE. On this basis, the staff finds that the applicant's description of the acceptance criteria acceptable. The staff confirmed that the acceptance criteria program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.6. The staff finds this program element acceptable. (7) Corrective Actions - The adequacy of the applicant's 10 CFR 50, Appendix B Program associated with this program element is reviewed by the staff and addressed in SER Section 3.0.4. The staff reviewed other aspects of this program element to determine whether or not it satisfied the criteria defined in SRP-LR Appendix A.1.2.3.7. The staff finds that the applicant will take corrective action when conditions adverse to the quality of the primary containment and its integral attachments exist, by performing evaluations and/or repair and replacements. On this basis, the staff finds that the applicant's description of the corrective actions acceptable. (8) Confirmation Process - The adequacy of the applicant's 10 CFR 50, Appendix B Program associated with this program element was reviewed by the staff and is addressed in SER Section 3.0.4. The staff reviewed other aspects of this program element to determine whether or not it satisfied the criteria defined in SRP-LR Appendix A.1.2.3.8. The staff finds that the applicants confirmation process is part of the CAP and included reviews to assure that proposed actions are adequate, tracking and reporting of open corrective actions, and review of corrective action effectiveness. Any followup inspection required by the confirmation process is documented in accordance with the CAP. The CAP constitutes the confirmation process for the VYNPS AMPs and activities. The ASME Code, Section XI, Subsection IWE, also requires that when the primary containment and its integral attachments examination results require evaluation of flaws or areas of degradation, and the component is acceptable for continued service, the areas containing such flaws or areas of degradation shall be reexamined during the next inspection period in accordance with augmented inspections. In accordance with Subsection IWE, when the reexaminations reveal that the flaws or areas of degradation remain essentially unchanged for the next inspection period, these areas no longer require augmented examination. On this basis, the staff finds that the applicant's description of the confirmation process acceptable. 3-119

(9) Administrative Controls - The adequacy of the applicant's 10 CFR 50, Appendix B Program associated with this program element was reviewed by the staff and is addressed in SER Section 3.0.4. The staff reviewed other aspects of this program element to determine whether or not it satisfied the criteria defined in SRP-LR Appendix A.1.2.3.9. The staff finds that the applicants Containment Inservice Inspection Program has regulatory and administrative controls which provide a formal review and approval process of the program. On this basis, the staff finds that the applicant's description of the administrative controls acceptable. (10) Operating Experience - LRA Section B.1.15.1 states that RFO 21 inspections finds only two areas of potential age-related degradation; the drywell floor to metal containment moisture barrier had missing paint, cracked paint, and areas of corrosion on the base metal in the seal area; and corrosion was found in the area of the X-5G penetration. Engineering evaluation was performed and no significant wall loss was identified. Base metal was prepared, primed and painted to protect it from further corrosion, and the moisture barrier was replaced. RFO 22 inspections found two more areas of potential age-related degradation; surface pitting of primary containment vent headers and vent pipe bowls; and corrosion on torus penetrations X-207A-H. Evaluation determined that the components have significant margin to code minimum wall thickness and that the rate of corrosion is low due to the inerted containment environment during operation. Augmented inspections were not necessary since none of the identified corrosion was significant. RFO 24 inspections revealed flaking coating and rust staining on the bay 3 inner torus wall. Subsequent ultrasonic examination revealed no material loss. Also, visual inspection of drywell head exterior surface revealed areas of localized missing coating and primer with light corrosion, but no material loss. Resolution of these issues prior to loss of component intended function proves that the program is effective at managing aging effects for primary containment and its integral attachments. RFO 24 visual inspections of drywell interior surfaces, stabilizer assembly interior surfaces, torus penetrations, and drywell penetrations revealed areas of localized missing coating where the primer is intact, but no corrosion or material loss. Visual inspection of new drywell moisture barrier resulted in no recordable indications. Absence of aging effects on these components proves that the program is effective at managing aging effects for primary containment and its integral attachments. Further, QA surveillance during RFO 24 revealed a problem with program administrative controls. The issue was addressed and closed. The program was revised to require that engineering evaluations of indications that do not meet acceptance criteria be completed before the containment is declared operable. QA surveillance revealed an issue that could impact effectiveness of the program. Resolution of this issue provides evidence that the program remains effective at managing aging effects for primary containment and its integral attachments. A recent engineering system health report revealed no issues or findings that could impact program effectiveness. 3-120

The staff reviewed the summary of specific operating experience provided in the applicants applicable program basis document, as documented in the Audit and Review Report, for the Containment Inservice Inspection Program. The review indicated that the applicants Inservice Inspection - Containment Inservice Inspection Program is effective in identifying age-related degradation, implementing repairs, and maintaining the integrity of the containment pressure boundaries and the moisture barrier seal. The staff noted that there has been only one noteworthy component CR written as a result of the Inservice Inspection - Containment Inservice Inspection Program since the inception of the program. During the RFO 21 inspections, two areas of potential age-related degradation were discovered. The drywell floor to metal containment moisture barrier had missing paint, cracked paint, and areas of corrosion on the base metal in the seal area; and corrosion was found in the area of the X-5G penetration. The applicant performed an engineering evaluation and no significant wall thickness loss was identified. The applicant prepared, primed and painted the containment base metal to protect it from further corrosion, and the moisture barrier was replaced. Historically, the other deficiencies were limited to such things as flaking or missing coatings on the drywell liner, minor rust staining and corrosion of the drywell liner, and minor corrosion of drywell penetrations, torus penetrations, vent headers, vent pipe bowls, drywell head and torus bays. None of these deficiencies resulted in loss of intended function due to age-related degradation. This provides assurance that containment pressure boundary degradation has not been occurring since the inception of the program. The staff also noted that there was one noteworthy CR written by the applicants QA on a deficiency in the process for declaring the containment operable after a RFO. QA surveillance during RFO 24 revealed a problem with the Inservice Inspection - Containment Inservice Inspection Program administrative controls that could have impacted the effectiveness of the program. The applicant states in the LRA that the program was revised to require that engineering evaluations of indications that do not meet acceptance criteria be completed before the containment is declared operable. The staff finds that the applicants resolution of this issue ensures that the containment pressure boundary will not operate in a condition with findings that have not been evaluated. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. 3-121

UFSAR Supplement. In LRA Section A.2.1.16, the applicant provided the UFSAR supplement for the Containment Inservice Inspection Program. The staff reviewed LRA Section A.2.1.16 and finds the UFSAR supplement information an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its technical review of the applicant's Containment Inservice Inspection Program, 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). 3.0.3.3.3 Inservice Inspection Program Summary of Technical Information in the Application. LRA Section B.1.15.2 describes the Inservice Inspection Program, as an existing, plant-specific program. Section 50.55a of 10 CFR imposes inservice inspection requirements of ASME Code Section XI for Classes 1, 2, and 3 pressure-retaining components and their attachments in light-water cooled power plants. Additionally, 10 CFR 50.55a imposes inservice inspection requirements of ASME Code Section XI for Class MC and Class CC containment structures. Subsection IWE contains inspection requirements for Class MC metal containments and Class CC concrete containments. The scope of IWE includes steel liners for concrete containment and their attachments; containment hatches and airlocks; moisture barriers; and pressure-retaining bolting. The program uses NDE techniques to detect and characterize flaws. Three different types of examinations are volumetric, surface, and visual. Volumetric examinations are the most extensive, with such methods as radiographic, ultrasonic, or eddy current examinations to locate surface and subsurface flaws. Surface examinations like magnetic particle or dye penetrant testing locate surface flaws. Three levels of visual examinations specified are VT-1, VT-2, and VT-3. The Inservice Inspection Program encompasses ASME Code, Section XI, Subsection IWA, IWB, IWC, IWD and IWF requirements. The Inservice Inspection Program is based on ASME Code, Inspection Program B (IWA-2432), which has 10-year inspection intervals. Every 10 years the program is updated to the latest ASME Code edition and addendum, Section XI, approved by the staff, in accordance with 10 CFR 50.55a. On September 1, 2003, VYNPS entered the fourth ISI interval. The Code Edition and Addenda used for the fourth interval is the 1998 Edition with 2000 Addenda. The current program maintains the structural integrity of Classes 1, 2, and 3 systems and supports at the level required by 10 CFR 50.55a. Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.1.15.2 on the applicant's demonstration of the Inservice Inspection Program to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. 3-122

The staff reviewed the Inservice Inspection Program against the AMP elements found in the GALL Report, in SRP-LR Appendix A.1.2.3, and in SRP-LR Table A.1-1, focusing on how the program manages aging effects through the effective incorporation of 10 elements (i.e., scope of the program, preventive actions, parameters monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, administrative controls, and operating experience). The applicant indicated that the corrective actions, confirmation process, and administrative controls program elements are parts of the site-controlled QA program. The staff's evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven elements follows: (1) Scope of Program - LRA Section B.1.15.2 states that this program manages cracking, loss of material, and reduction of fracture toughness of reactor coolant system piping, components, and supports. The program implements applicable requirements of ASME Code, Section XI, Subsections IWA, IWB, IWC, IWD and IWF, and other requirements specified in 10 CFR 50.55a with approved NRC alternatives and relief requests. Every 10 years the Inservice Inspection Program is updated to the latest ASME Code Edition and Addendum, Section XI, approved by the NRC, in accordance with10 CFR 50.55a. ASME Code, Section XI inspection requirements for reactor vessel internals, (Subsection IWB, Categories B-N-1 and B-N-2) are not in the Inservice Inspection Program, but are included in the BWR Vessel Internals Program. For more information on the BWR Vessel Internals Program, see SER Section 3.0.3.2.7. The staff confirmed that the specific components for which the program manages aging effects are identified by the applicant, which satisfied the criterion as defined in SRP-LR Appendix A.1.2.3.1. They conform to the scope of ISI as set forth in ASME Code, Section XI, Subsections IWA, IWB, IWC, IWD and IWF and approved by the staff in accordance with 10 CFR 50.55a. On this basis, the staff finds that the applicants proposed program scope to be acceptable. The staff confirmed that the scope of the program program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.1. The staff finds this program element acceptable. (2) Preventive Actions - LRA Section B.1.15.2 states that this program is a condition monitoring program that does not include preventive actions. The staff confirmed that the preventive actions program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.2 for a condition monitoring program. On this basis, the staff finds the absence of preventive actions to be acceptable. The staff confirmed that the preventive actions program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.2. The staff finds this program element acceptable. 3-123

(3) Parameters Monitored or Inspected - LRA Section B.1.15.2 states that this program uses NDE techniques to detect and characterize flaws. Volumetric examinations such as radiographic, ultrasonic or eddy current examinations are used to locate surface and subsurface flaws. Surface examinations, such as magnetic particle or dye penetrant testing, are used to locate surface flaws. The applicant also stated that three levels of visual examinations are specified. VT-1 visual examination is conducted to assess the condition of the surface of the part being examined, looking for cracks and symptoms of wear, corrosion, erosion or physical damage. It can be done with either direct visual observation or with remote examination using various optical and video devices. VT-2 visual examination is conducted specifically to locate evidence of leakage from pressure retaining components (period pressure tests). While the system is in accordance with pressure for a leakage test, visual examinations are conducted to detect direct or indirect indication of leakage. VT-3 visual examination is conducted to determine general mechanical and structural condition of components and supports and to detect discontinuities and imperfections. The staff confirmed that the preventive actions program element satisfied the criteria defined in SRP-LR Appendix A.1.2.3.3. They are consistent with the requirements of applicable subsections Section XI of the ASME Code. Although the 1998 Edition (with year 2000 Addenda) is in effect for the current (fourth) interval, the program addresses the need to increase or expand examination scope as required to satisfy the requirements of 10 CFR 50.55a. In addition, the program addresses the need to revisit the specific version of the ASME Code in subsequent intervals and to re-evaluate exemptions to be requested. On this basis, the staff finds that the applicant's description of the parameters monitored/inspected is acceptable. The staff confirmed that the parameters monitored or inspected program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.3. The staff finds this program element acceptable. (4) Detection of Aging Effects - LRA Section B.1.15.2 states that this program manages cracking and loss of material, as applicable, for carbon steel, low alloy steel and stainless steel/nickel based alloy subcomponents of the RPV using NDE techniques specified in ASME Code, Section XI, Subsection IWB examination categories. The applicant also stated that its Inservice Inspection Program manages cracking, loss of preload, loss of material, and reduction of fracture toughness, as applicable, of reactor coolant system components using NDE techniques specified in ASME Code, Section XI, Subsections IWB, IWC and IWD examination categories. No AERMs are identified for lubrite sliding supports. However, the Inservice Inspection Program will confirm the absence of aging effects for the period of extended operation. In addition, the applicant stated that its Inservice Inspection Program manages loss of material for ASME Code, Class 1, 2, and 3 steel piping supports and steel component supports within containment, using NDE techniques specified in ASME Code, Section XI, Subsection IWF examination categories. 3-124

The staff confirmed that this program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.4 for the detection of aging effects. The applicants Inservice Inspection Program has been reviewed and accepted by the staff in accordance with 10 CFR 50.55a. On this basis, the staff finds that the applicant's description of the detection of aging effects is acceptable. The staff confirmed that the detection of aging effects program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.4. The staff finds this program element acceptable. (5) Monitoring and Trending - LRA Section B.1.15.2 states that program results are compared, as appropriate, to baseline data and, other previous test results. If indications are accepted for continued use by analytical evaluation, the areas containing such flaws are monitored during successive inspection periods. The applicant also stated that ISI results are recorded every operating cycle and provided to the NRC after each refueling outage via Owners Activity Reports prepared by the Inservice Inspection Program Coordinator. These detailed reports include scope of inspection and significant inspection results. The staff confirmed that the monitoring and trending program element satisfied the criteria defined in SRP-LR Appendix A.1.2.3.5. The implementing procedure and selected records of prior inspections were examined to confirm that the requirements of this program element are satisfied. On this basis, the staff finds that the applicant's description of the acceptance criteria is acceptable. The staff confirmed that the monitoring and trending program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.5. The staff finds this program element acceptable. (6) Acceptance Criteria - LRA Section B.1.15.2 states that in this program a preservice, or baseline, inspection of program components was performed prior to startup to assure freedom from defects greater than code-allowable. This baseline data also provides a basis for evaluating subsequent inspection results. Since plant startup, additional inspection criteria for Class 2 and 3 components have been required by 10 CFR 50.55a, for which baseline data has also been obtained. Results are compared, as appropriate, to baseline data, other previous test results, and acceptance criteria of the ASME Boiler and Pressure Vessel Code, Section XI, 1998 Edition, 2000 Addenda, for evaluation of any evidence of degradation. The staff confirmed that the acceptance criteria program element satisfied the criteria defined in SRP-LR Appendix A.1.2.3.6. The implementing procedure and selected records of prior inspections were examined to confirm that the requirements of this program element are satisfied. On this basis, the staff finds that the applicant's description of the acceptance criteria is acceptable. 3-125

The staff confirmed that the acceptance criteria program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.6. The staff finds this program element acceptable. (10) Operating Experience - LRA Section B.1.15.2 states that evaluation of pressure boundary components, including bolting, is by NDEs and visual inspections. Deviations from acceptance criteria are properly resolved. Inspections since 2001 revealed erosion of valve body internals, weld indications, recirculation pump bolting corrosion, and RHR valve bolting corrosion. The scope of welding inspections was expanded when rejectable indications were revealed. Condition reports documented indications and ensured resolution of those conditions. Corrective actions included repair and replacement of components. These actions prove that the program is effective at managing component aging effects. QA audits, QA surveillances, engineering system health reports, and staff inspections from 2001 to 2004 revealed no issues or findings that could impact program effectiveness. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.17, the applicant provided the UFSAR supplement for the Inservice Inspection Program. The staff reviewed this section and finds the UFSAR supplement information an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its technical review of the applicant's Inservice Inspection Program, 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). 3-126

3.0.3.3.4 Instrument Air Quality Program Summary of Technical Information in the Application. LRA Section B.1.16 describes the Instrument Air Quality Program as an existing, plant-specific program. The Instrument Air Quality Program maintains instrument air (IA) supplied to components free of water and significant contaminants, preserving an environment not conducive to loss of material. Dewpoint, particulate contamination, and hydrocarbon concentration are checked periodically to maintain IA quality. Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.1.16 on the applicant's demonstration of the Instrument Air Quality Program to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff reviewed the Instrument Air Quality Program against the AMP elements found in the GALL Report, in SRP-LR Appendix A.1.2.3, and in SRP-LR Table A.1-1, focusing on how the program manages aging effects through the effective incorporation of 10 elements (i.e., scope of the program, preventive actions, parameters monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, administrative controls, and operating experience). The applicant indicated that the corrective actions, confirmation process, and administrative controls program elements are parts of the site-controlled QA program. The staff's evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven elements follows: (1) Scope of Program - LRA Section B.1.16 states that this program applies to components within the scope of license renewal and subject to an AMR that are supplied with IA, for which pressure boundary integrity is required for the component to perform its intended function. The staff confirmed that the specific components for which the program manages aging effects are identified by the applicant, which satisfied the criterion as defined in SRP-LR Appendix A.1.2.3.1. In addition, on the basis of a review of implementing procedures and discussions with the applicants staff, the program reflects the VYNPS response to GL 88-14 as augmented by NRC Information Notice (IN) 81-38 and its first supplement. On this basis, the staff finds that the applicants proposed program scope is acceptable. The staff confirmed that the scope of the program program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.1. The staff finds this program element acceptable. (2) Preventive Actions - LRA Section B.1.16 states that system air quality is monitored and maintained within specified limits to ensure that IA supplied to components is maintained free of water and significant contaminants, thereby preventing loss of material. 3-127

The staff confirmed that the preventive actions program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.2. The activities for prevention and mitigation of aging effects on systems and components within the scope of license renewal that are supplied with IA are adequately described. On this basis, the staff finds that the applicant's preventive actions is acceptable. The staff confirmed that the preventive actions program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.2. The staff finds this program element acceptable. (3) Parameters Monitored or Inspected - LRA Section B.1.16 state that dewpoint, particulate contamination and hydrocarbon concentration are periodically checked to verify IA quality is maintained. The staff confirmed that the preventive actions program element satisfied the criteria defined in SRP-LR Appendix A.1.2.3.3. Dewpoint, particulate contamination and hydrocarbon concentration are linked to the aging effects of concern and are appropriate parameters to be monitored. Furthermore, in a letter dated July 6, 2006, the applicant committed to maintain the quality of compressed air in accordance with Instrument Society of America (ISA) S7.3 Quality Standard for Instrument Air. On this basis, the staff finds that the applicant's description of the parameters monitored/inspected is acceptable. The staff confirmed that the parameters monitored or inspected program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.3. The staff finds this program element acceptable. (4) Detection of Aging Effects - LRA Section B.1.16 states that dewpoint, particulate contamination and hydrocarbon concentration are periodically checked to verify IA quality is maintained, thereby preventing loss of material. At least once per 18 months, dew point, particulate contamination and hydrocarbon concentration are monitored at several locations in the IA system. The staff confirmed that the detection of aging effects program element satisfied the criteria defined in SRP-LR Appendix A.1.2.3.4. The staff reviewed the implementing procedures for measuring dewpoint, particulate contamination and hydrocarbon concentration monitoring. Degradation of the piping and any components would become evident by observation of excessive corrosion or by failure of the system or any item of components to meet specified performance limits. On this basis, the staff finds that the applicant's description of the detection of aging effects is acceptable. The staff confirmed that the detection of aging effects program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.4. The staff finds this program element acceptable. 3-128

(5) Monitoring and Trending - LRA Section B.1.16 states that results of sample analyses are maintained in the chemistry log. A condition report is issued if data indicates deteriorating IA quality. The staff confirmed that for visual inspection, the monitoring and trending program element satisfied the criteria defined in SRP-LR Appendix A.1.2.3.5. Effects of corrosion and the presence of contaminants are monitored by visual inspection and periodic system and component tests. On this basis, the staff finds that the applicant's description of monitoring and trending is acceptable. The staff confirmed that the monitoring and trending program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.5. The staff finds this program element acceptable. (6) Acceptance Criteria - LRA Section B.1.16 states that:

• dew point less than or equal to 40EC
• maximum particle size is 3 micrometers
• hydrocarbon content less than or equal to 1 parts per million (ppm)

The staff confirmed that the acceptance criteria program element satisfied the criteria defined in SRP-LR Appendix A.1.2.3.6. The acceptance criteria specified in the VYNPS Instrument Air Quality Program have been found to be appropriate for managing the aging effects in the IA system. On this basis, the staff finds that the applicant's description of the acceptance criteria is acceptable. The staff confirmed that the acceptance criteria program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.6. The staff finds this program element acceptable. (10) Operating Experience - LRA Section B.1.16 states that recent analyses revealed all parameters maintained within acceptance criteria. Absence of degradation of IA quality proves that the program is effective at maintaining IA supplied to components free of water and significant contaminants and preventing loss of material. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. 3-129

UFSAR Supplement. In LRA Section A.2.1.18, the applicant provided the UFSAR supplement for the Instrument Air Quality Program. The applicant committed (Commitment #28) to revise the program procedure by March 21, 2012, to indicate that the Instrument Air Program maintains IA quality in accordance with ISA S7.3. The staff reviewed this section and determined that, upon the implementation of Commitment

1. 28, 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 technical review of the applicant's Instrument Air Quality Program with the addition of Commitment #28, 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). 3.0.3.3.5 Periodic Surveillance and Preventive Maintenance Program Summary of Technical Information in the Application. LRA Section B.1.22 describes the Periodic Surveillance and Preventive Maintenance Program as an existing, plant-specific program. The Periodic Surveillance and Preventive Maintenance Program includes periodic inspections and tests that manage aging effects not managed by other AMPs. Preventive maintenance and surveillance testing are generally implemented through repetitive tasks or routine monitoring of plant operations. The program has taken credit in the AMR of the following systems and structures: reactor building, yard structures, HPCI system, standby gas treatment system (SGTS), primary containment atmosphere control (PCAC) system, SWS, EDG system, HVAC system, John Deere diesel, and nonsafety-related systems and components affecting safety-related systems. Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.1.22 on the applicant's demonstration of the Periodic Surveillance and Preventive Maintenance Program to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff reviewed the Periodic Surveillance and Preventive Maintenance Program against the AMP elements found in the GALL Report, in SRP-LR Appendix A.1.2.3, and in SRP-LR Table A.1-1, focusing on how the program manages aging effects through the effective incorporation of 10 elements (i.e., scope of the program, preventive actions, parameters monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, administrative controls, and operating experience). 3-130

The applicant indicated that the corrective actions, confirmation process, and administrative controls program elements are parts of the site-controlled QA program. The staff's evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven elements follows: (1) Scope of Program - LRA Section B.1.22 states that this program, with regard to license renewal, includes those tasks credited with managing aging effects identified in AMRs. The staff confirmed that the specific components for which the program manages aging effects are identified by the applicant, which satisfies the criterion as defined in SRP-LR Appendix A.1.2.3.1. On this basis, the staff finds that the applicants proposed program scope acceptable. The staff confirmed that the scope of the program program element satisfies the recommendnation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.1. The staff finds this program element acceptable. (2) Preventive Actions - LRA Section B.1.22 states that inspection and testing activities used to identify component aging effects do not prevent aging effects. However, activities are intended to prevent failures of components that might be caused by aging effects. The staff confirmed that the preventive actions program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.2. Since inspection and testing activities do not rely on preventive actions and preventive actions need not be provided, the staff finds that the applicant's preventive actions acceptable. The staff confirmed that the preventive actions program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.2. The staff finds this program element acceptable. (3) Parameters Monitored or Inspected - LRA Section B.1.22 states that this program provides instructions for monitoring structures, systems, and components to detect degradation. Inspection and testing activities monitor various parameters including system flow, system pressure, surface condition, loss of material, presence of corrosion products, and signs of cracking. The staff reviewed the applicants basis document and compared with AMRs which credit Periodic Surveillance and Preventive Maintenance Program and concurred with the applicant that inspection and testing activities monitor various parameters including system flow, system pressure, surface condition, loss of material, presence of corrosion products, and signs of cracking. The staff confirmed that the preventive actions program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.3. On this basis, the staff finds that the applicant's description of the parameters monitored or inspected is acceptable. The staff confirmed that the parameters monitored or inspected program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.3. The staff finds this program element acceptable. 3-131

(4) Detection of Aging Effects - LRA Section B.1.22 states that preventive maintenance activities and periodic surveillances provide for periodic component inspections and testing to detect aging effects. Inspection intervals are established such that they provide timely detection of degradation. Inspection intervals are dependent on component material and environment and take into consideration industry and plant-specific operating experience and manufacturers recommendations. Each inspection or test occurs at least once every ten years. The extent and schedule of inspections and testing assure detection of component degradation prior to loss of intended functions. Established techniques such as visual inspections are used. The staff reviewed the applicants basis document to confirm that the program provides inspection intervals and inspection method. The staff finds that periodic surveillance intervals and requirements meet TS requirements and the inspection and testing interval for surface condition degradation is 5 years. During the audit and review, the staff asked the applicant to justify if inspection interval of 5 years for general corrosion of carbon steel CW system components exposed to raw water environment is adequate. The applicant responded that: (1) From reviewing its Service Water Monitoring Program, MIC is significantly inhibited when exposed to chlorination. Circulating water is periodically treated with chlorine, which further reduces this potential for attack for this system and that general corrosion, even in raw water systems such as circulating water, is not fast acting; (2) PSPM inspection activities are performed on 10 CFR 54.4(a)(2) systems that have been in service for the life of the plant without required inspections per the VYNPS corrective action program. If significant changes are noted, the frequency in the PSPM can be updated; (3) The consequences of failure due to loss of material are low; and (4) With the exception of the alternate cooling tower cell, the circulating water system does not run through the reactor building or near any safety-related equipment. Based on the aging stressors described above, the applicant concluded that the alternate cooling tower cell will not be impacted. In addition, SRP-LR Appendix A.1.2.2-3 states that risk significance may be considered in developing the details of an aging management program. The staff reviewed the information provided by the applicant. On the basis of its review of the applicants technical justification and operating experience, the staff found that the inspection interval of 5 years is adequate for monitoring general corrosion of carbon steel components exposed to a raw water environment in the circulating water system to assure corrective action is taken prior to loss of intended function. The staff confirmed that this program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.4. The staff finds that the applicants program provides inspection intervals and inspection method and that periodic surveillance interval and requirements meet TS requirement and the inspection and testing interval for surface condition degradation is 5 years. On this basis, the staff finds that the applicant's description of the detection of aging effects is acceptable. The staff confirmed that the detection of aging effects program element satisfies therecommendnation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.4. The staff finds this program element acceptable. 3-132

(5) Monitoring and Trending - LRA Section B.1.22 states that preventive maintenance and surveillance testing activities provide for monitoring and trending of aging degradation. Inspection and testing intervals are established such that they provide for timely detection of component degradation. Inspection and testing intervals are dependent on component material and environment and take into consideration industry and plant-specific operating experience and manufacturers recommendations. The staff reviewed applicants program and its related operating procedures and determines the program is used to identify component degradation. Any degraded components will be handled through CAP. The staff determines that for visual inspection, this program element satisfies the criteria defined in Appendix SRP-LR A.1.2.3.5. On this basis, the staff finds that the applicant's description of the monitoring and trending is acceptable. The staff confirmed that the monitoring and trending program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.5. The staff finds this program element acceptable. (6) Acceptance Criteria - LRA Section B.1.22 states that this programs acceptance criteria are defined in specific inspection and testing procedures. The procedures confirm component integrity by verifying the absence of aging effects or by comparing applicable parameters to limits based on applicable intended functions established by plant design basis. The staff reviewed VYNPS operating procedures for various systems (primary containment surveillance, secondary containment surveillance) and confirmed that the testing frequency is determined by the IST program criteria and the TS and is performed as scheduled by the surveillance test schedule. The staff also reviewed the VYNPS operating procedures and confirmed that the applicants acceptance criteria were clearly defined in its operating procedures. For example, the staff reviewed applicants procedures, as documented in the Audit and Review Report, and confirmed the acceptance criteria established by plant design basis. On the basis of its review, the staff determines that acceptance criteria of the applicants program satisfied the criteria defined in SRP-LR Appendix A.1.2.3.6. On this basis, the staff finds this acceptable. The staff confirmed that the acceptance criteria program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.6. The staff finds this program element acceptable. (10) Operating Experience - LRA Section B.1.22 states that recent inspection results (2001 to 2004) show that the program is effective in managing component aging effects. For example, the material condition of cranes was consistent with inspection acceptance criteria to which the program documents referred (i.e., no significant corrosion or wear; equipment lock sliding doors had no significant wear or corrosion; HPCI turbine GSC tubes were not fouled; HPCI turbine casing had no significant corrosion or erosion; standby gas treatment demister and loop seal components had no significant corrosion; 3-133

John Deere diesel exhaust gas components had no significant corrosion or cracking; and ECCS corner room recirculation units had no significant corrosion). QA audits and surveillances, self-assessments, engineering system health reports, and staff inspections from 2001 to 2004 concluded that actions to preclude recurrence of a previous adverse trend had been effective and revealed no issues or findings that could impact program effectiveness. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.24, the applicant provided the UFSAR supplement for the Periodic Surveillance and Preventive Maintenance Program. The applicant committed ( Commitment #17) to enhance the Periodic Surveillance and Preventive Maintenance Program to assure that the effects of aging will be managed by March 21, 2012. The staff reviewed this section and determined that, upon the implementation of Commitment

1. 17, 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 technical review of the applicant's Periodic Surveillance and Preventive Maintenance Program with the addition of Commitment #17, 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). 3-134

3.0.3.3.6 Vernon Dam FERC Inspection Summary of Technical Information in the Application. LRA Section B.1.27.3 and LRA supplement dated July 3, 2007 describe the Vernon Dam FERC Inspection as an existing, plant-specific program. The Vernon Dam is subject to the Federal Energy Regulatory Commission (FERC) inspection program. This program consists of visual inspections in accordance with FERC guidelines and complies with Tittle 18 of the Code of Federal Regulations (CFR), Conservation of Power and Water Resources, Part 12, (Safety of Water Power Projects and Project Works), and Division of Dam Safety and Inspections Operating Manual. In accordance with FERC regulations, the owner has been granted an exemption from part 12, Subpart D. As indicated in NUREG-1801 for water control structures, NRC has found that FERC / US Army Corp of Engineers dam inspections and maintenance program are acceptable for aging management. In addition, Vernon dam personnel conduct a daily visual inspection of all the project facilities. An operations crew attends the plant daily. Vernon dam engineering performs an annual inspection of all the project structures and divers make a thorough inspection once every five year on both upsteam and downsteam sides. The operational inspection frequency for licensed and exempt low hazard potential dams is biennial. Reports of operational inspections are filed with the FERC. Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.1.27.3 and the July 3, 2007 supplement on the applicant's demonstration of the Vernon Dam FERC Inspection to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The applicant stated that the Vernon Dam FERC Inspection Program is an existing plant-specific program. Vernon Dam is subject to the FERC inspection program. This program consists of a daily visual inspection of all the project facilities by Vernon Dam personnel. An operations crew attends the plant daily. Vernon dam engineering performs an annual inspection of all the project structures and divers make a thorough inspection once every five year on both upstream and downstream sides, and is in compliance with Title 18 of the Code of Federal Regulations, Conservation of Power and Water Resources, Part 12 (Safety of Water Power Projects and Project Works). The NRC has found that mandated FERC inspection programs are acceptable for aging management. The applicant stated, in the LRA, in accordance with the operating experience, that recent inspections (1998-2002) of the Vernon Dam found minor concrete erosion on the spillway, a crack on a downstream pier, concrete surface erosion in the stanchion flashboard section, spalling at the base of a trash sluice wall, and a crack in the spillway gallery. None of these conditions are threatening structural support and, therefore, do not require immediate repair. However, the areas of degradation will continue to be monitored. Continued monitoring of minor degradation provides evidence that the program is effective for managing aging effects for the dam. Recent FERC assessment (2002) of the Vernon Dam structures found that SCs are maintained in accordance with terms of the license, including daily visual inspections of structural integrity, and periodic underwater inspections on both the upstream and downstream sides of the dam. 3-135

In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in LRA Section B.1.27.3, regarding the applicant's demonstration of the Vernon Dam FERC Inspection to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff reviewed the program basis documents and reports. In addition, the staff reviewed the listed operating experience in which FERC inspections of Vernon Dam found minor concrete erosion on the spillway, a crack on a downstream pier, concrete surface erosion in the stanchion flashboard section, spalling at the base of a trash sluice wall, and a crack in the spillway gallery and found that the FERC inspections were effective in identifying aging effects on Vernon Dam. The above deficiencies were noted for continued monitoring by the Vernon Dam owner and during the continuing FERC Dam inspections. None of these conditions are threatening structural support and, therefore, do not require immediate repair. However, the areas of degradation will continue to be monitored. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel and the dams owner to confirm that the operating experience did not reveal any degradation not bounded by industry experience. During the audit and review, the staff found FERC letter dated August 6, 1997, which exempted the Vernon Hydroelectric Station (VHS) from the requirement of 18 CFR Part 12, Subpart D for submittal of an Independent Consultants Safety Inspections Report, based on its low hazard classification. The staffs interpretation of the August 6, 1997, letter led it to assume that the dam owner still had to perform the Subpart D inspection but did not have to submit the report for FERC review and approval. For clarification, the FERC New York Regional Office was contacted. In its response to the staff on November 2, 2006, FERC stated: The intention of the letter issued on August 6, 1997... was to exempt the Vernon Project from all the requirements of Part 12, Subpart D of 18 CFR. This includes not only the requirement to submit a report but also the requirement of having the dam inspected by an Independent Consultant. The staff also reviewed the applicant responses to RAI 3.6.2.2-N-08. In its letter date July 14, 2006, the applicant stated: Entergy, consistent with the Peach Bottom precedent, credited the [Federal Energy Regulatory Commission] FERC dam inspection program to manage the effects of aging on civil and structural elements of the VHS. Since the daily and annual inspections of the dam are not part of a VYNPS aging management program but are conducted by the dam owner under FERC oversight, the applicant was asked in RAI 3.6.2.2-N-08-1 to describe specific reports, and describe any corrective actions that have been taken as a result of the inspection reports as they pertain to the VHS as required by 10 CFR 54.21(a)(3). In letter dated July 3, 2007, the applicant committed (Commitment #50) that during the period of extended operation, at least once every five years, VYNPS will confirm that the Vernon Dam 3-136

owner is performing the required FERC inspections based on a review of the Vernon Dam owners reports to FERC. VY will document the condition in the Entergy Correction Actions Program and evaluate operability as described in BVY 96-043 and BVY 97-025 if it is determined that the required inspections are not being performed. Conclusion. The staff finds that the aging management for the Vernon Dam is performed by the owner of the VHS and FERC. In addition, inspections with reports are performed by the FERC New York Regional office. On the basis of its review of the operating experience and discussions with the applicant's technical personnel, the dams owner, and the FERC New York Regional Office, the staff concludes that the FERC inspection program in addition to the daily visual inspections and the annual inspection conducted by Vernon Dam personnel will adequately manage the aging effects for the Vernon Dam. 3.0.3.3.7 Water Chemistry Control - Auxiliary Systems Program Summary of Technical Information in the Application. LRA Section B.1.30.1 describes the Water Chemistry Control - Auxiliary Systems Program as an existing, plant-specific program. The purpose of the Water Chemistry Control - Auxiliary Systems Program is to manage aging effects for components exposed to treated water. Program activities include sampling and analysis of stator cooling water and plant heating boiler systems and flushing of the John Deere diesel cooling water system. Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.1.30.1 on the applicant's demonstration of the Water Chemistry Control - Auxiliary Systems Program to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff reviewed the Water Chemistry Control - Auxiliary Systems Program against the AMP elements found in the GALL Report, in SRP-LR Appendix A.1.2.3, and in SRP-LR Table A.1-1, focusing on how the program manages aging effects through the effective incorporation of 10 elements (i.e., scope of the program, preventive actions, parameters monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, administrative controls, and operating experience). The applicant indicated that the corrective actions, confirmation process, and administrative controls program elements are parts of the site-controlled QA program. The staff's evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven elements follows: (1) Scope of Program - LRA Section B.1.30.1 states that program activities include sampling and analysis of stator cooling water and plant heating boiler systems, and flushing of the John Deere Diesel cooling water system. 3-137

The staff confirmed that the specific components for which the program manages aging effects are identified by the applicant, which satisfies the criterion as defined in SRP-LR Appendix A.1.2.3.1. On this basis, the staff finds that the applicants proposed program scope acceptable. The staff confirmed that the scope of the program program element satisfies the recommendnation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.1. The staff finds this program element acceptable. (2) Preventive Actions - LRA Section B.1.30.1 states that this program includes monitoring and control of stator cooling water and plant heating boiler FW to minimize exposure to aggressive environments and application of corrosion inhibitors to manage general, crevice, and pitting corrosion. John Deere Diesel cooling water chemistry is controlled to minimize exposure to aggressive environments by periodic flushing and replacement of the coolant and coolant conditioner. The staff reviewed the applicants basis document, which stated that Cortrol OS 7700 and 50 percent Sodium Hydroxide were added as a corrosion inhibitor. Cortrol OS 7700 is added to boiler FW and contains an oxygen scavenger (hydroquinone) to reduce generalized corrosion, and a neutralized amine to minimize localized or pitting corrosion. The staff confirmed that the existing chemistry activities and preventive actions taken by the applicant satisfies the criteria in SRP-LR Appendix A.1.2.3.2. The staff reviewed the applicants basis document, as documented in the Audit and Review Report, which stated that Cortrol OS 7700 and 50 percent Sodium Hydroxide were added as a corrosion inhibitor. Cortrol OS 7700 is added to boiler FW and contains an oxygen scavenger (hydroquinone) to reduce generalized corrosion, and a neutralized amine to minimize localized or pitting corrosion. On this basis, the staff finds that the applicant's preventive actions acceptable. The staff confirmed that the preventive actions program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.2. The staff finds this program element acceptable. (3) Parameters Monitored or Inspected - LRA Section B.1.30.1 states that in accordance with industry recommendations, stator cooling water and plant heating boiler FW parameters monitored include conductivity, corrosion products, and dissolved oxygen. The applicant also stated that the procedure will be enhanced (Commitment #26) to flush the John Deere Diesel generator cooling water system and replace the coolant and coolant conditioner every three (3) years. The staff confirmed that the preventive actions program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.3. The staff reviewed the applicants basis documents, as documented in the Audit and Review Report, to determine that applicants monitoring schedule is adequate. The staff concludes that the dissolved oxygen, metals and conductivity are monitored per the surveillance schedule. On this basis, the staff finds that the applicant's description of the parameters monitored or inspected is acceptable. 3-138

The staff confirmed that the parameters monitored or inspected program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.3. The staff finds this program element acceptable. (4) Detection of Aging Effects - LRA Section B.1.30.1 states that this program manages loss of material for stator cooling water, plant heating boiler, and John Deere Diesel system components. The applicant also stated in LRA Section B.1.30.1, that the One-Time Inspection Program describes inspections planned to verify the effectiveness of water chemistry control programs to ensure that significant degradation is not occurring and component intended function is maintained during the period of extended operation. The staff confirmed that the detection of aging effects program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.3. The staff acknowledged that this is a mitigation program and does not provide for detection of any aging effects, such as loss of material and crack initiation and growth. The applicants One-time inspection program is to be undertaken to verify the effectiveness of the water chemistry program to ensure that significant degradation is not occurring. On this basis, the staff finds that the applicant's description of the detection of aging effects is acceptable. The staff confirmed that the detection of aging effects program element satisfies the recommenndation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.4. The staff finds this program element acceptable. (5) Monitoring and Trending - LRA Section B.1.30.1 states that program values from analyses are archived for long-term trending and review. The staff confirmed that this program element satisfies the criteria defined in SRP Section A.1.2.3.5. The staff reviewed procedure, as documented in the Audit and Review Report, to determine that applicants monitoring schedule is adequate. On the basis of its review, the staff concludes that the dissolved oxygen, metals and conductivity are monitored per the surveillance schedule. The staff determines the program was used to monitor chemistry content and any abnormal chemistry reported will be handled through CAP. On this basis, the staff finds the applicants monitoring and trending acceptable. The staff confirmed that the monitoring and trending program element satisfies the recommenndation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.5. The staff finds this program element acceptable. (6) Acceptance Criteria - LRA Section B.1.30.1 states that acceptance criteria for chemistry parameters are in accordance with specific manufacturers recommendations and general guidelines provided in EPRI Report 1007820, Revision 1 to TR-107396, Closed Cooling Water Chemistry Guidelines. The staff reviewed the acceptance criteria in the applicants program basis documents. The staff determines that the acceptance criteria for chemistry parameters are in accordance with specific manufactures recommendations and general guidelines 3-139

provided in EPRI Report 1007820, Revision 1 to TR-107396, Closed Cooling Water Chemistry Guidelines. On this basis, the staff finds the applicant's acceptance criteria is acceptable. The staff confirmed that this program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.6. The staff reviewed the acceptance criteria in the applicants program basis documents, as documented in the Audit and Review Report. The staff determines that the acceptance criteria for chemistry parameters are in accordance with specific manufactures recommendations general guidelines provided in EPRI Report 1007820, Revision 1 to TR-107396, Closed Cooling Water Chemistry Guidelines. On this basis, the staff finds the applicant's acceptance criteria acceptable. The staff confirmed that the acceptance criteria program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.6. The staff finds this program element acceptable. (10) Operating Experience - LRA Section B.1.30.1 states that stator cooling water and house heating boiler sample results in 2004 and 2005 show parameters within acceptance criteria, proving that the program is effective for managing component loss of material, cracking, and fouling. A QA audit in 2003 revealed no issues or findings that could impact program effectiveness. The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff finds that the CAP, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated in the future to provide objective evidence to support the conclusion that the effects of aging are adequately managed. The staff confirmed that the operating experience program element satisfies the recommendation in the GALL Report and the criterion defined in SRP-LR Appendix A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. In LRA Section A.2.1.34, the applicant provided the UFSAR supplement for the Water Chemistry Control - Auxiliary Systems Program. In addition, in a letter dated January 14, 2007, the applicant provided an amendment to its LRA to explicitly state, One-Time Inspection Program, activities will confirm the effectiveness of Water Chemistry Control - Auxiliary Systems Program. The applicant committed (Commitment #26) to enhance procedures to flush the John Deere Diesel Generator cooling water system and replace the coolant conditioner every three years by March 21, 2012. The staff reviewed LRA Section A.2.1.34 and determined that, upon the implementation of Commitments #26, the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). 3-140

Conclusion. On the basis of its technical review of the applicant's Water Chemistry Control - Auxiliary Systems Program with the addition of Commitment #26, 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). 3.0.3.3.8 Bolted Cable Connections Program Summary of Technical Information in the Application. In a letter dated January 4, 2007, applicant revised its LRA. The applicant submitted its Appendix B, Section B.1.33, Bolted Cable Connections Program. The applicant described that the Bolted Cable Connections Program is a plant-specific program. Cable connections are used to connect cable conductors to the cables or electrical devices. Connections associated with cables within the scope of license renewal are considered in this program. The most common types of connections used in the nuclear power plants are splices (butt or bolted), crimp-type ring lugs, connectors, and terminal blocks. Most connections involve insulting material and metallic parts. This AMP for electrical cable connections (metallic parts) accounts for loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation. This program has been developed as an alternate to GALL AMP XI.E6, Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirement. The applicant also stated that this program will be implemented prior to the period of extended operation. Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in revised LRA Section B.1.33, regarding the applicant's demonstration of the Bolted Cable Connections Program to ensure that the effects of aging, as discussed above, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The Audit and Review Report details the staff's audit evaluation of this AMP. The staff reviewed the Bolted Cable Connections Program against the AMP elements finds in the GALL Report, SRP-LR Appendix A.1.2.3 and SRP-LR Table A.1-1, focusing its review on how the program manages aging effects through the effective incorporation of 10 elements (i.e., scope of program, preventive actions, parameters monitored/inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, administrative controls, and operating experience). The staffs evaluation of the 10 program element are provided below. The staff's evaluation of the applicants QA program is discussed in SER Section 3.0.4. (1) Scope of Program - The applicant stated, in revised LRA, that this program applies to Non-Environmental qualification connections associated with cables in-scope of license renewal. This program does not include the high-voltage (>35 kV) switchyard connections. In-scope connections are evaluated for applicability of this program. The criteria for including connections in the program are that the connection is a bolted connection and is not covered in accordance with the Environmental Qualification Program or an existing preventive maintenance program. 3-141

The staff determines that the specific commodity groups for which the program manages aging effects are identified (Non-environmental qualification bolted cable connections associated with cables in-scope of license renewal), which satisfies the criterion defined in SRP-LR Appendix A.1.2.3.1. The staff determines that the exclusion of high-voltage (>35 kV) switchyard connections, connections covered in accordance with the Environmental Qualification Program, and an existing preventive maintenance program, acceptable. Switchyard connections are addressed in SER Section 3.6.2.2. Environmental qualification cable connections are covered as required by 10 CFR 50.49. Cable connections in accordance with a preventive maintenance program are periodically inspected. On this basis, the staff finds that the applicants scope of program acceptable. (2) Preventive Actions - The applicant stated, in the revised LRA, that this one-time inspection program is a condition monitoring program; therefore, no actions are taken as part of this program to prevent or mitigate aging degradation. The staff determines that the preventive actions program element satisfies the criteria defined in SRP-LR Appendix B.1.2.3.2. The staff finds it acceptable because this is a condition monitoring program and there is no need for preventive actions. On this basis, the staff finds the applicants preventive actions acceptable. (3) Parameters Monitored/Inspected - The applicant stated, in the revised LRA, that this program will focus on the metallic parts of the cable connections. The one-time inspection verifies that the loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation is not an issue that requires a periodic AMP. The staff determines that the parameters monitored/inspected program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.3. Loosening (or high resistance) of bolted cable connections are the potential aging effects due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation. The design of bolted cable connections usually account for the above stressors. The one-time inspection is to confirm that these stressors are not an issue that requires a periodic AMP. On this basis, the staff finds that the applicants parameters monitored or inspected acceptable. (4) Detection of Aging Effects - The applicant stated, in the revised LRA, that a representative sample of electrical connections within the scope of license renewal, are subject to an AMR and will be inspected or tested prior to the period of extended operation to verify there are no AERMs during the period of extended operation. The factors considered for sample selection will be application (medium and low voltage), circuit loading (high load), and location (high temperature, high humidity, vibration, etc.). The technical basis for the sample selected is to be documented. Inspection methods may include thermography, contact resistance testing, or other appropriate methods including visual, based on plant configuration and industry guidance. The one-time inspection provides additional confirmation to support operating experience that shows electrical connections have not experienced a high degree of failures, and that existing installation and maintenance practices are effective. 3-142

The staff determines that this program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.4. Thermography is used to detect aging effects of bolted cable connections due to thermal cycling, ohmic heating, electrical transients, and vibration. Contact resistance measurement is an appropriate inspection technique to detect high resistance of bolted cable connections due to chemical contamination, corrosion, and oxidation. Visual inspection is an alternative technique to thermography or measuring connection resistance of bolted connections that are covered with materials like heat shrink tape, sleeving, and insulating boots. The staff also determines that the proposed one-time inspection is acceptable because the design of these connections will account for the stresses associated with the above aging effects and one-time inspection is to confirm that these stressors/mechanisms should not be a significant aging issue. On this basis, the staff finds that the applicants detection of aging effects acceptable. (5) Monitoring and Trending - The applicant stated, in the revised LRA, that in this program, trending actions are not included as part of this program because this is a one-time inspection. The staff determines that absence of trending for testing is acceptable, since the test is a one-time inspection and the ability to trend inspection results is limited by the available data. Furthermore, the staff did not see a need for such activities. On this basis, the staff finds the applicants monitoring and trending acceptable. (6) Acceptance Criteria - The applicant stated, in the revised LRA, that the acceptance criteria for each inspection/surveillance are defined by the specific type of inspection or test performed for the specific type of cable connections. Acceptance criteria ensure that the intended functions of the cable connections can be maintained consistent with the CLB. The staff determines that this program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.6. The staff finds it acceptable on the basis that acceptance criteria for inspection/surveillance are defined by the specific type of inspection or test performed for the specific type of connection. The applicant will follow current industry standards which, when implemented, will ensure that the license renewal intended functions of the cable connections will be maintained consistent with the CLB. (7) Corrective Actions - The adequacy of the applicant's 10 CFR 50, Appendix B Program associated with this program element was reviewed by the staff and is addressed in SER Section 3.0.4. The staff reviewed other aspects of this program element to determine whether or not it satisfies the criteria defined in SRP-LR Appendix A.1.2.3.7. In the LRA, the applicant stated that corrective actions are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. The staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address corrective actions. On this basis, the staff finds that the applicant's description of the corrective actions is acceptable. (8) Confirmation Process - The adequacy of the applicant's 10 CFR 50, Appendix B Program associated with this program element was reviewed by the staff and is addressed in SER Section 3.0.4. 3-143

The staff reviewed other aspects of this program element to determine whether or not it satisfies the criteria defined in SRP-LR Appendix A.1.2.3.8. In the LRA, the applicant stated that the confirmation process is part of the CAP. The CAP constitutes the confirmation process for AMPs and activities. On this basis, the staff finds that the applicant's description of the confirmation process is acceptable. (9) Administrative Controls - The adequacy of the applicant's 10 CFR 50, Appendix B Program associated with this program element was reviewed by the staff and is addressed in SER Section 3.0.4. The staff reviewed other aspects of this program element to determine whether or not it satisfies the criteria defined in SRP-LR Appendix A.1.2.3.9. In the LRA, the applicant stated that the administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. The staff finds the requirements of 10 CFR Part 50, Appendix B acceptable to address administrative controls. On this basis, the staff finds that the applicant's description of the administrative controls is acceptable. (10) Operating Experience - The applicant stated, in the revised LRA, that operating experience has shown that loosening of connections and corrosion of connections could be a problem without proper installation and maintenance activities. Industry operating experience supports performing this one-time inspection program in lieu of a periodic testing program. This one-time inspection program will verify that the installation and maintenance activities are effective. To address NEIs concerns about the lack of operating experience to support GALL AMP XI.E6 (NEIs White Paper on GALL AMP XI.E6, dated September 5, 2006), the staff confirmed that there is little operating experience related to failed connections due to aging that have been identified and these operating experience do not support a periodic inspection as currently recommended in GALL AMP XI.E6. The staff finds that the proposed one-time inspection program will ensure that either aging of metallic cable connections is not occurring or existing preventive maintenance program is effective such that a periodic inspection program is not required. On the basis of its review, the staff concludes that the applicants Bolted Cable Connections Program will verify that aging of metallic cable connections is not occurring and the installation and maintenance activities are effective. UFSAR Supplement. In revised LRA Section A.2.1.39, the applicant provided the UFSAR supplement for the Bolted Cable Connections Program. The applicant stated that its Bolted Cable Connections Program will focus on the metallic parts of the cable connections. This sampling program provides a one-time inspection to verify that the loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation is not an aging issue that requires a periodic AMP. A representative sample of the electrical cable connection population subject to an AMR will be inspected or tested. Connections covered in accordance with the Environmental Qualification program, or connections inspected or tested as part of a preventive maintenance program are excluded from an AMR. The factors considered for sample selection will be application (medium and low voltage), circuit loading (high 3-144

load), and location (high temperature, high humidity, vibration, etc.) The technical basis for the sample selected is to be documented. This program will be implemented prior to the period of extended operation. The staff reviewed the UFSAR supplement, and determines that it provides a adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicants program, the staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained during the period of extended operation, as required by 10 CFR 54.21(a)(3). On the basis of its review of the UFSAR supplement for this program, the staff also finds that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs Pursuant to 10 CFR 54.21(a)(3), the applicant is required to demonstrate that the effects of aging on SCs subject to an AMR will be adequately managed so that their intended function(s) will be maintained consistent with the CLB for the period of extended operation. SRP-LR, Branch Technical Position (BTP) RLSB-1, Aging Management Review-Generic, describes ten elements of an acceptable AMP. Elements (7), (8), and (9) are associated with the QA activities of corrective actions, confirmation process, and administrative controls. BTP RLSB-1 Table A.1-1, Elements of an Aging Management Program for License Renewal, provides the following description of these program elements: (7) Corrective Actions - Corrective actions, including root cause determination and prevention of recurrence, should be timely. (8) Confirmation Process - The confirmation process should ensure that preventive actions are adequate and that appropriate corrective actions have been completed and are effective. (9) Administrative Controls - Administrative controls should provide a formal review and approval process. Those aspects of the AMP that affect the quality of safety-related SSCs and are subject to the QA requirements of 10 CFR Part 50, Appendix B are noted in SRP-LR, BTP IQMB-1, Quality Assurance for Aging Management Programs. Additionally, for nonsafety-related SCs subject to an AMR, the existing 10 CFR Part 50 Appendix B QA program may be used by the applicant to address the elements of corrective action, confirmation process, and administrative control. BTP IQMB-1 provides the following guidance with regard to the QA attributes of AMPs: C Safety-related SCs are subject to 10 CFR Part 50 Appendix B requirements which are adequate to address all quality-related aspects of an AMP consistent with the CLB of the facility for the period of extended operation. 3-145

C For nonsafety-related SCs that are subject to an AMR, an applicant has an option to expand the scope of its 10 CFR Part 50 Appendix B program to include these SCs to address corrective action, confirmation process, and administrative control for aging management during the period of extended operation. In this case, the applicant should document such commitment in the UFSAR supplement in accordance with 10 CFR 54.21(d). 3.0.4.1 Summary of Technical Information in the Application In LRA Sections A.2.1, Aging Management Programs and Activities, and B.0.3, VYNPS Corrective Actions, Confirmation Process and Administrative Controls, 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. A single QA Program is used which includes the elements of corrective action, confirmation process, and administrative controls. Corrective actions, confirmation, and administrative controls are applied in accordance with the CAP regardless of the safety classification of the components. Specifically, in LRA Sections A.2.1 and B.0.3, respectively, the applicant stated that the QA Program implements the requirements of 10 CFR 50, Appendix B, and is consistent with NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants. LRA Section 3.0, Aging Management Review Results, provided an AMR summary for each unique component type or commodity group determined to require aging management during the period of extended operation. 3.0.4.2 Staff Evaluation Pursuant to 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 maintained consistent with the CLB for the period of extended operation. NUREG-1800, 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, confirmation process, and administrative control. BTP RLSB-1, Table A.1-1, Elements of an Aging Management Program for License Renewal, provides the following description of these quality attributes: corrective actions, including root cause determination and prevention of recurrence, should be timely; the confirmation process should ensure that preventive actions are adequate and that appropriate corrective actions have been completed and are effective; and, administrative controls should provide a formal review and approval process. NUREG-1800, BTP IQMB-1 noted that those aspects of the AMP that affect quality of safety-related SSCs are subject to the QA requirements of Appendix B to 10 CFR Part 50. Additionally, for nonsafety-related SCs subject to an AMR, the applicant's existing Appendix B to 3-146

10 CFR Part 50 QA program may be used to 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 SCs are subject to Appendix B to 10 CFR Part 50 requirements which are adequate to address all quality-related aspects of an AMP consistent with the CLB of the facility for the period of extended operation. For nonsafety-related SCs that are subject to an AMR 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 Final Safety Analysis Report (FSAR) supplement in accordance with 10 CFR 54.21(d). The staff reviewed the applicant's AMPs described in LRA Appendix A, Section A.2.1, Appendix B, Sections B.0.3 and B.1, and in applicants AMP evaluation reports. The purpose of this review was to ensure consistency in the use of the QA attributes for each program and that aging management activities were consistent with the staffs guidance described in NUREG-1800, BTP IQMB-1. During the review of the LRA and AMP evaluation reports, the staff identified inconsistencies associated with corrective action, confirmation, and administrative control processes regarding the AMP for the VHS structural components. LRA Section B.1.27 and the AMP evaluation reports stated that the AMP was consistent with NUREG-1801 and that the applicants CAP was applicable to the VHS. When discussing this AMP with the applicant, the applicant stated that it did not own the VHS and that its CAP did not apply to VHS as indicated in the LRA and AMP evaluation reports. Additionally, the staff found that AMP evaluation reports did not consistently describe the application of the 10 CFR Part 50, Appendix B, QA Program for the corrective action, confirmation process, and administrative control attributes for each AMP. In RAI 3.0-1, dated July 10, 2006, the staff requested that the applicant clarify its use of the 10 CFR Part 50, Appendix B, QA Program for corrective action, confirmation process, and administrative controls, and to supplement the LRA, as necessary, to clearly indicate the application of the QA Program, or an alternative for the corrective action, confirmation, and administrative control process attributes for each AMP. In its responses, by letters dated July 14, 2006, August 10, 2006, October 20, 2006, and January 4, 2007, the applicant further described the application of the VYNPS 10 CFR Part 50, Appendix B, QA Program for corrective action, confirmation process, and administrative controls, and provided a revision to the UFSAR Supplement. The revision stated, in part: The corrective action, confirmation process, and administrative controls of the ENTERGY (10 CFR Part 50, Appendix B) Quality Assurance Program are applicable to all aging management programs that will be required during the period of extended operation, with the exception of the Vernon Dam FERC inspection. 3-147

With respect to the VHS, the applicant stated, in part, that although the VHS is not under the VYNPS QA program, any issues identified with respect to the availability of the VHS to perform its license renewal intended function will require invoking the VYNPS QA program. The VHS civil and structural elements will be managed through the continued use of the FERC dam inspection program, and the pertinent electrical system elements will be managed through a combination of VYNPS AMPs and the inspection and periodic maintenance processes of the owner/operator. In the event that any of these processes identify a condition which indicates the VHS is incapable of performing its license renewal intended function, this will require entry into the VYNPS corrective action program (in accordance with the VYNPS Technical Specifications) and therefore invokes the associated elements of the VYNPS QA program. Additionally, the applicant monitors the availability of the VHS to ensure continued ability to perform its License renewal intended function, through conformance with the availability specified in the NUMARC 87-00 for meeting the requirements of the SBO rule, and will invoke the VYNPS Corrective Action program if those requirements cannot be maintained. The staff has reviewed the applicants responses to this RAI and concluded that the applicant has adequately addressed the staffs concerns associated with implementation of the VYNPS 10 CFR Appendix B Quality Assurance Program with respect to the VYNPS AMPs and the VHS. Therefore, the staffs concern described in RAI 3.0-1 is resolved. 3.0.4.3 Conclusion On the basis of the staffs evaluation, the descriptions and applicability of the plant-specific AMPs and their associated quality attributes provided in LRA Appendix A, Section A.2.1, and Appendix B, Sections B.0.3 and B.1, and the RAI response, are consistent with the staffs 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 the requirements of 10 CFR 54.21(a)(3). 3.1 Aging Management of Reactor Vessel, Reactor Vessel Internals, and Reactor Coolant System This section of the SER documents the staffs review of the applicants AMR results for the reactor vessel, reactor vessel internals, and reactor coolant system components and component groups of:

• reactor vessel
• reactor vessel internals
• reactor coolant pressure boundary 3.1.1 Summary of Technical Information in the Application LRA Section 3.1 provides AMR results for the reactor vessel, reactor vessel internals, and reactor coolant system components and component groups. LRA Table 3.1.1, Summary of Aging Management Evaluations for the Reactor Coolant System, is a summary comparison of the applicants AMRs with those evaluated in the GALL Report for the reactor vessel, reactor vessel internals, and reactor coolant system components and component groups.

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The applicants 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 applicants 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 whether the applicant provided sufficient information to demonstrate that the effects of aging for the reactor vessel, reactor vessel internals, and reactor coolant system 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). The staff conducted an onsite audit of AMRs to ensure the applicants 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. The staffs evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staffs audit evaluation are documented in SER Section 3.1.2.1. In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicants further evaluations were consistent with the SRP-LR Appendix 3.1.2.2 acceptance criteria. The staffs audit evaluations are documented in SER Section 3.1.2.2. The staff also conducted a technical review of the remaining AMRs that were not consistent with, or not addressed in, the GALL Report. The technical review evaluated whether all plausible aging effects have been identified and whether the aging effects listed were appropriate for the material-environment combinations specified. The staffs evaluations are documented in SER Section 3.1.2.3. For SSCs which the applicant claimed were not applicable or required no aging management, the staff reviewed the AMR line items and the plants operating experience to verify the applicants claims. Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or monitoring aging for the reactor vessel, internals and reactor coolant system components. Table 3.1-1 summarizes the staffs evaluation of components, aging effects/mechanisms, and AMPs listed in LRA Section 3.1 and addressed in the GALL Report. 3-149

Table 3.1-1 Staff Evaluation for Reactor Vessel, Reactor Vessel Internals, and Reactor Coolant System Components in the GALL Report Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Steel pressure Cumulative fatigue TLAA, evaluated in TLAA Fatigue is a vessel support skirt damage accordance with TLAA.(See SER and attachment 10 CFR 54.21(c) Section 3.1.2.2.1) welds (3.1.1-1) Steel; stainless Cumulative fatigue TLAA, evaluated in TLAA Fatigue is a steel; steel with damage accordance with TLAA.(See SER nickel-alloy or 10 CFR 54.21(c) Section 3.1.2.2.1) stainless steel and environmental cladding; effects are to be nickel-alloy reactor addressed for vessel components: Class 1 components flanges; nozzles; penetrations; safe ends; thermal sleeves; vessel shells, heads and welds (3.1.1-2) Steel; stainless Cumulative fatigue TLAA, evaluated in TLAA Fatigue is a TLAA. steel; steel with damage accordance with (See SER nickel-alloy or 10 CFR 54.21(c) Section 3.1.2.2.1) stainless steel and environmental cladding; effects are to be nickel-alloy RCPB addressed for piping, piping Class 1 components components, and piping elements exposed to reactor coolant (3.1.1-3) Steel pump and Cumulative fatigue TLAA, evaluated in TLAA Fatigue is a TLAA. valve closure bolting damage accordance with (See SER (3.1.1-4) 10 CFR 54.21(c) Section 3.1.2.2.1) check Code limits for allowable cycles (less than 7000 cycles) of thermal stress range Stainless steel and Cumulative fatigue TLAA, evaluated in TLAA Fatigue is a TLAA. nickel alloy reactor damage accordance with (See SER vessel internals 10 CFR 54.21(c) Section 3.1.2.2.1) components (3.1.1-5) 3-150

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Nickel alloy tubes Cumulative fatigue TLAA, evaluated in None Not applicable to and sleeves in a damage accordance with BWRs reactor coolant and 10 CFR 54.21(c) secondary FW/steam environment (3.1.1-6) Steel and stainless Cumulative fatigue TLAA, evaluated in None Not applicable to steel RCPB closure damage accordance with BWRs bolting, head 10 CFR 54.21(c) closure studs, support skirts and attachment welds, pressurizer relief tank components, steam generator components, piping and components external surfaces and bolting (3.1.1-7) Steel; stainless Cumulative fatigue TLAA, evaluated in None Not applicable to steel; and damage accordance with BWRs nickel-alloy RCPB 10 CFR 54.21(c) piping, piping and environmental components, piping effects are to be elements; flanges; addressed for nozzles and safe Class 1 components ends; pressurizer vessel shell heads and welds; heater sheaths and sleeves; penetrations; and thermal sleeves (3.1.1-8) Steel; stainless Cumulative fatigue TLAA, evaluated in None Not applicable to steel; steel with damage accordance with BWRs nickel-alloy or 10 CFR 54.21(c) stainless steel and environmental cladding; effects are to be nickel-alloy reactor addressed for vessel components: Class 1 components flanges; nozzles; penetrations; pressure housings; safe ends; thermal sleeves; vessel shells, heads and welds (3.1.1-9) 3-151

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Steel; stainless Cumulative fatigue TLAA, evaluated in None Not applicable to steel; steel with damage accordance with BWRs nickel-alloy or 10 CFR 54.21(c) stainless steel and environmental cladding; effects are to be nickel-alloy steam addressed for generator Class 1 components components (flanges; penetrations; nozzles; safe ends, lower heads and welds) (3.1.1-10) Steel top head Loss of material due Water Chemistry Water Chemistry Consistent with enclosure (without to general, pitting and One-Time Control-BWR GALL Report, which cladding) top head and crevice Inspection Program (B.1.30.2); recommends further nozzles (vent, top corrosion One-Time evaluation (See head spray or Inspection Program SER reactor core (B.1.21); Inservice Sections 3.1.2.1.1 isolation cooling, Inspection Program and 3.1.2.2.2) and spare) exposed (B.1.15.2) to reactor coolant (3.1.1-11) Steel steam Loss of material due Water Chemistry None Not applicable to generator shell to general, pitting and One-Time BWRs assembly exposed and crevice Inspection to secondary FW corrosion and steam (3.1.1-12) Steel and stainless Loss of material due Water Chemistry Water Chemistry Consistent with steel isolation to general (steel and One-Time Control-BWR GALL Report, which condenser only), pitting and Inspection Program (B.1.30.2); recommends further components crevice corrosion One-Time evaluation (See exposed to reactor Inspection Program SER coolant (B.1.21); Inservice Sections 3.1.2.1.2 (3.1.1-13) Inspection Program and 3.1.2.2.2) (B.1.15.2) Stainless steel, Loss of material due Water Chemistry Water Chemistry Consistent with nickel-alloy, and to pitting and and One-Time Control-BWR GALL Report, which steel with crevice corrosion Inspection Program (B.1.30.2); recommends further nickel-alloy or One-Time evaluation (See stainless steel Inspection Program SER cladding reactor (B.1.21); Inservice Sections 3.1.2.1.3. vessel flanges, Inspection Program and 3.1.2.2.2) nozzles, (B.1.15.2); BWR penetrations, safe Vessels Internals ends, vessel shells, Program (B.1.7) heads and welds (3.1.1-14) 3-152

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Stainless steel; Loss of material due Water Chemistry Water Chemistry Consistent with steel with to pitting and and One-Time Control-BWR GALL Report, which nickel-alloy or crevice corrosion Inspection Program (B.1.30.2); recommends further stainless steel One-Time evaluation (See cladding; and Inspection Program SER nickel-alloy RCPB (B.1.21); Inservice Sections 3.1.2.1.4 components Inspection Program and 3.1.2.2.2) exposed to reactor (B.1.15.2) coolant (3.1.1-15) Steel steam Loss of material due Inservice None Not applicable to generator upper and to general, pitting Inspection (IWB, BWRs lower shell and and crevice IWC, and IWD), and transition cone corrosion Water Chemistry exposed to and, for secondary FW and Westinghouse steam Model 44 and (3.1.1-16) 51 S/G, if general and pitting corrosion of the shell is known to exist, additional inspection procedures are to be developed. Steel (with or Loss of fracture TLAA, evaluated in TLAA Loss of fracture without stainless toughness due to accordance with toughness is a steel cladding) neutron irradiation Appendix G of TLAA (See SER reactor vessel embrittlement 10 CFR 50 and Section 3.1.2.1.5) beltline shell, RG 1.99. The nozzles, and welds applicant may (3.1.1-17) choose to demonstrate that the materials of the nozzles are not controlling for the TLAA evaluations. Steel (with or Loss of fracture Reactor Vessel Reactor Vessel Consistent with without stainless toughness due to Surveillance Surveillance GALL Report, which steel cladding) neutron irradiation Program (B.1.24) recommends further reactor vessel embrittlement evaluation (See beltline shell, SER nozzles, and welds; Section 3.1.2.2.3) safety injection nozzles (3.1.1-18) Stainless steel and Cracking due to A plant-specific Water Chemistry Consistent with nickel alloy top head SCC and IGSCC AMP is to be Control-BWR GALL Report, which enclosure vessel evaluated. Program (B.1.30.2); recommends further flange leak One-Time evaluation (See detection line Inspection Program SER (3.1.1-19) (B.1.21) Section 3.1.2.2.4) 3-153

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Stainless steel Cracking due to Inservice None Not applicable (See isolation condenser SCC and IGSCC Inspection (IWB, SER components IWC, and IWD), Section 3.1.2.2.4) exposed to reactor Water Chemistry, coolant and plant-specific (3.1.1-20) verification program Reactor vessel shell Crack growth due to TLAA None Not applicable to fabricated of cyclic loading BWRs SA508-Cl 2 forgings clad with stainless steel using a high-heat-input welding process (3.1.1-21) Stainless steel and Loss of fracture FSAR supplement None Not applicable to nickel alloy reactor toughness due to commitment to BWRs vessel internals neutron irradiation (1) participate in components embrittlement, void industry RVI aging exposed to reactor swelling programs coolant and neutron (2) implement flux applicable results (3.1.1-22) (3) submit for NRC approval > 24 months before the extended period an RVI inspection plan based on industry recommendation. Stainless steel Cracking due to A plant-specific None Not applicable to reactor vessel SCC AMP is to be BWRs closure head flange evaluated. leak detection line and bottom-mounted instrument guide tubes (3.1.1-23) Class 1 CASS Cracking due to Water Chemistry None Not applicable to piping, piping SCC and, for CASS BWRs components, and components that do piping elements not meet the exposed to reactor NUREG-0313 coolant guidelines, a (3.1.1-24) plant-specific AMP Stainless steel jet Cracking due to A plant-specific None Not applicable (See pump sensing line cyclic loading AMP is to be SER (3.1.1-25) evaluated. Section 3.1.2.2.8 and 3.1.2.3.4) 3-154

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Steel and stainless Cracking due to Inservice None Not applicable (See steel isolation cyclic loading Inspection (IWB, SER condenser IWC, and IWD) and Section 3.1.2.2.8) components plant-specific exposed to reactor verification program coolant (3.1.1-26) Stainless steel and Loss of preload due FSAR supplement None Not applicable to nickel alloy reactor to stress relaxation commitment to BWRs vessel internals (1) participate in screws, bolts, tie industry RVI aging rods, and hold-down programs springs (2) implement (3.1.1-27) applicable results (3) submit for NRC approval > 24 months before the extended period an RVI inspection plan based on industry recommendation. Steel steam Loss of material due A plant-specific None Not applicable to generator FW to erosion AMP is to be BWRs impingement plate evaluated. and support exposed to secondary FW (3.1.1-28) Stainless steel Cracking due to A plant-specific BWR Vessel Consistent with steam dryers flow-induced AMP is to be Internals Program GALL Report, which exposed to reactor vibration evaluated. (B.1.7) recommends further coolant evaluation (See (3.1.1-29) SER Sections 3.1.2.1.6 and 3.1.2.2.11) 3-155

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Stainless steel Cracking due to Water Chemistry None Not applicable to reactor vessel SCC, and FSAR BWRs internals irradiation-assisted supplement components SCC commitment to (e.g., upper (1) participate in internals assembly, industry RVI aging rod cluster control programs assembly guide (2) implement tube assemblies, applicable results baffle/former (3) submit for NRC assembly, lower approval > 24 internal assembly, months before the shroud assemblies, extended period an plenum cover and RVI inspection plan plenum cylinder, based on industry upper grid recommendation. 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) Nickel alloy and Cracking due to Inservice None Not applicable to steel with primary water stress Inspection (IWB, BWRs nickel-alloy cladding corrosion cracking IWC, and IWD) and piping, piping Water Chemistry component, piping and FSAR supp elements, commitment to penetrations, implement nozzles, safe ends, applicable plant and welds (other commitments to than reactor vessel (1) NRC Orders, head); pressurizer Bulletins, and GLs heater sheaths, associated with sleeves, diaphragm nickel alloys and plate, manways and (2) staff-accepted flanges; core industry guidelines. support pads/core guide lugs (3.1.1-31) Steel steam Wall thinning due to A plant-specific None Not applicable to generator FW inlet flow-accelerated AMP is to be BWRs ring and supports corrosion evaluated. (3.1.1-32) 3-156

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Stainless steel and Changes in FSAR supplement None Not applicable to nickel alloy reactor dimensions due to commitment to BWRs vessel internals void swelling (1) participate in components industry RVI aging (3.1.1-33) programs (2) implement applicable results (3) submit for NRC approval > 24 months before the extended period an RVI inspection plan based on industry recommendation. Stainless steel and Cracking due to Inservice None Not applicable to nickel alloy reactor SCC and primary Inspection (IWB, BWRs CRD head water stress IWC, and IWD) and penetration corrosion cracking Water Chemistry pressure housings and for nickel alloy, (3.1.1-34) comply with applicable NRC Orders and provide a commitment in the FSAR supplement to implement applicable (1) Bulletins and GLs and (2) staff-accepted industry guidelines. Steel with stainless Cracking due to Inservice None Not applicable to steel or nickel alloy SCC and primary Inspection (IWB, BWRs cladding primary water stress IWC, and IWD) and side components; corrosion cracking Water Chemistry steam generator and for nickel alloy, upper and lower comply with heads, tubesheets applicable NRC and tube-to-tube Orders and provide sheet welds a commitment in the (3.1.1-35) FSAR supplement to implement applicable (1) Bulletins and GLs and (2) staff-accepted industry guidelines. 3-157

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Nickel alloy, Cracking due to Water Chemistry None Not applicable to stainless steel SCC and primary and One-Time BWRs pressurizer spray water stress Inspection and, for head corrosion cracking nickel alloy welded (3.1.1-36) spray heads, comply with applicable NRC Orders and provide a commitment in the FSAR supplement to implement applicable (1) Bulletins and GLs and (2) staff-accepted industry guidelines. Stainless steel and Cracking due to Water Chemistry None Not applicable to nickel alloy reactor SCC, primary water and FSAR BWRs vessel internals stress corrosion supplement components cracking, commitment to (e.g., upper irradiation-assisted (1) participate in internals assembly, stress corrosion industry RVI aging rod cluster control cracking programs assembly guide (2) implement tube assemblies, applicable results lower internal (3) submit for NRC assembly, CEA approval > 24 shroud assemblies, months before the core shroud extended period an assembly, core RVI inspection plan support shield based on industry assembly, core recommendation. barrel assembly, lower grid assembly, flow distributor assembly) (3.1.1-37) Steel (with or Cracking due to BWR CR Drive BWR CRD Return Consistent with without stainless cyclic loading Return Line Nozzle Line Nozzle GALL Report, which steel cladding) CRD Program (B.1.2) recommends no return line nozzles further evaluation exposed to reactor (See SER coolant Section 3.1.2.1) (3.1.1-38) Steel (with or Cracking due to BWR Feedwater BWR Feedwater Consistent with without stainless cyclic loading Nozzle Nozzle Program GALL Report, which steel cladding) FW (B.1.3) recommends no nozzles exposed to further evaluation reactor coolant (See SER (3.1.1-39) Section 3.1.2.1) 3-158

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Stainless steel and Cracking due to BWR Penetrations Water Chemistry Consistent with nickel alloy SCC, IGSCC, cyclic and Water Control-BWR GALL Report, which penetrations for loading Chemistry (B.1.30.2); BWR recommends no CRD stub tubes Penetrations further evaluation instrumentation, jet Program (B.1.4); (See SER pump BWR Vessel Section 3.1.2.1.7) instrumentation, Internals (B.1.7); standby liquid Inservice Inspection control, flux monitor, Program (B.1.15.2) and drain line exposed to reactor coolant (3.1.1-40) Stainless steel and Cracking due to BWR Stress BWR Stress Consistent with nickel alloy piping, SCC and IGSCC Corrosion Cracking Corrosion Cracking GALL Report, which piping components, and Water Program (B.1.5); recommends no and piping elements Chemistry Water Chemistry further evaluation greater than or Control-BWR (See SER equal to 4 inches Program (B.1.30.2); Section 3.1.2.1.8) NPS; nozzle safe Inservice Inspection ends and Program (B.1.15.2); associated welds One-Time (3.1.1-41) Inspection Program (B.1.21) Stainless steel and Cracking due to BWR Vessel ID BWR Vessel ID Consistent with nickel alloy vessel SCC and IGSCC Attachment Welds Attachment Welds GALL Report, which shell attachment and Water Program (B.1.6); recommends no welds exposed to Chemistry Water Chemistry further evaluation reactor coolant Control-BWR (See SER (3.1.1-42) Program (B.1.30.2) Section 3.1.2.1) Stainless steel fuel Cracking due to BWR Vessel BWR Vessel Consistent with supports and CRD SCC and IGSCC Internals and Water Internals Program GALL Report, which assemblies CRD Chemistry (B.1.7); Water recommends no housing exposed to Chemistry further evaluation reactor coolant Control-BWR (See SER (3.1.1-43) Program (B.1.30.2) Section 3.1.2.1) Stainless steel and Cracking due to BWR Vessel BWR Vessel Consistent with nickel alloy core SCC, IGSCC, Internals and Water Internals Program GALL Report, which shroud, core plate, irradiation-assisted Chemistry (B.1.7); Water recommends no core plate bolts, stress corrosion Chemistry further evaluation support structure, cracking Control-BWR (See SER top guide, CS lines, Program (B.1.30.2) Section 3.1.2.1.9) spargers, jet pump assemblies, CRD housing, nuclear instrumentation guide tubes (3.1.1-44) 3-159

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Steel piping, piping Wall thinning due to Flow-Accelerated Flow-Accelerated Consistent with components, and flow-accelerated Corrosion Corrosion Program GALL Report, which piping elements corrosion (B.1.13) recommends no exposed to reactor further evaluation coolant (See SER (3.1.1-45) Section 3.1.2.1) Nickel alloy core Cracking due to Inservice None Consistent with shroud and core SCC, IGSCC, Inspection (IWB, GALL Report, which plate access hole irradiation-assisted IWC, and IWD), and recommends no cover (mechanical stress corrosion Water Chemistry further evaluation covers) cracking (See SER (3.1.1-46) Section 3.1.2.3.4 Stainless steel and Loss of material due Inservice One-Time Consistent with nickel-alloy reactor to pitting and Inspection (IWB, Inspection Program GALL Report, which vessel internals crevice corrosion IWC, and IWD), and (B.1.15.2); Water recommends no exposed to reactor Water Chemistry Chemistry further evaluation coolant Control-BWR (See SER (3.1.1-47) Program (B.1.30.2) Section 3.1.2.1.10) Steel and stainless Cracking due to Inservice Inservice Inspection Consistent with steel Class 1 piping, SCC, IGSCC (for Inspection (IWB, Program (B.1.15.2); GALL Report, which fittings and branch stainless steel only), IWC, and IWD), One-Time recommends no connections < 4 and thermal and Water chemistry, Inspection Program further evaluation inches NPS mechanical loading and One-Time (B.1.21); Water (See SER exposed to reactor Inspection of ASME Chemistry Section 3.1.2.1.11) coolant Code Class 1 Control-BWR (3.1.1-48) Small-bore Piping Program (B.1.30.2) Nickel alloy core Cracking due to Inservice BWR Vessel Consistent with shroud and core SCC, IGSCC, Inspection (IWB, Internals Program GALL Report, which plate access hole irradiation-assisted IWC, and IWD), (B.1.7); Water recommends no cover (welded stress corrosion Water Chemistry, Chemistry further evaluation covers) cracking and, for BWRs with Control-BWR (See SER (3.1.1-49) a crevice in the Program (B.1.30.2) Section 3.1.2.1.12) access hole covers, augmented inspection using UT or other demonstrated acceptable inspection of the access hole cover welds High-strength low Cracking due to Reactor Head Reactor Head Consistent with alloy steel top head SCC and IGSCC Closure Studs Closure Studs GALL Report, which closure studs and Program (B.1.23); recommends no nuts exposed to air Inservice Inspection further evaluation with reactor coolant Program (B.1.15.2) (See SER leakage Section 3.1.2.1.13) (3.1.1-50) 3-160

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) CASS jet pump Loss of fracture Thermal Aging and Thermal Aging and Consistent with assembly castings; toughness due to Neutron Irradiation Neutron Irradiation GALL Report, which orificed fuel support thermal aging and Embrittlement of Embrittlement of recommends no (3.1.1-51) neutron irradiation CASS CASS Program further evaluation embrittlement (B.1.29) (See SER Section 3.1.2.1) Steel and stainless Cracking due to Bolting Integrity Bolting Integrity Consistent with steel RCPB pump SCC, loss of Program GALL Report, which and valve closure material due to recommends no bolting, manway wear, loss of further evaluation and holding bolting, preload due to (See SER flange bolting, and thermal effects, Section 3.1.2.1.14) closure bolting in gasket creep, and high-pressure and self-loosening high-temperature systems (3.1.1-52) Steel piping, piping Loss of material due Closed-Cycle None Not applicable. components, and to general, pitting Cooling Water (There are no steel piping elements and crevice System components of the exposed to closed corrosion Class 1 reactor cycle cooling water vessel, vessel (3.1.1-53) internals or RCPB exposed to closed cycle cooling water.) (See SER Section 3.1.2.3.4) Copper alloy piping, Loss of material due Closed-Cycle None Not applicable. piping components, to pitting, crevice, Cooling Water (There are no and piping elements and galvanic System copper alloy exposed to closed corrosion components of the cycle cooling water Class 1 reactor (3.1.1-54) vessel, vessel internals or RCPB exposed to closed cycle cooling water.) (See SER Section 3.1.2.3.4) 3-161

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) CASS Class 1 pump Loss of fracture Inservice Inservice Inspection Consistent with casings, and valve toughness due to inspection (IWB, Program (B.1.15.2); GALL Report, which bodies and bonnets thermal aging IWC, and IWD). One-Time recommends no exposed to reactor embrittlement Thermal aging Inspection Program further evaluation coolant > 250EC susceptibility (B.1.21) (See SER (> 482EF) screening is not Section 3.1.2.1.15) (3.1.1-55) necessary, inservice inspection requirements are sufficient for managing these aging effects. ASME Code Case N-481 also provides an alternative for pump casings. Copper alloy > 15 Loss of material due Selective Leaching None Not applicable percent Zn piping, to selective leaching of Materials (There are no steel piping components, components of the and piping elements Class 1 reactor exposed to closed vessel, vessel cycle cooling water internals or RCPB (3.1.1-56) exposed to closed cycle cooling water.) (See SER Section 3.1.2.3.4) CASS Class 1 Loss of fracture Thermal Aging One-Time (See SER piping, piping toughness due to Embrittlement of Inspection Program Section 3.1.2.1.16) component, and thermal aging CASS (B.1.21) piping elements and embrittlement CRD pressure housings exposed to reactor coolant > 250EC (> 482EF) (3.1.1-57) Steel RCPB Loss of material due Boric Acid None Not applicable to external surfaces to Boric acid Corrosion BWRs exposed to air with corrosion borated water leakage (3.1.1-58) Steel steam Wall thinning due to Flow-Accelerated None Not applicable to generator steam flow-accelerated Corrosion BWRs nozzle and safe corrosion end, FW nozzle and safe end, auxiliary feedwater nozzles and safe ends exposed to secondary FW/steam (3.1.1-59) 3-162

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Stainless steel flux Loss of material due Flux Thimble Tube None Not applicable to thimble tubes (with to Wear Inspection BWRs or without chrome plating) (3.1.1-60) Stainless steel, Cracking due to Inservice None Not applicable to steel pressurizer cyclic loading Inspection (IWB, BWRs integral support IWC, and IWD) exposed to air with metal temperature up to 288EC (550EF) (3.1.1-61) Stainless steel, Cracking due to Inservice None Not applicable to steel with stainless cyclic loading Inspection (IWB, BWRs steel cladding IWC, and IWD) reactor coolant system cold leg, hot leg, surge line, and spray line piping and fittings exposed to reactor coolant (3.1.1-62) Steel reactor vessel Loss of material due Inservice None Not applicable to flange, stainless to Wear Inspection (IWB, BWRs steel and nickel IWC, and IWD) alloy reactor vessel 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) Stainless steel and Cracking due to Inservice None Not applicable to steel with stainless SCC, primary water Inspection (IWB, BWRs steel or nickel alloy stress corrosion IWC, and IWD) and cladding pressurizer cracking Water Chemistry components (3.1.1-64) 3-163

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Nickel alloy reactor Cracking due to Inservice None Not applicable to vessel upper head primary water stress Inspection (IWB, BWRs and CRD corrosion cracking IWC, and IWD) and penetration nozzles, Water Chemistry instrument tubes, and Nickel-Alloy head vent pipe (top Penetration Nozzles head), and welds Welded to the (3.1.1-65) Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Steel steam Loss of material due Inservice None Not applicable to generator to erosion Inspection (IWB, BWRs secondary manways IWC, and IWD) for and handholds Class 2 components (cover only) exposed to air with leaking secondary-side water and/or steam (3.1.1-66) Steel with stainless Cracking due to Inservice None Not applicable to steel or nickel alloy cyclic loading Inspection (IWB, BWRs cladding; or IWC, and IWD), and stainless steel Water Chemistry pressurizer components exposed to reactor coolant (3.1.1-67) Stainless steel, Cracking due to Inservice None Not applicable to steel with stainless SCC Inspection (IWB, BWRs steel cladding IWC, and IWD), and Class 1 piping, Water Chemistry fittings, pump casings, valve bodies, nozzles, safe ends, manways, flanges, CRD housing; pressurizer heater sheaths, sleeves, diaphragm plate; pressurizer relief tank components, reactor coolant system cold leg, hot leg, surge line, and spray line piping and fittings (3.1.1-68) 3-164

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Stainless steel, Cracking due to Inservice None Not applicable to nickel alloy safety SCC, primary water Inspection (IWB, BWRs injection nozzles, stress corrosion IWC, and IWD), and safe ends, and cracking Water Chemistry associated welds and buttering exposed to reactor coolant (3.1.1-69) Stainless steel; Cracking due to Inservice None Not applicable to steel with stainless SCC, thermal and Inspection (IWB, BWRs steel cladding mechanical loading IWC, and IWD), Class 1 piping, Water chemistry, fittings and branch and One-Time connections < 4 Inspection of ASME inches Code Class 1 NPS exposed to Small-bore Piping reactor coolant (3.1.1-70) High-strength low Cracking due to Reactor Head None Not applicable to alloy steel closure SCC; loss of Closure Studs BWRs head stud assembly material due to wear exposed to air with reactor coolant leakage (3.1.1-71) Nickel alloy steam Cracking due to Steam Generator None Not applicable to generator tubes and OD SCC and Tube Integrity and BWRs sleeves exposed to intergranular attack, Water Chemistry secondary loss of material due FW/steam to fretting and wear (3.1.1-72) Nickel alloy steam Cracking due to Steam Generator None Not applicable to generator tubes, primary water stress Tube Integrity and BWRs repair sleeves, and corrosion cracking Water Chemistry tube plugs exposed to reactor coolant (3.1.1-73) Chrome plated Cracking due to Steam Generator None Not applicable to steel, stainless SCC, loss of Tube Integrity and BWRs steel, nickel alloy material due to Water Chemistry steam generator crevice corrosion anti-vibration bars and fretting exposed to secondary FW/steam (3.1.1-74) 3-165

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Nickel alloy Denting due to Steam Generator None Not applicable to once-through steam corrosion of carbon Tube Integrity and BWRs generator tubes steel tube support Water Chemistry exposed to plate secondary FW/steam (3.1.1-75) Steel steam Loss of material due Steam Generator None Not applicable to generator tube to erosion, general, Tube Integrity and BWRs support plate, tube pitting, and crevice Water Chemistry bundle wrapper corrosion, ligament exposed to cracking due to secondary corrosion FW/steam (3.1.1-76) Nickel alloy steam Loss of material due Steam Generator None Not applicable to generator tubes and to wastage and Tube Integrity and BWRs sleeves exposed to pitting corrosion Water Chemistry phosphate chemistry in secondary FW/steam (3.1.1-77) Steel steam Wall thinning due to Steam Generator None Not applicable to generator tube flow-accelerated Tube Integrity and BWRs support lattice bars corrosion Water Chemistry exposed to secondary FW/steam (3.1.1-78) Nickel alloy steam Denting due to Steam Generator None Not applicable to generator tubes corrosion of steel Tube Integrity; BWRs exposed to tube support plate Water Chemistry secondary and, for plants that FW/steam could experience (3.1.1-79) denting at the upper support plates, evaluate potential for rapidly propagating cracks and then develop and take corrective actions consistent with Bulletin 88-02. 3-166

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) CASS reactor Loss of fracture Thermal Aging and None Not applicable to vessel internals toughness due to Neutron Irradiation BWRs (e.g., upper thermal aging and Embrittlement of internals assembly, neutron irradiation CASS lower internal embrittlement assembly, CEA shroud assemblies, control rod guide tube assembly, core support shield assembly, lower grid assembly) (3.1.1-80) Nickel alloy or Cracking due to Water Chemistry None Not applicable to nickel-alloy clad primary water stress BWRs steam generator corrosion cracking divider plate exposed to reactor coolant (3.1.1-81) Stainless steel Cracking due to Water Chemistry None Not applicable to steam generator SCC BWRs primary side divider plate exposed to reactor coolant (3.1.1-82) Stainless steel; Loss of material due Water Chemistry None Not applicable to steel with to pitting and BWRs nickel-alloy or crevice corrosion stainless steel cladding; and nickel-alloy reactor vessel internals and RCPB components exposed to reactor coolant (3.1.1-83) Nickel alloy steam Cracking due to Water Chemistry None Not applicable to generator SCC and One-Time BWRs components such Inspection or as, secondary side Inservice nozzles Inspection (IWB, (vent, drain, and IWC, and IWD). instrumentation) exposed to secondary FW/steam (3.1.1-84) 3-167

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Nickel alloy piping, None None None Consistent with piping components, GALL Report ( See and piping elements SER exposed to air - Section 3.1.2.1) indoor uncontrolled (external) (3.1.1-85) Stainless steel None None None Consistent with piping, piping GALL Report ( See components, and SER piping elements Section 3.1.2.1) exposed to air - indoor uncontrolled (External); air with borated water leakage; concrete; gas (3.1.1-86) Steel piping, piping None None None Not applicable components, and (There are no piping elements in components of the concrete Class 1 reactor (3.1.1-87) vessel, vessel internals or RCPB exposed to concrete.) The staffs review of the reactor vessel, reactor vessel internals, and reactor coolant system component groups followed any one of several approaches. One approach, 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 approach, 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. A third approach, 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. The staffs review of AMPs credited to manage or monitor aging effects of the reactor vessel, reactor vessel internals, and reactor coolant system components is documented in SER Section 3.0.3. 3.1.2.1 AMR Results Consistent with the GALL Report Summary of Technical Information in the Application. LRA Section 3.1.2.1 identifies the materials, environments, AERMs, and the following programs that manage aging effects for the reactor vessel, reactor vessel internals, and reactor coolant system components:

• BWR Control Rod Drive Return Line Nozzle Program
• BWR Feedwater Nozzle Program
• BWR Penetrations Program
• BWR Stress Corrosion Cracking Program 3-168
• BWR Vessel Inside Diameter Attachment Welds Program
• BWR Vessel Internals Program
• Flow-Accelerated Corrosion Program
• Inservice Inspection Program
• One-Time Inspection Program
• Reactor Head Closure Studs Program
• Reactor Vessel Surveillance Program
• System Walkdown Program
• Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program
• Water Chemistry Control - BWR Program
• Water Chemistry Control - Closed Cooling Water Program Staff Evaluation. LRA Tables 3.1.2-1 through 3.1.2-3 summarize AMRs for the reactor vessel, reactor vessel internals, and reactor coolant system components and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed consistency with the report and for which it does not recommend further evaluation, the staffs 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 through E indicating 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 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 AMP. The staff audited these line items to verify consistency with the GALL Report and verified that the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also determines whether the applicants AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions. Note C indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified 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 GALL Report. The staff also determines 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. 3-169

Note D indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL 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 identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also determines whether the applicants AMP was consistent with the GALL 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 determines whether the credited AMP would manage the aging effect consistently with the GALL AMP and whether the AMR was valid for the site-specific conditions. 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: (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 reactor vessel, reactor vessel internals, and reactor coolant system components that are subject to an AMR. On the basis of its audit and review, the staff determines that, for AMRs not requiring further evaluation, as identified in LRA Table 3.1.1, the applicants references to the GALL Report are acceptable and no further staff review is required. 3.1.2.1.1 Loss of Material Due to General, Pitting and Crevice Corrosion In the discussion column of LRA Table 3.1.1, Item 3.1.1-11, the applicant stated that the Water Chemistry Control-BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material in carbon steel components of the reactor vessel. The Inservice Inspection Program supplements the applicants Water Chemistry Control-BWR Program for components. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in LRA Tables 3.1.2-1 to 3.1.2-3. The staff reviewed the applicants Water Chemistry Control - BWR Program, One-Time Inspection Program, and Inservice Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11, 3.0.3.1.6, and 3.0.3.3.3, respectively. The staff found each program acceptable. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.1.1, Item 3.1.1-11 in the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore is acceptable. 3-170

On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. The staff evaluated the applicants claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicants consideration of recent operating experience and proposals for managing the 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 its AMRs. Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for these components 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). 3.1.2.1.2 Loss of Material Due to General (Steel Only), Pitting and Crevice Corrosion In the discussion column of LRA Table 3.1.1, Item 3.1.1-13, the applicant stated that Water Chemistry Control-BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material in carbon steel components of the reactor vessel. The Inservice Inspection Program supplements the applicants Water Chemistry Control-BWR Program for certain of these components. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in LRA Tables 3.1.2-1 to 3.1.2-3. The staff reviewed the applicants Water Chemistry Control - BWR Program, One-Time Inspection Program, and Inservice Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11, 3.0.3.1.6, and 3.0.3.3.3, respectively. The staff found each program acceptable. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.1.1, Item 3.1.1-13 in the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore is acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.1.2.1.3 Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.1.1, Item 3.1.1-14, the applicant stated that the Water Chemistry Control-BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material in carbon steel components of the reactor vessel. Either the Inservice Inspection Program or the BWR Vessel Internals Program supplements the applicants Water Chemistry Control-BWR Program for certain of these components. 3-171

During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in LRA Tables 3.1.2-1 to 3.1.2-3. The staff reviewed the applicants Water Chemistry Control - BWR Program, One-Time Inspection Program, Inservice Inspection Program, and BWR Vessel Internals Program. These evaluations are documented in SER Sections 3.0.3.1.11, 3.0.3.1.6, 3.0.3.3.3, and 3.0.3.2.7, respectively. The staff found each program acceptable. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.1.1, Item 3.1.1-14 in the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore is acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.1.2.1.4 Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.1.1, Item 3.1.1-15, the applicant stated that the Water Chemistry Control-BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material in carbon steel components of the reactor vessel. The Inservice Inspection Program supplements the applicants Water Chemistry Control-BWR Program for certain of these components. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified. The staff reviewed the applicants Water Chemistry Control - BWR Program, One-Time Inspection Program, and Inservice Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11, 3.0.3.1.6, and 3.0.3.3.3, respectively. The staff found each program acceptable. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.1.1, Item 3.1.1-15 in the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore is acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.1.2.1.5 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement In the discussion column of LRA Table 3.1.1, Item 3.1.1-17, the applicant stated that loss of fracture toughness for the reactor vessel beltline shell and welds is a TLAA. During the audit and review, the staff noted that the applicants controlling documentation for materials in the nozzles leading to the vessel lacked sufficient calculations and accountability for errors. In accordance with Regulatory Guide (RG ) 1.190, "Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence," analytic uncertainty is to be considered in the calculation of fluence. The staff further noted that in the applicants NSSS supplier document, GE-NE-000-0007-2342-R1-NP (dated July 2003), "Entergy Northeast Vermont Yankee Neutron 3-172

Flux Evaluation," flux variations of up to but less than 19 percent were considered. During the audit and review, the applicant provided extrapolated data for determining if the top of the recirculation inlet nozzles might experience an extended power uprate fluence of greater than 1X1017 n/cm2. In RAI 3.1.1-17-P-01, the staff asked the applicant if a maximum variation of approximately 19 percent was considered in this extrapolated data. If not, what calculated fluence level that could be experienced by the top of the recirculation inlet nozzles if the applicant considered a maximum flux variation of just less than 19 percent. In its response, by letter dated September 5, 2006, the applicant stated that a 19 percent uncertainty was not added to the fluence value in determining whether the nozzle (nozzle to vessel weld) would exceed 1X1017 n/cm2 (E greater than 1 MeV). The applicant further stated that the fluence was extrapolated to determine the height at which fluence would equal 1 x1017 n/cm2 rather than to specifically estimate the fluence at the nozzle. The applicant also stated that the projected fluence in this region changes rapidly with elevation. The projected 1/4 T fluence at the bottom of the active fuel is 0.985 X1017 n/cm2, and 5.5 inches lower, at the nozzle to vessel weld, the estimated fluence is 0.66 X1017 n/cm2. The applicant stated that if the fluence is increased by 19 percent to cover possible error in the analysis, the fluence at the nozzle to vessel weld would be 0.792 X1017 n/cm2. Therefore, the recirculation injection nozzles, and their welds, remain below the 1X1017 n/cm2 threshold for the period of extended operation. The staff reviewed the GE fluence calculations, GE-NE-000-0007-2342-R1-NP, in conjunction with RAI 4.2-1. The staffs evaluation of this TLAA is documented in SER Section 4.2. The staff found the applicants response acceptable because the applicant used up to 19 percent flux variations in its fluence calculation. The staffs concern described in RAI 3.3.1-17-P-01 is resolved. 3.1.2.1.6 Cracking Due to Flow-Induced Vibration In the discussion column of LRA Table 3.1.1, Item 3.1.1-29, the applicant stated that the BWR Vessel Internals Program will manage cracking in the stainless steel steam dryers. During the audit and review, the staff asked the applicant for additional information on the AMP. VYNPS technical personnel stated that a steam dryer monitoring plan had been submitted as part of the power uprate application and approved by the staff. In addition, BWRVIP-139, Steam Dryer Inspection and Flaw Evaluation Guidelines, has been submitted to the NRC for review and approval. It is expected that this BWRVIP will be approved by the NRC prior to the period of extended operation and as such will become a part of the BWR Vessel Internals Program. VYNPS will manage cracking of the steam dryers per the BWR Vessel Internals Program during the period of extended operation. Exceptions, if any, will be subject to review and approval by the staff. 3-173

The staff finds that since the applicant committed (Commitment #37) to implement BWRVIP-139 as approved by the staff, if the staff does approve BWRVIP-139, this aging effect/mechanism will be adequately managed as recommended by the GALL Report. If the staff does not issue an SER approving the use of BWRVIP-139, a plant-specific program must be submitted at least 24 months prior to the period of extended operation for review and approval. 3.1.2.1.7 Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking, Cyclic Loading In the discussion column of LRA Table 3.1.1, Item 3.1.1-40, the applicant stated that cracking in stainless steel and nickel-alloy nozzles and penetrations in the reactor vessel is managed by the Water Chemistry Control-BWR Program and either BWR Penetrations Program, BWR Vessel Internals Program, or Inservice Inspection Program. The applicant also stated that cracking of the nickel-based alloy CRD stub tubes is managed using the BWR Vessel Internals Program and the Water Chemistry Control - BWR Program. The staff reviewed the applicants BWR Vessel Internals Program. This evaluation is documented in SER Section 3.0.3.2.7. The staff finds that inspection guidance for the CRD stub tubes is included in BWRVIP-47, BWR Lower Plenum Inspection and Flaw Evaluation Guidelines, which has been reviewed and accepted by the staff. Because the BWR Vessel Internals Program incorporates the applicable guidelines of BWRVIP-47, the staff finds it to be an acceptable method for aging management of cracking of the CRD stub tubes. The applicant also stated that stainless steel incore housings are managed using the Inservice Inspection Program and the Water Chemistry Control - BWR Program. The staff reviewed the applicants Inservice Inspection Program. This evaluation is documented in SER Section 3.0.3.3.3. The program is plant-specific and incorporates the inspection requirements of ASME Code, Section XI in accordance with 10 CFR 50.55a. Because the Inservice Inspection Program provides for inspections that satisfy the requirements of the ASME Code as reviewed and accepted by the staff, the staff finds it to be an acceptable method for aging management of cracking of the incore housings. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.1.2.1.8 Cracking Due to Stress Corrosion Cracking and Intergranular Stress Corrosion Cracking In LRA Table 3.1.1, Item 3.1.1-41, the applicant stated that cracking in stainless steel and nickel-alloy piping, nozzle safe ends, and associated welds is managed by its Water Chemistry Control - BWR Program and the BWR Stress Corrosion Cracking Program. Cracking due to SCC and IGSCC is managed in this way for stainless steel safe ends on recirculation nozzles (inlet and outlet) and jet pump instrument nozzles as well as nickel-based alloy safe ends for CS. 3-174

In LRA Table 3.1.2-3, for pump casings and valve bodies of CASS, as well as piping, fittings, flow elements, and thermowells of stainless steel, the applicant augments the BWR Stress Corrosion Cracking Program and the Water Chemistry Programs with the Inservice Inspection Program. This meets the recommendations of the GALL Report for this item and is acceptable to the staff. The applicant also stated that other component types associated with this item but outside the scope of the BWR Stress Corrosion Cracking Program are to be managed using the Inservice Inspection Program and the Water Chemistry Control - BWR Program. Cracking is managed in this manner for stainless-steel-clad nozzles of low-alloy steel (recirculation, CS, head spray, head instrumentation, head vent, and jet pump instrument nozzles); nickel-based alloy flange leakoff nozzles; stainless steel head nozzle flanges, blank flanges, as well as safe ends for the SLC/P and instrumentation nozzles. Low-alloy steel is not susceptible to SCC and components less than 4 inches nominal pipe size (NPS) are not within the scope of the BWR Stress Corrosion Cracking Program. The FWthermal sleeves of stainless steel and nickel-based alloy are also managed using the Inservice Inspection Program and the Water Chemistry Control - BWR Program. During the audit and review, the staff asked the applicant's technical personnel to clarify how the FW inlet thermal sleeves can be managed with the Inservice Inspection - Inservice Inspection Program. The applicant's technical personnel stated that the VYNPS thermal sleeves are not welded in place, but rather they are installed with an interference fit. As such, there is no weld to the pressure boundary piping that can be examined by the Inservice Inspection Program. The applicant's technical personnel further stated that because there is no pressure boundary weld, these sleeves are not part of the pressure boundary. By letter dated July 14, 2006, the applicant revised LRA Table 3.1.2-1 to remove all line items for the Thermal Sleeves Feedwater Inlets (N4) component type. Interference fitted thermal sleeves are not subject to SCC and IGSCC. The thermal sleeves are managed using the Water Chemistry Control - BWR Program. On this basis, the staff determines that the aging of the thermal sleeves is adequately managed. The staff reviewed the applicants Inservice Inspection Program. This evaluation is documented in SER Section 3.0.3.3.3. The staff found the program acceptable. The program is plant-specific and incorporates the inspection requirements of ASME Code, Section XI in accordance with 10 CFR 50.55a. Because the Inservice Inspection Program provides for inspections to satisfy the requirements of the ASME Code as reviewed and accepted by the staff, the staff finds it to be an acceptable method for management of cracking of these components. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3-175

3.1.2.1.9 Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking, Irradiation-Assisted Stress Corrosion Cracking In the discussion column of LRA Table 3.1.1, Item 3.1.1-44, the applicant stated that cracking due to SCC, IGSCC, and IASCC in the CASS, stainless steel, and nickel-based alloy components internal to the reactor vessel is to be managed using the BWR Vessel Internals Program and the Water Chemistry Control-BWR Program. The applicant included access hole cover plates among these items, for which the GALL Report recommends augmented inspection using the Inservice Inspection Program if the plate is mechanically fastened or welded in such a way that a crevice is formed. In the LRA, the applicant stated that the access hole covers are welded in place, not mechanically fastened, and that they were welded in a manner that prevented the formation of a crevice. The staff reviewed the applicant's BWR Vessel Internals Program and Water Chemistry Control-BWR Program. These evaluations are documented in SER Sections 3.0.3.2.7 and 3.0.3.1.11, respectively. The staff found each program acceptable. Management of cracking due to SCC, IGSCC, and IASCC of these components is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.1.2.1.10 Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.1.1, Item 3.1.1-47, the applicant stated that loss of material in stainless steel and nickel-alloy components of the reactor vessel internals is managed by the Water Chemistry Control-BWR Program. The One-Time Inspection Program will verify the effectiveness of the applicants Water Chemistry Control-BWR Program to manage loss of material. The applicants Inservice Inspection Program is not applicable to most reactor vessel internals components since they are not part of the pressure boundary. Management of loss of material using the applicants Water Chemistry Control-BWR Program augmented by its One-Time Inspection Program is consistent with similar items in LRA Table 3.1.1. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in LRA Tables 3.1.2-1 to 3.1.2-3. The staff reviewed the applicants Water Chemistry Control - BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.1.1, Item 3.1.1-47 in the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3-176

3.1.2.1.11 Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking (For Stainless Steel Only), and Thermal and Mechanical Loading In the discussion column of LRA Table 3.1.1, Item 3.1.1-48, the applicant stated that cracking of Class 1 stainless steel components less than 4 inches NPS is managed by the Water Chemistry Control-BWR Program and the One-Time Inspection Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable. The staff asked the applicant to justify the omission of ISI from the management of aging for Class 1 components. By letter dated July 14, 2006, the applicant revised LRA Table 3.1.2-3 to apply the Inservice Inspection Program, in addition to the Water Chemistry Control - BWR Program and One-Time Inspection Program, to manage cracking for all component types of piping and fittings less than 4 inches NPS, with the exception of the head seal leak detection line. With this change, the staff finds the applicant's management of cracking due to SCC, IGSCC, and thermal and mechanical loading of steel and stainless steel Class 1 piping, fittings, and branch connections less than 4 inches NPS consistent with the GALL Report and therefore acceptable. The staff also asked the applicant for confirmation that CRD accumulators and condensing pots were less than 4 inches NPS and appropriate for inclusion with this item of LRA Table 3.1.1. The applicant stated that these components are connected using tubing less than 4 inches NPS and are outside the scope of the its Inservice Inspection Program. The staff reviewed the ISI database to confirm that these items are not in the scope of the applicants Inservice Inspection Program, and concludes that the use of the Water Chemistry Control-BWR Program and the One-Time Inspection Program to manage cracking of these components is appropriate. Cracking due to SCC, IGSCC and thermal and mechanical loading of stainless steel CRD drives exposed to treated water greater than 270EF in the RCPB is to be managed using "Inservice Inspection Program." The staff's review of the applicant's Inservice Inspection Program is documented in SER Section 3.0.3.3.3, which the staff found acceptable. The staff finds that this program satisfies the criteria of SRP-LR Appendix A.1 for stainless steel CRD drives in the RCPB and is therefore acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3-177

3.1.2.1.12 Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking, Irradiation-Assisted Stress Corrosion Cracking In the discussion column of LRA Table 3.1.1, Item 3.1.1-49, the applicant stated that VYNPS has welded access hole covers with no crevice behind the weld. Cracking of the nickel-alloy shroud support access hole covers is managed by BWR Vessel Internals Program, and Water Chemistry Control-BWR Program, as described in LRA Table 3.1.1, Item 3.1.1-44. The staff's evaluation of this AMR is documented in SER Section 3.1.2.1.9. On the basis of its review, the staff finds that augmented inspection of the access hole covers is not required to adequately manage this aging effect/mechanism and that management of cracking of the core shroud and core plate access hole cover is consistent with the recommendations of the GALL Report and is therefore acceptable. 3.1.2.1.13 Cracking Due to Stress Corrosion Cracking and Intergranular Stress Corrosion Cracking In the discussion column of LRA Table 3.1.1, Item 3.1.1-50, the applicant stated that the Reactor Head Closure Studs Program manages cracking in low alloy steel head closure flange bolting while the Inservice Inspection Program manages cracking in other low-alloy steel bolting of the RCS pressure boundary. The staff reviewed the applicant's Reactor Head Closure Studs Program and Inservice Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.14 and 3.0.3.3.3, respectively. The staff found each program acceptable. The staff noted that the applicant was managing cracking of other low alloy steel pressure boundary bolting (i.e., flange bolts and nuts [N6A, N6B, N7] and CRD flange capscrews and washers) with the Inservice Inspection Program. The staff asked the applicant to clarify how aging of steel and stainless steel bolting would be adequately managed in the absence of a Bolting Integrity Program. In a letter dated July 6, 2006, the applicant committed (Commitment

1. 34) to prepare and submit an AMP consistent with GALL AMP XI.M18, Bolting Integrity, for approval. In a letter dated October 17, 2006, the applicant revised its LRA. The applicant submitted its Bolting Integrity Program. The staffs evaluation of this program is documented in SER Section 3.0.3.2.19. With this AMP, the staff finds that the applicant's management of cracking of other low alloy steel bolting will be consistent with the GALL Report and therefore acceptable.

On the basis of its review, the staff finds that the applicant, with the Commitment #34 identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.1.2.1.14 Cracking Due to Stress Corrosion Cracking, Loss of Material Due to Wear, Loss of Preload Due to Thermal Effects, Gasket Creep, and Self-Loosening In the discussion column of LRA Table 3.1.1, Item 3.1.1-52, the applicant stated that cracking due to SCC, loss of material due to wear, loss of preload due to thermal effects, gasket creep, and self-loosening is to be managed using the Inservice Inspection Program. 3-178

The staff reviewed the applicants Inservice Inspection Program. This evaluation is documented in SER Section 3.0.3.3.3 and was found acceptable by the staff. During the audit and review, the staff asked the applicant to clarify how aging of steel and stainless steel bolting would be managed in the absence of a Bolting Integrity Program. In a letter dated July 6, 2006, the applicant committed (Commitment #34) to prepare and submit an AMP consistent with GALL AMP XI.M18, Bolting Integrity, for approval. In a letter dated October 17, 2006, the applicant revised its LRA. The applicant submitted its Bolting Integrity Program. The staffs evaluation of this program is documented in SER Section 3.0.3.2.19, which the staff found acceptable. With this AMP, the staff finds that the applicant's management of low alloy steel bolting will be consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant, with the Commitment #34 identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.1.2.1.15 Loss of Fracture Toughness Due to Thermal Aging Embrittlement In the discussion column of LRA Table 3.1.1, Item 3.1.1-55, the applicant stated that the Inservice Inspection Program and the One-Time Inspection Program will be used to manage the reduction of fracture toughness in CASS components of the RCPB. The staff reviewed the applicants Inservice Inspection Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.3.3 and 3.0.3.1.6, respectively. The staff found each program acceptable. The applicants management of loss of fracture toughness due to thermal aging embrittlement of CASS pump casings and valve bodies 4 inches NPS and larger with the Inservice Inspection Program and the One-Time Inspection Program is consistent with the GALL Report and therefore acceptable to the staff. The use of the applicants Inservice Inspection Program and One-Time Inspection Program for managing loss of fracture toughness of CASS valve bodies less than 4 inches NPS is appropriate because the adequacy of ISI has been demonstrated by NRC-performed bounding integrity analysis. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.1.2.1.16 Loss of Fracture Toughness Due to Thermal Aging Embrittlement In the discussion column of LRA Table 3.1.1, Item 3.1.1-57, the applicant stated that the One-Time Inspection Program will be used to manage aging of the CASS main steam flow restrictors. VYNPS has no other Class 1 piping, piping components, piping elements, or CRD housings made of CASS. During the audit and review, the applicant clarified the location and method of attachment of this component, which is welded to the inner surface of the main steam piping upstream of the main steam isolation valves (MSIVs). 3-179

The staff finds that the CASS flow restrictor is not within the scope of GALL AMP XI.M12, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS), because it is neither a pressure-retaining component nor internal to the reactor vessel. In addition, the staff finds that the applicants One-Time Inspection Program provides an appropriate way to confirm that no AERM affects the flow restrictor. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 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 the associated 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 AMRs in the GALL Report. 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 for the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.1.2.2 AMR Results Consistent with the GALL 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 reactor vessel, reactor vessel internals, and reactor coolant system 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 stress corrosion cracking and intergranular stress-corrosion cracking
• crack growth due to cyclic loading
• loss of fracture toughness due to neutron irradiation embrittlement and void swelling
• cracking due to stress corrosion cracking
• 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 stress corrosion cracking and irradiation-assisted stress corrosion cracking
• cracking due to primary water stress corrosion cracking
• wall thinning due to flow-accelerated corrosion
• changes in dimensions due to void swelling 3-180
• cracking due to stress corrosion cracking and primary water stress corrosion cracking
• cracking due to stress corrosion cracking, primary water stress corrosion cracking, and irradiation-assisted stress corrosion cracking
• quality assurance 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 audited and reviewed the applicants evaluation to determine whether it adequately addressed the issues further evaluated. In addition, the staff reviewed the applicants further evaluations against the criteria contained in SRP-LR Appendix 3.1.2.2. The staffs review of the applicants further evaluation follows.

3.1.2.2.1 Cumulative Fatigue Damage LRA Section 3.1.2.2.1 states that fatigue is a TLAA, as required by 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). The staffs review of the applicants evaluation of fatigue for the reactor vessel and the reactor vessel internals is discussed in SER Sections 4.3.1.1 and 4.3.1.2, respectively. The staffs review of the applicants evaluation of fatigue for the Class 1 portions of the reactor coolant boundary piping and components, including those for interconnecting systems, is discussed in SER Section 4.3.1.3. 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 SRP-LR Appendix 3.1.2.2.2 criteria: (1) LRA Section 3.1.2.2.2 addresses loss of material in steel components of the reactor pressure vessel exposed to reactor coolant due to general, pitting and crevice corrosion. 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 pressurized water reactor (PWR) steam generator shell assembly exposed to secondary FW 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 (vent, top head spray or reactor core isolation cooling (RCIC), 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 select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the components intended functions will be maintained during the period of extended operation. 3-181

LRA Section 3.1.2.2.2 states that loss of material due to general, pitting, and crevice corrosion in steel components of the reactor pressure vessel exposed to reactor coolant is managed by the Water Chemistry Control-BWR Program. The effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program through an inspection of a representative sample of components crediting this program including areas of stagnant flow. The Inservice Inspection Program supplements the Water Chemistry Control-BWR Program for these components. The staff finds that this meets the criteria of SRP-LR Section 3.1.2.2.2 and is therefore acceptable. (2) LRA Section 3.1.2.2.2 addresses loss of material in other steel components within the RCPB exposed to reactor coolant due to general, pitting, and crevice corrosion. SRP-LR Section 3.1.2.2.2 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 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 select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the components intended functions will be maintained during the period of extended operation. LRA Section 3.1.2.2.2 stated that this paragraph in the SRP-LR pertains to BWR isolation condenser components. VYNPS does not have an isolation condenser, however, loss of material due to general, pitting, and crevice corrosion in other steel components within the RCPB exposed to reactor coolant is managed by the Water Chemistry Control-BWR Program. The effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program through an inspection of a representative sample of components crediting this program including areas of stagnant flow. For some components, the Inservice Inspection Program supplements the Water Chemistry Control-BWR Program. The staff finds that this meets the criteria of SRP-LR Section 3.1.2.2.2 and is therefore acceptable. (3) LRA Section 3.1.2.2.2 addresses loss of material of 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 due to pitting and crevice corrosion. 3-182

SRP-LR Section 3.1.2.2.2 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. 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 select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the components intended functions will be maintained during the period of extended operation. LRA Section 3.1.2.2.2 stated that loss of material due to general, pitting, and crevice corrosion in stainless steel, nickel-alloy and steel with stainless steel cladding components of the reactor pressure vessel, and loss of material in stainless steel (including CASS) components of the RCPB exposed to reactor coolant is managed by the Water Chemistry Control-BWR Program. The effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program through an inspection of a representative sample of components crediting this program including areas of stagnant flow. The One-Time Inspection Program is also used to manage loss of material from the main steam flow restrictor by means of a component-specific inspection. For some components, the Inservice Inspection or the BWR Vessel Internals Program supplements the Water Chemistry Control-BWR Program. The staff finds that this meets the criteria of SRP-LR Section 3.1.2.2.2 and is therefore acceptable. (4) LRA Section 3.1.2.2.2 addresses that this paragraph in the SRP-LR applies to PWRs only. 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 steam generator upper and lower shell and transition cone exposed to secondary FW and steam. The existing program controls chemistry to mitigate corrosion and ISI to detect loss of material. The extent and schedule of the existing steam generator inspections are designed to ensure that flaws cannot attain a depth sufficient to threaten the integrity of the welds; however, in accordance with 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 steam generators with a high-stress region at the shell to transition cone weld. Because VYNPS is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.2 does not apply to VYNPS. 3-183

Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.2 criteria. For those line 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 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). 3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement The staff reviewed LRA Section 3.1.2.2.3 against the following SRP-LR Section 3.1.2.2.3 criteria: (1) LRA Section 3.1.2.2.3 states that neutron irradiation embrittlement is a TLAA, as required by 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.2 documents the staffs review of the applicants evaluation of loss of fracture toughness for the reactor vessel beltline shell and welds. (2) LRA Section 3.1.2.2.3 was reviewed by the staff and is addressed in SER Section 4.2. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.3 criteria. For those line items that apply to LRA Section 3.1.2.2.3, 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 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 SRP-LR Section 3.1.2.2.4 criteria: (1) LRA Section 3.1.2.2.4 the applicant addresses cracking of stainless steel and nickel alloy BWR top head enclosure vessel flange leak detection lines due to SCC and IGSCC. SRP-LR Section 3.1.2.2.4 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 GALL Report recommends that a plant-specific AMP be evaluated because existing programs may not be capable of mitigating or detecting cracking due to SCC and IGSCC. LRA Section 3.1.2.2.4 states that the Water Chemistry Control-BWR Program and the One-Time Inspection Program will manage cracking due to SCC and IGSCC in the stainless steel head seal leak detection lines. The One-Time Inspection Program will include a volumetric examination for the detection of cracking. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program and its evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable. 3-184

The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. The staff finds that this combination satisfies the criteria of SRP-LR Appendix A.1 and is therefore acceptable. (2) LRA Section 3.1.2.2.4 states that VYNPS does not have an isolation condenser. SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCC may occur in stainless steel BWR isolation condenser components exposed to reactor coolant. The existing program controls reactor water chemistry to mitigate SCC and relies on ASME Code, Section XI, ISI; however, the existing program should be augmented to detect cracking due to SCC and IGSCC. The GALL Report recommends an augmented program to include temperature and radioactivity monitoring of the shell-side water and eddy current testing of tubes to ensure that component intended functions will be maintained during the period of extended operation. Because VYNPS has no isolation condenser, the staff finds that this item of SRP-LR Section 3.1.2.2.4 does not apply to VYNPS. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.4 criteria. For those line items that apply to LRA Section 3.1.2.2.4, 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). 3.1.2.2.5 Crack Growth Due to Cyclic Loading LRA Section 3.1.2.2.5 states that further evaluation of aging management in this area is not applicable to BWRs. The staff reviewed LRA Section 3.1.2.2.5 against the criteria in SRP-LR Section 3.1.2.2.5. In LRA Section 3.1.2.2.5, the applicant stated that SRP-LR Section 3.1.2.2.5 applies to PWRs only. SRP-LR Section 3.1.2.2.5 stated that crack growth due to cyclic loading could occur in reactor vessel 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 staff confirmed that the VYNPS vessel shell forgings were not clad using a high-heat-input welding process. On the basis that VYNPS does not have any components subject to this aging effect, the staff finds that this aging effect does not require management at VYNPS. 3-185

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. In LRA Section 3.1.2.2.6, the applicant stated that SRP-LR Section 3.1.2.2.6 applies to PWRs only. 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 reactor vessel internals components exposed to reactor coolant and neutron flux. The GALL Report recommends no further AMR if the applicant commits in the FSAR supplement: (1) to participate in industry programs for investigating and managing aging effects on reactor internals; (2) to 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, to submit an inspection plan for reactor internals to the staff for review and approval. The staff confirmed that the SRP-LR considers this aging effect/mechanism only for PWR components. On the basis that VYNPS does not have any components subject to this aging effect, the staff finds that this aging effect does not require management at VYNPS. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.6 criteria. For those line items that apply to LRA Section 3.1.2.2.6, 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). 3.1.2.2.7 Cracking Due to Stress Corrosion Cracking The staff reviewed LRA Section 3.1.2.2.7 against the following SRP-LR Section 3.1.2.2.7 criteria: (1) In LRA Section 3.1.2.2.7, the applicant stated that SRP-LR Section 3.1.2.2.7 applies to PWRs only. SRP-LR Section 3.1.2.2.7 states that cracking due to SCC may occur in the PWR stainless steel reactor vessel flange leak detection lines and bottom-mounted instrument guide tubes exposed to reactor coolant as well as in Class 1 PWR CASS reactor coolant system piping, piping components, and pipping elements exposed to reactor coolant. The GALL Report recommends that a plant-specific AMP be evaluated to ensure that this aging effect is adequately managed. The staff confirmed that the SRP-LR considers this aging effect/mechanism only for PWR components. 3-186

On the basis that VYNPS does not have any components subject to this aging effect, the staff finds that this aging effect does not require management at VYNPS. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.7 criteria. For those line items that apply to LRA Section 3.1.2.2.7, 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). 3.1.2.2.8 Cracking Due to Cyclic Loading The staff reviewed LRA Section 3.1.2.2.8 against the following SRP-LR Section 3.1.2.2.8 criteria: (1) LRA Section 3.1.2.2.8 addresses cracking of stainless steel BWR jet pump sensing lines due to cyclic loading. SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in the stainless steel BWR jet pump sensing lines. The GALL Report recommends that a plant-specific AMP be evaluated to ensure that this aging effect is adequately managed. LRA Section 3.1.2.2.8 stated that this paragraph in the SRP-LR pertains to the jet pump sensing lines inside the reactor vessel. At VYNPS, these lines have no license renewal intended function and thus are not subject to an AMR. In addition, the LRA stated that the lines inside the vessel do not form part of the RCS pressure boundary and their failure would not affect the performance of any functions in the scope of license renewal. However, the lines outside the vessel are part of the RCS pressure boundary and are subject to an AMR. The staff's evaluation of these lines which are included as piping and fitting components less 4 inches NPS and managed using LRA Table 3.1-1, Item 3.1.1-48 is documented in SER Section 3.1.2.1.11. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained during the period of extended operation, as required by 10 CFR 54.21(a)(3). (2) LRA Section 3.1.2.2.8 addresses the applicant stated that this paragraph in the SRP-LR pertains to BWR isolation condenser components. In LRA Section 3.1.2.2.8, the applicant stated that VYNPS does not have an isolation condenser. SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in steel and stainless steel BWR isolation condenser components exposed to reactor coolant. The existing program relies on ASME Code, Section XI, ISI; however, the existing program should be augmented to detect cracking due to cyclic loading. The GALL Report recommends an augmented program to include temperature and radioactivity monitoring of the shell-side water and eddy current testing of tubes to ensure that component intended functions will be maintained during the period of extended operation. 3-187

Because VYNPS has no isolation condenser, the staff finds that this item in SRP-LR Section 3.1.2.2.8 does not apply to VYNPS. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.8 criteria. For those line items that apply to LRA Section 3.1.2.2.8, 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 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). 3.1.2.2.9 Loss of Preload Due to Stress Relaxation The staff reviewed LRA Section 3.1.2.2.9 against the criteria in SRP-LR Section 3.1.2.2.9. In LRA Section 3.1.2.2.9, the applicant stated that this paragraph in the SRP-LR applies to PWRs only. 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 reactor vessel 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: (1) to participate in the industry programs for investigating and managing aging effects on reactor internals; (2) to 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, to submit an inspection plan for reactor internals to the staff for review and approval. On the basis that VYNPS does not have any components subject to this aging effect, the staff finds that this aging effect does not require management at VYNPS. 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. In LRA Section 3.1.2.2.10, the applicant stated that this paragraph in the SRP-LR applies to PWRs only. SRP-LR Section 3.1.2.2.10 states that loss of material due to erosion may occur in steel steam generator FW impingement plates and supports exposed to secondary FW. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that this aging effect is adequately managed. On the basis that VYNPS does not have any components subject to this aging effect, the staff finds that this aging effect does not require management at VYNPS. 3-188

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 addresses cracking of stainless steel steam dryers due to flow-induced vibration. SRP-LR Section 3.1.2.2.11 states that loss of material due to erosion may occur in steel steam generator FW impingement plates and supports exposed to secondary FW. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that this aging effect is adequately managed. The staff, as part of the its review of the applicants extended power uprate (EPU) application, conducted extensive reviews of the steam dryers. The staff reviewed the steam dryer analysis, and conducted technical audits at the GE Scale Model Test facility near San Jose, California and the GE office in Washington, DC. The steam dryer analysis involved evaluation of the pressure loads acting on the steam dryer during operation using computational fluid dynamics and acoustic circuit model analyses. The staff found that the uncertainty assumed by the applicant in its determination of the loads from the computational fluid dynamics analysis was significantly underestimated. To address this concern, and to confirm the applicants predictions regarding the hydrodynamic and acoustic loads on the steam dryer, the staff added license conditions to the VYNPS Facility Operation License when it approved the EPU in March 2006. The license conditions require monitoring, evaluating, and taking prompt action in response to potential adverse flow effects as a result of operation under extended power uprate conditions. One license condition also specifies visual inspections of the steam dryers during three consecutive refueling outages beginning with the spring 2007 refueling outage. The staff reviewed plant experience at Hatch and Brunswick related to plant transients after extended power uprates and did not observe any abnormal behavior in the steam dryers. On the basis of the operating experience and license conditions, the staff concludes that there is reasonable assurance that the VYNPS steam dryers will perform satisfactorily inservice under extended power uprate conditions during the proposed renewal period provided an adequate aging management program is used. The applicant stated that cracking due to flow-induced vibration in the stainless steel steam dryers is managed by the BWR Vessel Internals Program. The BWR Vessel Internals Program currently incorporates the guidance of GE-SIL-644, Revision 1. VYNPS will evaluate BWRVIP-139 once it is approved by the staff and either include its recommendations in the VYNPS BWR Vessel Internals Program or inform the staff of VYNPS's exceptions to that document. The staff finds the applicant's approach for managing cracking of steam dryers due to flow-induced vibration to be acceptable because the approach will be based on the guidelines developed by the ongoing activity of the BWRVIP. In addition, in a letter dated August 22, 2006, the applicant committed (Commitment #37) to continue inspections in accordance with the steam dryer monitoring plan, Revision 3, in the event that BWRVIP-139 is not approved prior to the period of extended operation. 3-189

The staff finds that since the applicant has committed (Commiment #37) to implement BWRVIP-139 as approved by the staff, if the staff does approve BWRVIP-139, this aging effect/mechanism will be adequately managed as recommended by the GALL Report. If the staff does not issue an SER approving the use of BWRVIP-139, the applicant must submit, for review and approval, a plant-specific program to manage cracking of the steam dryers due to flow-induced vibration. This must occur at least 24 months prior to the period of extended operation. The staff reviewed the applicants BWR Vessel Internals Program and finds it to be an acceptable method for managing cracking of the steam dryers due to flow-induced vibration based upon a commitment to implement BWRVIP-139 or to provide a plant-specific program for management of cracking in the steam dryers to the NRC for review and approval prior to the period of extended operation. Based on the programs identified above and Commitment #37, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.11 criteria. For those line items that apply to LRA Section 3.1.2.2.11, 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). 3.1.2.2.12 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. In LRA Section 3.1.2.2.12, the applicant stated that this paragraph in the SRP-LR applies to PWRs only. 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 FSAR supplement: (1) to participate in the industry programs for investigating and managing aging effects on reactor internals; (2) to 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, to submit an inspection plan for reactor internals to the staff for review and approval. On the basis that VYNPS does not have any components subject to this aging effect, the staff finds that this aging effect does not require management at VYNPS. 3-190

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. In LRA Section 3.1.2.2.13, the applicant stated that this paragraph in the SRP-LR applies to PWRs only. SRP-LR Section 3.1.2.2.13 states that cracking due to primary water stress corrosion cracking (PWSCC) may occur in PWR components made of nickel alloy and steel with nickel alloy cladding, including RCPB components and penetrations inside the reactor coolant system such as pressurizer heater sheathes and sleeves, nozzles, and other internal components. Except for reactor vessel upper head nozzles and penetrations, the GALL Report recommends ASME Code, 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 commits in the FSAR supplement to implement applicable: (1) bulletins and GLs; and (2) staff-accepted industry guidelines. On the basis that VYNPS does not have any components subject to this aging effect, the staff finds that this aging effect does not require management at VYNPS. 3.1.2.2.14 Wall Thinning Due to Flow-Accelerated Corrosion The staff reviewed LRA Section 3.1.2.2.14 against the criteria in SRP-LR Section 3.1.2.2.14. In LRA Section 3.1.2.2.14, the applicant stated that this paragraph in the SRP-LR applies to PWRs only. SRP-LR Section 3.1.2.2.14 states that wall thinning due to flow-accelerated corrosion may occur in steel FW inlet rings and supports. The GALL Report references IN 91-19, ?Steam Generator Feedwater Distribution Piping Damage, for evidence of flow-accelerated corrosion in steam generators and recommends that a plant-specific AMP be evaluated because existing programs may not be capable of mitigating or detecting wall thinning due to flow-accelerated corrosion. On the basis that VYNPS does not have any components subject to this aging effect, the staff finds that this aging effect does not require management at VYNPS 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. In LRA Section 3.1.2.2.15, the applicant stated that this paragraph in the SRP-LR applies to PWRs only. 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: (1) to participate in the industry programs for investigating and managing aging effects on reactor internals; (2) to evaluate and implement the results of the industry programs as applicable to the 3-191

reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, to submit an inspection plan for reactor internals to the staff for review and approval. On the basis that VYNPS does not have any components subject to this aging effect, the staff finds that this aging effect does not require management at VYNPS. 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 SRP-LR Section 3.1.2.2.16 criteria: In LRA Section 3.1.2.2.16, the applicant stated that this paragraph in the SRP-LR applies to PWRs only. SRP-LR Section 3.1.2.2.16 states that cracking due to SCC may occur on the primary coolant side of PWR steel steam generator upper and lower heads, tubesheets, and tube-to-tube sheet welds made or clad with stainless steel. Cracking due to PWSCC may occur on the primary coolant side of PWR steel steam generator upper and lower heads, tubesheets, and tube-to-tube sheet welds made or clad with nickel alloy. 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. The GALL Report recommends ASME Code, Section XI, ISI and control of water chemistry to manage this aging effect and recommends no further AMR for PWSCC of nickel alloy if the applicant complies with applicable NRC orders and commits in the FSAR supplement to implement applicable: (1) bulletins and GLs; and (2) staff-accepted industry guidelines. On the basis that VYNPS does not have any components subject to this aging effect, the staff finds that this aging effect does not require management at VYNPS. 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 the criteria in SRP-LR Section 3.1.2.2.17. In LRA Section 3.1.2.2.17, the applicant stated that this paragraph in the SRP-LR applies to PWRs only. SRP-LR Section 3.1.2.2.17 states that cracking due to SCC, PWSCC, and IASCC may occur in PWR stainless steel and nickel alloy reactor vessel internals components. The existing program controls water chemistry to mitigate these aging effects; however, the existing program should be augmented to manage these aging effects for reactor vessel internals components. The GALL Report recommends no further AMR if the applicant commits in the FSAR supplement: (1) to participate in the industry programs for investigating and managing aging effects on reactor internals; (2) to 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, to submit an inspection plan for reactor internals to the staff for review and approval. 3-192

On the basis that VYNPS does not have any components subject to this aging effect, the staff finds that this aging effect does not require management at VYNPS. 3.1.2.2.18 Quality Assurance for Aging Management of Nonsafety-Related Components SER Section 3.0.4 documents the staffs evaluation of the applicants QA program, which the staff found acceptable. Conclusion. On the basis of its review, for applicable component groups evaluated in the GALL Report for which the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determines that the applicant adequately addressed the issues that were further evaluated. The staff finds that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.1.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Tables 3.1.2-1 through 3.1.2-3, 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 3.1.2-1 through 3.1.2-3, the applicant indicated, via notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided further information about how it will manage the aging effects. Specifically, note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line 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 line item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report. Staff Evaluation. For component type, material, and environment combinations not evaluated in the GALL Report, the staff reviewed the applicants evaluation to determine whether 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. The staffs evaluation is documented in the following sections. 3.1.2.3.1 Reactor Vessel Summary of Aging Management Evaluation - LRA Table 3.1.2-1 The staff reviewed LRA Table 3.1.2-1, which summarizes the results of AMR evaluations for the reactor vessel component groups. In LRA Table 3.1.2-1, the applicant proposed to manage loss of material from low-alloy steel closure flange studs, nuts, washers and bushings exposed to air using AMP B.1.23, Reactor Head Closure Studs Program. 3-193

The staff reviewed the Reactor Head Closure Studs Program and its evaluation is documented in SER Section 3.0.3.2.14. The program includes ISI in conformance with the requirements of ASME Code, Section XI, Subsection IWB, and preventive measures to mitigate cracking and loss of material of reactor head closure studs, nuts, washers, and bushings. The staff determines that the AMP is adequate for managing the aging effects for which it is credited. On the basis of its review, the staff finds the aging effect of loss of material from low-alloy steel closure flange studs, nuts, washers and bushings exposed to air is effectively managed using the Reactor Head Closure Studs Program. In LRA Table 3.1.2-1, the applicant proposed to manage loss of material from low-alloy steel stabilizer pads and support skirt exposed to air using the Inservice Inspection (ISI) Program. The staff reviewed the Inservice Inspection Program and its evaluation is documented in SER Section 3.0.3.3.3, which the staff found acceptable. The plant-specific program implements ISI in conformance with the requirements of ASME Code, Section XI and 10 CFR 50.55a. The staff determines that the AMP is adequate for managing the aging effects for which it is credited. On the basis of its review, the staff finds the aging effect of loss of material from low-alloy steel stabilizer pads and support skirt exposed to air is effectively managed using the Inservice Inspection Program. In LRA Table 3.1.2-1, the applicant proposed to manage cracking of the stainless steel cap on the CRD return line exposed to treated water greater than 270EF using the BWR CRD Return Line Nozzle Program and the Water Chemistry Control - BWR Program. The staff reviewed the BWR CRD Return Line Nozzle Program and the Water Chemistry Control - BWR Program. These evaluations are documented in SER Sections 3.0.3.2.2 and 3.0.3.1.11, respectively. The staff found each program acceptable. The applicant stated that it has rerouted the CRD return flow to the reactor water cleanup (RWCU) system and capped the CRD return line vessel nozzle to mitigate cracking. The applicant further stated that it will monitor the effects of crack initiation and growth on the intended function of the control rod drive return line nozzle and cap by implementing AMP B.1.2, BWR CRD Return Line Nozzle. AMP B.1.2 complies with the requirements of GALL AMP XI.M6, BWR CRD Return Line Nozzle, with one exception. The staff reviewed this exception and to determine the validity of the applicants technical basis to exclude the weld joint between CRD return line and the RWCU piping from the aging management review. GALL AMP XI.M6 requires application of the American Society of Mechanical Engineers (ASME) Code Section XI, 2001 Edition through 2003 Addenda, Subsection IWB 2500-1 inspection requirements, and the NUREG-0619, BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking, recommendations to monitor this aging effect in the CRD return line welds. 3-194

With respect to the aging degradation of the capped CRD return line nozzle, the applicant stated that the capped CRD return line nozzle at the VYNPS unit will be monitored by the ASME Code, Section XI inservice inspection (ISI) examination as required by AMP B.1.2. In RAI B.1.2-1, dated August 16, 2006, the staff requested that the applicant provide the following information regarding the CRD return line capped weld: (1) Configuration, location and material of construction of the capped nozzle. This should include the existing base material for the nozzle, piping (if piping remnants exist) and cap material, and any welds. (2) Inspection criteria for this weld and the cap are managed in accordance with the guidelines of BWRVIP-75, BWR Vessel and Internals Project (BWRVIP), Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedule. (3) The effect of the event at Pilgrim (leaking weld at capped nozzle, September 30, 2003) is applicable to VYNPS. The staff issued Information Notice 2004-08, Reactor Coolant Pressure Boundary Leakage Attributable to Propagation of Cracking in Reactor Vessel Nozzle Welds, dated April 22, 2004, which states that the cracking occurred in an Alloy 182 weld that was previously repaired extensively. Discuss experience with previous leakage at the VYNPS capped nozzle, if any. Include in your discussion the past inspection techniques applied, the results obtained, and mitigative strategies imposed. Provide information as to how the plant-specific experience related to this aging effect impacts the attributes specified in AMP B.1.2, BWR CRD Return line Nozzles. In response to RAI B.1.2-1, in a letter dated August 30, 2006, the applicant stated that the material of construction of the cap at the VYNPS unit is ASME SA 182 Grade 316 L (low carbon) stainless steel. Type 316L (low carbon) stainless steel weld material, which has better resistance to IGSCC than non-L grade stainless steel weld material, was used for the cap-to-nozzle weld. At the time of installation (1979) visual testing (VT), liquid penetrant testing (PT), and radiographic testing (RT) were performed on the cap-to-nozzle weld and no reportable indications were found. Subsequent examinations included ultrasonic testing (UT) and VT in 1979, PT in 1989, and UT and PT in 2002, and thus far no reportable indications were identified. The applicant stated that by using a low carbon stainless steel base metal cap and low carbon stainless steel weld material, it can mitigate IGSCC in the cap-to-nozzle weld. Since past inspections indicated no active aging degradation in the cap-to-nozzle weld, the applicant concluded that the aging degradation in the subject weld is adequately managed by the BWR CRD Return Line Nozzle Program. The staff reviewed the applicants response and finds it acceptable because implementation of the BWR CRD Return Line Nozzle Program and the inspection requirements of the ASME Code, Section XI ISI Program for the CRD return lines would be consistent with the GALL AMP XI.M6. The staffs concern described in RAI B.1.2-1 is resolved. On the basis of its review, the staff finds the aging effect of cracking of the stainless steel CRD return line cap is effectively managed using the BWR CRD Return Line Nozzle Program and the Water Chemistry Control - BWR Program. 3-195

In LRA Table 3.1.2-1, the applicant proposed to manage cracking of the low-alloy steel bottom head, upper head, closure flanges, shell, main steam nozzle, and drain nozzle exposed to treated water greater than 220EF using the Inservice Inspection (ISI) Program and the Water Chemistry Control - BWR Program. The staff reviewed the Inservice Inspection Program and the Water Chemistry Control - BWR Program. These evaluations are documented in SER Sections 3.0.3.3.3 and 3.0.3.1.11, respectively. The Water Chemistry Control - BWR Program mitigates cracking of low-alloy steel components fully or partially clad with stainless steel in contact with reactor coolant. The Inservice Inspection Program monitors the effects of crack initiation and growth on the intended function of bottom head, upper head, closure flanges, shell, main steam nozzle, and drain nozzle. The staff determines that these programs are adequate to manage the aging effects for which they are credited. On the basis of its review the staff finds the aging effect of cracking of the low-alloy steel bottom head, upper head, closure flanges, shell, main steam nozzle, and drain nozzle is effectively managed using the Inservice Inspection Program and the Water Chemistry Control - BWR Program. In LRA Table 3.1.2-1, the applicant proposed to manage fatigue damage (cracking-fatigue) of the stainless steel bolting for flanges and incore housing exposed to air using a TLAA. During the audit and review, the staff noted that TLAA-metal fatigue was credited for managing cracking due to fatigue for almost all of the component types in the reactor coolant system. The applicant responded that entries listing cracking fatigue with TLAA-metal fatigue only met the screening criteria and these entries must be reviewed to determine if a TLAA-metal fatigue analysis exists. In a letter dated July 14, 2006, the applicant revised the LRA by deleting the line item in LRA Table 3.1.2-1 for incore housing bolting in which cracking-fatigue was managed by TLAA-metal fatigue. The staff finds this acceptable. On the basis of its review, the staff finds cracking due to fatigue for incore housing bolting is not managed by TLAA-metal fatigue as previously stated in the LRA. Cracking is instead managed using the Inservice Inspection Program. The staff determines that this program is adequate to manage the aging effects for which it is credited. 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). 3.1.2.3.2 Reactor Vessel Internals Summary of Aging Management Evaluation - LRA Table 3.1.2-2 The staff reviewed LRA Table 3.1.2-2, which summarizes the results of AMR evaluations for the reactor vessel internals component groups. In LRA Table 3.1.2-2, the applicant proposed to manage loss of preload of stainless steel core plate rim hold-down bolts exposed to treated water greater than 270EF using a TLAA. 3-196

The core plate rim hold-down bolts are subject to stress relaxation due to thermal and irradiation effects and, consequently, they would experience 5 to 19 percent loss of preload. The applicant identified that loss of preload in core plate rim hold-down bolts is a TLAA issue. The applicant, in LRA Section 4.7.2.2, stated that it would comply with the guidelines specified in the Boiling Water Reactor Vessel Inspection Program BWRVIP-25 report, "BWR Core Plate Inspection and Flaw Evaluation Guidelines," which includes inspection criteria for the core plate rim hold-down bolts. The applicant claimed that by invoking the inspection requirements of the BWRVIP-25 report it would adequately manage loss of preload of the core plate rim hold-down bolts during the extended period of operation. With respect to the TLAA issue associated with the loss of preload for the core plate rim hold-down bolts, the applicant stated that to date no plant-specific analysis was done in accordance with the current licensing basis. The applicant however, made a commitment (Commitment # 29) to either install wedges or perform plant-specific analysis that meets the requirements of the BWRVIP-25 report. If the applicant chooses to install wedges, the core plate rim hold-down bolts are excluded from the BWRVIP-25 inspection guidelines. The staff evaluation of this TLAA is documented in SER Section 4.7. On the basis of its review, the staff finds that, with Commitment #29, 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). 3.1.2.3.3 Reactor Coolant Pressure Boundary Summary of Aging Management Evaluation - LRA Table 3.1.2-3 The staff reviewed LRA Table 3.1.2-3, which summarizes the results of AMR evaluations for the RCPB component groups. In LRA Table 3.1.2-3, the applicant proposed to manage cracking of low-alloy and stainless steel bolting exposed to air using the Inservice Inspection Program. The staff reviewed the Inservice Inspection Program and its evaluation is documented in SER Section 3.0.3.3.3. The staff asked the applicant to clarify how aging of stainless steel bolting would be adequately managed in the absence of a Bolting Integrity Program. In a letter dated July 6, 2006, the applicant agreed to prepare and submit an AMP consistent with GALL AMP XI.M18, Bolting integrity, for approval. In a letter dated October 17, 2006, the applicant revised its LRA. The applicant submitted its Bolting Integrity Program. The staffs evaluation of this program is documented in SER Section 3.0.3.2.19. The staff finds that, with this AMP, the applicant's management of low-alloy and stainless steel bolting of the RCS pressure boundary is consistent with the GALL Report and therefore acceptable. 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). 3-197

3.1.2.3.4 Aging Effect/Mechanism in Table 3.1.1 That are Not Applicable for VYNPS The staff reviewed LRA Table 3.1.1, which provides a summary of aging management evaluations for the reactor vessel, internals and reactor coolant system evaluated in the GALL Report. In LRA Table 3.1.1, Item 3.1.1-25, the applicant stated that the jet pump instrumentation lines inside the reactor vessel have no intended function within the scope of license renewal and for that reason are not subject to an AMR. The lines outside the vessel are part of the RCS pressure boundary and are subject to an AMR. These lines are included as piping and fittings less than 4 inches NPS. During the audit and review, the applicant confirmed that component types subject to this aging effect are addressed by LRA Table 3.1.1, Item 3.1.1-48. The evaluation of Table 3.1.1, Item 3.1.1-48 is documented in SER Section 3.1.2.1.11. In LRA Table 3.1.1, Item 3.1.1-46, the applicant stated that the cracking of nickel alloy core shroud and core plate access hole cover (mechanical covers) due to SCC, IGSCC, and IASCC is not applicable at VYNPS. On the basis that the access hole covers are welded in a manner that leaves no crevice for which augmented inspection would be appropriate, the staff finds that, for this component type, this aging effect is not applicable to VYNPS. In LRA Table 3.1.1, Item 3.1.1-53, the applicant stated that the loss of material of steel piping, piping components, and piping elements exposed to closed cycle cooling water due to general, pitting and crevice corrosion is not applicable at VYNPS. On the basis that there are no components exposed to closed cycle cooling water in the reactor vessel, internals and reactor coolant system at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for these systems. In LRA Table 3.1.1, Item 3.1.1-54, the applicant stated that the loss of material of copper alloy piping, piping components, and piping elements exposed to closed cycle cooling water due to pitting, crevice, and galvanic corrosion is not applicable at VYNPS. On the basis that there are no copper-alloy components in the reactor vessel, internals and reactor coolant system at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for these systems. In LRA Table 3.1.1, Item 3.1.1-56, the applicant stated that the loss of material of copper alloy greater than 15 percent zinc piping, piping components, and piping elements exposed to closed cycle cooling water due to selective leaching is not applicable at VYNPS. On the basis that there are no copper-alloy components in the reactor vessel, internals and reactor coolant system at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for these systems. 3.1.2.3.5 Reactor Vessel, Internals and Reactor Coolant System AMR Line Items That Have No Aging Effects (LRA Tables 3.1.2-1 through 3.1.2-3) In LRA Tables 3.1.2-1 through 3.1.2-3, the applicant identified line items where no aging effects were identified as a result of its aging review process. 3-198

In LRA Tables 3.1.2-1 through 3.1.2-3, the applicant identified AMR line items where no aging effects were identified as a result of its aging review process. Specifically, instances in which the applicant states that no aging effects were identified occurred when components fabricated from carbon and low-alloy steel are exposed to an (indoor) air environment. Industry experience has shown that general corrosion of carbon steel or low-alloy steel components occurs only if the components were exposed to outdoor environments or to indoor environments that could promote the condensation of water on the external surfaces of the components. The external surface of the reactor vessel and the piping, fittings, and valve bodies of the reactor pressure boundary are normally at elevated temperatures. Consequently they are always dry, and corrosion is not observed. The staff acknowledged, in NUREG-1833, that steel in an indoor controlled air environment exhibits no aging effect and that steel components and structures will therefore remain capable of performing intended functions consistent with the CLB for the period of extended operation. Because the external surface of the reactor vessel and the piping, fittings, and valve bodies of the reactor pressure boundary are not subject to an AERM, the staff finds the absence of an AMP for these component types to be acceptable. The staff concludes that there are no AERMs for carbon and low-alloy steel components exposed to indoor air. On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results involving material, environment, AERMs, and AMP combinations that are 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). 3.1.3 Conclusion The staff concludes that the applicant has provided sufficient information to demonstrate that the effects of aging for the reactor vessel, reactor vessel internals, and reactor coolant system 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 staffs review of the applicants AMR results for the ESF systems components and component groups of:

• residual heat removal system
• core spray system
• automatic depressurization system
• high pressure coolant injection system
• reactor core isolation cooling system
• standby gas treatment system
• primary containment penetrations 3-199

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 for the Engineered Safety Features, is a summary comparison of the applicants AMRs with those evaluated in the GALL Report for the ESF systems components and component groups. The applicants 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 applicants review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report. 3.2.2 Staff Evaluation The staff reviewed LRA Section 3.2 to determine whether the applicant 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). The staff conducted an onsite audit of AMRs to ensure the applicants 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. The staffs evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staffs audit evaluation are documented in SER Section 3.2.2.1. In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicants further evaluations were consistent with the SRP-LR Section 3.2.2.2 acceptance criteria. The staffs audit evaluations are documented in SER Section 3.2.2.2. The staff also conducted a technical review of the remaining AMRs that were not consistent with, or not addressed in, the GALL Report. The technical review evaluated whether all plausible aging effects have been identified and whether the aging effects listed were appropriate for the material-environment combinations specified. The staffs evaluations are documented in SER Section 3.2.2.3. For SSCs which the applicant claimed were not applicable or required no aging management, the staff reviewed the AMR line items and the plants operating experience to verify the applicants claims. Table 3.2-1 summarizes the staffs evaluation of components, aging effects/mechanisms, and AMPs listed in LRA Section 3.2 and addressed in the GALL Report. 3-200

Table 3.2-1 Staff Evaluation for Engineered Safety Features Systems Components in the GALL Report Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Steel and stainless Cumulative fatigue TLAA, evaluated in TLAA Fatigue is a TLAA. steel piping, piping damage accordance with (See SER components, and 10 CFR 54.21(c) Section 4.3.1.3.2) piping elements in ECCS (3.2.1-1) Steel with stainless Loss of material due A plant-specific Not applicable to steel cladding pump to cladding breach AMP is to be None BWRs casing exposed to evaluated. treated borated water Reference NRC (3.2.1-2) Information Notice 94-63, Boric Acid Corrosion of Charging Pump Casings Caused by Cladding Cracks Stainless steel Loss of material due Water Chemistry Water Chemistry Consistent with containment to pitting and and One-Time Control-BWR GALL Report, which isolation piping and crevice corrosion Inspection Program (B.1.30.2); recommends further components internal One-Time Inspection evaluation (See surfaces exposed to Program (B.1.21) SER treated water Section 3.2.2.2.3) (3.2.1-3) Stainless steel Loss of material due A plant-specific None Not applicable (See piping, piping to pitting and AMP is to be SER components, and crevice corrosion evaluated. Section 3.2.2.2.3) piping elements exposed to soil (3.2.1-4) Stainless steel and Loss of material due Water Chemistry Water Chemistry Consistent with aluminum piping, to pitting and and One-Time Control-BWR GALL Report, which piping components, crevice corrosion Inspection Program (B.1.30.2); recommends further and piping elements One-Time evaluation (See exposed to treated Inspection Program SER water (B.1.21) Section 3.2.2.2.3) (3.2.1-5) Stainless steel and Loss of material due Lubricating Oil Oil Analysis Consistent with copper alloy piping, to pitting and Analysis and Program (B.1.20); GALL Report, which piping components, crevice corrosion One-Time One-Time recommends further and piping elements Inspection Inspection Program evaluation (See exposed to (B.1.21) SER lubricating oil Section 3.2.2.2.3) (3.2.1-6) 3-201

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Partially encased Loss of material due A plant-specific None Not applicable (See stainless steel tanks to pitting and AMP is to be SER with breached crevice corrosion evaluated for pitting Section 3.2.2.2.3) moisture barrier and crevice exposed to raw corrosion of tank water bottoms because (3.2.1-7) moisture and water can egress under the tank due to cracking of the perimeter seal from weathering. Stainless steel Loss of material due A plant-specific Periodic Consistent with piping, piping to pitting and AMP is to be Surveillance and GALL Report, which components, piping crevice corrosion evaluated. Preventive recommends further elements, and tank Maintenance evaluation (See internal surfaces Program (B.1.22) SER exposed to Section 3.2.2.2.3) condensation (internal) (3.2.1-8) Steel, stainless Reduction of heat Lubricating Oil Oil Analysis Consistent with steel, and copper transfer due to Analysis and Program (B.1.20); GALL Report, which alloy heat fouling One-Time One-Time recommends further exchanger tubes Inspection Inspection Program evaluation (See exposed to (B.1.21) SER lubricating oil Section 3.2.2.2.4) (3.2.1-9) Stainless steel heat Reduction of heat Water Chemistry Water Chemistry Consistent with exchanger tubes transfer due to and One-Time Control-BWR GALL Report, which exposed to treated fouling Inspection Program (B.1.30.2); recommends further water One Time evaluation (See (3.2.1-10) Inspection Program SER (B.1.21) Section 3.2.2.2.4) Elastomer seals and Hardening and loss A plant-specific None Not applicable (See components in of strength due to AMP is to be SER SGTS exposed to elastomer evaluated. Section 3.2.2.2.5) air - indoor degradation uncontrolled (3.2.1-11) Stainless steel Loss of material due A plant-specific None Not applicable high-pressure safety to erosion AMP is to be (PWR) injection (charging) evaluated for pump miniflow erosion of the orifice orifice exposed to due to extended use treated borated of the centrifugal water high pressure safety (3.2.1-12) injection pump for normal charging. 3-202

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Steel drywell and Loss of material due A plant-specific None Not applicable (See suppression to general corrosion AMP is to be SER chamber spray and fouling evaluated. Section 3.2.2.2.7) system nozzle and flow orifice internal surfaces exposed to air - indoor uncontrolled (internal) (3.2.1-13) Steel piping, piping Loss of material due Water Chemistry Water Chemistry Consistent with components, and to general, pitting, and One-Time Control-BWR GALL Report, which piping elements and crevice Inspection Program (B.1.30.2); recommends further exposed to treated corrosion One Time evaluation (See water Inspection Program SER (3.2.1-14) (B.1.21 Section 3.2.2.2.8) Steel containment Loss of material due Water Chemistry Water Chemistry Consistent with isolation piping, to general, pitting, and One-Time Control-BWR GALL Report, which piping components, and crevice Inspection Program (B.1.30.2); recommends further and piping elements corrosion One Time evaluation (See internal surfaces Inspection Program SER exposed to treated (B.1.21) Section 3.2.2.2.8) water (3.2.1-15) Steel piping, piping Loss of material due Lubricating Oil Oil Analysis Consistent with components, and to general, pitting, Analysis and Program (B.1.20); GALL Report, which piping elements and crevice One-Time One-Time recommends further exposed to corrosion Inspection Inspection Program evaluation (See lubricating oil (B.1.21) SER (3.2.1-16) Section 3.2.2.2.8) Steel (with or Loss of material due Buried Piping and Buried Piping Consistent with without coating or to general, pitting, Tanks Surveillance Inspection Program GALL Report, which wrapping) piping, crevice, and MIC or (B.1.1) recommends further piping components, Buried Piping and evaluation (See and piping elements Tanks Inspection SER buried in soil Section 3.2.2.2.9) (3.2.1-17) Stainless steel Cracking due to BWR Stress BWR Stress Consistent with piping, piping SCC and IGSCC Corrosion Cracking Corrosion Cracking GALL Report, which components, and and Water Program (B.1.5); recommends no piping elements Chemistry Water Chemistry further evaluation exposed to treated Control-BWR (See SER water > 60EC Program (B.1.30.2); Section 3.2.2.1.9) (> 140EF) One-Time Inspection (3.2.1-18) Program (B.1.21) 3-203

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Steel piping, piping Wall thinning due to Flow-Accelerated Flow-Accelerated Consistent with components, and flow-accelerated Corrosion Corrosion Program GALL Report, which piping elements corrosion (B.1.13) recommends no exposed to steam or further evaluation treated water (See SER (3.2.1-19) Section 3.2.2.1.10) CASS piping, piping Loss of fracture Thermal Aging None Not applicable components, and toughness due to Embrittlement of (There are no CASS piping elements thermal aging CASS components in the exposed to treated embrittlement ESF systems.) water (borated or (See SER unborated) > 250EC Section 3.2.2.3.8) (> 482EF) (3.2.1-20) High-strength steel Cracking due to Bolting Integrity None Not applicable closure bolting cyclic loading, SCC (High strength steel exposed to air with closure bolting is steam or water not used in ESF leakage systems.) (3.2.1-21) (See SER Section 3.2.2.3.8) Steel closure bolting Loss of material due Bolting Integrity Bolting Integrity Consistent with the exposed to air with to general corrosion Program (B.1.31) GALL Report. steam or water (See SER leakage Section 3.2.2.3.8) (3.2.1-22) Steel bolting and Loss of material due Bolting Integrity System Walkdown Consistent with the closure bolting to general, pitting, Program (B.1.28) and GALL Report. exposed to air - and crevice Bolting Integrity (See SER outdoor (external), corrosion Program (B.1.31) Section 3.2.2.1.11) or air - indoor uncontrolled (external) (3.2.1-23) Steel closure bolting Loss of preload due Bolting Integrity Bolting Integrity Consistent with exposed to air - to thermal effects, Program GALL Report, which indoor uncontrolled gasket creep, and (B.1.31) recommends no (external) self-loosening further evaluation (3.2.1-24) (See SER Section 3.2.2.1.18) Stainless steel Cracking due to Closed-Cycle Water Chemistry Consistent with piping, piping SCC Cooling Water Control-Closed GALL Report, which components, and System Cooling Water recommends no piping elements Program (B.1.30.3) further evaluation exposed to closed (See SER cycle cooling water Section 3.2.2.1) > 60EC (> 140EF) (3.2.1-25) 3-204

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Steel piping, piping Loss of material due Closed-Cycle None Not applicable. components, and to general, pitting, Cooling Water (Steel containment piping elements and crevice System isolation components exposed to closed corrosion exposed to closed cycle cooling water cycle cooling water (3.2.1-26) are all part of other safety systems that are evaluated separately.) (See SER Section 3.2.2.3.8) Steel heat Loss of material due Closed-Cycle Water Chemistry Consistent with exchanger to general, pitting, Cooling Water Control-Closed GALL Report, which components crevice, and System Cooling Water recommends no exposed to closed galvanic corrosion Program (B.1.30.3) further evaluation cycle cooling water (See SER (3.2.1-27) Section 3.2.2.1) Stainless steel Loss of material due Closed-Cycle Water Chemistry Consistent with piping, piping to pitting and Cooling Water Control-Closed GALL Report, which components, piping crevice corrosion System Cooling Water recommends no elements, and heat Program (B.1.30.3) further evaluation exchanger (See SER components Section 3.2.2.1) exposed to closed-cycle cooling water (3.2.1-28) Copper alloy piping, Loss of material due Closed-Cycle None There are no copper piping components, to pitting, crevice, Cooling Water alloy components piping elements, and galvanic System exposed to closed and heat exchanger corrosion cycle cooling water components in the ESF exposed to closed systems.) cycle cooling water (See SER (3.2.1-29) Section 3.2.2.3.8) Stainless steel and Reduction of heat Closed-Cycle Water Chemistry Consistent with copper alloy heat transfer due to Cooling Water Control-Closed GALL Report, which exchanger tubes fouling System Cooling Water recommends no exposed to closed Program (B.1.30.3) further evaluation cycle cooling water (See SER (3.2.1-30) Section 3.2.2.1) 3-205

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) External surfaces of Loss of material due External Surfaces System Walkdown Consistent with steel components to general corrosion Monitoring Program (B.1.28) GALL Report, which including ducting, recommends no piping, ducting further evaluation closure bolting, and (See SER containment Section 3.2.2.1.12) isolation piping external surfaces exposed to air - indoor uncontrolled (external); condensation (external) and air - outdoor (external) (3.2.1-31) Steel piping and Loss of material due Inspection of System Walkdown Consistent with ducting components to general corrosion Internal Surfaces in Program (B.1.28) GALL Report, which and internal Miscellaneous recommends no surfaces exposed to Piping and Ducting further evaluation air - indoor Components (See SER uncontrolled Section 3.2.2.1.13) (Internal) (3.2.1-32) Steel encapsulation Loss of material due Inspection of None Not applicable (The components to general, pitting, Internal Surfaces in ESF systems exposed to air - and crevice Miscellaneous include no steel indoor uncontrolled corrosion Piping and Ducting encapsulation (internal) Components components.) (3.2.1-33) Steel piping, piping Loss of material due Inspection of Periodic Surveillance Consistent with components, and to general, pitting, Internal Surfaces in and Preventive GALL Report, which piping elements and crevice Miscellaneous Maintenance recommends no exposed to corrosion Piping and Ducting Program (B.1.22) further evaluation condensation Components (See SER (internal) Section 3.2.2.1.14) (3.2.1-34) Steel containment Loss of material due Open-Cycle Cooling Containment Leak Consistent with isolation piping and to general, pitting, Water System Rate Program (B.1.8); GALL Report, which components internal crevice, and MIC, Containment recommends no surfaces exposed to and fouling Inservice Inspection further evaluation raw water Program (B.1.15.1) (See SER (3.2.1-35) Section 3.2.2.1.15) Steel heat Loss of material due Open-Cycle Cooling Service Water Consistent with exchanger to general, pitting, Water System Integrity Program GALL Report, which components crevice, galvanic, (B.1.26); Periodic recommends no exposed to raw and MIC, and Surveillance and further evaluation water fouling Preventive (See SER (3.2.1-36) Maintenance (B.1.22) Section 3.2.2.1.16) 3-206

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Stainless steel Loss of material due Open-Cycle Cooling Periodic Surveillance Consistent with piping, piping to pitting, crevice, Water System and Preventive GALL Report, which components, and and MIC Maintenance (B.1.22) recommends no piping elements further evaluation exposed to raw (See SER water Section 3.2.2.1.17) (3.2.1-37) Stainless steel Loss of material due Open-Cycle Cooling None Not applicable containment to pitting, crevice, Water System (There are no isolation piping and and MIC, and stainless steel components internal fouling containment surfaces exposed to isolation raw water components (3.2.1-38) exposed to raw water in the ESF systems.) (See SER Section 3.2.2.3.8) Stainless steel heat Loss of material due Open-Cycle Cooling Service Water Consistent with exchanger to pitting, crevice, Water System Integrity Program GALL Report, which components and MIC, and (B.1.26) recommends no exposed to raw fouling further evaluation water (See SER (3.2.1-39) Section 3.2.2.1) Steel and stainless Reduction of heat Open-Cycle Cooling Service Water Consistent with steel heat transfer due to Water System Integrity Program GALL Report, which exchanger tubes fouling (B.1.26) recommends no (serviced by further evaluation open-cycle cooling (See SER water) exposed to Section 3.2.2.1) raw water (3.2.1-40) Copper alloy > 15 Loss of material due Selective Leaching None Not applicable percent Zn piping, to selective leaching of Materials (There are no piping components, copper alloy > 15 piping elements, percent zinc and heat exchanger components components exposed to closed exposed to closed cycle cooling water cycle cooling water in the ESF (3.2.1-41) systems.) (See SER Section 3.2.2.3.8) Gray cast iron Loss of material due Selective Leaching Selective Leaching Consistent with piping, piping to selective leaching of Materials Program (B.1.25) GALL Report, which components, piping recommends no elements exposed further evaluation to closed-cycle (See SER cooling water Section 3.2.2.1) (3.2.1-42) 3-207

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Gray cast iron Loss of material due Selective Leaching None Not applicable piping, piping to selective leaching of Materials (There are no gray components, and cast iron piping elements components exposed to soil exposed to soil in (3.2.1-43) the ESF systems.) (See SER Section 3.2.2.3.8) Gray cast iron motor Loss of material due Selective Leaching Selective Leaching Consistent with cooler exposed to to selective leaching of Materials Program (B.1.25) GALL Report, which treated water recommends no (3.2.1-44) further evaluation (See SER Section 3.2.2.1) Aluminum, copper Loss of material due Boric Acid None Not applicable to alloy > 15 to Boric acid Corrosion BWRs percent Zn, and corrosion steel external surfaces, bolting, and piping, piping components, and piping elements exposed to air with borated water leakage (3.2.1-45) Steel encapsulation Loss of material due Inspection of None Not applicable to components to general, pitting, Internal Surfaces in BWRs exposed to air with crevice and boric Miscellaneous borated water acid corrosion Piping and Ducting leakage (internal) Components (3.2.1-46) CASS piping, piping Loss of fracture Thermal Aging None Not applicable to components, and toughness due to Embrittlement of BWRs piping elements thermal aging CASS exposed to treated embrittlement borated water > 250EC (> 482EF) (3.2.1-47) Stainless steel or Cracking due to Water Chemistry None Not applicable to stainless-steel-clad SCC BWRs steel piping, piping components, piping elements, and tanks (including safety injection tanks/accumulators) exposed to treated borated water > 60EC (> 140EF) (3.2.1-48) 3-208

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Stainless steel Loss of material due Water Chemistry None Not applicable to piping, piping to pitting and BWRs components, piping crevice corrosion elements, and tanks exposed to treated borated water (3.2.1-49) Aluminum piping, None None None Not applicable ( See piping components, SER and piping elements Section 3.2.2.1) exposed to air - indoor uncontrolled (internal/external) (3.2.1-50) Galvanized steel None None None Not applicable ducting exposed to air - indoor controlled (external) (3.2.1-51) Glass piping None None None Consistent with elements exposed GALL Report to air - indoor Galvanized steel uncontrolled surfaces are (external), evaluated as steel lubricating oil, raw in the ESF water, treated water, systems.) or treated borated water (3.2.1-52) Stainless steel, None None None Consistent with copper alloy, and GALL Report ( See nickel alloy piping, SER piping components, Section 3.2.2.1) and piping elements exposed to air - indoor uncontrolled (external) (3.2.1-53) Steel piping, piping None None None Not applicable components, and (There are no steel piping elements components of the exposed to air - ESF systems in indoor controlled indoor controlled air (external) environments. All (3.2.1-54) indoor air environments are conservatively considered to be uncontrolled) 3-209

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Steel and stainless None None None Not applicable steel piping, piping (There are no steel components, and or stainless steel piping elements in components in the concrete ESF systems (3.2.1-55) embedded in concrete). Steel, stainless None None None Consistent with steel, and copper GALL Report ( See alloy piping, piping SER components, and Section 3.2.2.1) piping elements exposed to gas (3.2.1-56) Stainless steel and None None None Not applicable to copper alloy < 15 BWRs percent Zn piping, piping components, and piping elements exposed to air with borated water leakage (3.2.1-57) The staffs review of the ESF systems component groups followed any one of several approaches. One approach, 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 approach, 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 approach, 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. The staffs review of AMPs credited to manage or monitor aging effects of the ESF systems components is documented in SER Section 3.0.3. 3.2.2.1 AMR Results Consistent with the GALL Report Summary of Technical Information in the Application LRA Section 3.2.2.1 identifies the materials, environments, AERMs, and the following programs that manage aging effects for the ESF systems components:

• Buried Piping and Tanks Inspection Program
• Containment Leak Rate Program
• Flow-Accelerated Corrosion Program
• Heat Exchanger Monitoring Program
• Oil Analysis Program
• One-Time Inspection Program
• Periodic Surveillance and Preventive Maintenance Program
• Selective Leaching Program 3-210
• Service Water Integrity Program
• System Walkdown Program
• Water Chemistry Control - Auxiliary Systems Program
• Water Chemistry Control - BWR Program
• Water Chemistry Control - Closed Cooling Water Program Staff Evaluation. LRA Tables 3.2.2-1 through 3.2.2-7 summarize AMRs for the ESF systems components and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed consistency with the report and for which it does not recommend further evaluation, the staffs 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 through E indicating 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 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 AMP. The staff audited these line items to verify consistency with the GALL Report and verified that the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also determines whether the applicants AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions. Note C indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified 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 GALL Report. The staff also determines 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, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL 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 identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also determines whether the applicants AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions. 3-211

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 determines whether the credited AMP would manage the aging effect consistently with the GALL AMP and whether the AMR was valid for the site-specific conditions. 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: (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 ESF systems components that are subject to an AMR. On the basis of its audit and review, the staff determines that, for AMRs not requiring further evaluation, as identified in LRA Table 3.2.1, the applicants references to the GALL Report are acceptable and no further staff review is required. 3.2.2.1.1 Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-3, the applicant stated that the Water Chemistry Control - BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material for stainless steel containment isolation piping and components internal surfaces exposed to treated water of the ESF system. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. The staff reviewed the applicants Water Chemistry Control - BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-3 within the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. The staff evaluated the applicants claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicants consideration of recent operating experience and proposals for managing the 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 its AMRs. Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for these components 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). 3-212

3.2.2.1.2 Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-5, the applicant stated that the Water Chemistry Control - BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material in stainless steel and aluminum piping and piping components exposed to treated water of the ESF system. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. The staff reviewed the applicants Water Chemistry Control - BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-5 within the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.2.2.1.3 Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-6, the applicant stated that the Oil Analysis Program manages loss of material in stainless steel and copper alloy components. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. In a letter dated July 14, 2006, the applicant revised the LRA so that the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program. The staff reviewed the applicant's Oil Analysis Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.6, respectively. The staff found each program acceptable. With the change discussed above, the applicant is managing the loss of material due to pitting, and crevice corrosion of stainless steel and copper alloy piping, piping components, and piping elements exposed to lubricating oil in a manner that is consistent with the GALL Report and therefore acceptable to the staff. In addition, this aging effect is also managed for carbon steel gauges, filter housings, heater housings, pump casings, strainer housings, tanks, gear boxes, and heat exchanger shells as well as gray cast iron valve bodies exposed to lubricating oil. On the basis of its review, the staff finds that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.2.2.1.4 Reduction of Heat Transfer Due to Fouling In the discussion column of LRA Table 3.2.1, Item 3.2.1-9, the applicant stated that the Oil Analysis Program manages reduction of heat transfer in steel, stainless steel and copper alloy components. 3-213

During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. In a letter dated July 14, 2006, the applicant revised the LRA so that the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program. The staff reviewed the applicant's Oil Analysis Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.6, respectively. With the change discussed above, the applicant is managing the reduction of heat transfer due to fouling of steel, stainless steel and copper alloy heat exchanger tubes exposed to lubricating oil in a manner that is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.2.2.1.5 Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-10, the applicant stated that the Water Chemistry Control - BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material in stainless steel heat exchanger tubes exposed to treated water of the ESF system. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. The staff reviewed the applicants Water Chemistry Control - BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-10 within the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.2.2.1.6 Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-14, the applicant stated that the Water Chemistry Control - BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material in steel piping, piping components, and piping elements exposed to treated water of the ESF system. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. The staff reviewed the applicants Water Chemistry Control - BWR Program and One-Time Inspection Program. These 3-214

evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-14 within the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.2.2.1.7 Loss of Material Due to Pitting and Crevice Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-15, the applicant stated that the Water Chemistry Control - BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material in steel containment isolation piping, piping components, and piping elements internal surfaces exposed to treated of the ESF system. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. The staff reviewed the applicants Water Chemistry Control - BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-15 within the population that is subject to the One-Time Inspection Program. This is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.2.2.1.8 Loss of Material Due to General, Pitting and Crevice Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-16 the applicant stated that the Oil Analysis Program manages loss of material in steel components. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. In a letter dated July 14, 2006, the applicant revised the LRA so that the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program. The staff reviewed the applicant's Oil Analysis Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.6, respectively. The staff found each program acceptable. With the change discussed above, the applicant is managing the loss of material due to general pitting, and crevice corrosion of steel piping, piping components, and piping elements exposed to lubricating oil in a manner that is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3-215

3.2.2.1.9 Cracking Due to Stress Corrosion Cracking and Intergranular Stress Corrosion Cracking In the discussion column of LRA Table 3.2.1, Item 3.2.1-18, the applicant stated that the Water Chemistry Control - BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage cracking due to SCC and IGSCC in stainless steel piping, piping components, and piping elements of the ESF system. The VYNPS Water Chemistry Control - BWR Program optimizes the primary water chemistry to minimize the potential for cracking. This is accomplished by limiting the levels of contaminants in the reactor coolant system that could cause cracking. Additionally, VYNPS has instituted hydrogen water chemistry with noble metals to limit the potential for IGSCC through the reduction of dissolved oxygen in the treated water. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the LRA Tables 3.2.2-1 to 3.2.2-7. The staff reviewed the applicants Water Chemistry Control - BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff found each program acceptable. On the basis of its review, the staff finds that managing cracking due to SCC and IGSCC Water Chemistry Control-BWR Program, One-Time Inspection Program, and Inservice Inspection Program appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.2.2.1.10 Wall Thinning Due to Flow-Accelerated Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-19, the applicant stated that the Flow-Accelerated Corrosion Program will be used to manage wall thinning in steel piping, piping components, and piping elements exposed to steam or treated water of the ESF system. The staff reviewed the applicants Flow-Accelerated Corrosion Program. This evaluation is documented in SER Section 3.0.3.1.2, which the staff found acceptable. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-19 within the population that is subject to the Flow-Accelerated Corrosion Program. This is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.2.2.1.11 Loss of Material Due to General, Pitting and Crevice Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-23 the applicant stated that the System Walkdown Program manages loss of material due to general, pitting and crevice corrosion exposed to air outdoor (external) or air indoor uncontrolled (external) for steel bolting and closure bolting components. 3-216

During the audit and review, the staff asked the applicant to clarify the basis for using its System Walkdown Program to manage aging of carbon steel bolting instead the AMP recommended by the GALL Report. In a letter dated July 6, 2006, the applicant agreed to prepare and submit an AMP consistent with GALL AMP XI.M18, Bolting Integrity, for review and approval. In a letter dated October 17, 2006, the applicant revised its LRA. The applicant submitted its Bolting Integrity Program. The staffs evaluation of this program is documented in SER Section 3.0.3.2.19. With this change, the applicants management of loss of material due to general, pitting and crevice corrosion of steel bolting and closure bolting, will be consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.2.2.1.12 Loss of Material Due to General Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-31, the applicant stated that the System Walkdown Program will be used to manage loss of material to 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) in the ESF system. The staff reviewed the applicants System Walkdown Program. This evaluation is documented in SER Section 3.0.3.1.9, which the staff found acceptable. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-31 within the population that is subject to the System Walkdown Program. This is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.2.2.1.13 Loss of Material Due to General Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-32, the applicant stated that the System Walkdown Program will be used to manage loss of material to steel piping, fan housing, valve body, and ducting components and internal surfaces exposed to air-indoor uncontrolled (internal) in the ESF, SA, and HVAC systems. The staff reviewed the applicants System Walkdown Program. This evaluation is documented in SER Section 3.0.3.1.9. The staff found the program acceptable. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-32 within the population that is subject to the System Walkdown Program. This is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3-217

3.2.2.1.14 Loss of Material Due to General, Pitting and Crevice Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-34, the applicant stated that the Periodic Surveillance and Preventive Maintenance Program will be used to manage loss of material to steel piping, piping components and piping elements exposed to condensation (internal) in the ESF system. The staff reviewed the applicants Periodic Surveillance and Preventive Maintenance Program. This evaluation is documented in SER Section 3.0.3.3.5, which the staff found acceptable. Preventive maintenance activities and periodic surveillances provide for periodic component inspections and testing to detect aging effects. Inspection intervals are established such that they provide timely detection of degradation. Inspection intervals are dependent on component material and environment and take into consideration industry and plant-specific operating experience and manufacturers recommendations. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-34 within the population that is subject to the Periodic Surveillance and Preventive Maintenance Program. This is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.2.2.1.15 Loss of Material Due to General, Pitting, Crevice Corrosion, Microbiologically-Influenced Corrosion and Fouling In the discussion column of LRA Table 3.2.1, Item 3.2.1-35, the applicant stated that the Containment Leak Rate Program will be used to manage loss of material due to general, pitting, crevice corrosion, MIC and fouling of steel containment isolation piping and components internal surfaces exposed to raw water in the ESF system. The staff reviewed the applicants Containment Leak Rate Program. This evaluation is documented in SER Section 3.0.3.2.8, which the staff found acceptable. During the audit and review, the staff confirmed that the Containment Leak Rate Program is supplemented by the Containment Inservice Inspection Program, which performs inspections to validate the Containment Leak Rate Program. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-35 within the population that is subject to the Containment Leak Rate Program. This is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3-218

3.2.2.1.16 Loss of Material Due to General, Pitting, Crevice, Galvanic, Microbiologically-Influenced Corrosion and Fouling In the discussion column of LRA Table 3.2.1, Item 3.2.1-36, the applicant stated that the Service Water Integrity Program manages loss of material for carbon steel components exposed to raw water and for other piping components of the SGTS while the Periodic Surveillance and Preventive Maintenance Program manages loss of material for carbon steel components exposed to raw water in the ESF system. The staff reviewed the applicants Service Water Integrity Program and Periodic Surveillance and Preventive Maintenance Program. These evaluations are documented in SER Sections 3.0.3.2.16 and 3.0.3.3.5, respectively. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.2.1, Item 3.2.1-36 within the population that is subject to the Service Water Integrity and Periodic Surveillance and Preventive Maintenance Programs. This is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.2.2.1.17 Loss of Material Due to Pitting, Crevice Corrosion and Microbiologically-Influenced Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-37, the applicant stated that the Periodic Surveillance and Preventive Maintenance Program will be used to manage loss of material due to pitting, crevice corrosion, MIC and fouling of stainless steel piping, piping components and piping elements exposed to raw water in the ESF system. The staff reviewed the applicants Periodic Surveillance and Preventive Maintenance Program. This evaluation is documented in SER Section 3.0.3.3.5. This is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.2.2.1.18 Loss of Preload Due to Thermal Effects, Gasket Creep and Self-Loosening In the discussion column of LRA Table 3.2.1, Item 3.2.1-24 the applicant stated that the loss of preload was not an AERM. During the audit and review, the staff asked the applicant to justify the position that was taken in not managing the aging effect for loss of preload, instead of using the AMP recommended in the GALL Report. In a letter dated July 6, 2006, the applicant committed (Commitment #34) to prepare and submit an AMP consistent with GALL AMP XI.M18, Bolting Integrity, for review and approval. In a letter dated October 17, 2006, the applicant revised its LRA. The applicant submitted its Bolting Integrity Program. The staffs evaluation of this program is documented in SER Section 3.0.3.2.19, which the staff found acceptable. In addition, by letter dated January 4, 2007, the applicant provided clarification that its Bolting Integrity Program addresses 3-219

all bolting. With this change, the applicants management of loss of preload due to thermal effects, gasket creep and self loosening of steel closure bolting, will be consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant, with the change in the application and Commitment #34 identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 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 the associated 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 AMRs in the GALL Report. 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 for the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.2.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended Summary of Technical Information in the Application. In LRA Section 3.2.2.2, the applicant 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 MIC
• quality assurance for aging management of nonsafety-related components Staff Evaluation. 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 audited and reviewed the applicants evaluation to determine whether it adequately addressed the issues further evaluated. In addition, the staff reviewed the applicants further evaluations against the criteria contained in SRP-LR Section 3.2.2.2. The staffs review of the applicants further evaluation follows.

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3.2.2.2.1 Cumulative Fatigue Damage LRA Section 3.2.2.2.1 states that fatigue is a TLAA, as required by 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the staffs review of the applicants evaluation of this TLAA. 3.2.2.2.2 Loss of Material Due to Cladding The staff reviewed LRA Section 3.2.2.2.2 against the criteria in SRP-LR Section 3.2.2.2.2. In LRA Section 3.2.2.2.2, the applicant stated that for the cracking due to underclad cracking, this aging effect is not applicable to VYNPS. This item covers underclad cracking of cladding on PWR steel pump casings. VYNPS is a BWR and does not have charging pumps or steel pump casings with stainless steel cladding. SRP-LR Section 3.2.2.2.2 states that loss of material due to cladding breach may occur in PWR steel pump casings with stainless steel cladding exposed to treated borated water. The GALL Report references IN 94-63, Boric Acid Corrosion of Charging Pump Casings Caused by Cladding Cracks, and recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed. The staff determined that the cracking due to underclad cracking is not applicable to VYNPS. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. 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 SRP-LR Section 3.2.2.2.3 criteria: (1) LRA Section 3.2.2.2.3 addresses loss of material of internal surfaces of stainless steel piping and components in ESF systems exposed to treated water due to pitting and crevice corrosion. SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosion may occur on internal surfaces of stainless steel containment isolation piping, piping components, and piping elements exposed to treated water. The existing AMP monitors and controls water chemistry to mitigate degradation. 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 select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the components intended functions will be maintained during the period of extended operation. 3-221

The LRA states that loss of material due to pitting and crevice corrosion for internal surfaces of stainless steel piping and components in ESF systems exposed to treated water is managed by the Water Chemistry Control-BWR Program. The effectiveness of the applicants Water Chemistry Control-BWR Program will be confirmed by VYNPS the One-Time Inspection Program, through an inspection of a representative sample of components including areas of stagnant flow. The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. The staff finds that this combination satisfies the criteria of SRP-LR Section 3.2.2.2.3 and therefore is acceptable. (2) LRA Section 3.2.2.2.3 addresses the loss of material due to pitting and crevice corrosion, this aging effect is not applicable to VYNPS. At VYNPS, there are no stainless steel ESF system components that are in contact with a soil environment. This item is therefore not applicable. SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosion may occur in stainless steel piping, piping components, and piping elements exposed to soil. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed. The staff determines that stainless steel components are not present in a soil environment, therefore, the loss of material due to pitting and crevice corrosion is not applicable at VYNPS. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. (3) LRA Section 3.2.2.2.3 addresses the loss of material of BWR stainless steel and aluminum piping and piping components exposed to treated water due to pitting and crevice corrosion. 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 existing AMP monitors and controls water chemistry for BWRs to mitigate degradation. 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 select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the components intended functions will be maintained during the period of extended operation. 3-222

The LRA states that loss of material from pitting and crevice corrosion for BWR stainless steel and aluminum piping and piping components exposed to treated water is managed by the Water Chemistry Control-BWR Program. The effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components including areas of stagnant flow. The applicants Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. The staff finds that this combination satisfies the criteria of SRP-LR Section 3.2.2.2.3 and therefore is acceptable. (4) LRA Section 3.2.2.2.3 addresses loss of material of copper alloy and stainless steel piping and components in ESF systems that are exposed to lubricating oil due to pitting and crevice corrosion. SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosion may occur in stainless steel and copper alloy piping, piping components, and piping elements exposed to lubricating oil. The existing program periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation to verify the effectiveness of lubricating oil programs. A one-time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The LRA states that loss of material from pitting and crevice corrosion could occur for copper alloy and stainless steel piping and components in ESF systems that are exposed to lubricating oil. Loss of material is managed by the Oil Analysis Program, which includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. Operating experience at VYNPS has confirmed the effectiveness of this program in maintaining contaminants within limits such that corrosion has not and will not affect the intended functions of these components. The applicants Oil Analysis Program maintains oil systems free of contaminants (primarily water and particulates) thereby preserving an environment that is not conducive to loss of material. The staff reviewed the applicant's plant-specific and industry operating experience and confirmed that the program is maintaining contaminants within limits such that corrosion has not affected the intended functions of these components. In a letter dated July 14, 2006, the applicant stated that the Oil Analysis Program will be supplemented by the One-Time Inspection Program, to verify its effectiveness. The staff finds that this combination satisfies the criteria of SRP-LR Section 3.2.2.2.3 and therefore is acceptable. 3-223

(5) LRA Section 3.2.2.2.3 addresses the loss of material due to pitting and crevice corrosion, this aging effect is not applicable to VYNPS. Loss of material from pitting and crevice corrosion could occur for partially encased stainless steel tanks exposed to raw water due to cracking of the perimeter seal from weathering. At VYNPS, there are no outdoor stainless steel tanks in the ESF systems. SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosion may occur in partially encased stainless steel tanks exposed to raw water due to cracking of the perimeter seal from weathering. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that this aging effect is adequately managed. The GALL Report recommends that a plant-specific AMP be evaluated because moisture and water can egress under the tank if the perimeter seal is degraded. The staff determines through discussions with the applicants technical personnel, that the loss of material due to pitting and crevice corrosion is therefore not applicable. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. (6) LRA Section 3.2.2.2.3 addresses loss of material of BWR stainless steel piping and piping components internally exposed to condensation due to pitting and crevice corrosion. SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosion may occur in stainless steel piping, piping components, piping elements, and tanks exposed to internal condensation. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed. The LRA states that loss of material from pitting and crevice corrosion for BWR stainless steel piping and piping components internally exposed to condensation is managed by the Periodic Surveillance and Preventive Maintenance Program. This program uses visual and other NDE techniques to manage loss of material for these components. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for loss of material from pitting and crevice corrosion which may occur for stainless steel piping, piping components, piping elements, and tanks exposed to internal condensation. It is therefore acceptable to the staff. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.2.2.2.3 criteria. For those line items that apply to LRA Section 3.2.2.2.3, 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 function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 3-224

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 SRP-LR Section 3.2.2.2.4 criteria: (1) LRA Section 3.2.2.2.4 addresses the reduction of heat transfer of copper alloy heat exchanger tubes exposed to lubricating oil in ESF systems due to fouling. SRP-LR Section 3.2.2.2.4 states that reduction of heat transfer due to fouling may occur in steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating oil. The existing AMP monitors and controls lube oil chemistry to mitigate reduction of heat transfer due to fouling. However, control of lube oil chemistry may not always be fully effective in precluding fouling; therefore, the effectiveness of lube oil chemistry control should be verified to ensure that fouling does not occur. The GALL Report recommends further evaluation of programs to verify the effectiveness of lube oil chemistry control. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the components intended functions will be maintained during the period of extended operation. The LRA states that reduction of heat transfer due to fouling for copper alloy heat exchanger tubes exposed to lubricating oil in ESF systems is managed by the Oil Analysis Program. There are no stainless steel or steel heat exchanger tubes exposed to lubricating oil in the ESF systems. This program includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to fouling. Operating experience has confirmed the effectiveness of this program in maintaining contaminants within limits such that fouling has not and will not affect the intended functions of these components. The applicants Oil Analysis Program maintains oil systems free of contaminants (primarily water and particulates) thereby preserving an environment that is not conducive to fouling. The staff reviewed the applicant's plant-specific and industry operating experience and confirmed that the program is maintaining contaminants within limits such that corrosion has not affected the intended functions of these components. In a letter dated July 14, 2006, the applicant stated that the Oil Analysis Program will be supplemented by the One-Time Inspection Program, to verify its effectiveness. The staff finds that this combination satisfies the criteria of SRP-LR Section 3.2.2.2.4 and is therefore acceptable. (2) LRA Section 3.2.2.2.4 addresses the reduction of heat transfer of stainless steel heat exchanger tubes exposed to treated water in ESF systems due to fouling. SRP-LR Section 3.2.2.2.4 states that reduction of heat transfer due to fouling may occur in stainless steel heat exchanger tubes exposed to treated water. The existing program controls water chemistry to manage reduction of heat transfer due to fouling. However, control of water chemistry may be inadequate; therefore, the GALL Report recommends that the effectiveness of water chemistry control programs should be verified to ensure that reduction of heat transfer due to fouling does not occur. A one-time inspection is an acceptable method to ensure that reduction of heat transfer does not occur and that component intended functions will be maintained during the period of extended operation. 3-225

The LRA states that reduction of heat transfer due to fouling for stainless steel heat exchanger tubes exposed to treated water in ESF systems is managed by the Water Chemistry Control-BWR Program. The effectiveness of the applicants Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including areas of stagnant flow. The applicants Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements. The staff finds that this combination satisfies the criteria of SRP-LR Section 3.2.2.2.4 and is therefore acceptable. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.2.2.2.4 criteria. For those line items that apply to LRA Section 3.2.2.2.4, 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). 3.2.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation The staff reviewed LRA Section 3.2.2.2.5 against the criteria in SRP-LR Section 3.2.2.2.5. LRA Section 3.2.2.2.5 addresses the hardening and loss of strength due to elastomer degradation, this aging effect is not applicable to VYNPS. At VYNPS, there are no elastomeric components in the ESF systems. 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 SGTS ductwork and filters exposed to air - indoor uncontrolled. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed. The staff determines through discussions with the applicants technical personnel that the hardening and loss of strength due to elastomer degradation is not applicable. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. 3.2.2.2.6 Loss of Material Due to Erosion The staff reviewed LRA Section 3.2.2.2.6 against the criteria in SRP-LR Section 3.2.2.2.6. LRA Section 3.2.2.2.6 addresses the loss of material due to erosion, this aging effect is not applicable to VYNPS. This discussion refers to stainless steel high pressure safety injection (HPSI) pump miniflow recirculation orifice exposed to treated borated water. VYNPS is a BWR and has no HPSI pump miniflow orifice and as such this item is not applicable. 3-226

SRP-LR Section 3.2.2.2.6 states that loss of material due to erosion may occur in the stainless steel HPSI pump miniflow recirculation orifice exposed to treated borated water. The GALL Report recommends that plant-specific AMPs be evaluated for erosion of the orifice due to extended use of the centrifugal HPSI pump for normal charging. The GALL Report references Licensee Event Report 50-275/94-023 for evidence of erosion. Further evaluation is recommended to ensure that the aging effect is adequately managed. The staff determines, through discussions with the applicants technical personnel, that the loss of material due to erosion is not applicable. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. 3.2.2.2.7 Loss of Material Due to General Corrosion and Fouling The staff reviewed LRA Section 3.2.2.2.7 against the criteria in SRP-LR Section 3.2.2.2.7. LRA Section 3.2.2.2.7 addresses the loss of material due to general corrosion and fouling, this aging effect is not applicable to VYNPS. This item refers to loss of material due to general corrosion and fouling occurring for steel drywell and suppression chamber spray system nozzle and flow orifice internal surfaces exposed to air-indoor uncontrolled (internal). At VYNPS, the spray nozzles are copper alloy and are not subject to loss of material due to general corrosion in an indoor air environment. There are also no orifices in ECCS systems exposed to an indoor air environment (internal). 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. This aging mechanism and effect will apply since the spray nozzles and flow orifices are occasionally wetted even though this system is mostly on standby. The wetting and drying of these components can accelerate corrosion and fouling. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed. The staff determined, through discussions with the applicants technical personnel, that the loss of material due to general corrosion and fouling in steel drywell and suppression chamber spray system nozzle and flow orifice internal surfaces exposed to air-indoor uncontrolled (internal) is not applicable. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. 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 SRP-LR Section 3.2.2.2.8 criteria: (1) LRA Section 3.2.2.2.8 addresses the loss of material of BWR steel piping and components in ESF systems exposed to treated water due to general, pitting, and crevice corrosion. 3-227

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 existing AMP monitors and controls water chemistry for BWRs to mitigate degradation. However, control of water chemistry does not preclude loss of material due to general, 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 select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the components intended functions will be maintained during the period of extended operation. The LRA states that loss of material due to general, pitting and crevice corrosion for BWR steel piping and components in ESF systems exposed to treated water is managed by the Water Chemistry Control-BWR Program. The effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including areas of stagnant flow. The applicants Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The One-Time Inspection Program is used to verify the effectiveness through inspection of a representative inspection including stagnant and low flow areas. The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements. The staff finds that this combination satisfies the criteria of SRP-LR Section 3.2.2.2.8 and is therefore acceptable. (2) LRA Section 3.2.2.2.8 addresses the loss of material of internal surfaces of primary containment penetration steel piping and components exposed to treated water due to general, pitting and crevice corrosion. SRP-LR Section 3.2.2.2.8 states that loss of material due to general, pitting, and crevice corrosion may occur on the internal surfaces of steel containment isolation piping, piping components, and piping elements exposed to treated water. The existing AMP monitors and controls water chemistry to mitigate degradation. However, control of water chemistry does not preclude loss of material due to general, 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 select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the components intended functions will be maintained during the period of extended operation. The LRA states that the loss of material due to general, pitting and crevice corrosion for internal surfaces of primary containment penetration steel piping and components exposed to treated water is managed by the Water Chemistry Control-BWR Program. The 3-228

effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components including areas of stagnant flow. The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements. The staff finds that this combination satisfies the criteria of SRP-LR Section 3.2.2.2.8 and is therefore acceptable. (3) LRA Section 3.2.2.2.8 addresses loss of material of steel piping and components in ESF systems exposed to lubricating oil due to general, pitting and crevice corrosion. SRP-LR Section 3.2.2.2.8 states that loss of material due to general, pitting, and crevice corrosion may occur in steel piping, piping components, and piping elements exposed to lubricating oil. The existing program periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation to verify the effectiveness of lubricating oil programs. A one-time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The LRA states that loss of material due to general, pitting and crevice corrosion for steel piping and components in ESF systems exposed to lubricating oil is managed by the Oil Analysis Program. This program includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. Operating experience has confirmed the effectiveness of this program in maintaining contaminants within limits such that corrosion has not and will not affect the intended functions of these components. The applicants Oil Analysis Program maintains oil systems free of contaminants (primarily water and particulates) thereby preserving an environment that is not conducive to fouling. The staff reviewed the applicants plant-specific and industry operating experience and confirmed that the program is maintaining contaminants within limits such that corrosion has not affected the intended functions of these components. In a letter dated July 14, 2006, the applicant stated that its Oil Analysis Program will be supplemented by the One-Time Inspection Program, to verify its effectiveness. The staff finds this combination satisfies the criteria of SRP-LR Section 3.2.2.2.8 and is therefore acceptable. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.2.2.2.8 criteria. For those line items that apply to LRA Section 3.2.2.2.8, 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 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). 3-229

3.2.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced Corrosion The staff reviewed LRA Section 3.2.2.2.9 against the criteria in SRP-LR Section 3.2.2.2.9. LRA Section 3.2.2.2.9 addresses loss of material of steel (with or without coating or wrapping) piping and piping components buried in soil in ESF systems due to general, pitting, crevice, and MIC. SRP-LR Section 3.2.2.2.9 states that loss of material due to general, pitting, crevice, and MIC may occur in steel (with or without coating or wrapping) piping, piping components, and piping elements buried in soil. Buried piping and tanks inspection programs rely on industry practice, frequency of pipe excavation, and operating experience to manage the aging effects of loss of material from general, pitting, and crevice corrosion, and MIC. The effectiveness of the buried piping and tanks inspection program should be verified by evaluation of an applicants inspection frequency and operating experience with buried components to ensure that loss of material does not occur. The LRA states that loss of material due to general, pitting, crevice, and MIC for steel (with or without coating or wrapping) piping and piping components buried in soil in ESF systems is managed by the Buried Piping Inspection Program. There are no buried tanks in the ESF systems. The applicants Buried Piping Inspection Program will include: (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried carbon steel components. Buried components will be inspected when excavated during maintenance. An inspection will be performed within 10 years of entering the period of extended operation, unless an opportunistic inspection occurred within this 10-year period. The staff confirmed that buried piping has already been inspected within the final 10-year period before the period of extended operation. Therefore, even if no other buried piping is examined before the period of extended operation, VYNPS has followed staff guidance regarding the examination of buried piping through the end of the current operating license. The proposed schedule for inspection (if there is no other opportunity) is consistent with the staffs guidance and therefore acceptable to the staff. Based on the program identified above, the staff concludes that it meets SRP-LR Section 3.2.2.2.9 criteria. For those line items that apply to LRA Section 3.2.2.2.9, 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). 3-230

3.2.2.2.10 Quality Assurance for Aging Management of Nonsafety-Related Components SER Section 3.0.4 documents the staffs evaluation of the applicants QA program, which the staff found acceptable. Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for which the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determines that the applicant adequately addressed the issues that were further evaluated. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.2.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Tables 3.2.2-1 through 3.2.2-7, the staff reviewed additional details of the 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 3.2.2-7, the applicant indicated, via notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided further information concerning how the aging effects will be managed. Specifically, note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line 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 line item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report. Staff Evaluation. For component type, material, and environment combinations that are not evaluated in the GALL Report, the staff reviewed the applicants evaluation to determine whether it had 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. The staffs evaluation is discussed in the following sections. 3.2.2.3.1 Residual Heat Removal System Summary of Aging Management Evaluation - LRA Table 3.2.2-1 The staff reviewed LRA Table 3.2.2-1, which summarizes the results of AMR evaluations for the RHRS component groups. In LRA Table 3.2.2-1, the applicant proposed to manage cracking of stainless steel heat exchanger tubes exposed to a raw water environment using the Service Water Integrity Program. 3-231

The staff reviewed the applicants Service Water Integrity Program and its evaluation is documented in SER Section 3.0.3.2.16. The applicant stated, in the LRA, that this program relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the SWS will be managed for the period of extended operation. The SWS includes the SW, RHRSW, and alternate cooling systems. The program includes surveillance and control techniques to manage aging effects in the SWS or SCs serviced by the SWS. The staff finds the cracking of stainless steel heat exchanger tubes exposed to raw water environments are effectively managed using the Service Water Integrity Program. On this basis, the staff finds that management of cracking in the RHRS is acceptable. In LRA Table 3.2.2-1, the applicant proposed to manage loss or material of carbon steel materials for component types of bolting exposed to air-indoor (external) environment using the System Walkdown Program. During the audit and review, the staff asked the applicant to clarify the basis for using its System Walkdown Program to manage aging of carbon steel bolting instead of the recommended GALL AMP XI.M18, Bolting Integrity. By a letter dated July 6, 2006, the applicant agreed to prepare and submit for review and approval an AMP consistent with GALL AMP XI.M18. By a letter dated October 17, 2006, the applicant revised its LRA to include a discussion of its Bolting Integrity Program in LRA Section B.1.31. The staffs evaluation of the applicants System Walkdown Program and Bolting Integrity Program is documented in SER Sections 3.0.3.1.9 and in 3.0.3.2.19, respectively. The staff finds that the applicants Bolting Integrity Program conformed to the GALL Report and encompass all safety-related bolting as delineated in NUREG-1339, which includes the criteria established in the 1995 Edition through the 1996 Addenda of ASME Code, Section XI and that the applicants System Walkdown Program is comprised of inspections of external surfaces of components subject to an AMR. On this basis, the staff finds that the applicants management of carbon steel bolting in the RHRS consistent with the GALL Report and therefore acceptable. 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). 3.2.2.3.2 Core Spray System Summary of Aging Management Evaluation - LRA Table 3.2.2-2 The staff reviewed LRA Table 3.2.2-2, which summarizes the results of AMR evaluations for the CSS component groups. In LRA Table 3.2.2-2, the applicant proposed to manage loss or material of carbon steel materials for component types of bolting exposed to air-indoor (external) environment using the System Walkdown Program. During the audit and review, the staff asked the applicant to clarify the basis for using the System Walkdown Program to manage aging of carbon steel bolting instead of the recommended GALL AMP XI.M18, Bolting Integrity. By a letter dated July 6, 2006, the applicant agreed to prepare and submit for review and approval an AMP consistent with GALL AMP XI.M18. By a letter dated 3-232

October 17, 2006, the applicant revised its LRA to include a discussion of the Bolting Integrity Program in LRA Section B.1.31. The applicants System Walkdown Program and Bolting Integrity Program are documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff finds that the applicants Bolting Integrity Program conformed to the GALL Report and is adequate. On this basis, the staff finds that the applicants management of carbon steel bolting, in the CSS, is consistent with the GALL Report and therefore acceptable. 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). 3.2.2.3.3 Automatic Depressurization System Summary of Aging Management Evaluation - LRA Table 3.2.2-3 The staff reviewed LRA Table 3.2.2-3, which summarizes the results of AMR evaluations for the automatic depressurization system component groups. In LRA Table 3.2.2-3, the applicant proposed to manage loss or material of carbon steel materials for component types of bolting exposed to air-indoor (external) environment using the System Walkdown Program. During the audit and review, the staff asked the applicant to clarify the basis for using the System Walkdown Program to manage aging of carbon steel bolting instead of the recommended GALL AMP XI.M18, Bolting Integrity. By letter dated July 14, 2006, the applicant agreed to prepare and submit for review and approval an AMP consistent with GALL AMP XI.M18. By a letter dated October 17, 2006, the applicant revised its LRA to include a discussion of the Bolting Integrity Program in LRA Section B.1.31. The staffs evaluation of the applicants System Walkdown Program and Bolting Integrity Program are documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff finds that the applicants Bolting Integrity Program conformed to the GALL Report and is adequate. On this basis, the staff finds that the applicants management of carbon steel bolting, in the automatic depressurization system, consistent with the GALL Report and therefore acceptable. 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). 3.2.2.3.4 High Pressure Coolant Injection System Summary of Aging Management Evaluation - LRA Table 3.2.2-4 The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for the HPCIS component groups. 3-233

In LRA Table 3.2.2-4, the applicant proposed to manage loss of material wear of copper alloy heat exchanger tubes exposed to lube oil and treated water environments using the Heat Exchanger Monitoring Program. The staff reviewed the applicants Heat Exchanger Monitoring Program and its evaluation is documented in SER Section 3.0.3.3.1. The Heat Exchanger Monitoring Program will be used to inspect heat exchanger tubes for degradation using eddy current inspections. As stated in the LRA, this AMP is credited with managing the aging effect of loss of material on the pressure boundary intended function for the components for which this AMP is credited. The staff finds the aging effect of loss of material due to wear of copper alloy heat exchanger tubes exposed to lube oil and treated water are effectively managed using Heat Exchanger Monitoring Program. On this basis, the staff finds that management of loss of material wear in the HPCIS is acceptable. In LRA Table 3.2.2-4, the applicant proposed to manage cracking of stainless steel orifice, tubing, and valve body exposed to lube oil environments using the Oil Analysis Program. The staff reviewed the Oil Analysis Program and its evaluation is documented in SER Section 3.0.3.2.13. LRA Section A.2.1.22, states that the Oil Analysis Program maintains oil systems free of contaminants (primarily water and particulates) thereby preserving an environment that is not conducive to loss of material, cracking, or fouling. Activities include sampling and analysis of lubricating oil for detrimental contaminants, water, and particulates. In a letter dated July 14, 2006, the applicant stated that the effectiveness of the Oil Analysis Program will be confirmed by the One-Time Inspection Program. On this basis the staff finds that the aging effect of cracking of stainless steel material exposed to a lube oil environment is effectively managed using the Oil Analysis Program and that management of cracking in the HPCIS is acceptable. In LRA Table 3.2.2-4, the applicant proposed to manage loss or material of carbon steel and stainless steel materials for component types of bolting exposed to an air-indoor (external) and air-outdoor (external) environment using the System Walkdown Program. During the audit and review, the staff asked the applicant to clarify the basis for using the System Walkdown Program to manage aging of carbon steel and stainless steel bolting instead of the recommended GALL AMP XI.M18, Bolting Integrity. By a letter dated July 14, 2006, the applicant agreed to prepare and submit for review and approval an AMP consistent with GALL AMP XI.M18l. By a letter dated October 17, 2006, the applicant revised its LRA to include a discussion of the Bolting Integrity Program in LRA Section B.1.31. The staffs evaluation of the applicants System Walkdown Program and Bolting Integrity Program in documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff finds that the applicants Bolting Integrity Program conformed to the recommendations of the GALL Report and encompass all safety-related bolting as delineated in NUREG-1339, which includes the criteria established in the 1995 Edition through the 1996 Addenda of ASME Code, Section XI and the applicants System Walkdown Program comprised of inspections of external surfaces of components subject to an AMR. On this basis, the staff finds that the applicants management of carbon steel and stainless steel bolting, in the HPCIS, consistent with the GALL Report and therefore acceptable. 3-234

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). 3.2.2.3.5 Reactor Core Isolation Cooling System Summary of Aging Management Evaluation - LRA Table 3.2.2-5 The staff reviewed LRA Table 3.2.2-5, which summarizes the results of AMR evaluations for the reactor core isolation cooling system (RCICS) component groups. In LRA Table 3.2.2-5, the applicant proposed to manage loss of material wear of copper alloy and aluminum heat exchanger tubes and steam heaters exposed to treated water and a lube oil environment using the Heat Exchanger Monitoring Program. The staff review the Heat Exchanger Monitoring Program and its evaluation is documented in SER Section 3.0.3.3.1. The Heat Exchanger Monitoring Program will inspect heat exchangers for degradation. Loss of material wear is the aging effect managed by this program. Representative tubes within the sample population of heat exchangers will be eddy current tested at a frequency determined by internal and external operating experience to ensure that effects of aging are identified prior to loss of intended function. The sample population of heat exchangers includes the HPCI GSC, HPCI lube oil cooler, RCIC lube oil cooler, CST steam reheat coil, drywell atmospheric cooling units (RRU-1, 2, 3 and 4), RRP seal water coolers, RRP motor upper and lower bearing oil coolers, and RRP motor air coolers. If degradation is found, then an evaluation will be performed to evaluate its effects on the heat exchanger's design functions including its ability to withstand a seismic event. The staff determines that the preventive actions program element satisfies the criteria defined in SRP-LR Appendix A.1.2.3.3. In the LRA, this AMP is credited with managing the aging effect of loss of material on the pressure boundary intended function for the components for which this AMP is credited. On this basis, the staff finds that management of loss of material wear in the RCICS is acceptable. In LRA Table 3.2.2-5, the applicant proposed to manage loss of material of carbon steel and stainless steel materials for component types of bolting exposed to an air-indoor (external) and air-outdoor (external) environment using the System Walkdown Program. During the audit and review, the staff asked the applicant to clarify the basis for using the System Walkdown Program to manage aging of carbon steel and stainless steel bolting instead of the recommended GALL AMP XI.M18, Bolting Integrity. By a letter dated July 6, 2006, the applicant agreed to prepare and submit for review and approval an AMP consistent with GALL AMP XI.M18. By a letter dated October 17, 2006, the applicant revised its LRA to include a discussion of the Bolting Integrity Program in LRA Section B.1.31. The staffs evaluation of the applicants System Walkdown Program and Bolting Integrity Program are documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff finds that the applicants Bolting Integrity Program conformed to the recommendations of the GALL Report and encompass all safety-related bolting as delineated in NUREG-1339, which includes the criteria established in the 3-235

1995 Edition through the 1996 Addenda of ASME Code, Section XI and the applicants System Walkdown Program comprised of inspections of external surfaces of components subject to an AMR. On this basis, the staff finds that the applicants management of carbon steel and stainless steel bolting, in the RCICS, consistent with the GALL Report and therefore acceptable. 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). 3.2.2.3.6 Standby Gas Treatment System Summary of Aging Management Evaluation - LRA Table 3.2.2-6 The staff reviewed LRA Table 3.2.2-6, which summarizes the results of AMR evaluations for the SGTS component groups. In LRA Table 3.2.2-6, the applicant proposed to manage loss of material of carbon steel materials for component types of bolting exposed to an air-indoor (external) environment using the System Walkdown Program. During the audit and review, the staff asked the applicant to clarify the basis for using the System Walkdown Program to manage aging of carbon steel bolting instead of the recommended GALL AMP XI.M18, Bolting Integrity. By a letter dated July 6, 2006, the applicant agreed to prepare and submit for review and approval an AMP consistent with GALL AMP XI.M18l. By a letter dated October 17, 2006, the applicant revised its LRA to include a discussion of the Bolting Integrity Program in LRA Section B.1.31. The staffs evaluation of the applicants System Walkdown Program and Bolting Integrity Program are documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff finds that the applicants Bolting Integrity Program conformed to the recommendations of the GALL Report and encompass all safety-related bolting as delineated in NUREG-1339, which includes the criteria established in the 1995 Edition through the 1996 Addenda of ASME Code, Section XI and the applicants System Walkdown Program comprised of inspections of external surfaces of components subject to an AMR. On this basis, the staff finds that the applicants management of carbon steel bolting, in the SGTS, consistent with the GALL Report and therefore acceptable. 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). 3.2.2.3.7 Primary Containment Penetrations Summary of Aging Management Evaluation - LRA Table 3.2.2-7 The staff reviewed LRA Table 3.2.2-7, which summarizes the results of AMR evaluations for the primary containment penetrations component groups. 3-236

In LRA Table 3.2.2-7, the applicant proposed to manage loss of material of carbon steel materials for component types of piping and valve body exposed to an untreated water environment using the Containment Leak Rate Program. The staffs evaluation of the applicants Containment Leak Rate Program and is documented in SER Section 3.0.3.2.8. The containment leak rate tests are required to assure that: (a) leakage through primary reactor containment and systems and components penetrating primary containment shall not exceed allowable values specified in technical specifications or associated bases and (b) periodic surveillance of reactor containment penetrations and isolation valves is performed so that proper maintenance and repairs are made during the service life of containment, and systems and components penetrating primary containment. As documented in the Audit and Review Report, the Containment Leak Rate Program is supplemented by the Containment Inservice Inspection Program, which performs inspections of containment including the penetrations. The staff finds that the aging effect of loss of material of carbon steel material exposed to an untreated water environment is effectively managed using the Containment Leak Rate Program. On this basis, the staff finds that management of loss of material in the primary containment penetrations is acceptable. In LRA Table 3.2.2-7, the applicant proposed to manage loss of material of carbon steel materials for component types of bolting exposed to an air-indoor (external) environment using the System Walkdown Program. During the audit and review, the staff asked the applicant to clarify the basis for using the System Walkdown Program to manage aging of carbon steel bolting instead of the recommended GALL AMP XI.M18, Bolting Integrity. By a letter dated July 6, 2006, the applicant agreed to prepare and submit for review and approval an AMP consistent with GALL AMP XI.M18. By a letter dated October 17, 2006, the applicant revised its LRA to include a discussion of the Bolting Integrity Program in LRA Section B.1.31.The staffs evaluation of the applicants System Walkdown Program and Bolting Integrity Program are documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff finds that the applicants management of carbon steel bolting, in the primary containment penetrations, consistent with the GALL Report and therefore acceptable. 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). 3.2.2.3.8 Aging Effects/Mechanisms Not Applicable at VYNPS - LRA Table 3.2.1 The staff reviewed LRA Table 3.2.1, which provides a summary of aging management evaluations for the ESF systems evaluated in the GALL Report. In LRA Table 3.2.1, Item 3.2.1-20, the applicant stated that loss of fracture toughness of CASS piping, piping components, and piping elements exposed to treated water (borated or unborated) greater than250EC (482EF) due to thermal aging embrittlement is not applicable at VYNPS. 3-237

The staff reviewed, in the LRA and supporting documents, the ESF systems for any CASS piping, piping components, and piping elements exposed to treated water (borated or unborated) greater than 250EC (482EF), that have loss of fracture toughness due to thermal aging embrittlement. The staff determines that the loss of fracture toughness of CASS piping, piping components, and piping elements exposed to treated water is not applicable at VYNPS. On the basis that there are no CASS piping, piping components, and piping elements exposed to treated water in the ESF systems at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for this component type. In LRA Table 3.2.1, Item 3.2.1-21, the applicant stated that cracking of high-strength steel closure bolting exposed to air with steam or water leakage due to cyclic loading and SCC is not applicable at VYNPS. The staff reviewed, in the LRA and supporting documents, the ESF systems for any high-strength steel closure bolting exposed to air with steam or water leakage due to cyclic loading. The staff determines that cracking of high-strength steel closure bolting exposed to air with steam or water leakage due to cyclic loading and SCC is not applicable at VYNPS. On the basis that there are no high-strength steel closure bolting in the ESF systems at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for this component type. In LRA Table 3.2.1, Item 3.2.1-22, the applicant stated that loss of material of steel closure bolting exposed to air with steam or water leakage due to general corrosion is not applicable at VYNPS. However, by letter dated January 4, 2007, the applicant providing additional clarification stating that its Bolting Integrity Program applies to all bolting exposed to air. The staff reviewed the applicants January 4, 2007 letter and determined that loss of material of steel closure bolting is managed by Bolting Integrity Program and consistent with the GALL Report recommendation. On this basis, the staff finds this acceptable. In LRA Table 3.2.1, Item 3.2.1-26, the applicant stated that loss of material of steel piping, piping components, and piping elements exposed to closed cycle cooling water due to general, pitting, and crevice corrosion is not applicable at VYNPS. Steel containment isolation components exposed to closed cycle cooling water are all part of other safety systems that are evaluated separately. The staff reviewed, in the LRA and supporting documents, the ESF systems for loss of material of steel piping, piping components, and piping elements exposed to closed cycle cooling water due to general, pitting, and crevice corrosion. The staff finds that the loss of material of steel piping, piping components, and piping elements exposed to closed cycle cooling water due to general, pitting, and crevice corrosion is not applicable to VYNPS. On the basis that there are no steel piping, piping components, and piping elements in the ESF systems at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for this component type. In LRA Table 3.2.1, Item 3.2.1-29, the applicant stated that the loss of material of copper alloy piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling water due to pitting, crevice, and galvanic corrosion is not applicable at VYNPS. There are no copper alloy components exposed to closed cycle cooling water in the ESF system. 3-238

The staff reviewed, in the LRA and supporting documents, the ESF systems for loss of material of copper alloy piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling water due to pitting, crevice, and galvanic corrosion. The staff that the loss of material of copper alloy piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling water due to pitting, crevice, and galvanic corrosion is not applicable to VYNPS. On the basis that there are no copper alloy piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling water in the ESF systems at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for this component type. In LRA Table 3.2.1, Item 3.2.1-33, the applicant stated that the loss of material of steel encapsulation components exposed to air-indoor uncontrolled (internal) due to general, pitting, and crevice corrosion is not applicable at VYNPS. There are no steel encapsulation components in the ESF system. The staff reviewed, in the LRA and supporting documents, the ESF systems for loss of material of steel encapsulation components exposed to air-indoor uncontrolled (internal) due to general, pitting, and crevice corrosion. The staff finds that the loss of material of steel encapsulation components exposed to air-indoor uncontrolled (internal) due to general, pitting, and crevice corrosion is not applicable to VYNPS. On the basis that there are no steel encapsulation components in the ESF systems at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS. In LRA Table 3.2.1, Item 3.2.1-38, the applicant stated that the loss of material of stainless steel containment isolation piping and components internal surfaces exposed to raw water due to pitting, crevice, and MIC, and fouling is not applicable at VYNPS. There are no stainless steel containment isolation piping and components internal surfaces exposed to raw water in the ESF system. The staff reviewed, in the LRA and supporting documents, the ESF systems for loss of material of stainless steel containment isolation piping and components internal surfaces exposed to raw water due to pitting, crevice, and MIC, and fouling. The staff finds that the loss of material of stainless steel containment isolation piping and components internal surfaces exposed to raw water due to pitting, crevice, and MIC, and fouling is not applicable to VYNPS. On the basis that there are no stainless steel containment isolation piping and components internal surfaces exposed to raw water in the ESF systems at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for this component type. In LRA Table 3.2.1, Item 3.2.1-41, the applicant stated that loss of material of copper alloy greater than 15 percent zinc piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling water due to selective leaching is not applicable at VYNPS. The staff reviewed, in the LRA and supporting documents, the ESF systems for loss of material of copper alloy greater than15 percent Zinc piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling water due to selective leaching. The staff finds that the loss of material of copper alloy greater than 15 percent zinc piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling 3-239

water due to selective leaching is not applicable to VYNPS. On the basis that there are no copper alloy greater than 15 percent zinc piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling water in the ESF systems at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for this component type. In LRA Table 3.2.1, Item 3.2.1-43, the applicant stated that loss of material of gray cast iron piping, piping components, and piping elements exposed to soil due to selective leaching is not applicable at VYNPS. There are no gray cast iron piping, piping components, and piping elements exposed to soil in the ESF system. The staff reviewed, in the LRA and supporting documents, the ESF systems for loss of material of gray cast iron piping, piping components, and piping elements exposed to soil due to selective leaching. The staff finds that the loss of material of gray cast iron piping, piping components, and piping elements exposed to soil due to selective leaching is not applicable to VYNPS. On the basis that there are no gray cast iron piping, piping components, and piping elements exposed to soil in the ESF systems at VYNPS, the staff finds that this aging effect is not applicable to VYNPS for this component type. 3.2.2.3.9 Engineered Safety Features Systems AMR Line Items With No Aging Effects (LRA Tables 3.2.2-1 through 3.2.2-7) In LRA Tables 3.2.2-1 through 3.2.2-7, the applicant identified AMR line items where no aging effects were identified as a result of its AMR. Specifically, instances in which the applicant states that no aging effects were identified occurred with components fabricated from aluminum, copper alloy, fiberglass, and stainless steel material exposed to air indoor (internal/external), air outdoor (external), and sand/concrete environment. The GALL Report states that steel, copper and stainless steel in an environment of plant air indoor (external), are not subject to any aging mechanisms. The staff reviewed LRA Tables 3.2.2-1 through 3.2.2-7 and concludes that the applicants analysis of the material and environment combinations will allow components fabricated of these materials, in these environments, that are within the scope of license renewal, to perform their intended function during the period of extended operation. No aging effects are considered to be applicable to components fabricated from aluminum, copper alloy, fiberglass, and stainless steel material exposed to air indoor (internal/external), air outdoor (external) and sand/concrete environment. Copper alloy, aluminum, and stainless steel components are highly resistant to corrosion in dry atmospheres in the absence of corrosive species, as cited in the American Society for Metals International Metals Handbook, Ninth Edition, Volume 13, the staff has accepted the position that stainless steel in an indoor (internal/external) environment and copper alloy and aluminum in an indoor (internal/external) and sand/concrete environments exhibit no aging effects. The staff concludes that the component or structure will therefore remain capable of performing its intended functions consistent with the CLB for the period of extended operation. 3-240

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results involving material, environment, AERM, and AMP combinations that are 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). 3.2.3 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 staffs review of the applicants AMR results for the auxiliary systems components and component groups of:

• standby liquid control system
• service water systems
• reactor building closed cooling water system
• emergency diesel generator system
• fuel pool cooling systems
• fuel oil system
• instrument air system
• fire protection-water system
• fire protection-carbon dioxide system
• heating, ventilation, and air conditioning systems
• primary containment atmosphere control and containment atmosphere dilution systems
• John Deere diesel
• miscellaneous systems in-scope for 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 for the Auxiliary Systems Evaluated in Chapter VII of NUREG-1801, is a summary comparison of the applicants AMRs with those evaluated in the GALL Report for the auxiliary systems components and component groups.

The applicants AMRs evaluated and incorporated applicable plant-specific and industry operating experience in the determination of AERMs. The plant-specific evaluation included reviews of condition reports and discussions with appropriate site personnel to identify AERMs. The applicants review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report. 3-241

3.3.2 Staff Evaluation The staff reviewed LRA Section 3.3 to determine whether the applicant provided sufficient information to demonstrate that the effects of aging for the auxiliary systems components that are within the scope of license renewal and subject to an AMR will be adequately managed so that the intended 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 performed an onsite audit of AMRs to ensure the applicants 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. The staffs evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staffs audit evaluation are documented in SER Section 3.3.2.1. In the onsite audit, the staff also selected AMRs that were consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicants further evaluations were consistent with the SRP-LR Section 3.3.2.2 acceptance criteria. The staffs audit evaluations are documented in SER Section 3.3.2.2. In the onsite audit, the staff also conducted a technical review of the remaining AMRs that were not consistent with, or not addressed in, the GALL Report. The technical review evaluated whether all plausible aging effects have been identified and whether the aging effects listed were appropriate for the material-environment combinations specified. The staffs evaluations are documented in SER Section 3.3.2.3. Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or monitoring aging for the auxiliary systems components. For SSCs which the applicant claimed were not applicable or required no aging management, the staff reviewed the AMR line items and the plants operating experience to verify the applicants claims. Table 3.3-1 summarizes the staffs evaluation of components, aging effects/mechanisms, and AMPs, listed in LRA Section 3.3 and addressed in the GALL Report. 3-242

Table 3.3-1 Staff Evaluation for Auxiliary System Components in the GALL Report Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Steel cranes - Cumulative fatigue TLAA to be None This line item was structural girders damage evaluated for not used. Steel exposed to air - structural girders of cranes are indoor cranes. See the evaluated as uncontrolled Standard Review structural (external) Plan, Section 4.7 for components in SER (3.3.1-1) generic guidance for Section 3.5. meeting the requirements of 10 CFR 54.21(c)(1). Steel and Cumulative fatigue TLAA, evaluated in None Fatigue is a TLAA. stainless steel damage accordance with (See SER piping, piping 10 CFR 54.21(c) Section 3.3.2.2.1) components, piping elements, and heat exchanger components exposed to air - indoor uncontrolled, treated borated water or treated water (3.3.1-2) Stainless steel Reduction of heat Water Chemistry Water Chemistry Consistent with heat exchanger transfer due to and One-Time Control-BWR GALL Report, which tubes exposed to fouling Inspection Program (B.1.30.2); recommends further treated water One-Time Inspection evaluation (See SER (3.3.1-3) Program (B.1.21) Sections 3.3.2.1.1 and 3.3.2.2.2) Stainless steel Cracking due to Water Chemistry Water Chemistry Not applicable. piping, piping SCC and One-Time Control-BWR (See SER components, and Inspection Program (B.1.30.2); Section 3.3.2.2.3) piping elements One-Time Inspection exposed to Program (B.1.21) sodium pentaborate solution > 60EC (> 140EF) (3.3.1-4) 3-243

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Stainless steel Cracking due to Plant-specific Water Chemistry Consistent with and stainless clad SCC Control-BWR GALL Report, which steel heat Program (B.1.30.2); recommends further exchanger One-Time Inspection evaluation (See SER components Program (B.1.21) Sections 3.3.2.1.2 exposed to treated and 3.3.2.2.3) water > 60EC (> 140EF) (3.3.1-5) Stainless steel Cracking due to Plant-specific Periodic Surveillance Consistent with the diesel engine SCC and Preventive GALL Report, which exhaust piping, Maintenance Program recommends further piping (B.1.22) evaluation. components, and (See SER piping elements Sections 3.3.2.1.3 and exposed to diesel 3.3.2.2.3) exhaust (3.3.1-6) Stainless steel Cracking due to Water Chemistry None Not applicable to non-regenerative SCC and cyclic and a plant-specific BWRs heat exchanger loading verification program. (See SER components An acceptable Section 3.3.2.2.4) exposed to treated verification program borated water is to include > 60EC (> 140EF) temperature and (3.3.1-7) radioactivity monitoring of the shell side water, and eddy current testing of tubes. Stainless steel Cracking due to Water Chemistry None Not applicable to regenerative heat SCC and cyclic and a plant-specific BWRs exchanger loading verification program. (See SER components The AMP is to be Section 3.3.2.2.4) exposed to treated augmented by borated water verifying the > 60EC (> 140EF) absence of cracking (3.3.1-8) due to SCC and cyclic loading. A plant-specific AMP is to be evaluated. 3-244

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Stainless steel Cracking due to Water Chemistry None Not applicable to high-pressure SCC and cyclic and a plant-specific BWRs pump casing in loading verification program. (See SER PWR chemical The AMP is to be Section 3.3.2.2.4) and volume augmented by control system verifying the (3.3.1-9) absence of cracking due to SCC and cyclic loading. A plant-specific AMP is to be evaluated. High-strength Cracking due to Bolting Integrity None Not applicable. steel closure SCC, cyclic loading The AMP is to be (High-strength steel bolting exposed to augmented by bolting is not used in air with steam or appropriate the auxiliary water leakage. inspection to detect systems.) (3.3.1-10) cracking if the bolts are not otherwise replaced during maintenance. Elastomer seals Hardening and loss Plant-specific Periodic Surveillance Consistent with and components of strength due to and Preventive GALL Report, which exposed to elastomer Maintenance recommends further air-indoor degradation Program (B.1.22) evaluation (See SER uncontrolled Sections 3.3.2.1.4 (internal/external) and 3.3.2.2.5) (3.3.1-11) Elastomer lining Hardening and loss A plant-specific None Not applicable (See exposed to treated of strength due to AMP that SER water or treated elastomer determines and Section 3.3.2.2.5) borated water degradation assesses the (3.3.1-12) qualified life of the linings in the environment is to be evaluated. Boral, boron steel Reduction of Plant-specific Water Chemistry Consistent with spent fuel storage neutron-absorbing Control-BWR Program GALL Report, which racks capacity and loss of (B.1.30.2); One-Time recommends further neutron-absorbing material due to Inspection Program evaluation (See SER sheets exposed to general corrosion (B.1.21) Sections 3.3.2.1.5 treated water or and 3.3.2.2.6) treated borated water (3.3.1-13) 3-245

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Steel piping, Loss of material due Lubricating Oil Oil Analysis Program Consistent with piping component, to general, pitting, Analysis and (B.1.20); One-Time GALL Report, which and piping and crevice One-Time Inspection Program recommends further elements exposed corrosion Inspection (B.1.21) evaluation (See SER to lubricating oil Sections 3.3.2.1.6 (3.3.1-14) and 3.3.2.2.7) Steel reactor Loss of material due Lubricating Oil None Not applicable (See coolant pump oil to general, pitting, Analysis and SER collection system and crevice One-Time Section 3.3.2.2.7) piping, tubing, and corrosion Inspection valve bodies exposed to lubricating oil (3.3.1-15) Steel reactor Loss of material due Lubricating Oil None Not applicable (See coolant pump oil to general, pitting, Analysis and SER collection system and crevice One-Time Section 3.3.2.2.7) tank exposed to corrosion Inspection to lubricating oil evaluate the (3.3.1-16) thickness of the lower portion of the tank Steel piping, Loss of material due Water Chemistry Water Chemistry Consistent with piping to general, pitting, and One-Time Control-BWR GALL Report, which components, and and crevice Inspection Program (B.1.30.2); recommends further piping elements corrosion One-Time Inspection evaluation (See SER exposed to treated Program (B.1.21) Sections 3.3.2.1.7 water and 3.3.2.2.7) (3.3.1-17) Stainless steel Loss of Plant-specific Periodic Surveillance Consistent with the and steel diesel material/general and Preventive GALL Report, which engine exhaust (steel only), pitting Maintenance Program recommends further piping, piping and crevice (B.1.22); Fire evaluation. components, and corrosion Protection Program (See SER piping elements (B.1.12.1) Sections 3.3.2.1.8 and exposed to diesel 3.3.2.2.7) exhaust (3.3.1-18) Steel (with or Loss of material due Buried Piping and Buried Piping Consistent with without coating or to general, pitting, Tanks Surveillance Inspection Program GALL Report, which wrapping) piping, crevice, and MIC or Buried Piping and (B.1.1) recommends further piping Tanks Inspection evaluation (See SER components, and Section 3.3.2.2.8) piping elements exposed to soil (3.3.1-19) 3-246

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Steel piping, Loss of material due Fuel Oil Chemistry Diesel Fuel Monitoring Consistent with the piping to general, pitting, and One-Time Program (B.1.9); GALL Report, which components, crevice, and MIC, Inspection One-Time Inspection recommends further piping elements, and fouling Program (B.1.21) evaluation. and tanks (See SER exposed to fuel oil Sections 3.3.2.1.9 and (3.3.1-20) 3.3.2.2.9) Steel heat Loss of material due Lubricating Oil Oil Analysis Program Consistent with the exchanger to general, pitting, Analysis and (B.1.20); GALL Report, which components crevice, and MIC, One-Time One-Time Inspection recommends further exposed to and fouling Inspection Program (B.1.21) evaluation. lubricating oil (See SER (3.3.1-21) Sections 3.3.2.1.10 and 3.3.2.2.9) Steel with Loss of material due Water Chemistry None Not applicable (See elastomer lining or to pitting and crevice and One-Time SER stainless steel corrosion (only for Inspection Section 3.3.2.2.10) cladding piping, steel after piping lining/cladding components, and degradation) piping elements exposed to treated water and treated borated water (3.3.1-22) Stainless steel Loss of material due Water Chemistry Water Chemistry Consistent with the and steel with to pitting and crevice and One-Time Control-BWR Program GALL Report, which stainless steel corrosion Inspection (B.1.30.2); One-Time recommends further cladding heat Inspection Program evaluation. exchanger (B.1.21) (See SER components Sections 3.3.2.1.11 exposed to treated and 3.3.2.2.10) water (3.3.1-23) Stainless steel Loss of material due Water Chemistry Water Chemistry Consistent with the and aluminum to pitting and crevice and One-Time Control-BWR Program GALL Report, which piping, piping corrosion Inspection (B.1.30.2); One-Time recommends further components, and Inspection Program evaluation. piping elements (B.1.21) (See SER exposed to treated Sections 3.3.2.1.12 water and 3.3.2.2.10) (3.3.1-24) 3-247

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Copper alloy Loss of material due A plant-specific System Walkdown Consistent with the HVAC piping, to pitting and crevice AMP is to be Program (B.1.28); GALL Report, which piping corrosion evaluated. Periodic Surveillance recommends further components, and Preventive evaluation. piping elements Maintenance Program (See SER exposed to (B.1.22); Service Sections 3.3.2.1.13 condensation Water Integrity and 3.3.2.2.10) (external) Program (B.1.26); (3.3.1-25) Heat Exchanger Monitoring Program (B.1.14) Copper alloy Loss of material due Lubricating Oil Oil Analysis Program Consistent with the piping, piping to pitting and crevice Analysis and (B.1.20); One-Time GALL Report, which components, and corrosion One-Time Inspection Program recommends further piping elements Inspection (B.1.21) evaluation. exposed to (See SER lubricating oil Sections 3.3.2.1.14 (3.3.1-26) and 3.3.2.2.10) Stainless steel Loss of material due A plant-specific System Walkdown Consistent with the HVAC ducting and to pitting and crevice AMP is to be Program (B.1.28); GALL Report, which aluminum HVAC corrosion evaluated. Periodic Surveillance recommends further piping, piping and Preventive evaluation. components and Maintenance Program (See SER piping elements (B.1.22); Service Sections 3.3.2.1.15 exposed to Water Integrity and 3.3.2.2.10) condensation Program (B.1.26) (3.3.1-27) Copper alloy fire Loss of material due A plant-specific Periodic Surveillance Consistent with the protection piping, to pitting and crevice AMP is to be and Preventive GALL Report, which piping corrosion evaluated. Maintenance Program recommends further components, and (B.1.22); Instrument evaluation. piping elements Air Quality Program (See SER exposed to (B.1.16) Sections 3.3.2.1.16 condensation and 3.3.2.2.10) (internal) (3.3.1-28) Stainless steel Loss of material due A plant-specific Buried Piping Consistent with the piping, piping to pitting and crevice AMP is to be Inspection Program GALL Report, which components, and corrosion evaluated. (B.1.1) recommends further piping elements evaluation. exposed to soil (See SER (3.3.1-29) Sections 3.3.2.1.17) 3-248

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Stainless steel Loss of material due Water Chemistry Water Chemistry Consistent with the piping, piping to pitting and crevice and One-Time Control-BWR Program GALL Report, which components, and corrosion Inspection (B.1.30.2); One-Time recommends further piping elements Inspection Program evaluation. exposed to (B.1.21) (See SER sodium Sections 3.3.2.1.18 pentaborate and 3.3.2.2.10) solution (3.3.1-30) Copper alloy Loss of material due Water Chemistry Water Chemistry Consistent with the piping, piping to pitting, crevice, and One-Time Control-BWR Program GALL Report, which components, and and galvanic Inspection (B.1.30.2); One-Time recommends further piping elements corrosion Inspection Program evaluation. exposed to treated (B.1.21) (See SER water Sections 3.3.2.1.19 (3.3.1-31) and 3.3.2.2.11) Stainless steel, Loss of material due Fuel Oil Chemistry Diesel Fuel Monitoring Consistent with the aluminum and to pitting, crevice, and One-Time Program (B.1.9); GALL Report, which copper alloy and MIC Inspection One-Time Inspection recommends further piping, piping Program (B.1.21) evaluation. components, and (See SER piping elements Sections 3.3.2.1.20 exposed to fuel oil and 3.3.2.2.12) (3.3.1-32) Stainless steel Loss of material due Lubricating Oil Oil Analysis Program Consistent with the piping, piping to pitting, crevice, Analysis and (B.1.20); One-Time GALL Report, which components, and and MIC One-Time Inspection Program recommends further piping elements Inspection (B.1.21) evaluation. exposed to (See SER lubricating oil Sections 3.3.2.1.21 (3.3.1-33) and 3.3.2.2.12) Elastomer seals Loss of material due Plant-specific None Not applicable. and components to Wear (See SER exposed to air - Section 3.3.2.2.13) indoor uncontrolled (internal or external) (3.3.1-34) Steel with Loss of material due A plant-specific None Not applicable to stainless steel to cladding breach AMP is to be BWRs cladding pump evaluated. casing exposed to Reference NRC treated borated IN 94-63, Boric water Acid Corrosion of (3.3.1-35) Charging Pump Casings Caused by Cladding Cracks. 3-249

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Boraflex spent fuel Reduction of Boraflex Monitoring None Not applicable. storage racks neutron-absorbing (Boraflex is not used neutron-absorbing capacity due to in the VYNPS spent sheets exposed to boraflex degradation fuel storage racks.) treated water (3.3.1-36) Stainless steel Cracking due to BWR Reactor Water Water Chemistry Consistent with the piping, piping SCC, IGSCC Cleanup System Control-BWR Program GALL Report. components, and (B.1.30.2); One-Time (See SER piping elements Inspection Program Section 3.3.2.1.22) exposed to treated (B.1.21) water > 60EC (> 140EF) (3.3.1-37) Stainless steel Cracking due to BWR Stress Water Chemistry Consistent with the piping, piping SCC Corrosion Cracking Control-BWR Program GALL Report. components, and and Water (B.1.30.2); One-Time (See SER piping elements Chemistry Inspection Program Section 3.3.2.1.23) exposed to treated (B.1.21) water > 60EC (> 140EF) (3.3.1-38) Stainless steel Cracking due to Water Chemistry None Not applicable. BWR spent fuel SCC There are no storage racks stainless steel spent exposed to treated fuel storage water > 60EC components with (> 140EF) intended functions (3.3.1-39) exposed to treated water >60EC (> 140EF).) Steel tanks in Loss of material due Aboveground Steel System Walkdown Consistent with the diesel fuel oil to general, pitting, Tanks Program (B.1.28) GALL Report. system exposed and crevice (See SER to air-outdoor corrosion Section 3.3.2.1.24) (external) (3.3.1-40) High-strength Cracking due to Bolting Integrity None Not applicable. steel closure cyclic loading, SCC (High-strength steel bolting exposed to closure bolting is not air with steam or used in the auxiliary water leakage systems.) (3.3.1-41) 3-250

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Steel closure Loss of material due Bolting Integrity None This line item was not bolting exposed to to general corrosion used. Loss of material air with steam or of steel closure bolting water leakage was addressed by (3.3.1-42) other line items including 3.3.1-43, 3.3.1-55 and 3.3.1-58. Steel bolting and Loss of material due Bolting Integrity Bolting Integrity Consistent with the closure bolting to general, pitting, Program (B.1.31) GALL Report. exposed to and crevice (See SER air-indoor corrosion Section 3.3.2.1.25) uncontrolled (external) or air-outdoor (External) (3.3.1-43) Steel compressed Loss of material due Bolting Integrity Bolting Integrity Consistent with the air system closure to general, pitting, Program (B.1.31) GALL Report. bolting exposed to and crevice (See SER condensation corrosion Section 3.3.2.1.25) (3.3.1-44) Steel closure Loss of preload due Bolting Integrity Bolting Integrity Consistent with the bolting exposed to to thermal effects, Program (B.1.31) GALL Report. air-indoor gasket creep, and (See uncontrolled self-loosening Section 3.3.2.1.25) (external) (3.3.1-45) Stainless steel Cracking due to Closed-Cycle Water Chemistry Consistent with the and stainless clad SCC Cooling Water Control-Closed GALL Report. steel piping, piping System Cooling Water (See SER components, Program (B.1.30.3); Section 3.3.2.1.26) piping elements, One-Time Inspection and heat Program (B.1.21) exchanger components exposed to closed cycle cooling water > 60EC (> 140EF) (3.3.1-46) 3-251

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Steel piping, Loss of material due Closed-Cycle Water Chemistry Consistent with the piping to general, pitting, Cooling Water Control-Closed GALL Report. components, and crevice System Cooling Water (See SER piping elements, corrosion Program (B.1.30.3); Section 3.3.2.1.27) tanks, and heat Water Chemistry exchanger Control-Auxiliary components Systems Program exposed to closed (B.1.30.1); One-Time cycle cooling Inspection Program water (B.1.21) (3.3.1-47) Steel piping, Loss of material due Closed-Cycle Water Chemistry Consistent with the piping to general, pitting, Cooling Water Control-Closed GALL Report. components, crevice, and System Cooling Water (See SER piping elements, galvanic corrosion Program (B.1.30.3); Section 3.3.2.1.28) tanks, and heat One-Time Inspection exchanger Program (B.1.21) components exposed to closed cycle cooling water (3.3.1-48) Stainless steel; Loss of material due Closed-Cycle Water Chemistry Consistent with the steel with to MIC Cooling Water Control-Closed GALL Report. stainless steel System Cooling Water (See SER cladding heat Program (B.1.30.3); Section 3.3.2.1.29) exchanger One-Time Inspection components Program (B.1.21) exposed to closed cycle cooling water (3.3.1-49) Stainless steel Loss of material due Closed-Cycle Water Chemistry Consistent with the piping, piping to pitting and crevice Cooling Water Control-Closed GALL Report. components, and corrosion System Cooling Water (See SER piping elements Program (B.1.30.3); Section 3.3.2.1.30) exposed to closed Water Chemistry cycle cooling Control-Auxiliary water Systems Program (3.3.1-50) (B.1.30.1); One-Time Inspection Program (B.1.21) 3-252

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Copper alloy Loss of material due Closed-Cycle Water Chemistry Consistent with the piping, piping to pitting, crevice, Cooling Water Control-Closed GALL Report. components, and galvanic System Cooling Water (See SER piping elements, corrosion Program (B.1.30.3); Section 3.3.2.1.31) and heat Water Chemistry exchanger Control-Auxiliary components Systems Program exposed to closed (B.1.30.1); One-Time cycle cooling Inspection Program water (B.1.21) (3.3.1-51) Steel, stainless Reduction of heat Closed-Cycle Water Chemistry Consistent with the steel, and copper transfer due to Cooling Water Control-Closed GALL Report. alloy heat fouling System Cooling Water (See SER exchanger tubes Program (B.1.30.3); Section 3.3.2.1.32) exposed to closed One-Time Inspection cycle cooling Program (B.1.21) water (3.3.1-52) Steel compressed Loss of material due Compressed Air Instrument Air Quality Consistent with the air system piping, to general and Monitoring Program (B.1.16) GALL Report. piping pitting corrosion (See SER components, and Section 3.3.2.1.33) piping elements exposed to condensation (internal) (3.3.1-53) Stainless steel Loss of material due Compressed Air Instrument Air Quality Consistent with the compressed air to pitting and crevice Monitoring Program (B.1.16) GALL Report. system piping, corrosion (See SER piping Section 3.3.2.1.34) components, and piping elements exposed to internal condensation (3.3.1-54) Steel ducting Loss of material due External Surfaces System Walkdown Consistent with the closure bolting to general corrosion Monitoring Program (B.1.28) GALL Report. exposed to air - (See SER indoor Section 3.3.2.1) uncontrolled (external) (3.3.1-55) 3-253

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Steel HVAC Loss of material due External Surfaces System Walkdown Consistent with the ducting and to general corrosion Monitoring Program (B.1.28) GALL Report. components (See SER external surfaces Section 3.3.2.1) exposed to air - indoor uncontrolled (external) (3.3.1-56) Steel piping and Loss of material due External Surfaces System Walkdown Consistent with the components to general corrosion Monitoring Program (B.1.28) GALL Report. external surfaces (See SER exposed to air - Section 3.3.2.1) indoor uncontrolled (External) (3.3.1-57) Steel external Loss of material due External Surfaces System Walkdown Consistent with the surfaces exposed to general corrosion Monitoring Program (B.1.28) GALL Report. to air-indoor (See SER uncontrolled Section 3.3.2.1) (external), air-outdoor (external), and condensation (external) (3.3.1-58) Steel heat Loss of material due External Surfaces System Walkdown Consistent with the exchanger to general, pitting, Monitoring Program (B.1.28) GALL Report. components and crevice (See SER exposed to corrosion Section 3.3.2.1) air-indoor uncontrolled (external) or air-outdoor (external) (3.3.1-59) Steel piping, Loss of material due External Surfaces System Walkdown Consistent with the piping to general, pitting, Monitoring Program (B.1.28) GALL Report. components, and and crevice (See SER piping elements corrosion Section 3.3.2.1) exposed to air-outdoor (external) (3.3.1-60) 3-254

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Elastomer fire Increased hardness, Fire Protection Fire Protection Consistent with the barrier penetration shrinkage and loss Program (B.1.12.1) GALL Report. seals exposed to of strength due to (See SER air-outdoor or weathering Section 3.3.2.1.35) air-indoor uncontrolled (3.3.1-61) Aluminum piping, Loss of material due Fire Protection None Not applicable. piping to pitting and crevice (There are no components, and corrosion aluminum piping elements components with exposed to raw intended functions water exposed to raw water (3.3.1-62) in the auxiliary systems.) Steel fire rated Loss of material due Fire Protection Fire Protection Consistent with the doors exposed to to Wear Program (B.1.12.1) GALL Report. air-outdoor or (See SER air-indoor Section 3.3.2.1.36) uncontrolled (3.3.1-63) Steel piping, Loss of material due Fire Protection and None This line item was piping to general, pitting, Fuel Oil Chemistry not used. Loss of components, and and crevice material of steel piping elements corrosion components exposed to fuel oil exposed to fuel oil (3.3.1-64) was addressed by other line items including 3.3.1-20 and 3.3.1-32. Reinforced Concrete cracking Fire Protection and None This line item was concrete structural and spalling due to Structures not used. Reinforced fire barriers-walls, aggressive chemical Monitoring Program concrete structural ceilings and floors attack, and reaction fire barriers are exposed to with aggregates evaluated as air-indoor structural uncontrolled components in SER (3.3.1-65) Section 3.5. Reinforced Concrete cracking Fire Protection and None This line item was concrete structural and spalling due to Structures not used. Reinforced fire barriers-walls, freeze thaw, Monitoring Program concrete structural ceilings and floors aggressive chemical fire barriers are exposed to attack, and reaction evaluated as air-outdoor with aggregates structural (3.3.1-66) components in SER Section 3.5. 3-255

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Reinforced Loss of material due Fire Protection and None This line item was concrete structural to corrosion of Structures not used. Reinforced fire barriers-walls, embedded steel Monitoring Program concrete structural ceilings and floors fire barriers are exposed to evaluated as air-outdoor or structural air-indoor components in SER uncontrolled Section 3.5. (3.3.1-67) Steel piping, Loss of material due Fire Water System Fire Water System Consistent with the piping to general, pitting, Program (B.1.12.2); GALL Report. components, and crevice, and MIC, Periodic Surveillance (See SER piping elements and fouling and Preventive Section 3.3.2.1.37) exposed to raw Maintenance Program water (B.1.22); One-Time (3.3.1-68) Inspection Program (B.1.21) Stainless steel Loss of material due Fire Water System Fire Water System Consistent with the piping, piping to pitting and crevice Program (B.1.12.2); GALL Report. components, and corrosion, and Fire Protection (See SER piping elements fouling Program (B.1.12.1) Section 3.3.2.1.38) exposed to raw water (3.3.1-69) Copper alloy Loss of material due Fire Water System Fire Water System Consistent with the piping, piping to pitting, crevice, Program (B.1.12.2); GALL Report. components, and and MIC, and fouling Fire Protection (See SER piping elements Program (B.1.12.1); Section 3.3.2.1.39) exposed to raw Periodic Surveillance water and Preventive (3.3.1-70) Maintenance Program (B.1.22) Steel piping, Loss of material due Inspection of Periodic Surveillance Consistent with the piping to general, pitting, Internal Surfaces in and Preventive GALL Report. components, and and crevice Miscellaneous Maintenance Program (See SER piping elements corrosion Piping and Ducting (B.1.22) Section 3.3.2.1.40) exposed to moist Components air or condensation (Internal) (3.3.1-71) Steel HVAC Loss of material due Inspection of Periodic Surveillance Consistent with the ducting and to general, pitting, Internal Surfaces in and Preventive GALL Report. components crevice, and (for drip Miscellaneous Maintenance Program (See SER internal surfaces pans and drain lines) Piping and Ducting (B.1.22) Section 3.3.2.1.41) exposed to MIC Components condensation (Internal) (3.3.1-72) 3-256

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Steel crane Loss of material due Inspection of Periodic Surveillance Consistent with the structural girders to general corrosion Overhead Heavy and Preventive GALL Report. in load handling Load and Light Load Maintenance Program (See SER system exposed (Related to (B.1.22); Structures Section 3.3.2.1.42) to air-indoor Refueling) Handling Monitoring Program uncontrolled Systems (B.1.27.2) (external) (3.3.1-73) Steel cranes - rails Loss of material due Inspection of None This line item was not exposed to to Wear Overhead Heavy used. Steel crane rails air-indoor Load and Light Load are evaluated as uncontrolled (Related to structural components (external) Refueling) Handling in SER Section 3.5. (3.3.1-74) Systems Elastomer seals Hardening and loss Open-Cycle Cooling None Not applicable. and components of strength due to Water System (There are no exposed to raw elastomer elastomeric water degradation; loss of components exposed (3.3.1-75) material due to to raw or untreated erosion water in the auxiliary systems that require aging management.) Steel piping, Loss of material due Open-Cycle Cooling Service Water Consistent with the piping to general, pitting, Water System Integrity Program GALL Report. components, and crevice, and MIC, (B.1.26) (See SER piping elements fouling, and Section 3.3.2.1) (without lining/ lining/coating coating or with degradation degraded lining/coating) exposed to raw water (3.3.1-76) Steel heat Loss of material due Open-Cycle Cooling Service Water Consistent with the exchanger to general, pitting, Water System Integrity Program GALL Report. components crevice, galvanic, (B.1.26); Heat (See SER exposed to raw and MIC, and fouling Exchanger Monitoring Section 3.3.2.1.43) water Program (B.1.14) (3.3.1-77) 3-257

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Stainless steel, Loss of material due Open-Cycle Cooling None This line was not nickel alloy, and to pitting and crevice Water System used. There are no copper alloy corrosion nickel alloy piping, piping components exposed components, and to raw water in the piping elements auxiliary systems. exposed to raw Stainless steel and water copper alloy (3.3.1-78) components exposed to raw water are addressed in other line items including 3.3.1-79 and 3.3.1-81. Stainless steel Loss of material due Open-Cycle Cooling Service Water Consistent with the piping, piping to pitting and crevice Water System Integrity Program GALL Report. components, and corrosion, and (B.1.26) (See SER piping elements fouling Section 3.3.2.1) exposed to raw water (3.3.1-79) Stainless steel Loss of material due Open-Cycle Cooling None Not applicable. and copper alloy to pitting, crevice, Water System (This line applies to piping, piping and MIC EDG system components, and components. At piping elements VYNPS, these exposed to raw components are not water exposed to raw water (3.3.1-80) (heat exchanger components exposed to raw water are addressed in Line Item 3.3.1-82). Copper alloy Loss of material due Open-Cycle Cooling Service Water Consistent with the piping, piping to pitting, crevice, Water System Integrity Program GALL Report. components, and and MIC, and fouling (B.1.26) (See SER piping elements, Section 3.3.2.1) exposed to raw water (3.3.1-81) Copper alloy heat Loss of material due Open-Cycle Cooling Service Water Consistent with the exchanger to pitting, crevice, Water System Integrity Program GALL Report. components galvanic, and MIC, (B.1.26) (See SER exposed to raw and fouling Section 3.3.2.1) water (3.3.1-82) 3-258

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Stainless steel Reduction of heat Open-Cycle Cooling Service Water Consistent with the and copper alloy transfer due to Water System Integrity Program GALL Report. heat exchanger fouling (B.1.26); Fire (See SER tubes exposed to Protection Program Section 3.3.2.1.44) raw water (B.1.12.1) (3.3.1-83) Copper alloy > 15 Loss of material due Selective Leaching Selective Leaching Consistent with the percent Zn piping, to selective leaching of Materials Program (B.1.25) GALL Report. piping (See SER components, Section 3.3.2.1) piping elements, and heat exchanger components exposed to raw water, treated water, or closed cycle cooling water (3.3.1-84) Gray cast iron Loss of material due Selective Leaching Selective Leaching Consistent with the piping, piping to selective leaching of Materials Program (B.1.25) GALL Report. components, and (See SER piping elements Section 3.3.2.1) exposed to soil, raw water, treated water, or closed-cycle cooling water (3.3.1-85) Structural steel Loss of material due Structures None This line item was not (new fuel storage to general, pitting, Monitoring Program used. Structural steel rack assembly) and crevice of the new fuel exposed to corrosion storage rack air-indoor assembly is evaluated uncontrolled as a structural (external) component in SER (3.3.1-86) Section 3.5. Boraflex spent fuel Reduction of Boraflex Monitoring None Not applicable to storage racks neutron-absorbing BWRs neutron-absorbing capacity due to sheets exposed to boraflex degradation treated borated water (3.3.1-87) 3-259

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Aluminum and Loss of material due Boric Acid Corrosion None Not applicable to copper alloy > 15 to Boric acid BWRs percent Zn piping, corrosion piping components, and piping elements exposed to air with borated water leakage (3.3.1-88) Steel bolting and Loss of material due Boric Acid Corrosion None Not applicable to external surfaces to Boric acid BWRs exposed to air with corrosion borated water leakage (3.3.1-89) Stainless steel Cracking due to Water Chemistry None Not applicable to and steel with SCC BWRs stainless steel cladding piping, piping components, piping elements, tanks, and fuel storage racks exposed to treated borated water > 60EC (> 140EF) (3.3.1-90) Stainless steel Loss of material due Water Chemistry None Not applicable to and steel with to pitting and crevice BWRs stainless steel corrosion cladding piping, piping components, and piping elements exposed to treated borated water (3.3.1-91) Galvanized steel None None None Not applicable. piping, piping (Galvanized steel components, and surfaces are piping elements evaluated as steel exposed to for the auxiliary air-indoor systems.) uncontrolled (3.3.1-92) 3-260

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Glass piping None None None Consistent with the elements exposed GALL Report. to air, air-indoor (See LRA uncontrolled Section 3.3.2.1) (external), fuel oil, lubricating oil, raw water, treated water, and treated borated water (3.3.1-93) Stainless steel None None None Consistent with and nickel alloy GALL Report. piping, piping (See LRA components, and Section 3.3.2.1) piping elements exposed to air-indoor uncontrolled (external) (3.3.1-94) Steel and None None None Not applicable. aluminum piping, (There are no piping components exposed components, and to controlled indoor air piping elements at VYNPS.) exposed to air-indoor controlled (external) (3.3.1-95) Steel and None None None Consistent with the stainless steel GALL Report. piping, piping (See LRA components, and Section 3.3.2.1) piping elements in concrete (3.3.1-96) Steel, stainless None None None Consistent with the steel, aluminum, GALL Report. and copper alloy (See LRA piping, piping Section 3.3.2.1) components, and piping elements exposed to gas (3.3.1-97) 3-261

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Steel, stainless None None None Not applicable. steel, and copper (Dried (treated) air is alloy piping, piping maintained as an components, and environment as a piping elements result of the exposed to dried Instrument Air Quality air Program, so aging (3.3.1-98) effects may occur without that program.) Stainless steel None None None Not applicable to and copper alloy BWRs

< 15 percent Zn piping, piping components, and piping elements exposed to air with borated water leakage (3.3.1-99)

The staffs review of the auxiliary systems component groups followed any one of several approaches. One approach, 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 approach, 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 approach, 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. The staffs review of AMPs credited to manage or monitor aging effects of the auxiliary systems components is documented in SER Section 3.0.3. 3.3.2.1 AMR Results Consistent with the GALL Report Summary of Technical Information in the Amended Application. LRA Section 3.3.2.1 identifies the materials, environments, AERMs, and the following programs that manage aging effects for the auxiliary systems components:

• Buried Piping and Tanks Inspection Program
• Diesel Fuel Monitoring Program
• Fire Protection Program
• Fire Water System Program
• Flow-Accelerated Corrosion Program
• Heat Exchanger Monitoring Program
• Instrument Air Quality Program
• Oil Analysis Program
• One-Time Inspection Program
• Periodic Surveillance and Preventive Maintenance Program 3-262
• Selective Leaching Program
• Service Water Integrity Program
• System Walkdown Program
• Water Chemistry Control - Auxiliary Systems Program
• Water Chemistry Control - BWR Program
• Water Chemistry Control - Closed Cooling Water Program Staff Evaluation. LRA Tables 3.3.2-1 through 3.3.2-12 and Tables 3.3.2-13-1 through 3.3.2-13-58 summarize AMRs for the auxiliary systems components and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed consistency with the report and for which it does not recommend further evaluation, the staffs 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 through E indicating 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 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 AMP. The staff audited these line items to verify consistency with the GALL Report and verified that the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also determines whether the applicants AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions. Note C indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified 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 GALL Report. The staff also determines 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. 3-263

Note D indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL 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 identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also determines whether the applicants AMP was consistent with the GALL 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 determines whether the credited AMP would manage the aging effect consistently with the GALL AMP and whether the AMR was valid for the site-specific conditions. 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 staffs evaluation follows. 3.3.2.1.1 Reduction of Heat Transfer Due to Fouling For reduction of heat transfer due to fouling of stainless steel heat exchanger tubes exposed to treated water, the GALL Report recommends programs consistent with GALL AMP XI.M2, Water Chemistry and GALL AMP XI.M32, One-Time Inspection. In the LRA Table 3.3.1, Item 3.3.1-3, the applicant stated that its Water Chemistry Control-BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage reduction of heat transfer due to fouling in stainless steel heat exchanger tubes exposed to treated water. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.3.1-3 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The applicants Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicants management of the reduction of heat transfer due to fouling in stainless steel heat exchanger tubes exposed to treated water consistent with the GALL Report and therefore acceptable. 3-264

On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.2 Cracking Due to Stress Corrosion Cracking For cracking due to SCC of stainless steel and stainless clad steel heat exchanger components exposed to treated water greater than 60EC (greater than140EF), the GALL Report recommends a plant-specific program. In LRA Table 3.3.1, Item 3.3.1-5, the applicant stated that cracking in stainless steel heat exchanger tubes exposed to treated water greater than140EF is managed by the Water Chemistry Control-BWR Program. The One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.1.1-5 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The applicants Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicants management of cracking in stainless steel heat exchanger tubes exposed to treated water greater than 140EF consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.3 Cracking Due to Stress Corrosion Cracking For cracking due to SCC of stainless steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust, the GALL Report recommends a plant-specific program. In LRA Table 3.3.1, Item 3.3.1-6, the applicant stated that cracking of stainless steel exhaust components will be managed by the Periodic Surveillance and Preventive Maintenance Program. The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program. This evaluation is documented in SER Section 3.0.3.3.5. This is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for expansion joints exposed to exhaust gas and therefore is acceptable to the staff. 3-265

On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.4 Hardening and Loss of Strength Due to Elastomer Degradation For hardening and loss of strength due to elastomer degradation of elastomer seals and components exposed to air-indoor uncontrolled (internal/external), the GALL Report recommends a plant-specific program. In LRA Table 3.3.1, Item 3.3.1-11, the applicant stated that the change in material properties of elastomer components exposed to indoor air will be managed by the Periodic Surveillance and Preventive Maintenance Program. The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program. This evaluation is documented in SER Section 3.0.3.3.5. This is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for duct flexible connections in the HVAC system and therefore is acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.5 Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General Corrosion For reduction of neutron-absorbing capacity and loss of material due to general corrosion of boral, boron steel spent fuel storage racks neutron-absorbing sheets exposed to treated water or treated borated water, the GALL Report recommends a plant-specific program. In the LRA Table 3.3.1, Item 3.3.1-13, the applicant stated that the Water Chemistry Control-BWR Program manages the degradation of boral. During the audit and review, the staff asked the applicant how a purely preventive program could address this aging effect. The applicant confirmed that where the Water Chemistry Control-BWR Program was applied, including prevention of loss of material from boral, the One-Time Inspection Program would be used to confirm its effectiveness. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state that the effectiveness of the Water Chemistry Control-BWR Program is confirmed by the One-Time Inspection Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The applicants Water Chemistry Control-BWR Program relies on monitoring and 3-266

control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicants management of the degradation of boral using the combination of these AMPs satisfies the criteria of the SRP-LR Appendix A.1 and is therefore acceptable. On the basis of its review, the staff determines that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.6 Loss of Material Due to General, Pitting, and Crevice Corrosion For loss of material due to general, pitting, and crevice corrosion of steel piping, piping components, and piping elements exposed to lubricating oil, the GALL Report recommends programs consistent with GALL AMP XI.M39, Lubricating Oil Analysis, and GALL AMP XI.M32, One-Time Inspection. In the discussion column of LRA Table 3.3.1, Item 3.3.1-14, the applicant stated that the Oil Analysis Program, manages loss of material in steel components. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state that the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program. The staff reviewed the applicant's Oil Analysis Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.6, respectively. With the change discussed above, the applicant is managing the loss of material due to general, pitting, and crevice corrosion of steel piping, piping components, and piping elements exposed to lubricating oil in a manner that is consistent with the GALL Report and therefore acceptable. In addition, this aging effect is also managed for carbon steel gauges, filter housings, heater housings, pump casings, strainer housings, tanks, gear boxes, and heat exchanger shells as well as gray cast iron valve bodies exposed to lubricating oil. On the basis of its review, the staff determines that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.7 Loss of Material Due to General, Pitting, and Crevice Corrosion For loss of material due to general, pitting, and crevice corrosion of steel piping, piping components, and piping elements exposed to treated water, the GALL Report recommends programs consistent with GALL AMP XI.M2, Water Chemistry and GALL AMP XI.M32, One-Time Inspection. 3-267

In LRA Table 3.3.1, Item 3.3.1-17, the applicant stated that the loss of material in steel components is managed by the Water Chemistry Control - BWR Program. The One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.1.1-17 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The applicants Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicants management of loss of material in steel components consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.8 Loss of Material/General (Steel Only), Pitting and Crevice Corrosion For loss of material/general (steel only), pitting and crevice corrosion of stainless steel and steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust, the GALL Report recommends a plant-specific program. In the LRA Table 3.3.1, Item 3.3.1-18, the applicant stated that the Periodic Surveillance and Preventive Maintenance Program and the Fire Protection Program will manage loss of material in steel and stainless steel components exposed to diesel exhaust. The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program. This evaluation is documented in SER Section 3.0.3.3.5. This is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 and therefore is acceptable. The staff also reviewed the applicant's Fire Protection Program. This evaluation is documented in SER Section 3.0.3.2.11. This AMP is consistent, with exceptions and enhancements, with GALL AMP XI.M26, Fire Protection, and the staff therefore finds it to be an acceptable method for management of loss of material from carbon steel expansion joints in the EDG system, stainless steel expansion joints and carbon steel piping, silencers, and turbochargers in the EDG, fire protection-water, and John Deere Diesel systems exposed to diesel exhaust. On the basis of its review, the staff determines that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3-268

3.3.2.1.9 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced Corrosion, and Fouling For loss of material due to general, pitting, crevice, and MIC, and fouling of steel piping, piping components, piping elements, and tanks exposed to fuel oil, the GALL Report recommends a program consistent with GALL AMP XI.M30, Fuel Oil Chemistry and GALL AMP XI.M32, One-Time Inspection. In LRA Table 3.3.1, Item 3.3.1-20, the applicant stated that the Diesel Fuel Monitoring Program manages loss of material in steel components. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant amended its LRA. The applicant stated that the LRA is revised to state that the One-Time Inspection Program will verify the effectiveness of the Diesel Fuel Monitoring Program. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.3.1-20 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Diesel Fuel Monitoring Program and One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.2.9 and 3.0.3.1.6, respectively. The staff concludes that the applicants Diesel Fuel Monitoring Program in conjunction with the One-Time Inspection Program provided assurance that the loss of material due to corrosion is adequately managed by monitoring and controlling conditions that would cause this aging effect and by monitoring the effectiveness of the program through surveillance and testing. On this basis, the staff finds that the applicant management of loss of material due to general, pitting, crevice, and MIC, and fouling of steel piping, piping components, piping elements, and tanks exposed to fuel oil consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.10 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced Corrosion, and Fouling For loss of material due to general, pitting, crevice, and MIC, and fouling of steel heat exchanger components exposed to lubricating oil, the GALL Report recommends programs consistent with GALL AMP XI.M39, Lubricating Oil Analysis and GALL AMP XI.M32, One-Time Inspection. In LRA Table 3.3.1, Item 3.3.1-21, the applicant stated that the Oil Analysis Program manages loss of material in steel heat exchanger components. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant amended its LRA. The applicant stated that LRA is revised to state that the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program. During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.3.1-21 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Oil 3-269

Analysis Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.6, respectively. The Oil Analysis Program includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. Operating experience at VYNPS has confirmed the effectiveness of this program in maintaining contaminants within limits such that corrosion has not and will not affect the intended functions of these components. The Oil Analysis Program will be supplemented by the One-Time Inspection Program to verify its effectiveness. On this basis, the staff finds that the applicants management of loss of material due to general, pitting, crevice, and MIC, and fouling of steel heat exchanger components exposed to lubricating oil consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.11 Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of stainless steel and steel with stainless steel cladding heat exchanger components exposed to treated water, the GALL Report recommends programs consistent with GALL AMP XI.M2, Water Chemistry and GALL AMP XI.M32, One-Time Inspection. In LRA Table 3.3.1, Item 3.3.1-23, the applicant stated that the loss of material in stainless steel heat exchanger components is managed by the Water Chemistry Control-BWR Program. The One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). During interviews with the applicants technical personnel staff, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.3.1-23 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The applicants Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicants management of loss of material in stainless steel heat exchanger components consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3-270

3.3.2.1.12 Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of stainless steel and aluminum piping, piping components, and piping elements exposed to treated water, the GALL Report recommends programs consistent with GALL AMP XI.M2, Water Chemistry and GALL AMP XI.M32, One-Time Inspection. In LRA Table 3.3.1, Item 3.3.1-24, the applicant stated that the loss of material in stainless steel components is managed by the Water Chemistry Control-BWR Program. The One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.3.1-24 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The applicants Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicants management of loss of material in stainless steel components consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.13 Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of copper alloy HVAC piping, piping components, piping elements exposed to condensation (external), the GALL Report suggests that a plant-specific AMP is to be evaluated. In LRA Table 3.3.1, Item 3.3.1-25, the applicant stated that the System Walkdown Program, Periodic Surveillance and Preventive Maintenance Program, Service Water Integrity Program and the Heat Exchanger Monitoring Program will manage loss of material in copper alloy components. The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosion from copper-alloy (greater than15 percent zinc) heat exchanger tubes exposed to condensation in the reactor building CCWS is to be managed using the Heat Exchanger Monitoring Program, a plant-specific AMP. The staffs review of the applicant's Heat Exchanger Monitoring Program is documented in SER Section 3.0.3.3.1. This is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for heat exchanger tubes in the reactor building CCWS and therefore is acceptable. 3-271

The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosion from copper-alloy (less than15 percent zinc) heat exchanger tubes exposed to condensation in the HVAC system is to be managed using the Periodic Surveillance and Preventive Maintenance Program, a plant-specific AMP. The staffs review of the applicant's Periodic Surveillance and Preventive Maintenance Program is documented in SER Section 3.0.3.3.5. This is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for heat exchanger tubes of the HVAC system and therefore is acceptable. The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosion from copper-alloy (greater than15 percent zinc) heat exchanger tubes exposed to condensation in the SW and HVAC systems is to be managed using the Service Water Integrity Program. The staffs review of the applicant's Service Water Integrity Program is documented in SER Section 3.0.3.2.16. The program satisfies the criteria of SRP-LR Appendix A.1 for heat exchanger tubes in the SW and HVAC systems and therefore is acceptable. The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosion from copper-alloy (greater than15 percent zinc) valve bodies in the SWS and HVAC system exposed to condensation is to be managed using the System Walkdown Program. The staffs review of the applicant's System Walkdown Program is documented in SER Section 3.0.3.1.9. The program satisfies the criteria of SRP-LR Appendix A.1 for valve bodies in the SWS and pump casings in the HVAC system exposed to condensation and therefore is acceptable. The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosion from copper-alloy (less than15 percent zinc) piping, tubing and valve bodies in the SWS; compressor housings and tubing in the HVAC system; and copper-alloy tubing in the CW, CWP, house heating boiler, and RHRSW systems exposed to condensation is to be managed using the System Walkdown Program. The staffs review of the applicant's System Walkdown Program is documented in SER Section 3.0.3.1.9. The program satisfies the criteria of SRP-LR Appendix A.1 for piping, tubing, valve bodies, and compressor housing exposed to condensation in the SW CW, CWP, HB, RHRSW, and HVAC systems and therefore is acceptable. On the basis of its review, the staff determines that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.14 Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of copper alloy piping, piping components, and piping elements exposed to lubricating oil, the GALL Report recommends programs consistent with GALL AMP XI.M39, Lubricating Oil Analysis and GALL AMP XI.M32, One-Time Inspection. 3-272

In LRA Table 3.3.1, Item 3.3.1-26, the applicant stated that the Oil Analysis Program manages loss of material in copper alloy components. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state that the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program. The staff reviewed the applicant's Oil Analysis Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.6, respectively. With the change discussed above, the applicant is managing the loss of material due to pitting and crevice corrosion of copper alloy piping, piping components, and piping elements exposed to lubricating oil in a manner that is consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff determines that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.15 Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of stainless steel HVAC ducting and aluminum HVAC piping, piping components and piping elements exposed to condensation, the GALL Report suggests that a plant-specific AMP is to be evaluated. In LRA Table 3.3.1, Item 3.3.1-27, the applicant stated that the System Walkdown Program, Periodic Surveillance and Preventive Maintenance Program, and the Service Water Integrity Program manage loss of material in stainless steel components. The applicant also stated that there are no aluminum pressure boundary components exposed to condensation in the VYNPS auxiliary systems. The staffs evaluations of the applicants System Walkdown Program, Periodic Surveillance and Preventive Maintenance Program, and the Service Water Integrity Program are documented in SER Sections 3.0.3.1.9, 3.0.3.3.5, and 3.0.3.2.16, respectively. The System Walkdown Program is consistent with program described in GALL AMP XI.M36, External Surface Monitoring. The Periodic Surveillance and Preventive Maintenance Program includes periodic inspections and tests that manage aging effects not managed by other AMP s. The Service Water Integrity Program relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the SWSs will be managed for the period of extended operation. The staff determines that the combination of these AMPs satisfies the criteria of SRP-LR Appendix A.1 for a plant-specific AMP. On these basis, the staff finds that the applicant adequately manage the loss of material due to pitting and crevice corrosion of stainless steel components. The staff also reviewed LRA and supporting documents to confirm that there are no aluminum boundary components exposed to condensation in the VYNPS auxiliary systems. The applicant stated that loss of material due to pitting and crevice corrosion from stainless steel piping, tanks, and valve bodies of the EDG system exposed to untreated air is to be managed using the Periodic Surveillance and Preventive Maintenance Program, a plant-specific AMP. 3-273

The staffs evaluation of the applicant's Periodic Surveillance and Preventive Maintenance Program is documented in SER Section 3.0.3.3.5. This program includes periodic inspections and tests of the EDG system to manage aging effects. On this basis, the staff finds the loss of material due to pitting and crevice corrosion from steel piping, tanks, and valve bodies of the EDG system adequately managed. The applicant also stated that loss of material due to pitting and crevice corrosion from stainless steel suction barrels exposed to condensation in the SWS is to be managed using the Service Water Integrity Program. The staffs evaluation of the applicant's Service Water Integrity Program is documented in SER Section 3.0.3.2.16. The Service Water Integrity Program includes surveillance and control techniques to manage aging effects in the SWS or SCs by the SWS. The program relies on implementation of the recommendation of GL 89-13 to ensure that the effects of aging will be managed. On this basis, the staff finds that loss of material due to pitting and crevice corrosion from stainless steel suction barrels is adequately managed. In addition, the applicant stated loss of material due to pitting and crevice corrosion in condensation from stainless steel piping, tubing, and valve bodies of the RHRSW system as well as from bolting, expansion joints, indicators, orifices, piping, tubing, thermowells, and valve bodies of the SWS is to be managed using the System Walkdown Program. The staffs evaluation of the applicant's System Walkdown Program is documented in SER Section 3.0.3.1.9. The System Walkdown Program is consistent with the program described in GALL AMP XI.M36, External Surfaces Monitoring. This program entails inspections of external surfaces of components subject to an AMR. The program is also credited with managing loss of material from internal surfaces where internal and external material-environment combinations are the same and external surface conditions represent internal surface conditions. On this basis, the staff finds that the loss of material due to pitting and crevice corrosion in condensation from stainless steel piping, tubing, and valve bodies of the RHRSW system as well as from bolting, expansion joints, indicators, orifices, piping, tubing, thermowells, and valves bodies of the SWS. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.16 Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of copper alloy fire protection piping, piping components, and piping elements exposed to condensation (internal), the GALL Report suggests that a plant-specific AMP is to be evaluated. In LRA Table 3.3.1, Item 3.3.1-28, the applicant stated that the Periodic Surveillance and Preventive Maintenance Program and the Instrument Air Quality Program will manage loss of material in copper alloy components. The applicant also stated that loss of material due to pitting and crevice corrosion from copper alloy tubing and valve bodies of the EDG system exposed to untreated air is to be managed using the Periodic Surveillance and Preventive Maintenance Program, a plant-specific AMP. 3-274

The staffs evaluation of the applicant's Periodic Surveillance and Preventive Maintenance Program is documented in SER Section 3.0.3.3.5. The staff determines that the applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1, which includes periodic inspections and tests to manage aging effects. On the basis that the components are inspected and tested periodically, staff finds that the of loss of material due to pitting and crevice corrosion from copper alloy tubing and valve will be adequately managed. The applicant also stated that loss of material due to pitting and crevice corrosion from copper-alloy valve bodies in the IA system exposed to treated air is to be managed using the Instrument Air Quality Program, a plant-specific AMP. The staffs evaluation of the applicant's Instrument Air Quality Program is documented in SER Section 3.0.3.3.4. The staff determines that the applicants Instrument Air Quality Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. The program ensures that IA supplied to components is maintained free of water and significant contaminants, thereby preserving an environment that is not conducive to loss of material. On this basis, the staff finds that the applicants management of the loss of material for copper-alloy components exposed to treated air (internal) using its Instrument Air Quality Program acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, in a manner consistent with the GALL Report. 3.3.2.1.17 Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of stainless steel piping, piping components, and piping elements exposed to soil, the GALL Report recommends that a plant-specific AMP is to be evaluated. In LRA Table 3.3.1, Item 3.3.1-29, the applicant stated that the Buried Piping Inspection Program, manages loss of material in stainless steel components. The staff reviewed the applicant's Buried Piping Inspection Program and its evaluation is documented in SER Section 3.0.3.2.1. The applicants Buried Piping Inspection Program is consistent, with exceptions and enhancement, with GALL AMP XI.M34, Buried Piping and Tanks Inspection. The staff concludes that the applicants Buried Piping Inspection Program provided assurance that the program will manage aging effects on the external surfaces of buried steel piping. On this basis, the staff finds that applicants management of loss of material in stainless steel components using its Buried Piping Inspection Program acceptable. On the basis of its review, the staff determines that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3-275

3.3.2.1.18 Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of stainless steel piping, piping components, and piping elements exposed to sodium pentaborate solution, the GALL Report recommends programs consistent with GALL AMP XI.M2, Water Chemistry and GALL AMP XI.M32, One-Time Inspection. In LRA Table 3.3.1, Item 3.3.1-30, the applicant stated that the loss of material in stainless steel components is managed by the Water Chemistry Control-BWR Program. The One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.3.1-30 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.2.11 and 3.0.3.1.6, respectively. The applicants Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicants management of loss of material in stainless steel components consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.19 Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion For loss of material due to pitting, crevice, and galvanic corrosion of copper alloy piping, piping components, and piping elements exposed to treated water, the GALL Report recommends programs consistent with GALL AMP XI.M2, Water Chemistry and GALL AMP XI.M32, One-Time Inspection. In LRA Table 3.3.1, Item 3.3.1-31, the applicant stated that loss of material in copper alloy components exposed to treated water is managed by the Water Chemistry Control-BWR Program. The applicant also stated the One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). During interviews with the applicants technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.3.1, Item 3.3.1-31 in the population that is subject to the One-Time Inspection Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.2.11 and 3.0.3.1.6, respectively. The applicants Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 3-276

(BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds that the applicants management of loss of material in copper alloy components exposed to treated water consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.20 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion For loss of material due to pitting, crevice, and MIC of stainless steel, aluminum and copper alloy piping, piping components, and piping elements exposed to fuel oil, the GALL Report recommends programs consistent with GALL AMP XI.M30, Fuel Oil Chemistry and GALL AMP XI.M32, One-Time Inspection. In LRA Table 3.3.1, Item 3.3.1-32, the applicant stated that the Diesel Fuel Monitoring Program manages loss of material in stainless steel, aluminum and copper alloy components. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state that the One-Time Inspection Program verifies the effectiveness of the Diesel Fuel Monitoring Program. The staff reviewed the applicant's Diesel Fuel Monitoring Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.9 and 3.0.3.1.6, respectively. The staff determines that the applicants Diesel Fuel Monitoring Program in conjunction with the One-Time Inspection Program provided assurance that loss of material in stainless steel, aluminum and copper alloy components is adequately managed by monitoring and controlling conditions that would cause this aging effect and by monitoring the effectiveness of the program through surveillance and testing. On this basis, the staff finds that the applicant management of loss of material in stainless steel, aluminum and copper alloy components consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff determines that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.21 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion For loss of material due to pitting, crevice, and MIC of stainless steel piping, piping components, and piping elements exposed to lubricating oil, the GALL Report recommends programs consistent with GALL AMP XI.M39, Lubricating Oil Analysis and GALL AMP XI.M32, One-Time Inspection. 3-277

In the discussion column of LRA Table 3.3.1, Item 3.3.1-33, the applicant stated that the Oil Analysis Program manages loss of material in stainless steel components. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program. The staff reviewed the applicant's Oil Analysis Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.6, respectively. With the change discussed above, the applicant is managing the loss of material due to pitting, crevice, and MIC of stainless steel piping, piping components, and piping elements exposed to lubricating oil in a manner that is consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff determines that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.22 Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking For cracking due to SCC, IGSCC of stainless steel piping, piping components, and piping elements exposed to treated water greater than 140EF, the GALL Report recommends a program consistent with GALL AMP XI.M25, BWR Reactor Water Cleanup System Program. In LRA Table 3.3.1, Item 3.3.1-37, the applicant stated that cracking of stainless steel components of the reactor water cleanup (RWCU) system is managed by the Water Chemistry Control-BWR Program. The applicant also stated the One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program-BWR Program. In addition, the applicant stated that the only components to which this line item applies are included in-scope only in accordance with10 CFR 54.4(a)(2) and listed in the LRA series 3.3.2-13-xx tables. The GALL Report stated that no IGSCC inspection is recommended for plants that have piping made of material that is resistant to IGSCC, and that have satisfactorily completed all actions requested in GL 89-10. During the audit and review, the staff confirmed that VYNPS meets these criteria. The staff finds that since VYNPS satisfies these criteria, the Water Chemistry Control-BWR Program is an acceptable alternative to GALL AMP XI.M25 to manage cracking. As described in LRA Table 3.3.1, Item 3.3.1-37, the One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program-BWR Program. The staff reviewed the applicants Water Chemistry Control-BWR Program and its evaluation is documented in SER Section 3.0.3.1.11. The staff finds this program to be effective in mitigating cracking due to SCC, IGSCC of stainless steel piping, piping components, and piping elements exposed to treated water greater than 140EF. It is to be combined with the One-Time Inspection Program to confirm the effectiveness of the Water Chemistry-BWR Program. The staff finds this combination of programs will adequately manage this aging effect and their use is acceptable. 3-278

On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.23 Cracking Due to Stress Corrosion Cracking For cracking due to SCC of stainless steel piping, piping components, and piping elements exposed to treated water greater than140EF, the GALL Report recommends programs consistent with GALL AMP XI.M7, BWR Stress Corrosion Cracking and GALL AMP XI.M2, Water Chemistry. In LRA Table 3.3.1, Item 3.3.1-38, the applicant stated that the Water Chemistry Control-BWR Program, manages cracking of stainless steel components. None of the auxiliary system components are within the scope of BWR Stress Corrosion Cracking Program, (all relevant components are included in the reactor vessel, internals and reactor coolant systems). The One-Time Inspection Program, will be used to verify the effectiveness of the Water Chemistry Program. During the audit and review, the staff asked the applicant for clarification on the basis of which items were excluded. The applicant stated that all of the components addressed with auxiliary systems were less than 4 inches NPS. The staff reviewed drawings, as documented in the Audit and Review Report, and confirmed that all of the components addressed with the auxiliary systems were less than 4 inches NPS. The staff determines that the applicant's management of cracking of stainless steel flow elements, piping, tubing, and valve bodies of the nuclear boiler and primary containment atmospheric control and containment air dilution system exposed to treated water greater than 140EF using the its Water Chemistry Control -BWR Program and One-Time Inspection Program consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.24 Loss of Material Due to General, Pitting, and Crevice Corrosion For loss of material due to general, pitting, and crevice corrosion of steel tanks in diesel fuel oil system exposed to air - outdoor (external), the GALL Report recommends program consistent with GALL AMP XI.M29, Aboveground Steel Tanks Program. In LRA Table 3.3.1, Item 3.3.1-40, the applicant stated that the System Walkdown Program, manages loss of material in steel tanks of the diesel fuel oil system exposed to outdoor air through visual inspections. The staff reviewed the applicant's System Walkdown Program and its evaluation is documented in SER Section 3.0.3.1.9. The System Walkdown Program manages the loss of material due to general, pitting, and crevice corrosion of steel tanks in diesel fuel oil systems exposed to outdoor air through periodic visual inspections which can detect this aging effect/mechanism before the loss of intended function. On this basis, the staff finds this acceptable. 3-279

On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.25 Loss of Material Due to General, Pitting, and Crevice Corrosion For loss of material due to general, pitting, and crevice corrosion of steel bolting and closure bolting exposed to air, the GALL Report recommends a program consistent with GALL AMP XI.M18, Bolting Integrity. In LRA Table 3.3.1, Item 3.3.1-43, the applicant stated that the System Walkdown Program, manages the loss of material for steel bolting through the use of visual inspections that are performed at least once per refueling cycle. During the audit and review, the staff asked the applicant to clarify how aging of steel bolting and closure bolting would be managed in the absence of a Bolting Integrity Program. In a letter dated July 6, 2006, the applicant agreed to prepare and submit an AMP consistent with GALL AMP XI.M18, Bolting Integrity, for approval. In letters dated October 17, 2006 and January 4, 2007, the applicant revised its LRA, committing (Commitment #34) to a Bolting Integrity Program. The staffs evaluation of the applicants System Walkdown Program and Bolting Integrity Program are documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The program Bolting Integrity Program applies to bolting and torquing practices of safety-related and nonsafety-related carbon and stainless steel bolting for pressure-retaining components, NSSS component supports, and structural joints. The program addresses all safety and nonsafety-relates bolting regardless of size (except the reactor vessel closure studs which are address by the Reactor Vessel Closure Studs Program) and material. The applicants Bolting Integrity Program conforms to the recommendations of the GALL Report and encompass all safety-related bolting as delineated in NUREG-1339, which includes the criteria established in the 1995 Edition through the 1996 Addenda of ASME Code, Section XI. The applicants System Walkdown Program comprises of inspections of external surfaces of components subject to an AMR. On this basis, the staff finds that the applicants management of loss of material for steel bolting consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant, with the commitment identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.26 Cracking Due to Stress Corrosion Cracking For cracking due to SCC of stainless steel and stainless clad steel piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling water greater than140EF, the GALL Report recommends a program consistent with GALL AMP XI.M21, Closed-Cycle Cooling Water System. In LRA Table 3.3.1, Item 3.3.1-46, the applicant stated that the Water Chemistry Control-Closed Cooling Water Program, manages cracking for stainless steel components. During the audit and review, the applicant stated that for this aging effect, the One-Time Inspection Program will be explicitly identified in the system tables (Tables 3.3.2.-1 through 3-280

3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control - Closed Cooling Water Program. The staff reviewed the applicant's Water Chemistry Control-Closed Cooling Water Program and One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.2.18 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-Closed Cooling Water Program is consistent with GALL AMP XI.M21 with one exception which is related to performance testing. This exception would not affect the management of cracking due to SCC. Therefore, the staff finds that the applicant is managing SCC of stainless steel and stainless clad steel piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling water greater than 140EF in a manner consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.27 Loss of Material Due to General, Pitting, and Crevice Corrosion For loss of material due to general, pitting, and crevice corrosion of steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to closed cycle cooling water, the GALL Report recommends a program consistent with GALL AMP XI.M21, Closed-Cycle Cooling Water System. In the discussion column of LRA Table 3.3.1, Item 3.3.1-47, the applicant stated that, for steel components of most auxiliary systems, the Water Chemistry Control-Closed Cooling Water Program manages loss of material. Furthermore, the applicant stated that the Water Chemistry Control-Auxiliary Systems Program manages loss of material for steel components of the house heating boiler and stator cooling systems. During the audit and review, the applicant stated that for this aging effect, the One-Time Inspection Program will be explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state that the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control - Closed Cooling Water Program. The staff reviewed the applicant's Water Chemistry Control-Auxiliary Systems Program. This evaluation is documented in SER Section 3.0.3.3.7. The applicant's program is a plant-specific program. This program includes application of the One-Time Inspection Program to verify the effectiveness of the Water Chemistry Control-Auxiliary Systems Program. Therefore, the staff determines that the applicant is adequately managing the loss of material due to general, pitting, and crevice corrosion of steel coolers, filter housings, heat exchangers (shell), piping, pump casings, steam traps, strainer housings, tanks, valve bodies, and copper alloy tubing exposed to treated water in the house heating boiler and stator cooling systems. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3-281

3.3.2.1.28 Loss of Material Due to General, Pitting, Crevice, and Galvanic Corrosion For loss of material due to general, pitting, crevice, and galvanic corrosion of steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to closed cycle cooling water, the GALL Report recommends a program consistent with GALL AMP XI.M21, Closed-Cycle Cooling Water System. In LRA Table 3.3.1, Item 3.3.1-48 the applicant stated that the Water Chemistry Control-Closed Cooling Water Program, manages loss of material for steel heat exchanger components. During the audit and review, the applicant stated that for this aging effect, the One-Time Inspection Program will be explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-Closed Cooling Water Program. The staff reviewed the applicant's Water Chemistry Control-Closed Cooling Water Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.18 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-Closed Cooling Water Program is consistent with GALL AMP XI.M21 with one exception which is related to performance testing. This exception would not affect the management of loss of material due to general, pitting, crevice, and galvanic corrosion. Therefore, the staff determines that the applicant is managing loss of material due to general, pitting, crevice, and galvanic corrosion of steel heat exchanger components (bonnet, shell, tubes, and tubesheet) exposed to closed cycle cooling water in a manner consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.29 Loss of Material Due to Microbiologically-Influenced Corrosion For loss of material due to MIC of stainless steel and steel with stainless steel cladding heat exchanger components exposed to closed cycle cooling water, the GALL Report recommends a program consistent with GALL AMP XI.M21, Closed-Cycle Cooling Water System. In LRA Table 3.3.1, Item 3.3.1-49, the applicant stated that the Water Chemistry Control-Closed Cooling Water Program manages loss of material for stainless steel heat exchanger components. During the audit and review, the applicant stated that for managing this aging effect, the One-Time Inspection Program will be explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state that the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-Closed Cooling Water Program. 3-282

The staff reviewed the applicant's Water Chemistry Control-Closed Cooling Water Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.18 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-Closed Cooling Water Program is consistent with GALL AMP XI.M21 with one exception which is related to performance testing. This exception would not affect the management of loss of material due to MIC. Therefore, the staff determines that the applicant is managing loss of material due to MIC of stainless steel and steel with stainless steel cladding heat exchanger components exposed to closed cycle cooling water in a manner consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.30 Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of stainless steel piping, piping components, and piping elements exposed to closed cycle cooling water, the GALL Report recommends a program consistent with GALL AMP XI.M21, Closed-Cycle Cooling Water System. In LRA Table 3.3.1, Item 3.3.1-50, the applicant stated that the Water Chemistry Control-Closed Cooling Water Program manages loss of material for stainless steel components and that for stainless steel components of the demineralized water system, the Water Chemistry Control-Auxiliary Systems Program manages loss of material. During the audit and review, the applicant stated that for managing this aging effect, the One-Time Inspection Program will be explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state that the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-Closed Cooling Water Program. The staff reviewed the applicant's Water Chemistry Control-Closed Cooling Water Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.18 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-Closed Cooling Water Program is consistent with GALL AMP XI.M21 with one exception which is related to performance testing. This exception would not affect the management of loss of material due to pitting and crevice corrosion. Therefore, the staff determines that the applicant is managing loss of material due to pitting and crevice corrosion of stainless steel piping, piping components, and piping elements exposed to closed cycle cooling water in a manner consistent with the GALL Report and therefore acceptable. During the audit and review, the staff asked the applicant to clarify why there were no items in LRA Table 3.3.2-13-12 being managed by the Water Chemistry Control-Auxiliary Systems Program as stated in the discussion column of LRA Table 3.3.1, Item 3.3.1-50. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant revised LRA Table 3.3.1, Item 3.3.1-50 to replace the Water Chemistry Control-Auxiliary Systems Program in the Discussion column with the Water Chemistry Control-BWR Program. The LRA Table 3.3.1 item 3-283

referenced in LRA Table 3.3.2-13-12 managed by the Water Chemistry Control-BWR Program is LRA Table 3.3.1, Item 3.3.1-17, which the staff evaluated in SER Section 3.3.2.1.7. The staff finds that for LRA Table 3.3.1, Item 3.3.1-17, the applicant stated that the loss of material in steel components is managed by the Water Chemistry Control - BWR Program. The One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program. On this basis, the staff finds this change acceptable. On the basis of its review, the staff finds that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.31 Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion For loss of material due to pitting, crevice, and galvanic corrosion of copper alloy piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling water, the GALL Report recommends a program consistent with GALL AMP XI.M21, Closed-Cycle Cooling Water System. In LRA Table 3.3.1, Item 3.3.1-51, the applicant stated that the Water Chemistry Control-Closed Cooling Water Program manages loss of material for copper alloy components. During the audit and review, the applicant stated that for managing this aging effect, the One-Time Inspection Program will be explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-Closed Cooling Water Program. The staff reviewed the applicant's Water Chemistry Control-Closed Cooling Water Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.18 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control-Closed Cooling Water Program is consistent with GALL AMP XI.M21 with one exception which is related to performance testing. This exception would not affect the management of loss of material due to pitting, crevice, and galvanic corrosion. Therefore, the staff finds that the applicant is managing loss of material due to pitting, crevice, and galvanic corrosion of copper alloy piping, piping components, piping elements, and heat exchanger components exposed to closed cycle cooling water in a manner consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. In LRA Table 3.3.1, Item 3.3.1-51, the applicant stated that, for copper alloy components of the house heating boiler system, demineralized water system, and portions of the HVAC system, the Water Chemistry Control-Auxiliary Systems Program manages loss of material. The applicant's Water Chemistry Control-Auxiliary Systems Program is a plant-specific program. This program includes application of the One-Time Inspection Program to verify the effectiveness of the Water Chemistry Control-Auxiliary Systems Program. The staff evaluations 3-284

of these programs are documented in SER Section 3.0.3.3.7 and 3.0.3.1.6, respectively. The Water Chemistry Control-Auxiliary Systems Program uses specific manufacturers recommendations and general guidelines provided in EPRI Report 1007820 as acceptance criteria for chemistry parameters. It is combined with the One-Time Inspection Program to confirm the effectiveness of the Water Chemistry-Auxiliary Systems Program. The staff finds this combination of programs will adequately manage this aging effect and their use is acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.32 Reduction of Heat Transfer Due to Fouling For reduction of heat transfer due to fouling of steel, stainless steel, and copper alloy heat exchanger tubes exposed to closed cycle cooling water, the GALL Report recommends programs consistent with GALL AMP XI.M21, Closed-Cycle Cooling Water System. In LRA Table 3.3.1, Item 3.3.1-52, the applicant stated that the Water Chemistry Control-Closed Cooling Water Program manages reduction of heat transfer for copper alloy heat exchanger tubes exposed to closed cycle cooling water. The applicant also stated that auxiliary systems have no steel or stainless steel heat exchanger tubes exposed to closed cycle cooling water with a heat transfer intended function. During the audit and review, the applicant stated that for managing this aging effect, the One-Time Inspection Program will be explicitly identified in the system tables (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-Closed Cooling Water Program. The staff reviewed the applicant's Water Chemistry Control - Closed Cooling Water Program and One-Time Inspection Program. These evaluations are documented in SER Sections 3.0.3.2.18 and 3.0.3.1.6, respectively. The applicant's Water Chemistry Control - Closed Cooling Water Program is consistent with GALL AMP XI.M21 with one exception which is related to performance testing. During the audit and review, the staff asked the applicant to clarify how fouling would be adequately managed without performance testing. The applicant addressed the exception to the GALL Report for performance monitoring by stating that the One-Time Inspection Program includes inspections to verify the effectiveness of the water chemistry control AMP s by confirming that unacceptable cracking, loss of material, and fouling is not occurring. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control - Closed Cooling Water Program. The staffs evaluation of this exception is provided in SER Section 3.0.3.2.18.3. The staff determined that the applicant would select representative samples from the low-flow and stagnant flow areas of the listed CCWSs in the One-Time Inspection Program, which will provide assurance that the aging effects for this system will be adequately managed. On this basis, the staff finds this exception acceptable. 3-285

On the basis of its review, the staff finds that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.33 Loss of Material Due to General and Pitting Corrosion For loss of material due to general and pitting corrosion of steel compressed air system piping, piping components, and piping elements exposed to condensation (internal), the GALL Report recommends programs consistent with GALL AMP XI.M24, Compressed Air Monitoring. In LRA Table 3.3.1, Item 3.3.1-53, the applicant stated that the Instrument Air Quality Program manages loss of material for carbon steel components exposed to treated air. The staffs evaluation of the applicant's Instrument Air Quality Program is documented in SER Section 3.0.3.3.4. The staff determines that the applicants Instrument Air Quality Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. The program ensures that IA supplied to components is maintained free of water and significant contaminants, thereby preserving an environment that is not conducive to loss of material. On this basis, the staff finds that the applicants management of the loss of material for carbon steel components exposed to treated air using its Instrument Air Quality Program acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, in a manner consistent with the GALL Report. 3.3.2.1.34 Loss of Material Due to Pitting and Crevice Corrosion For loss of material due to pitting and crevice corrosion of stainless steel compressed air system piping, piping components, and piping elements exposed to internal condensation, the GALL Report recommends programs consistent with GALL AMP XI.M24, Compressed Air Monitoring. In LRA Table 3.3.1, Item 3.3.1-54, the applicant stated that the Instrument Air Quality Program manages loss of material for stainless steel components of auxiliary system exposed to treated air. The staffs evaluation of the applicant's Instrument Air Quality Program is documented in SER Section 3.0.3.3.4. The staff determines that the applicants Instrument Air Quality Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. The program ensures that IA supplied to components is maintained free of water and significant contaminants, thereby preserving an environment that is not conducive to loss of material. On this basis, the staff finds that the applicants management of the loss of material for stainless steel components of auxiliary system exposed to treated air using its Instrument Air Quality Program acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, in a manner consistent with the GALL Report. 3-286

3.3.2.1.35 Increased Hardness, Shrinkage and Loss of Strength Due to Weathering For increased hardness, shrinkage and loss of strength due to weathering of elastomer fire barrier penetration seals exposed to air, the GALL Report recommends programs consistent with GALL AMP XI.M26, Fire Protection. In the LRA Table 3.3.1, Item 3.3.1-61, the applicant stated that this line item was not used in the auxiliary systems tables. Fire barrier seals are evaluated as structural components in LRA Section 3.5. Cracking and the change in material properties of elastomer seals are managed by the Fire Protection Program. During the audit and review, the staff noted that in LRA Table 3.5.2-6 for component elastomer penetration sealant in a protected from weather environment, the aging effects are cracking and change in material properties. For this line item, two AMPs are shown, Fire Protection and Structures Monitoring. The referenced GALL Report line item is VII.G-1 and the LRA Table 3.3.1, Item 3.3.1-61. The GALL Reports Line Item VII.G-1 is for component fire barrier penetration seals. Furthermore, in the discussion column for LRA Table 3.3.1, Item 3.3.1-61, the applicant stated: Cracking and the change in material properties of elastomer seals are managed by the Fire Protection Program. The applicant was asked to clarify why this AMR line item is not split into two lines: (1) penetration sealant (fire) with AMP Fire Protection, the GALL Report reference VII.G-1, LRA Table 1 Line Item 3.3.1-61 and a Note B; and, (2) penetration sealant (flood, radiation) with AMP Structures Monitoring, the GALL Report reference III.A6-12, LRA Table 1 Line Item 3.5.1-44 and a Note C. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to separate this component line item into two line items as follows: Table 3.3-2 AMR Line Items for Elastomer Penetration Sealants

a. Delete line item:

Bulk Commodities N Structure NUREG Aging Effect Aging o and/or Intended 1801 Vol. Table 1 Material Environment Requiring Management t Component/ Function 2 Item Management Program e Commodity Item s Penetration EN, FB, Elastomer Protected Cracking, Fire III.A6-1 3.5.1-44 C sealant (fire, FLB, PB, from Change in Protection, 2 flood, SNS weather material Structures (TP-7) radiation) properties Monitoring 3-287

b. Add line item:

Bulk Commodities N Structure NUREG Aging Effect Aging o and/or Intended 1801 Vol. Table 1 Material Environment Requiring Management t Component/ Function 2 Item Management Program e Commodity Item s Penetration EN, FB, Elastomer Protected Cracking, Fire VII.G-1 3.3.1-61 B sealant PB, SNS from Change in Protection (A-19) (fire) weather material properties

c. Add line item:

Bulk Commodities N Structure NUREG Aging Effect Aging o and/or Intended 1801 Vol. Table 1 Material Environment Requiring Management t Component/ Function 2 Item Management Program e Commodity Item s Penetration EN, FLB, Elastomer Protected Cracking, Structures III.A6-1 3.5.1-44 C sealant PB, SNS from Change in Monitoring 2 (flood, weather material (TP-7) radiation) properties During the audit and review, the staff noted that in LRA Table 3.5.2-6 for elastomer seismic isolation joints in a protected from weather environment, the aging effects are cracking and change in material properties. The AMP shown is Fire Protection. The referenced GALL Report line item is VII.G-1 and the LRA Table 3.3.1, Item 3.3.1-61. The GALL Report Line Item VII.G-1 is for component fire barrier penetration seals. In the discussion column for LRA Table 3.3.1, Item 3.3.1-61, the applicant stated: Cracking and the change in material properties of elastomer seals are managed by the Fire Protection Program There is no mention of seismic gaps. In the discussion column for LRA Table 3.5.1, Item 3.5.1-44, the applicant stated: Loss of sealing is a consequence of elastomer cracking and change in material properties. Component types include: moisture barrier, compressible joints and seals used for seismic gaps, and fire barrier seals. The Structures Monitoring Program manages cracking and change in material properties. 3-288

Because this discussion addresses seismic gaps and fire barrier seals, the applicant was asked to clarify why this AMR line item does not show Structures Monitoring as the AMP instead of Fire Protection with the GALL Report reference III.A6-12, LRA Table 3.5.1, Item 3.5.1-44 with a Note C. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to denote the following changes:

1. Note C is changed to Note E for this line item.

2. The discussion in LRA Table 3.3.1, Item 3.3.1-61 is revised to read as follows. This line item was not used in the auxiliary systems tables. Fire barrier seals are evaluated as structural components in Section 3.5. Cracking and change in material properties of elastomer seals, including seismic isolation joints located in fire barriers, are managed by the Fire Protection Program.

3. An additional line item is added to read as follows.

Table 3.3-3 AMR Line Item for Elastomer Seismic Isolation Joints Bulk Commodities N Structure NUREG Aging Effect Aging o and/or Intended 1801 Vol. Table 1 Material Environment Requiring Management t Component/ Function 2 Item Management Program e Commodity Item s Seismic SSR Elastomer Protected Cracking, Structures III.A6-1 3.5.1-44 C isolation from Change in Monitoring 2 joint weather material (TP-7) properties On the basis of its review, the staff finds that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.36 Loss of Material Due to Wear For loss of material due to wear of steel fire rated doors exposed to air, the GALL Report recommends a program consistent with GALL AMP XI.M26, Fire Protection. In LRA Table 3.3.1, Item 3.3.1-63, the applicant stated that this line item was not used in the auxiliary systems tables. Steel fire doors are evaluated as structural components in LRA Section 3.5. The loss of material for fire doors is managed by the Fire Protection Program. During the audit and review, the staff noted that in LRA Table 3.5.2-6 for carbon steel fire doors in a protected from weather environment, the aging effect is loss of material. The referenced GALL Report line item is VII.G-3 and the LRA Table 3.3.1 Item is 3.3.1-63. The GALL Report Line Item VII.G-3 is for component fire rated doors. The applicant was asked to clarify why the note is C, (different component but consistent with the GALL Report otherwise) for this AMR line 3-289

item, instead of Note B (consistent with the GALL Report, but AMP takes exceptions). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA is revised to change Note C to Note B for this line item. The staff finds this change acceptable. On the basis of its review, the staff finds that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.37 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced Corrosion, and Fouling For 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 GALL Report recommends a program consistent with GALL AMP XI.M27, Fire Water System. In LRA Table 3.3.1, Item 3.3.1-68, the applicant stated that the loss of material in steel components exposed to raw or untreated water is managed by the Fire Water System Program. The staff reviewed the applicant's Fire Water System Program and its evaluation is documented in SER Section 3.0.3.2.12. The staff determined that the applicants Fire Water System Program consistent with GALL AMP XI.M27, with exceptions and enhancement, and finds that the applicants Fire Water System Program provided assurance that the aging effects for the components in the scope of its Fire Water System Program are adequately managed. The applicant also stated, in the LRA, that for carbon steel filter housing, strainer housing, tanks, traps, and valve bodies of the IA and PW systems exposed to untreated water, the Periodic Surveillance and Preventive Maintenance Program manages loss of material. The staffs review of the applicant's Periodic Surveillance and Preventive Maintenance Program is documented in SER Section 3.0.3.3.5. This is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for loss of material from carbon steel filter housing, strainer housing, tanks, traps, and valve bodies of the IA and PW systems, which the staff found acceptable. The applicant stated, in the LRA, that for carbon steel piping retired in place, piping of the potable water system, as well as orifices, piping, pump casings, strainer housings, and valve bodies of the radwaste systems, the applicant proposes to manage loss of material due to general, pitting, crevice, and MIC in untreated water using the One-Time Inspection Program. In RAI 3.3.1-68-K-01, the staff requested that the applicant provide justification for the use of the One-Time Inspection Program to management aging of carbon steel exposed to raw water in the potable water system; radwaste, liquid and solid system; and equipment retired in place system as opposed to a periodic inspection. In its response, by letter dated September 5, 2006, the applicant states that the "untreated water" environment for the carbon steel potable water system components in LRA Table 3.3.2-13-29 is not "raw water"; it is actually treated water. Water for this system comes from onsite wells and is monitored and treated to meet the regulations of the state of Vermont. It was labeled "untreated water" because conductivity and dissolved oxygen are not monitored. 3-290

Carbon steel is not expected to experience significant aging effects in this treated water environment. The applicant states that a One-Time Inspection of carbon steel potable water system components exposed to "untreated water" will be performed to confirm the absence of significant aging effects. If the One-Time Inspection identifies significant aging effects, the corrective action program will ensure that appropriate followup actions are implemented including periodic inspections, if necessary. The applicant also stated that the "untreated water" environment for the carbon steel and copper alloy radwaste system components in LRA Table 3.3.2-13-32 is originally treated water that may now contain contaminants. Therefore, the aging management program has been changed, from One-Time Inspection Program to Periodic Surveillance and Preventive Maintenance Program for managing loss of material for carbon steel and copper alloy components in the radwaste system exposed to untreated water (LRA Table 3.3.2-13-32). The "untreated water" environment for the equipment retired in place system carbon steel piping component in LRA Table 3.3.2-13-35 should be listed as Air - indoor (int) and that the LRA table will be changed to reflect the above environment. Based on its review, the staff finds the applicants response to RAI 3.3.1-68-K-03 acceptable because this is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for loss of material from carbon steel components exposed to raw water in the potable water; radwaste, liquid and solid; and equipment retired in place systems. The staffs concern described in RAI 3.3.1-68-K-03 is resolved. On the basis of its review, the staff finds that the applicant, with the satisfactory resolution of the request for additional information identified above, appropriately addressed the aging effect/mechanism, in a manner consistent with the GALL Report. 3.3.2.1.38 Loss of Material Due to Pitting and Crevice Corrosion, and Fouling For loss of material due to pitting and crevice corrosion, and fouling of stainless steel piping, piping components, and piping elements exposed to raw water, the GALL Report recommends a program consistent with GALL AMP XI.M27, Fire Water System. In LRA Table 3.3.1, Item 3.3.1-69, the applicant stated that the loss of material in stainless steel components exposed to raw water is managed by the Fire Water System Program, Fire Protection Program, and the One-Time Inspection Program. During the audit and review, the staff noted that the applicant did not apply the One-Time Inspection Program to any AMR line items to which LRA Table 3.3.1, Item 3.3.1-69 was applied (Tables 3.3.2.-1 through 3.3.2.-13). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant revised the LRA to remove the reference to the One-Time Inspection Program in LRA Table 3.3.1, Item 3.3.1-69. The staff finds this acceptable. The staff also asked the applicant to justify the application of the Fire Protection Program rather than the Fire Water System Program to manage filters and filter housings in raw water. The applicant explained that the components in question were managed as support components of the engine that drives the fire pump. The Fire Protection Program performs tests and inspections of the diesel engine and its support components and is therefore credited for these components. 3-291

The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in SER Section 3.0.3.2.11. This AMP is consistent, with exceptions and enhancements, with GALL AMP XI.M26, Fire Protection. The staff determined it to be an acceptable method for management of loss of material from EDG stainless steel filters and filter housings exposed to raw water. The staff determined that management of the stainless steel filters and filter housings in the fire protection water system using the Fire Protection Program to be consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant, with the change in the application identified above, appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.3.2.1.39 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion, and Fouling For loss of material due to pitting, crevice, and MIC, and fouling of copper alloy piping, piping components, and piping elements exposed to raw water, the GALL Report recommends programs consistent with GALL AMP XI.M27, Fire Water System. In LRA Table 3.3.1, Item 3.3.1-70, the applicant stated that the loss of material in copper alloy components exposed to raw water is managed by the Fire Water System Program, Fire Protection Program, and the One-Time Inspection Program. The staff asked the applicant to justify the application of the Fire Protection Program rather than the Fire Water System Program to manage copper-alloy heat exchangers and tubing in raw water. The applicant explained that the components in question were managed as support components of the engine that drives the fire pump. The Fire Protection Program performs tests and inspections of the diesel engine and its support components and is therefore credited for these components. The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in SER Section 3.0.3.2.11. This AMP is consistent, with exceptions and enhancements, with GALL AMP XI.M26, Fire Protection. The staff determines it to be an acceptable method for management of loss of material from fire water system copper-alloy heat exchangers and tubing exposed to raw water. The staff determines that management of the copper-alloy heat exchangers and tubing in the fire protection water system using the Fire Protection Program to be consistent with the GALL Report and therefore acceptable. During the audit and review, the staff asked the applicant to justify the application of the One-Time Inspection Program rather than the Fire Water System Program to manage copper-alloy tubing in untreated water of the radwaste, liquid and solid system. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant revised LRA Table 3.3.2-13-32 to replace the AMP of One-Time Inspection with the Periodic Surveillance and Preventive Maintenance Program for all line items containing carbon steel and copper alloy with an environment of untreated water. 3-292

The staffs evaluation of the applicant's Periodic Surveillance and Preventive Maintenance Program is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. The Periodic Surveillance and Preventive Maintenance Program manages loss of material of copper-alloy tubing exposed to untreated water by visual inspections or other NDE techniques. On this basis, the staff determines that this program is capable of detecting loss of material for copper-alloy tubing. On the basis of its review, the staff finds that the applicant, with the application changes identified above, appropriately addressed the aging effect/mechanism, in a manner consistent with the GALL Report. 3.3.2.1.40 Loss of Material Due to General, Pitting, and Crevice Corrosion For loss of material due to general, pitting, and crevice corrosion of steel piping, piping components, and piping elements exposed to moist air or condensation (internal), the GALL Report recommends programs consistent with GALL AMP XI.M38, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components. In LRA Table 3.3.1, Item 3.3.1-71, the applicant stated that the loss of material for steel components exposed to moist air or condensation is managed by the Periodic Surveillance and Preventive Maintenance Program using visual inspections or other NDE techniques. The staffs review of the applicants Periodic Surveillance and Preventive Maintenance Program is documented in SER Section 3.0.3.3.5. The Periodic Surveillance and Preventive Maintenance Program will manage the loss of material through visual inspections or other NDE techniques. On this basis, the staff determines that the aging of the steel piping, piping components, and piping elements is adequately managed. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, in a manner consistent with the GALL Report. 3.3.2.1.41 Loss of Material Due to General, Pitting, Crevice, and (For Drip Pans and Drain Lines) Microbiologically-Influenced Corrosion In LRA Table 3.3.1, Item 3.3.1-72, the applicant stated that loss of material of steel component internal surfaces exposed to condensation is managed by the Periodic Surveillance and Preventive Maintenance Program, using visual inspections or other NDE techniques. The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program. This evaluation is documented in SER Section 3.0.3.3.5. This is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for loss of material from carbon steel exposed to condensation in fan housings of the SWS and from carbon steel exposed to condensation in heat exchanger housings of the HVAC system. 3-293

On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, in a manner consistent with the GALL Report. 3.3.2.1.42 Loss of Material Due to General Corrosion In LRA Table 3.3.1, Item 3.3.1-73, the applicant stated that this line item was not used in the auxiliary systems tables. Steel crane structural girders are evaluated as structural components in SER Section 3.5. Loss of material for steel crane structural components is managed by the Periodic Surveillance and Preventive Maintenance Program and the Structures Monitoring Program. During the audit and review, the applicant confirmed that aging management of steel crane structural girders in load handling will conform to the standards cited in GALL AMP XI.M23 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems. The applicant's technical personnel stated that reactor building steel crane structural girders used in load handling are inspected in accordance with the Periodic Surveillance and Preventive Maintenance Program and process facility crane rails and girders are inspected in accordance with the Structures Monitoring Program. The Structures Monitoring Program will be enhanced, as identified in Appendix B, to address crane rails and girders. Aging management activities for crane rails and girders in accordance with these two programs are consistent with the program element described for in GALL AMP XI.M23. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, in a manner consistent with the GALL Report. 3.3.2.1.43 Loss of Material Due to General, Pitting, Crevice, Galvanic, and Microbiologically-Influenced Corrosion, and Fouling For loss of material due to general, pitting, crevice, galvanic, and MIC, and fouling of steel heat exchanger components exposed to raw water, the GALL Report recommends programs consistent with GALL AMP XI.M20, Open-Cycle Cooling Water System. In LRA Table 3.3.1, Item 3.3.1-77, the applicant stated that management of this aging effect is consistent with the GALL Report for most auxiliary systems. The Service Water Integrity Program manages loss of material for steel heat exchanger. For steel heat exchanger tubes of the reactor building CCWS, the Heat Exchanger Monitoring Program manages loss of material. The staffs evaluation of the applicant's Service Water Integrity Program is documented in SER Section 3.0.3.2.16. The applicants aging management of loss of material due to general, pitting, crevice, galvanic, and MIC, and fouling of steel heat exchanger components is consistent with the GALL Report and therefore acceptable. The staffs evaluation of the applicant's Heat Exchanger Monitoring Program is documented in SER Section 3.0.3.3.1. The Heat Exchanger Monitoring Program manages the loss of material for steel heat exchanger tubes of the reactor building through visual inspections or eddy current inspections on selected heat exchangers in various systems. On this basis, the staff determines that the aging of steel heat exchanger of the reactor building is adequately managed. 3-294

On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, in a manner consistent with the GALL Report. 3.3.2.1.44 Reduction of Heat Transfer Due to Fouling For reduction of heat transfer due to fouling of stainless steel and copper alloy heat exchanger tubes exposed to raw water, the GALL Report recommends programs consistent with GALL AMP XI.M20, Open-Cycle Cooling Water System. In LRA Table 3.3.1, Item 3.3.1-83, the applicant stated that for the fire protection system, the Fire Protection Program manages reduction of heat transfer in copper alloy heat exchanger tubes. During the audit and review, the staff asked the applicant to clarify the basis for management of fouling of copper alloy heat exchanger tubes exposed to raw water using the Fire Protection Program. The applicant stated that the heat exchangers represented are the fire pump diesel jacket water heat exchanger and the gear box oil cooler. Both heat exchangers use water from the fire water system (raw water) for cooling. The Fire Protection Program performs tests and inspections of the diesel engine. Since these heat exchangers are part of the fire diesel it is appropriate to manage fouling with the Fire Protection Program which tests the engine and its auxiliaries. The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in SER Section 3.0.3.2.11. This AMP is consistent, with exceptions and enhancements, with GALL AMP XI.M26, Fire Protection. The staff determines it to be an acceptable method for management of fouling of copper-alloy heat exchanger tubes exposed to raw water. The staff determines that management of fouling of the copper-alloy heat exchanger tubes in the fire protection water system using the fire protection AMP to be consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff determines that the applicant appropriately addressed the aging effect/mechanism, in a manner consistent with the GALL Report. Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for which the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determines that the applicant adequately addressed the issues that were further evaluated. The staff finds that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). 3-295

The staff evaluated the applicants claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicants consideration of recent operating experience and proposals for managing the 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 its AMRs. Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for these components 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 AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended Summary of Technical Information in the Amended Application. In LRA Section 3.3.2.2, the applicant further evaluates aging management, as recommended by the GALL Report, for the auxiliary systems 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 stress corrosion cracking
• cracking due to stress corrosion cracking 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
• quality assurance for aging management of nonsafety-related components Staff Evaluation. 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 audited and reviewed the applicants evaluation to determine whether it adequately addressed the issues further evaluated. In addition, the staff reviewed the applicants further evaluations against the criteria contained in SRP-LR Section 3.3.2.2. The staffs review of the applicants further evaluation follows.

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3.3.2.2.1 Cumulative Fatigue Damage LRA Section 3.3.2.2.1 states that fatigue is a TLAA, as required by 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the staffs review of the applicants evaluation of this TLAA. 3.3.2.2.2 Reduction of Heat Transfer Due to Fouling The staff reviewed LRA Section 3.3.2.2.2 against the criteria in SRP-LR Section 3.3.2.2.2. LRA Section 3.3.2.2.2 addresses the reduction of heat transfer of stainless steel heat exchanger tubes exposed to treated water due to fouling. SRP-LR Section 3.3.2.2.2 states that reduction of heat transfer due to fouling may occur in stainless steel heat exchanger tubes exposed to treated water. The existing program controls water chemistry to manage reduction of heat transfer due to fouling. However, control of water chemistry may be inadequate; therefore, the GALL Report recommends that the effectiveness of water chemistry control programs should be verified to ensure that reduction of heat transfer due to fouling does not occur. A one-time inspection is an acceptable method to ensure that reduction of heat transfer does not occur and that component intended functions will be maintained during the period of extended operation. The applicant stated that reduction of heat transfer due to fouling for stainless steel heat exchanger tubes exposed to treated water is managed by the Water Chemistry Control-BWR Program. The effectiveness of the applicants Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including areas of stagnant flow. The staff finds this to be consistent with the criteria of SRP-LR Section 3.3.2.2.2 and therefore acceptable. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.2 criteria. For those line items that apply to LRA Section 3.3.2.2.2, 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). 3-297

3.3.2.2.3 Cracking Due to Stress Corrosion Cracking The staff reviewed LRA Section 3.3.2.2.3 against the following SRP-LR Section 3.3.2.2.3 criteria: (1) LRA Section 3.3.2.2.3 addresses the cracking due to SCC, this aging effect is not applicable to VYNPS. Cracking due to SCC can occur in the stainless steel piping, piping components, and piping elements of the BWR SLC system that are exposed to sodium pentaborate solution greater than 140EF. At VYNPS, the sodium pentaborate solution in the SLC system does not exceed 140EF. Therefore cracking due to SCC is not an AERM for the SLC system. This item is not applicable to VYNPS. SRP-LR Section 3.3.2.2.3 states that cracking due to SCC may occur in the stainless steel piping, piping components, and piping elements of the BWR SLC system that are exposed to sodium pentaborate solution greater than 60 EC (140 EF). The existing AMP monitors and controls water chemistry to manage the aging effects of cracking due to SCC. However, high concentrations of impurities in crevices and with stagnant flow conditions may cause SCC; therefore, the GALL Report recommends that the effectiveness of water chemistry control programs should be verified to ensure that SCC does not occur. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that SCC does not occur and that component intended functions will be maintained during the period of extended operation. The staff determines that although the SLC injects through the drywell, where ambient temperatures may exceed 140EF, sodium pentaborate is not normally present in this portion of the system. For this reason, the staff finds that cracking in the SLC system due to SCC does not require aging management at VYNPS. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. (2) LRA Section 3.3.2.2.3 addresses cracking of stainless steel heat exchanger components exposed to treated water greater than 140EF due to SCC. SRP-LR Section 3.3.2.2.3 states that cracking due to SCC may occur in stainless steel and stainless clad steel heat exchanger components exposed to treated water greater than 60 EC (140 EF). The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed. 3-298

The applicant stated, in the LRA, that cracking due to SCC in stainless steel heat exchanger components exposed to treated water greater than 140EF is an AERM at VYNPS. There are no auxiliary system components at VYNPS with stainless steel cladding. For VYNPS auxiliary systems these stainless steel heat exchanger components are managed by the Water Chemistry Control-BWR Program. This program monitors parameters and contaminants to ensure they remain within the limits specified by the EPRI guidelines. The effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program for managing cracking using visual and ultrasonic inspection techniques. The use of the applicants One-Time Inspection Program in conjunction with its Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. The staff finds that this combination satisfies the criteria of SRP-LR Appendix A.1 and therefore is acceptable. (3) LRA Section 3.3.2.2.3 addresses cracking of stainless steel diesel engine exhaust piping exposed to diesel exhaust due to SCC. SRP-LR Section 3.3.2.2.3 states that cracking due to SCC may occur in stainless steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed. The applicant stated, in the LRA, that cracking due to SCC in stainless steel diesel engine exhaust piping exposed to diesel exhaust is an AERM at VYNPS. At VYNPS, cracking of stainless steel exhaust piping in the EDG system is managed by the Periodic Surveillance and Preventive Maintenance Program. This program uses visual and other NDE techniques to manage cracking of the piping. These inspections will manage the aging effect of cracking such that the intended function of the component will not be affected. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for cracking of stainless steel due to SCC when exposed to diesel exhaust. The staff finds that this satisfies the criteria of SRP-LR Section 3.3.2.2.3 and is therefore acceptable. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.3 criteria. For those line items that apply to LRA Section 3.3.2.2.3, 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 function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 3-299

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 SRP-LR Section 3.3.2.2.4 criteria: (1) LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading. SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occur in stainless steel PWR non-regenerative heat exchanger components exposed to treated borated water greater than 60 EC (140 EF) in the chemical and volume control system. The existing AMP monitors and controls primary water chemistry in PWRs to manage the aging effects of cracking due to SCC. However, control of water chemistry does not preclude cracking due to SCC and cyclic loading; therefore, the effectiveness of water chemistry control programs should be verified to ensure that cracking does not occur. The GALL Report recommends that a plant-specific AMP be evaluated to verify the absence of cracking due to SCC and cyclic loading to ensure that these aging effects are adequately managed. An acceptable verification program is to include temperature and radioactivity monitoring of the shell side water and eddy current testing of tubes. VYNPS is a BWR and does not have a non-regenerative heat exchanger exposed to treated borated water. This item is not applicable to VYNPS. The staff confirmed that VYNPS has no components from this group. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. (2) LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occur in stainless steel PWR regenerative heat exchanger components exposed to treated borated water greater than 60EC (140 EF). The existing AMP monitors and controls primary water chemistry in PWRs to manage the aging effects of cracking due to SCC. However, control of water chemistry does not preclude cracking due to SCC and cyclic loading; therefore, the effectiveness of water chemistry control programs should be verified to ensure that cracking does not occur. The GALL Report recommends that a plant-specific AMP be evaluated to verify the absence of cracking due to SCC and cyclic loading to ensure that these aging effects are adequately managed. VYNPS is a BWR and does not have a regenerative heat exchanger exposed to treated borated water. This item is not applicable to VYNPS. The staff confirmed that VYNPS has no components from this group. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. 3-300

(3) LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading. SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occur in the stainless steel pump casing for the PWR high-pressure pumps in the chemical and volume control system. The existing AMP monitors and controls primary water chemistry in PWRs to manage the aging effects of cracking due to SCC. However, control of water chemistry does not preclude cracking due to SCC and cyclic loading; therefore, the effectiveness of water chemistry control programs should be verified to ensure that cracking does not occur. The GALL Report recommends that a plant-specific AMP be evaluated to verify the absence of cracking due to SCC and cyclic loading to ensure that these aging effects are adequately managed. VYNPS is a BWR and does not have a chemical and volume control system. This item is not applicable to VYNPS. The staff confirmed that VYNPS has no components from this group. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. 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 SRP-LR Section 3.3.2.2.5 criteria: (1) LRA Section 3.3.2.2.5 addresses cracking and change of material properties due to elastomer degradation in elastomer duct flexible connections of the HVAC systems exposed to air-indoor. SRP-LR Section 3.3.2.2.5 states that hardening and loss of strength due to elastomer degradation may occur in elastomer seals and components of heating and ventilation systems exposed to air-indoor uncontrolled (internal/external). The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed. The applicant stated in the LRA that cracking and change in material properties due to elastomer degradation in elastomer duct flexible connections of the HVAC systems exposed to air-indoor are an AERM at VYNPS. These aging effects are managed by the Periodic Surveillance and Preventive Maintenance Program. This program includes visual inspections and physical manipulation of the flexible connections to confirm that the components are not experiencing any aging that would affect accomplishing their intended functions. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for cracking and change of material properties due to elastomer degradation in elastomer duct flexible connections of the HVAC systems exposed to air. 3-301

The staff finds that this satisfies the criteria of SRP-LR Section 3.3.2.2.5 and is therefore acceptable. (2) LRA Section 3.3.2.2.5 addresses the hardening and loss of strength due to elastomer degradation, this aging effect is not applicable to VYNPS. For the auxiliary systems at VYNPS, no credit is taken for any elastomer linings to prevent loss of material from the underlying carbon steel material such that the material is identified as carbon steel for the AMR. This item is not applicable to VYNPS. SRP-LR Section 3.3.2.2.5 states that hardening and loss of strength due to elastomer degradation may occur in elastomer linings of the filters, valves, and ion exchangers in spent fuel pool cooling and cleanup systems (BWR and PWR) exposed to treated water or treated borated water. The GALL Report recommends that a plant-specific AMP be evaluated to determine and assess the qualified life of the linings in the environment to ensure that these aging effects are adequately managed. In the discussion column of LRA Table 3.3.1, Item 3.3.1-12, the applicant stated that there are no elastomer lined components exposed to treated water in the auxiliary systems. The staff confirmed that VYNPS has no components from this group. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.5 criteria. For those line items that apply to LRA Section 3.3.2.2.5, 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). 3.3.2.2.6 Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General Corrosion The staff reviewed LRA Section 3.3.2.2.6 against the criteria in SRP-LR Section 3.3.2.2.6. LRA Section 3.3.2.2.6 addresses the loss of material and cracking of Boral spent fuel storage racks exposed to a treated water environment due to general corrosion. SRP-LR Section 3.3.2.2.6 states that reduction of neutron-absorbing capacity and loss of material due to general corrosion may occur in the neutron-absorbing sheets of BWR and PWR spent fuel storage racks exposed to treated water or treated borated water. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed. The applicant stated, in the LRA, that loss of material and cracking are an AERM for Boral spent fuel storage racks exposed to a treated water environment. These aging effects are managed by the Water Chemistry Control-BWR Program. 3-302

In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-BWR Program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program. The Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry to manage aging effects caused by corrosion. The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. On this basis, the staff finds the aging effect of loss of material due to general corrosion to be adequately managed. The applicant also stated that reduction of neutron-absorbing capacity is insignificant and requires no aging management. The potential for aging effects due to sustained irradiation of Boral was previously evaluated by the staff and determined to be insignificant. Plant operating experience with Boral coupons inspected in 1991 and 1996 is consistent with the staff's conclusion. Therefore, the staff finds that reduction of neutron-absorbing capacity does not require aging management. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.6 criteria. For those line 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 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). 3.3.2.2.7 Loss of Material Due to General, Pitting, and Crevice Corrosion The staff reviewed LRA Section 3.3.2.2.7 against the following SRP-LR Section 3.3.2.2.7 criteria: (1) LRA Section 3.3.2.2.7 addresses the loss of material of carbon steel piping and components in other auxiliary systems exposed to treated water due to general, pitting and crevice corrosion. SRP-LR Section 3.3.2.2.7 states that loss of material due to general, pitting, and crevice corrosion may occur in steel piping, piping components, and piping elements, including the tubing, valves, and tanks in the reactor coolant pump oil collection system, exposed to lubricating oil (as part of the fire protection system). The existing AMP periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of the lubricating oil program. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. In addition, corrosion may occur at locations in the reactor coolant pump oil collection tank where water from wash-downs may accumulate; therefore, the effectiveness of the program should be verified to ensure that 3-303

corrosion does not occur. The GALL Report recommends further evaluation of programs to manage loss of material due to general, pitting, and crevice corrosion, including determination of the thickness of the lower portion of the tank. A one-time inspection is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The applicant stated, in the LRA, that steel piping and components in auxiliary systems at VYNPS that are exposed to lubricating oil are managed by the Oil Analysis Program, which includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. Operating experience at VYNPS has confirmed the effectiveness of this program in maintaining contaminants within limits such that corrosion has not and will not affect the intended functions of these components. During the audit and review, the staff determines that Oil Analysis Program alone is not sufficient in managing the loss of material of steel piping, piping components, and piping elements, including the tubing, and valves, exposed to lubricating oil (as part of the fire protection system). In a letter dated July 14, 2006, the applicant revised its LRA to state that the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.3.2.2.7. Also, in the LRA, the applicant stated that VYNPS is a BWR with an inert containment atmosphere and has no reactor coolant pump oil collection system. The staff confirmed that VYNPS has no components from this group. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. (2) LRA Section 3.3.2.2.7 addresses loss of material of carbon steel piping and components in other auxiliary systems exposed to treated water due to general, pitting and crevice corrosion. SRP-LR Section 3.3.2.2.7 states that loss of material due to general, pitting, and crevice corrosion may occur in steel piping, piping components, and piping elements in the BWR RWCU and shutdown cooling systems exposed to treated water. The existing AMP monitors and controls reactor water chemistry to manage the aging effects of loss of material from general, pitting, and crevice corrosion. However, high concentrations of impurities in crevices and with stagnant flow conditions may cause general, pitting, or crevice corrosion; therefore, the effectiveness of the chemistry control program should be 3-304

verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage loss of material from general, pitting, and crevice corrosion to verify the effectiveness of the water chemistry program. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The applicant stated in the LRA that VYNPS does not have a separate shutdown cooling system. Loss of material due to general, pitting, and crevice corrosion in carbon steel piping and components in other auxiliary systems exposed to treated water are managed by the Water Chemistry Control-BWR Program. The effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including areas of stagnant flow. The staff reviewed the applicant's Water Chemistry Control-BWR Program and One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements. This combination satisfies the criteria of SRP-LR Section 3.2.2.2.7 and therefore is acceptable. The staff finds this to be consistent with the criteria of SRP-LR Section 3.3.2.2.7 and therefore acceptable. (3) LRA Section 3.3.2.2.7 addresses the loss of material of carbon steel and stainless steel diesel exhaust piping and components exposed to diesel exhaust in the EDG and John Deere Diesel generator systems due to general (steel only), pitting and crevice corrosion. SRP-LR Section 3.3.2.2.7 states that loss of material due to general (steel only), pitting, and crevice corrosion may occur in steel and stainless steel diesel exhaust piping, piping components, and piping elements exposed to diesel exhaust. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed. The applicant stated in the LRA that loss of material due to general (steel only), pitting and crevice corrosion for carbon steel and stainless steel diesel exhaust piping and components exposed to diesel exhaust in the EDG and John Deere Diesel generator systems is managed by the Periodic Surveillance and Preventive Maintenance Program. This program uses visual and other NDE techniques to manage loss of material for these components. The carbon steel and stainless steel diesel exhaust piping and components 3-305

in the fire protection system are managed by the Fire Protection Program. The applicants Fire Protection Program uses visual inspections of diesel exhaust piping and components to manage loss of material. These inspections in the Periodic Surveillance and Preventive Maintenance Program and Fire Protection Program will manage the aging effect of loss of material such that the intended function of the components will not be affected. The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program. The Periodic Surveillance and Preventive Maintenance manages the loss of material due to general, pitting, and crevice corrosion through periodic inspections and tests. These inspections and tests include visual or other NDE techniques. On this basis, the staff determines that the aging of the steel and stainless steel diesel exhaust piping, piping components, and piping elements exposed to diesel exhaust is adequately managed. The staff also reviewed the applicant's Fire Protection Program and its evaluation is documented in SER Section 3.0.3.2.11. The Fire Protection Program uses visual inspections of diesel exhaust piping and components. This AMP is consistent, with exceptions and enhancements, with GALL AMP XI.M26, Fire Protection. On this basis, staff determines that the aging of the carbon steel and stainless steel diesel exhaust piping and components in the fire protection system is adequately managed. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.3.2.2.7. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.7 criteria. For those line items that apply to LRA Section 3.3.2.2.7, 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). 3.3.2.2.8 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced Corrosion The staff reviewed LRA Section 3.3.2.2.8 against the criteria in SRP-LR Section 3.3.2.2.8. LRA Section 3.3.2.2.8 addresses loss of material of carbon steel (with or without coating or wrapping) piping and components buried in soil in the SW, fuel oil, and fire protection-water systems due to general, pitting, crevice, and MIC. SRP-LR Section 3.3.2.2.8 states that loss of material due to general, pitting, and crevice corrosion, and MIC may occur in steel (with or without coating or wrapping) piping, piping components, and piping elements buried in soil. Buried piping and tanks inspection programs rely on industry practice, frequency of pipe excavation, and operating experience to manage the 3-306

effects of loss of material from general, pitting, and crevice corrosion, and MIC. The effectiveness of the buried piping and tanks inspection program should be verified to evaluate an applicants inspection frequency and operating experience with buried components, ensuring that loss of material does not occur. The applicant stated in the LRA that loss of material due to general, pitting, crevice, and MIC for carbon steel (with or without coating or wrapping) piping and components buried in soil in the SW, fuel oil, and fire protection-water systems is managed by the Buried Piping Inspection Program. This program will include: (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried carbon steel components. The applicant also stated that buried components are to be inspected when excavated during maintenance. An inspection will be performed within 10 years of entering the period of extended operation, unless an opportunistic inspection occurs within this ten-year period. This program will manage the aging effect of loss of material such that the intended function of the components will not be affected. During the audit and review, the staff confirmed that buried piping has already been inspected within the final ten-year period before the period of extended operation. Therefore, even if no other buried piping is examined before the period of extended operation, VYNPS has complied with staff guidance regarding the examination of buried piping before the end of the current operating license. The proposed schedule for inspection (if there is no other opportunity) is consistent with the staffs position and therefore acceptable. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.8 criteria. For those line 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 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). 3.3.2.2.9 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 SRP-LR Section 3.3.2.2.9 criteria: (1) LRA Section 3.3.2.2.9 addresses the loss of material of carbon steel piping and components exposed to fuel oil due to general, pitting, crevice, and MIC. SRP-LR Section 3.3.2.2.9 states that loss of material due to general, pitting, and crevice corrosion, MIC, and fouling may occur in steel piping, piping components, piping elements, and tanks exposed to fuel oil. The existing AMP relies on fuel oil chemistry programs to monitor and control fuel oil contamination to manage loss of material due to corrosion or fouling. Corrosion or fouling may occur at locations where contaminants accumulate. The effectiveness of fuel oil chemistry programs should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of 3-307

programs to manage loss of material due to general, pitting, and crevice corrosion, MIC, and fouling to verify the effectiveness of fuel oil chemistry programs. A one-time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The applicant stated in the LRA that fouling is not an AERM for the fuel oil system at VYNPS. Loss of material due to general, pitting, crevice, and MIC for carbon steel piping and components exposed to fuel oil is an AERM at VYNPS and these components are managed by the Diesel Fuel Monitoring Program. This program includes sampling and monitoring of fuel oil quality to ensure they remain within the limits specified by the ASTM standards. Maintaining parameters within limits ensures that significant loss of material will not occur. Ultrasonic inspection of storage tank bottoms where water and contaminants accumulate will be performed to confirm the effectiveness of the Diesel Fuel Monitoring Program. In addition, operating experience has confirmed the effectiveness of this program in maintaining fuel oil quality within limits such that loss of material will not affect the intended functions of these components. During the audit and review, the staff determines that Diesel Fuel Monitoring Program alone is not sufficient in managing the loss of material of steel piping, piping components, piping elements, and tanks exposed to fuel oil. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program verifies the effectiveness of the Diesel Fuel Monitoring Program. The staff finds that, based on the programs and LRA review identified above, the applicant has met the criteria of SRP-LR Section 3.3.2.2.9. (2) LRA Section 3.3.2.2.9 addresses loss of material of carbon steel heat exchanger components exposed to lubricating oil due to general, pitting, crevice, MIC and fouling. SRP-LR Section 3.3.2.2.9 states that loss of material due to general, pitting, and crevice corrosion, MIC, and fouling may occur in steel heat exchanger components exposed to lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of lubricating oil programs. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The applicant stated in the LRA that loss of material due to general, pitting, crevice, MIC and fouling for carbon steel heat exchanger components exposed to lubricating oil are an AERM in the auxiliary systems, and is managed by the Oil Analysis Program. This program includes periodic sampling and analysis of lubricating oil to maintain 3-308

contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion or fouling. Operating experience has confirmed the effectiveness of this program in maintaining contaminants within limits such that corrosion and fouling has not and will not affect the intended functions of these components. The staff determines that Oil Analysis Program alone is not sufficient in managing the loss of material of steel heat exchanger components exposed to lubricating oil. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA is revised to state the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program. The staff finds that, based on the programs and LRA review identified above, the applicant has met the criteria of SRP-LR Section 3.3.2.2.9. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.9 criteria. For those line items that apply to LRA Section 3.3.2.2.9, 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). 3.3.2.2.10 Loss of Material Due to Pitting and Crevice Corrosion The staff reviewed LRA Section 3.3.2.2.10 against the following SRP-LR Section 3.3.2.2.10 criteria: (1) LRA Section 3.3.2.2.10 addresses loss of material from steel piping with elastomer lining or stainless steel cladding due to pitting and crevice corrosion is not applicable to VYNPS. Loss of material due to pitting and crevice corrosion could occur in BWR and PWR steel piping with elastomer lining or stainless steel cladding that are exposed to treated water and treated borated water if the cladding or lining is degraded. For the auxiliary systems at VYNPS no credit is taken for any elastomer linings or stainless steel cladding to prevent loss of material from the underlying carbon steel material such that the material is identified as carbon steel for the AMR. SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice corrosion may occur in BWR and PWR steel piping with elastomer lining or stainless steel cladding exposed to treated water and treated borated water if the cladding or lining is degraded. The existing AMP monitors and controls reactor water chemistry to manage the aging effects of loss of material from pitting and crevice corrosion. However, high concentrations of impurities in crevices and with stagnant flow conditions may cause pitting or crevice corrosion; 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 manage loss of material from pitting and crevice corrosion to verify the effectiveness of water chemistry control programs. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. 3-309

The applicant was asked in RAI 3.3.1-22-K-01 to confirm that no auxiliary components have elastomer linings or stainless steel cladding. If there are such components, to provide a list of these components. The applicant was also asked to provide additional justification for the determination that pitting and crevice corrosion do not require aging management. In a letter dated September 5, 2006, the applicant provided its response to RAI 3.3.1-22-K-01. The applicant stated that elastomer linings are conservatively not credited to prevent loss of material of underlying carbon steel material in auxiliary systems. Furthermore, the applicant stated that in LRA Section 3.3.2.2.7, loss of material due to general, pitting, and crevice corrosion in carbon steel piping and components in auxiliary systems exposed to treated water in managed by the Water Chemistry Control-BWR Program. The effectiveness of the Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program. The staff reviewed the applicants response and finds it acceptable. The staff also confirmed that steel piping with elastomer lining is managed in accordance with the component group of carbon steel piping and components. Further, the staffs concern described in RAI 3.3.1-22-K-01 is resolved. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.3.2.2.10. (2) LRA Section 3.3.2.2.10 addresses the loss of material of stainless steel piping and components and stainless steel heat exchanger components exposed to treated water due to pitting and crevice corrosion. SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice corrosion may occur in stainless steel and aluminum piping, piping components, piping elements, and for stainless steel and steel with stainless steel cladding heat exchanger components exposed to treated water. The existing AMP monitors and controls reactor water chemistry to manage the aging effects of loss of material from pitting and crevice corrosion. However, high concentrations of impurities in crevices and with stagnant flow conditions may cause pitting or crevice corrosion; 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 manage loss of material from pitting and crevice corrosion to verify the effectiveness of water chemistry control programs. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The applicant stated in the LRA that in the auxiliary systems at VYNPS there are no aluminum components exposed to treated water. Loss of material due to pitting and crevice corrosion for stainless steel piping and components, and for stainless steel heat exchanger components exposed to treated water in the auxiliary systems at VYNPS is 3-310

managed by the Water Chemistry Control-BWR Program. The effectiveness of the program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including susceptible locations such as areas of stagnant flow. The staff reviewed the applicants Water Chemistry Control-BWR Program and One-Time Inspection Program. The use of the One-Time Inspection Program in conjunction with the Water Chemistry Control-BWR Program provides both the preventive and inspection elements contained in a plant-specific program. This combination satisfies the criteria of SRP-LR Appendix A.1 and therefore is acceptable. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.3.2.2.10. (3) LRA Section 3.3.2.2.10 addresses the loss of material of copper alloy components exposed to condensation (external) in the HVAC and other auxiliary systems due to pitting and crevice corrosion. SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice corrosion may occur in copper alloy HVAC piping, piping components, and piping elements exposed to condensation (external). The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed. The applicant stated in the LRA that loss of material due to pitting and crevice corrosion for copper alloy components exposed to condensation (external) in the HVAC and other auxiliary systems is managed by the System Walkdown Program, the Periodic Surveillance and Preventive Maintenance Program, the Service Water Integrity Program, and the Heat Exchanger Monitoring Program. The applicants System Walkdown Program includes a periodic visual inspection. The applicants Periodic Surveillance and Preventive Maintenance Program, Service Water Integrity Program and the Heat Exchanger Monitoring Program include other NDE techniques to manage loss of material of the components. These inspections will manage the aging effect of loss of material such that the intended function of the components will not be affected. The staff evaluated each auxiliary system AMR associated with copper alloy components exposed to condensation. The application of programs that are not plant-specific was discussed with the applicants technical personnel. In each case, the staff finds that an appropriate program had been identified for monitoring loss of material due to pitting and crevice corrosion. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.3.2.2.10. 3-311

(4) LRA Section 3.3.2.2.10 addresses the loss of material of copper alloy components exposed to lubricating oil due to pitting and crevice corrosion. SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice corrosion may occur in copper alloy piping, piping components, and piping elements exposed to lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of lubricating oil programs. A one-time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The applicant stated in the LRA that loss of material due to pitting and crevice corrosion for copper alloy components exposed to lubricating oil in auxiliary systems is managed by the Oil Analysis Program, which includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. Operating experience has confirmed the effectiveness of this program in maintaining contaminants within limits such that corrosion has not and will not affect the intended functions of these components. During the audit and review, the staff determines that the applicants Oil Analysis Program alone is not sufficient in managing the loss of material of copper alloy piping, piping components, and piping elements exposed to lubricating oil. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program. The staff determines that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.3.2.2.10. (5) LRA Section 3.3.2.2.10 addresses the loss of material of HVAC aluminum piping, piping components, and piping elements and stainless steel ducting and components exposed to condensation due to pitting and crevice corrosion. SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice corrosion may occur in HVAC aluminum piping, piping components, and piping elements and stainless steel ducting and components exposed to condensation. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed. The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosion could occur for HVAC aluminum piping, piping components, and piping elements and stainless steel ducting and components exposed to condensation. At VYNPS, there are no aluminum components or stainless steel ducting exposed to condensation in the 3-312

HVAC systems. However, this item can be applied to stainless steel components exposed to condensation, both internal and external, in other systems. The System Walkdown Program, and the Service Water Integrity Program, will manage loss of material in stainless steel components exposed externally to condensation. The Periodic Surveillance and Preventive Maintenance Program, will manage loss of material in stainless steel components exposed internally or externally to condensation. These programs include a periodic visual inspection and the Periodic Surveillance and Preventive Maintenance Program includes other NDE techniques to manage loss of material of the components. The staff evaluated each auxiliary system AMR associated with stainless steel components exposed to condensation. The application of programs that are not plant-specific was discussed with the applicants technical personnel. In each case, the staff finds that an appropriate program had been identified for monitoring loss of material due to pitting and crevice corrosion. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.3.2.2.10. (6) LRA Section 3.3.2.2.10 addresses the loss of material of copper alloy fire protection system piping, piping components, and piping elements exposed to internal condensation due to pitting and crevice corrosion. SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice corrosion may occur in copper alloy fire protection system piping, piping components, and piping elements exposed to internal condensation. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed. The applicant stated in the LRA 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. At VYNPS, there are no copper alloy components exposed to condensation in the fire protection systems. However, this item can be applied to copper alloy components exposed to internal condensation in other systems. The Periodic Surveillance and Preventive Maintenance Program, will manage loss of material in copper alloy components exposed internally to untreated air, which is equivalent to condensation, through the use of visual inspections or other NDE techniques. The Instrument Air Quality Program, will manage loss of material in copper alloy components exposed internally to treated air. The applicants Instrument Air Quality Program maintains humidity and particulates within acceptable limits, thereby preserving the environment of treated air that is not conducive to corrosion. This is equivalent to the management of loss of material in steel and stainless steel components addressed in LRA Table 3.3.1, Items 3.3.1-53 and 3.3.1-54, respectively. 3-313

The staff evaluated each auxiliary system AMR associated with copper alloy components exposed to condensation. The staff finds that the Periodic Surveillance and Preventive Maintenance Program would be an appropriate, plant-specific program for monitoring loss of material (copper) due to pitting and crevice corrosion. The staff finds that the plant-specific Instrument Air Quality Program served to prevent condensation from forming inside the IA system. Also by reviewing the implementing procedures for measuring dewpoint, particulate concentration and hydrocarbon concentration monitoring, the staff noted that a degradation of the piping and any components would become evident by excessive corrosion or by failure of the system or of any components to meet specified performance limits (see SER Section 3.0.3.3.4.1.4). The staff finds that the Instrument Air Quality Program would be an appropriate plant-specific program monitoring loss of material due to pitting and crevice corrosion. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.3.2.2.10. (7) LRA Section 3.3.2.2.10 addresses the loss of material of stainless steel piping, piping components, and piping elements exposed to soil due to pitting and crevice corrosion. SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice corrosion may occur in stainless steel piping, piping components, and piping elements exposed to soil. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed. The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosion could occur for stainless steel piping, piping components, and piping elements exposed to soil. At VYNPS, there are no stainless steel piping components exposed to soil in the auxiliary systems. However, loss of material due to pitting and crevice corrosion for stainless steel bolting buried in soil in the fire protection-water systems is managed by the Buried Piping Inspection Program. This program will include: (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the buried stainless steel bolting. The applicant also stated that buried components are to be inspected when excavated during maintenance. An inspection will be performed within 10 years of entering the period of extended operation, unless an opportunistic inspection occurs within this 10-year period. This program will manage the aging effect of loss of material such that the intended function of the components will not be affected. During the audit and review, the staff confirmed that buried piping has already been inspected within the final 10-year period before the period of extended operation. Therefore, even if no other buried piping is examined before the period of extended operation, VYNPS has complied with staff guidance regarding the examination of buried piping before the end of the current operating license. The staff finds that the proposed schedule for inspection (if there is no other opportunity) is consistent with the staffs guidance and therefore acceptable. 3-314

The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.3.2.2.10. (8) LRA Section 3.3.2.2.10 addresses loss of material of stainless steel piping and components of the SLC system exposed to sodium pentaborate solution due to pitting and crevice corrosion. SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice corrosion may occur in stainless steel piping, piping components, and piping elements of the BWR SLC system exposed to sodium pentaborate solution. The existing AMP monitors and controls water chemistry to manage the aging effects of loss of material due to pitting and crevice corrosion. However, high concentrations of impurities in crevices and with stagnant flow conditions may cause loss of material due to pitting and crevice corrosion; therefore, the GALL Report recommends that the effectiveness of water chemistry control programs should be verified to ensure that this aging does not occur. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that loss of material due to pitting and crevice corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The applicant stated, in the LRA, that loss of material due to pitting and crevice corrosion for stainless steel piping and components of the SLC system exposed to sodium pentaborate solution is managed by the Water Chemistry Control-BWR Program. The effectiveness of the applicants Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including susceptible locations such as areas of stagnant flow. The staff determines this combination satisfies the criteria of SRP-LR Appendix A.1 and therefore is acceptable. The staff finds this to be consistent with the criteria of SRP-LR Section 3.3.2.2.10 and therefore acceptable. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.10 criteria. For those line 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 The staff reviewed LRA Section 3.3.2.2.11 against the criteria in SRP-LR Section 3.3.2.2.11. LRA Section 3.3.2.2.11 addresses the loss of material of copper alloy piping and components exposed to treated water in the auxiliary and other systems due to pitting and crevice, and galvanic corrosion. 3-315

SRP-LR Section 3.3.2.2.11 states that loss of material due to pitting, crevice, and galvanic corrosion may occur in copper alloy piping, piping components, and piping elements exposed to treated water. Therefore, the GALL Report recommends that the effectiveness of water chemistry control programs should be verified to ensure that this aging does not occur. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that loss of material due to pitting and crevice corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The applicant stated, in the LRA, that loss of material due to pitting and crevice, and galvanic corrosion for copper alloy piping and components exposed to treated water in the auxiliary and other systems is managed by the Water Chemistry Control-BWR Program. The effectiveness of the program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including susceptible locations such as areas of stagnant flow. The staff determines this combination satisfies the criteria of SRP-LR Appendix A.1 and therefore is acceptable. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.11 criteria. For those line items that apply to LRA Section 3.3.2.2.11, 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). 3.3.2.2.12 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion The staff reviewed LRA Section 3.3.2.2.12 against the following SRP-LR Section 3.3.2.2.12 criteria: (1) LRA Section 3.3.2.2.12 addresses the loss of material of stainless steel, aluminum and copper alloy piping, and components exposed to fuel oil due to pitting, crevice, and MIC. SRP-LR Section 3.3.2.2.12 states that loss of material due to pitting and crevice corrosion, and MIC may occur in stainless steel, aluminum, and copper alloy piping, piping components, and piping elements exposed to fuel oil. The existing AMP relies on the fuel oil chemistry program for monitoring and control of fuel oil contamination to manage loss of material due to corrosion; however, corrosion may occur at locations where contaminants accumulate and the effectiveness of fuel oil chemistry control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of the fuel oil chemistry control program. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The applicant stated, in the LRA, that loss of material due to pitting, crevice, and MIC in stainless steel, aluminum and copper alloy piping, and components exposed to fuel oil is an AERM and these components are managed by the Diesel Fuel Monitoring Program. This program includes sampling and monitoring of fuel oil quality to ensure they remain 3-316

within the limits specified by the ASTM standards. Maintaining parameters within limits ensures that significant loss of material will not occur. Operating experience has confirmed the effectiveness of this program in maintaining fuel oil quality within limits such that loss of material will not affect the intended functions of these components. The staff finds that the applicants Diesel Fuel Monitoring Program alone is not sufficient in managing the loss of material of stainless steel, aluminum and copper alloy piping, and components exposed to lubricating oil due to pitting, crevice, and MIC. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program verifies the effectiveness of the Diesel Fuel Monitoring Program. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.3.2.2.12. (2) LRA Section 3.3.2.2.12 addresses loss of material of stainless steel piping and components exposed to lubricating oil due to pitting, crevice, and MIC. SRP-LR Section 3.3.2.2.12 states that loss of material due to pitting and crevice corrosion, and MIC may occur in stainless steel piping, piping components, and piping elements exposed to lubricating oil. The existing program periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of lubricating oil programs. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The applicant stated in the LRA that loss of material due to pitting, crevice, and MIC in stainless steel piping and components exposed to lubricating oil is managed by the Oil Analysis Program, which includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. Operating experience has confirmed the effectiveness of this program in maintaining contaminants within limits such that corrosion has not and will not affect the intended functions of these components. The staff finds that Oil Analysis Program alone is not sufficient in managing the loss of material of stainless steel piping and components exposed to lubricating oil due to pitting, crevice, and MIC. In a letter dated July 14, 2006, the applicant amended the its LRA. The applicant stated that LRA is revised to state the One-Time Inspection Program verifies the effectiveness of the Oil Analysis Program. 3-317

The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.3.2.2.13. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.12 criteria. For those line items that apply to LRA Section 3.3.2.2.12, 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). 3.3.2.2.13 Loss of Material Due to Wear The staff reviewed LRA Section 3.3.2.2.13 against the criteria in SRP-LR Section 3.3.2.2.13. LRA Section 3.3.2.2.13 addresses the loss of material due to wear, this aging effect is not applicable to VYNPS. Loss of material due to wear could occur in the elastomer seals and components exposed to air indoor uncontrolled (internal or external). At VYNPS, in the auxiliary systems, this specific aging effect for elastomers is not applicable based on operating experience. Where the aging effects of change in material properties and cracking are identified for elastomer components, they are managed by the Periodic Surveillance and Preventive Maintenance Program. This item is not applicable to VYNPS auxiliary systems. SRP-LR Section 3.3.2.2.13 states that loss of material due to wear may occur in the elastomer seals and components exposed to air-indoor uncontrolled (internal or external). The GALL Report recommends further evaluation to ensure that these aging effects are adequately managed. During the audit and review, the staff finds that operating experience provided an insufficient basis for determining that this aging mechanism is not applicable at VYNPS. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant revised LRA Section 3.3.2.2.13 to state: Wear is the removal of surface layers due to relative motion between two surfaces. At VYNPS, in the auxiliary systems, this specific aging effect is not applicable because the HVAC elastomer coated fiberglass duct flexible connections are fixed at both ends, precluding wear. This item is not applicable to VYNPS auxiliary systems. The staff finds that wear is precluded by the system design feature. On this basis that this aging effect/mechanism is not applicable to VYNPS auxiliary systems, the staff finds that this aging effect is not applicable to VYNPS. 3-318

Based on the program identified above, the staff concludes that the applicants program meets SRP-LR Section 3.3.2.2.13 criteria. For those line items that apply to LRA Section 3.3.2.2.13, 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). 3.3.2.2.14 Loss of Material Due to Cladding Breach The staff reviewed LRA Section 3.3.2.2.14 against the criteria in SRP-LR Section 3.3.2.2.14. LRA Section 3.3.2.2.14 addresses the cracking due to underclad cracking, which could occur for PWR steel charging pump casings with stainless steel cladding exposed to treated borated water. As VYNPS is a BWR and has no charging pumps. This item is not applicable to VYNPS SRP-LR Section 3.3.2.2.14 states that loss of material due to cladding breach may occur in PWR steel charging pump casings with stainless steel cladding exposed to treated borated water. The GALL Report references IN 94-63 and recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed. The staff confirmed that VYNPS has no components from this group. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. 3.3.2.2.15 Quality Assurance for Aging Management of Nonsafey-Related Components SER Section 3.0.4 documents the staffs evaluation of the applicants QA program. Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for which the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determines that the applicant adequately addressed the issues that were further evaluated. The staff finds that the applicant had demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.3.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Tables 3.3.2-1 through 3.3.2-12 and Tables 3.3.2-13-1 through 3.3.2-13-58, 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. These items were reviewed and they are further addressed in SER Section 3.3.2.3. In LRA Tables 3.3.2-1 through 3.3.2-12 and Tables 3.3.2-13-1 through 3.3.2-13-58, the applicant indicated, via notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided 3-319

further information about how it will manage the aging effects. Specifically, note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line 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 line item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report. Staff Evaluation. For component type, material, and environment combinations not evaluated in the GALL Report, the staff reviewed the applicants evaluation to determine whether 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. The staffs evaluation is documented in the following sections. 3.3.2.3.1 Standby Liquid Control System Summary of Aging Management Evaluation - LRA Table 3.3.2-1 The staff reviewed LRA Table 3.3.2-1, which summarizes the results of AMR evaluations for the SLC system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-1 are consistent with the GALL Report. 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). 3.3.2.3.2 Service Water Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-2 The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations for the SWSs component groups. In LRA Table 3.3.2-2, the applicant proposed to manage loss of material due to wear of copper-alloy heat exchanger tubes exposed to condensation and stainless steel heat exchanger tubes exposed to treated water and using the Service Water Integrity Program. The staff reviewed the applicants Service Water Integrity Program and Its evaluation is documented in SER Section 3.0.3.2.16. The applicants Service Water Integrity Program relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the SWS will be managed for the period of extended operation. On this basis, the staff finds the loss of copper alloy due to wear when exposed to condensation is adequately managed using the Service Water Integrity Program. 3-320

In LRA Table 3.3.2-2, the applicant proposed to manage loss of material from stainless steel valve bodies exposed to outdoor air using the System Walkdown Program. The staff reviewed the applicants System Walkdown Program, which entails inspections of external surfaces of components subject to an AMR. The staffs evaluation is documented in SER Section 3.0.3.1.9. The System Walkdown Program includes inspections of external surfaces of components and is consistent with the program described in GALL AMP XI.M36, External Surfaces Monitoring. On this basis, the staff finds loss of material of stainless steel from valve bodies exposed to air is adequately managed using the System Walkdown Program. 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). 3.3.2.3.3 Reactor Building Closed Cooling Water System Summary of Aging Management Evaluation - LRA Table 3.3.2-3 The staff reviewed LRA Table 3.3.2-3, which summarizes the results of AMR evaluations for the RBCCW system component groups. In LRA Table 3.3.2-3, the applicant proposed to manage loss of material due to wear of carbon steel heat exchanger tubes exposed to untreated water, copper alloy heat exchanger tubes exposed to lubricating oil or condensation, and stainless steel heat exchanger tubes exposed to treated water or indoor air using the Heat Exchanger Monitoring Program. The staff reviewed the applicants Heat Exchanger Monitoring Program and its evaluation is documented in SER Section 3.0.3.3.1. Heat exchanger monitoring program will inspect the heat exchangers for degradation. Eddy current inspections will be performed, where practical, to determine heat exchanger tube wall thickness. These inspections are to ensure that effects of aging are identified prior to loss of intended function. On this basis, the staff finds loss of material from carbon steel heat exchanger tubes exposed to untreated water, copper alloy heat exchanger tubes exposed to lubricating oil or condensation, and stainless steel heat exchanger tubes exposed to treated water or indoor air is adequately managed using the Heat Exchanger Monitoring Program On this basis, the staff finds that management of loss of material due to wear in the RBCCW system is acceptable. 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). 3-321

3.3.2.3.4 Emergency Diesel Generator System Summary of Aging Management Evaluation-LRA Table 3.3.2-4 The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations for the EDG system component groups. In LRA Table 3.3.2-4, the applicant proposed to manage cracking of stainless steel strainers exposed to a lubricating oil environment using the Oil Analysis Program. In a letter dated July 14, 2006, the applicant amended the LRA so that the One-Time Inspection Program, verified the effectiveness of the Oil Analysis Program. The staff reviewed the applicants Oil Analysis Program, which is a monitoring program that maintains oil systems free of contaminants (primarily water and particulates) thereby preserving an environment that is not conducive to loss of material, cracking, or fouling. The staff also reviewed the applicants One-Time Inspection Program, which confirms the effectiveness of the Oil Analysis Program. The staffs evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.6, respectively. Because the Oil Analysis Program has maintained VYNPS oil systems free of contaminants and the effectiveness of the program will be confirmed by the One-Time Inspection Program, the staff finds that the cracking of stainless steel strainers exposed to lubricating oil is adequately managed using the Oil Analysis Program and the One-Time Inspection Program. On this basis, the staff finds that management of cracking in the EDG system is acceptable. In LRA Table 3.3.2-4, the applicant proposed to manage fatigue damage to stainless steel expansion joints as well as carbon steel expansion joints, piping, silencers, and turbochargers exposed to exhaust gas using TLAA. The staffs review of this TLAA evaluation is documented in SER Section 4.3. In LRA Table 3.3.2-4, the applicant proposed to manage fouling of aluminum heat exchanger (fins) and copper-alloy heat exchanger (tubes) using the Periodic Surveillance and Preventive Maintenance Program. The staff reviewed the Periodic Surveillance and Preventive Maintenance Program. Its evaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1.This program that includes periodic inspections and tests that manage aging effects not managed by other AMP s. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. On this basis, the staff finds that fouling of aluminum heat exchanger fins and copper alloy tubes when exposed to air is adequately managed using the Periodic Surveillance and Preventive Maintenance Program. In LRA Table 3.3.2-4, the applicant proposed to manage loss of material due to wear of copper-alloy heat exchanger tubes exposed to lubricating oil or treated water using the Service Water Integrity Program. 3-322

The staff reviewed the Service Water Integrity Program and its evaluation is documented in SER Section 3.0.3.2.16. The program relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the SWSs will be managed for the period of extended operation. On this basis, the staff finds loss of copper alloy due to wear when exposed to treated water is adequately managed using the Service Water Integrity Program. In LRA Table 3.3.2-4, the applicant proposed to manage loss of material due to wear of copper-alloy heat exchanger tubes exposed to indoor air using the Periodic Surveillance and Preventive Maintenance Program. The staff reviewed the Periodic Surveillance and Preventive Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. This program includes periodic inspections and tests that manage aging effects not managed by other AMPs. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. On this basis, the staff finds that loss of material from copper alloy tubes exposed to indoor air is adequately managed using the Periodic Surveillance and Preventive Maintenance Program. In LRA Table 3.3.2-4, the applicant proposed to manage loss of material from stainless steel strainers exposed to outdoor air using the System Walkdown Program. The staff reviewed the applicants System Walkdown Program, which entails inspections of external surfaces of components subject to an AMR. The staffs evaluation is documented in SER Section 3.0.3.1.9. The System Walkdown Program includes inspections of external surfaces of components and is consistent with the program described in GALL AMP XI.M36, External Surfaces Monitoring. On this basis, the staff finds loss of stainless steel from strainers exposed to air is adequately managed using the System Walkdown Program. On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results involving material, environment, AERM, and AMP combinations that are 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). 3.3.2.3.5 Fuel Pool Cooling Systems Summary of Aging Management Evaluation -LRA Table 3.3.2-5 The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for the fuel pool cooling systems component groups. In LRA Table 3.3.2-5, the applicant proposed to manage cracking of aluminum/boron carbide material for neutron absorber (boral) component types exposed to treated water using the Water Chemistry Control - BWR Program. The staffs evaluation of the Water Chemistry Control - BWR Program is documented in SER Section 3.0.3.1.11. This program is consistent with GALL AMP XI.M2, Water Chemistry. On the basis of its review, the staff found that, because the water chemistry will be monitored 3-323

periodically and controlled within established levels of contaminants, the aging effect of cracking of aluminum/boron carbide neutron absorber (boral) components exposed to treated water will be effectively managed by the Water Chemistry Control - BWR Program. 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). 3.3.2.3.6 Fuel Oil System Summary of Aging Management Evaluation-LRA Table 3.3.2-6 The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations for the fuel oil system component groups. In LRA Table 3.3.2-6, the applicant proposed to manage loss of material from carbon steel tanks exposed to concrete using the Diesel Fuel Monitoring Program. In a letter dated July 14, 2006, the applicant amended the LRA so that the One-Time Inspection Program, verified the effectiveness of the Diesel Fuel Monitoring Program. The staff reviewed the applicants Diesel Fuel Monitoring Program. The staff also reviewed the applicants One-Time Inspection Program, which confirms the effectiveness of the Diesel Fuel Monitoring Program. The staffs evaluations are documented in SER Sections 3.0.3.2.9 and 3.0.3.1.6, respectively. The Diesel Fuel Monitoring Program entails sampling to ensure that adequate diesel fuel quality is maintained to prevent corrosion of fuel systems. Exposure to fuel oil contaminants such as water and microbiological organisms is minimized by periodic draining and cleaning of tanks and by verifying the quality of new oil before its introduction into storage tanks. On this basis, the staff finds the loss of material from carbon-steel tanks is adequately managed using the Diesel Fuel Monitoring Program and the One-Time Inspection Program. In LRA Table 3.3.2-6, the applicant proposed to manage cracking of stainless steel flex hoses exposed to fuel oil using the Diesel Fuel Monitoring Program. In a letter dated July 14, 2006, the applicant amended the LRA so that applicants One-Time Inspection Program verified the effectiveness of its Diesel Fuel Monitoring Program. The staff reviewed the applicants Diesel Fuel Monitoring Program. The staff also reviewed the applicants One-Time Inspection Program, which confirms the effectiveness of the Diesel Fuel Monitoring Program. The staffs evaluations are documented in SER Sections 3.0.3.2.9 and 3.0.3.1.6, respectively. The Diesel Fuel Monitoring Program entails sampling to ensure that adequate diesel fuel quality is maintained to prevent corrosion of fuel systems. Exposure to fuel oil contaminants such as water and microbiological organisms is minimized by periodic draining and cleaning of tanks and by verifying the quality of new oil before its introduction into storage tanks. On this basis, the staff finds the cracking of stainless steel flex houses is adequately managed using the Diesel Fuel Monitoring Program and the One-Time Inspection Program. 3-324

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). 3.3.2.3.7 Instrument Air System Summary of Aging Management Evaluation-LRA Table 3.3.2-7 The staff reviewed LRA Table 3.3.2-7, which summarizes the results of AMR evaluations for the IA system component groups. The staff determines that all AMR evaluation results in LRA Table 3.3.2-7 are consistent with the GALL Report. 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 Fire Protection - Water System Summary of Aging Management Evaluation-LRA Table 3.3.2-8 The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for the fire protection-water system component groups. In LRA Table 3.3.2-8, the applicant proposed to manage cracking of stainless steel valve bodies exposed to treated water using the Fire Protection Program. The staff reviewed the applicants Fire Protection Program, which includes a fire barrier inspection and a diesel-driven fire pump inspection. The staffs evaluation is documented in SER Section 3.0.3.2.11. The Fire Protection Program includes periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests of fire rated doors to ensure that their operability is maintained. The diesel-driven fire pump inspection requires that the pump be periodically tested to ensure that the fuel supply line can perform its intended function. On this basis, the staff finds that cracking of stainless steel valve bodies exposed to treated water is adequately managed using the Fire Protection Program. In LRA Table 3.3.2-8, the applicant proposed to manage fatigue damage to carbon steel piping, silencer, and turbocharger as well as a stainless steel expansion joint exposed to exhaust gases and copper-alloy heat exchanger tubes as well as carbon steel heat exchanger (bonnet) and piping exposed to lubricating oil using the Fire Protection Program. The staff reviewed the applicants Fire Protection Program, which includes a fire barrier inspection and a diesel-driven fire pump inspection. The staffs evaluation is documented in SER Section 3.0.3.2.11. The Fire Protection Program requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and 3-325

functional tests of fire rated doors to ensure that their operability is maintained. The diesel-driven fire pump inspection requires that the pump be periodically tested to ensure that the fuel supply line can perform its intended function. On this basis, the staff determines that cracking due to fatigue of carbon steel piping, silencer, and turbocharger as well as a stainless steel expansion joint exposed to exhaust gases and copper-alloy heat exchanger tubes as well as carbon steel heat exchanger (bonnet) and piping exposed to lubricating oil is adequately managed using the Fire Protection Program. On this basis, the staff finds that management of cracking in the fire protection water system is acceptable. In LRA Table 3.3.2-8, the applicant proposed to manage fouling of copper-alloy heat exchanger tubes exposed to treated water using the Fire Protection Program. The staff reviewed the applicants Fire Protection Program, which includes a fire barrier inspection and a diesel-driven fire pump inspection. The staffs evaluation is documented in SER Section 3.0.3.2.11. The Fire Protection Program requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests of fire rated doors to ensure that their operability is maintained. The diesel-driven fire pump inspection requires that the pump be periodically tested to ensure that the fuel supply line can perform its intended function. On this basis, the staff finds that fouling of the copper-alloy heat exchanger tubes exposed to treated water is adequately managed using the Fire Protection Program. On this basis, the staff finds that management of fouling in the fire protection system is acceptable. In LRA Table 3.3.2-8, the applicant proposed to manage loss of material from aluminum heater housing; carbon steel filter housing, heat exchanger shell, piping, pump casing, and valve bodies; copper-alloy heat exchanger tubes, tubing, and valve bodies; as well as stainless steel valve bodies exposed to treated water using the Fire Protection Program. The staff reviewed the applicants Fire Protection Program, which includes a fire barrier inspection and a diesel-driven fire pump inspection. The staffs evaluation is documented in SER Section 3.0.3.2.11. The Fire Protection Program requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests of fire rated doors to ensure that their operability is maintained. The diesel-driven fire pump inspection requires that the pump be periodically tested to ensure that the fuel supply line can perform its intended function. On this basis, the staff finds that loss of material from aluminum heater housing; carbon steel filter housing, heat exchanger shell, piping, pump casing, and valve bodies; copper-alloy heat exchanger tubes, tubing, and valve bodies; as well as stainless steel valve bodies exposed to treated water is adequately managed using the Fire Protection Program. In LRA Table 3.3.2-8, the applicant proposed to manage loss of material from carbon steel flow nozzle, piping, tank, and valve bodies; copper-alloy flow nozzles and valve bodies; as well as gray cast iron valve bodies exposed to fire protection foam using the Fire Water System Program. 3-326

The staff reviewed the applicants Fire Water System Program and its evaluation is documented in SER Section 3.0.3.2.12. The Fire Water System Program applies to water-based fire protection systems that consist of sprinklers, nozzles, fittings, valves, hydrants, hose stations, standpipes, and aboveground and underground piping and components that are tested in accordance with applicable NFPA codes and standards. On this basis, the staff finds that loss of material from carbon steel flow nozzle, piping, tank, and valve bodies; copper-alloy flow nozzles and valve bodies; as well as gray cast iron valve bodies exposed to fire protection foam is adequately managed using the Fire Water System Program. In LRA Table 3.3.2-8, the applicant proposed to manage selective leaching of copper-alloy flow nozzles and valve bodies and gray cast iron valve bodies exposed to fire protection foam using the Selective Leaching Program. The staff reviewed the applicants Selective Leaching Program, which ensures the integrity of components made of cast iron, bronze, brass, and other alloys exposed to raw water, treated water, or groundwater that may lead to selective leaching. The staffs evaluation is documented in SER Section 3.0.3.1.7. The Selective Leaching Program is consistent with GALL AMP XI.M33, Selective Leaching of Materials. On this basis, the staff finds the selective leaching of material from copper-alloy flow nozzles and valve bodies and gray cast iron valve bodies exposed to fire protection foam is adequately managed using the Selective Leaching Program. In LRA Table 3.3.2-8, the applicant proposed to manage loss of material from stainless steel bolting and copper alloy nozzles exposed to outdoor air using the System Walkdown Program. The staff reviewed the applicants System Walkdown Program, which entails inspections of external surfaces of components subject to an AMR. The staffs evaluation is documented in SER Section 3.0.3.1.9. The staff determines the loss of material from stainless steel bolting and copper alloy nozzles exposed to outdoor air is adequately managed using the System Walkdown Program. The applicant also committed (Commitment #34) to a Bolting Integrity Program consistent with GALL AMP XI.M18, "Bolting Integrity." The staff's evaluation is documented in SER Section 3.0.3.2.19. The program applies to bolting and torquing practices of safety-related and nonsafety-related carbon and stainless steel bolting for pressure-retaining components, NSSS component supports, and structural joints. The program addresses all safety and nonsafety-relates bolting regardless of size (except the reactor vessel closure studs which are address by the Reactor Vessel Closure Studs Program) and material. On this basis, the staff finds that management of loss of material in the fire protection water system is acceptable. 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). 3-327

3.3.2.3.9 Fire Protection - CO2 System Summary of Aging Management Evaluation - LRA Table 3.3.2-9 The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for the fire protection - CO2 system component groups. In LRA Table 3.3.2-9, the applicant proposed to manage loss of material from copper alloy piping, tubing, and valve bodies and stainless steel bolting, orifices, tubing, and valve bodies exposed to outdoor air using the System Walkdown Program. The staff reviewed the applicants System Walkdown Program, which entails inspections of external surfaces of components subject to an AMR. The staffs evaluation is documented in SER Section 3.0.3.1.9. The System Walkdown Program includes inspections of external surfaces of components subject to an AMR. On this basis, the staff finds the loss of material from copper alloy piping, tubing, and valve bodies and stainless steel bolting, orifices, tubing, and valve bodies exposed to outdoor air is adequately managed using the System Walkdown Program. The applicant also committed (Commitment #34) to a Bolting Integrity Program consistent with GALL AMP XI.M18, "Bolting Integrity." The staff's evaluation is documented in SER Section 3.0.3.2.19. The program applies to bolting and torquing practices of safety-related and nonsafety-related carbon and stainless steel bolting for pressure-retaining components, NSSS component supports, and structural joints. The program addresses all safety and nonsafety-relates bolting regardless of size (except the reactor vessel closure studs which are address by the Reactor Vessel Closure Studs Program) and material. On this basis, the staff finds that management of loss of material in the fire protection CO2 system is acceptable. 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 Heating, Ventilation, and Air Conditioning Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-10 The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations for the HVAC systems component groups. In LRA Table 3.3.2-10, the applicant proposed to manage fouling of copper alloy heat exchanger tubes exposed to condensation using the Periodic Surveillance and Preventive Maintenance Program. The staff reviewed the applicants Periodic Surveillance and Preventive Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. This Program includes periodic inspections and tests that manage aging effects not managed by other AMP s. The preventive maintenance and surveillance testing 3-328

activities are generally implemented through repetitive tasks or routine monitoring of plant operations. On this basis, the staff finds fouling of copper alloy heat exchanger tubes exposed to condensation is adequately managed using the Periodic Surveillance and Preventive Maintenance Program. In LRA Table 3.3.2-10, the applicant proposed to manage fouling of aluminum heat exchanger fins and fouling of copper-alloy heat exchanger tubes exposed to condensation using the Service Water Integrity Program. The staff reviewed the applicants Service Water Integrity Program and its evaluation is documented in SER Section 3.0.3.2.16. The Service Water Integrity Program relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the SWSs will be managed for the period of extended operation. On this basis, the staff finds fouling of aluminum heat exchanger fins as well as fouling of copper-alloy heat exchanger tubes exposed to condensation is adequately managed using the Service Water Integrity Program. On this basis, the staff finds that management of fouling in the HVAC system is acceptable. In LRA Table 3.3.2-10, the applicant proposed to manage loss of material due to wear of copper alloy heat exchanger tubes exposed to condensation or treated water using the Periodic Surveillance and Preventive Maintenance Program. The staff reviewed the applicants Periodic Surveillance and Preventive Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. This program includes periodic inspections and tests that manage aging effects not managed by other AMPs. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. On this basis, the staff finds loss of material due to wear of copper alloy heat exchanger tubes exposed to condensation or treated water is adequately managed using the Periodic Surveillance and Preventive Maintenance Program. In LRA Table 3.3.2-10, the applicant proposed to manage loss of material due to wear of copper-alloy heat exchanger tubes exposed to condensation using the Service Water Integrity Program. The staff reviewed the applicants Service Water Integrity Program and its evaluation is documented in SER Section 3.0.3.2.16. The Service Water Integrity Program relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the SWSs will be managed for the period of extended operation. On this basis, the staff finds loss of material due to wear of copper-alloy heat exchanger tubes exposed to condensation is adequately managed using the Service Water Integrity Program. In LRA Table 3.3.2-10, the applicant proposed to manage loss of material from aluminum damper, fan, and louver housings; copper-alloy tubing and valve bodies; and stainless steel bolting exposed to outdoor air using the System Walkdown Program. 3-329

The staff reviewed the applicants System Walkdown Program and its evaluation is documented in SER Section 3.0.3.1.9. The System Walkdown Program includes inspections of external surfaces of components subject to an AMR. The program is also credited with managing loss of material from internal surfaces, for situations in which internal and external material and environment combinations are the same such that external surface condition is representative of internal surface condition. The applicant also committed (Commitment #34) to a Bolting Integrity Program consistent with GALL AMP XI.M18, "Bolting Integrity." The staff's evaluation is documented in SER Section 3.0.3.2.19. The program applies to bolting and torquing practices of safety-related and nonsafety-related carbon and stainless steel bolting for pressure-retaining components, NSSS component supports, and structural joints. The program addresses all safety and nonsafety-relates bolting regardless of size (except the reactor vessel closure studs which are address by the Reactor Vessel Closure Studs Program) and material. On this basis, the staff finds that management of loss of material in the fire protection water system is acceptable. On this basis, the staff finds the loss of material from the interior and exterior of aluminum damper, fan, and louver housings; copper-alloy tubing and valve bodies; as well as from stainless steel bolting exposed to outdoor air in the HVAC system is adequately managed using the System Walkdown Program and Bolting Integrity Program. In LRA Table 3.3.2-10, the applicant proposed to manage loss of material from copper-alloy heat exchanger tubes exposed to steam using the Water Chemistry Control-Auxiliary Systems Program. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-Auxiliary Systems Program. The staff reviewed the applicants Water Chemistry Control Program for auxiliary systems and the One-Time Inspection Program, which confirms the effectiveness of the Water Chemistry Control Program. The staffs evaluation is documented in SER Sections 3.0.3.3.7 and 3.0.3.1.6, respectively. The Water Chemistry Control Program controls contaminants at the lowest practical levels and provides corrosion protection for major systems and components. On this basis, the staff finds that loss of material from the interior of copper-alloy heat exchanger tubes exposed to steam is adequately managed using the Water Chemistry Control-Auxiliary Systems Program augmented by the One-Time Inspection Program. On this basis, the staff finds that management of loss of material in the HVAC system is acceptable. 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 Primary Containment Atmosphere Control and Containment Atmosphere Dilution Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-11 The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations for the PCAC and containment atmosphere dilution systems component groups. 3-330

In LRA Table 3.3.2-11, the applicant proposed to manage fouling of stainless steel heat exchangers exposed to indoor air using the Periodic Surveillance and Preventive Maintenance Program. The staff reviewed the Periodic Surveillance and Preventive Maintenance Program and. Its evaluation is documented in SER Section 3.0.3.3.5.The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. This program includes periodic inspections and tests that manage aging effects not managed by other AMPs. The Periodic Surveillance and Preventive Maintenance Program visually inspect external surfaces of the hydrogen analyzer pre-cooler (heat exchanger) to manage fouling. On this basis, the staff finds fouling of stainless steel heat exchangers exposed to indoor air is adequately managed using the Periodic Surveillance and Preventive Maintenance Program. On this basis, the staff finds that management of fouling in the PCAC and containment atmosphere dilution systems is acceptable. 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 John Deere Diesel Summary of Aging Management Evaluation-LRA Table 3.3.2-12 The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations for the John Deere diesel component groups. In LRA Table 3.3.2-12, the applicant proposed to manage cracking due to fatigue of stainless steel expansion joints and the carbon steel piping, silencer, and turbocharger exposed to exhaust gases using the Periodic Surveillance and Preventive Maintenance Program. The staff reviewed the applicants Periodic Surveillance and Preventive Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. This program includes periodic inspections and tests that manage aging effects not managed by other AMP s. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. Because the program has been demonstrated to detect and control cracking due to fatigue, the staff finds cracking of stainless steel expansion joints and the carbon steel piping, silencer, and turbocharger exposed to exhaust gases is adequately managed using the Periodic Surveillance and Preventive Maintenance Program. On this basis, the staff finds that management of cracking in the John Deere Diesel is acceptable. In LRA Table 3.3.2-12, the applicant proposed to manage fouling of a copper-alloy radiator exposed to indoor air using the Periodic Surveillance and Preventive Maintenance Program. 3-331

The staff reviewed the applicants Periodic Surveillance and Preventive Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1.This program includes periodic inspections and tests that manage aging effects not managed by other AMPs. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. The staff also reviewed the applicants operating history and industry-wide operating experience. Because the program has been demonstrated to detect and control fouling, the staff finds fouling of a copper-alloy radiator exposed to indoor air is adequately managed using the Periodic Surveillance and Preventive Maintenance Program. In LRA Table 3.3.2-12, the applicant proposed to manage fouling of a copper-alloy radiator and heat exchanger tubes exposed to treated water using the Water Chemistry Control-Auxiliary Systems Program. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-Auxiliary Systems Program. The staff reviewed the applicants Water Chemistry Control Program for auxiliary systems, which manages aging effects for components exposed to treated water. The staff also reviewed the applicants One-Time Inspection Program, which confirms the effectiveness of the Water Chemistry Control Program. The staffs evaluation is documented in SER Sections 3.0.3.3.7 and 3.0.3.1.6, respectively. In addition, the staff reviewed the applicant's operating history and industry-wide operating experience. The Water Chemistry Control Program controls contaminants at the lowest practical levels and provides corrosion protection for major systems and components. On this basis, the staff finds that fouling of copper-alloy radiator and heat exchanger tubes exposed to treated water is adequately managed using the Water Chemistry Control Program-Auxiliary Systems Program augmented by the One-Time Inspection Program. On this basis, the staff determines that management of fouling in the John Deere Diesel is acceptable. In LRA Table 3.3.2-12, the applicant proposed to manage loss of material from copper-alloy radiator and heat exchanger tubes and the carbon steel heater housings, piping, and pump casings exposed to treated water using the Water Chemistry Control-Auxiliary Systems Program, and the One-Time Inspection Program. The staff reviewed the applicants Water Chemistry Control Program for auxiliary systems, which manages aging effects for components exposed to treated water. The staff also reviewed the applicants One-Time Inspection Program, which confirms the effectiveness of the Water Chemistry Control Program. Its evaluation is documented in SER Sections 3.0.3.3.7 and 3.0.3.1.6, respectively. The Water Chemistry Control Program controls contaminants at the lowest practical levels and provides corrosion protection for major systems and components. On this basis, the staff determines that loss of material from copper-alloy radiator and heat exchanger tubes and carbon steel heater housings, piping and pump casings exposed to treated water is adequately managed using the Water Chemistry Control Program-Auxiliary Systems Program augmented by the One-Time Inspection Program. 3-332

In LRA Table 3.3.2-12, the applicant proposed to manage loss of material due to wear of the copper-alloy radiator in air and the copper-alloy heat exchanger tubes in lubricating oil using the Periodic Surveillance and Preventive Maintenance Program. The staff reviewed the applicants Periodic Surveillance and Preventive Maintenance Program. Its evaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1. This program includes periodic inspections and tests that manage aging effects not managed by other AM s. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. This program uses visual or other NDE techniques to manage loss of material. On this basis, the staff finds loss of material due to wear is adequately managed using the Periodic Surveillance and Preventive Maintenance Program. On this basis, the staff finds that management of loss of material in the John Deere Diesel is acceptable. 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). 3.3.2.3.13 Augmented Offgas System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-1 The staff reviewed LRA Table 3.3.2-13-1, which summarized the results of AMR evaluations for the AOG system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-1 are consistent with the GALL Reports. 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 Condensate System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-2 The staff reviewed LRA Table 3.3.2-13-2, which summarizes the results of AMR evaluations for the condensate system component groups. In LRA Table 3.3.2-13-2, the applicant proposed to manage cracking-fatigue from carbon steel heat exchanger (shell) exposed to treated water greater than 220E F using the One-Time Inspection Program. The staff reviewed the applicant's One-Time Inspection Program and its evaluation is documented in SER Section 3.0.3.1.6.The One-Time Inspection Program provides assurance that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly as not to affect the intended function of the component or structure. The staff finds the applicant's 3-333

One-Time Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M32, "One-Time Inspection" and GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping." On this basis, the staff finds the cracking-fatigue from carbon steel heat exchanger (shell) exposed to treated water greater than 220E F is adequately managed using the One-Time Inspection Program. On this basis, the staff finds that management of cracking-fatigue in the condensate system is acceptable. 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). 3.3.2.3.15 Containment Air Dilution, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-3 The staff reviewed LRA Table 3.3.2-13-3, which summarized the results of AMR evaluations for the containment air dilution component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-3 are consistent with the GALL Report. 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). 3.3.2.3.16 Condensate Demineralizer System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-4 The staff reviewed LRA Table 3.3.2-13-4, which summarized the results of AMR evaluations for the condensate demineralizer system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-4 are consistent with the GALL Report. 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). 3.3.2.3.17 Control Rod Drive System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-5 The staff reviewed LRA Table 3.3.2-13-5, which summarized the results of AMR evaluations for the CRD system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-5 are consistent with the GALL Report. 3-334

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 Core Spray System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-6 The staff reviewed LRA Table 3.3.2-13-6, which summarized the results of AMR evaluations for the CSS component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-6 are consistent with the GALL Report. 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). 3.3.2.3.19 Condensate Storage and Transfer System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-7 The staff reviewed LRA Table 3.3.2-13-7, which summarizes the results of AMR evaluations for the condensate storage and transfer system component groups. In LRA Table 3.3.2-13-7, the applicant proposed to manage loss of material from copper-alloy tubing and stainless steel bolting exposed to outdoor air using the System Walkdown Program. The staff reviewed the applicants System Walkdown Program and its evaluation is documented in SER Section 3.0.3.1.9. The System Walkdown Program include inspections of external surfaces of components subject to an AMR. The program is also credited with managing loss of material from internal surfaces, for situations in which internal and external material and environment combinations are the same such that external surface condition is representative of internal surface condition. The applicant also committed (Commitment #34) to a Bolting Integrity Program consistent with GALL AMP XI.M18, "Bolting Integrity." The staff's evaluation is documented in SER Section 3.0.3.2.19. The program applies to bolting and torquing practices of safety-related and nonsafety-related carbon and stainless steel bolting for pressure-retaining components, NSSS component supports, and structural joints. The program addresses all safety and nonsafety-relates bolting regardless of size (except the reactor vessel closure studs which are address by the Reactor Vessel Closure Studs Program) and material. On this basis, the staff finds the loss of material from the exterior of copper-alloy tubing as well as from stainless steel bolting exposed to outdoor air is adequately managed using the System Walkdown Program and the Bolting Integrity Program. On this basis, the staff finds that management of loss of material in the condensate storage and transfer system is acceptable. 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 3-335

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). 3.3.2.3.20 RWCU Filter Demineralizer System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-8 The staff reviewed LRA Table 3.3.2-13-8, which summarized the results of AMR evaluations for the RWCU filter demineralizer system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-8 are consistent with the GALL Report. 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). 3.3.2.3.21 Circulating Water System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-9 The staff reviewed LRA Table 3.3.2-13-9, which summarized the results of AMR evaluations for the CW system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-9 are consistent with the GALL Report. 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 Diesel Generator and Auxiliaries, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-10 The staff reviewed LRA Table 3.3.2-13-10, which summarized the results of AMR evaluations for the diesel generator and auxiliaries component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-10 are consistent with the GALL Report. 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 Diesel Lube Oil System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation - LRA Table 3.3.2-13-11 The staff reviewed LRA Table 3.3.2-13-11, which summarized the results of AMR evaluations for the diesel lube oil system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-11 are consistent with the GALL Report. 3-336

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 Demineralized Water System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-12 The staff reviewed LRA Table 3.3.2-13-12, which summarized the results of AMR evaluations for the demineralized water system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-12 are consistent with the GALL Report. 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 Feedwater System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-13 In LRA Table 3.3.2-13-13, the applicant proposed to manage cracking-fatigue from carbon steel heat exchanger (shell), pump casing, and strainer housing exposed to steam and treated water greater than 220E F using the One-Time Inspection Program. The staff reviewed the applicant's One-Time Inspection Program and its evaluation is documented in SER Section 3.0.3.1.6.The One-Time Inspection Program provides assurance that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly as not to affect the intended function of the component or structure. The staff finds the applicant's One-Time Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M32, "One-Time Inspection" and GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping." On this basis, the staff finds the cracking-fatigue from carbon steel heat exchanger (shell) exposed to steam and treated water greater than 220E F is adequately managed using the One-Time Inspection Program. On this basis, the staff finds that management of cracking-fatigue in the feedwater system is acceptable. 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). 3-337

3.3.2.3.26 Fuel Oil System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-14 The staff reviewed LRA Table 3.3.2-13-14, which summarized the results of AMR evaluations for the fuel oil system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-14 are consistent with the GALL Report. 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). 3.3.2.3.27 Fire Protection System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-15 The staff reviewed LRA Table 3.3.2-13-15, which summarized the results of AMR evaluations for the fire protection system component groups. In LRA Table 3.3.2-13-15, the applicant proposed to manage loss of material from copper-alloy tubing and stainless steel bolting exposed to outdoor air using the System Walkdown Program. The staff reviewed the applicants System Walkdown Program, which entails inspections of external surfaces of components subject to an AMR. The staffs evaluation is documented in SER Section 3.0.3.1.9. The program is also credited with managing loss of material from internal surfaces, for situations in which internal and external material and environment combinations are the same such that external surface condition is representative of internal surface condition. The staff also reviewed the applicants operating history and industry-wide operating experience. The System Walkdown Program includes visual inspections of copper-alloying tubing. The applicant also committed (Commitment #34) to a Bolting Integrity Program consistent with GALL AMP XI.M18, "Bolting Integrity." The staff's evaluation is documented in SER Section 3.0.3.2.19. The program applies to bolting and torquing practices of safety-related and nonsafety-related carbon and stainless steel bolting for pressure-retaining components, NSSS component supports, and structural joints. The program addresses all safety and nonsafety-relates bolting regardless of size (except the reactor vessel closure studs which are address by the Reactor Vessel Closure Studs Program) and material. On this basis, the staff finds the loss of material from the exterior of copper-alloy tubing and stainless steel bolting exposed to outdoor air is adequately managed using the System Walkdown Program and the Bolting Integrity Program. On this basis, the staff finds that management of loss of material in the fire protection system is acceptable. 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). 3-338

3.3.2.3.28 Fuel Pool Cooling System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-16 The staff reviewed LRA Table 3.3.2-13-16, which summarized the results of AMR evaluations for the fuel pool cooling system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-16 are consistent with the GALL Report. 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 Fuel Pool Cooling Filter Demineralizer System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-17 The staff reviewed LRA Table 3.3.2-13-17, which summarized the results of AMR evaluations for the fuel pool cooling filter demineralizer system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-17 are consistent with the GALL Report. 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). 3.3.2.3.30 House Heating Boiler System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-18 The staff reviewed LRA Table 3.3.2-13-18, which summarized the results of AMR evaluations for the house heating boiler system component groups. In LRA Table 3.3.2-13-18, the applicant proposed to manage loss of material from carbon steel heat exchangers (shell), piping, steam traps, strainer housings, and valve bodies exposed to steam or treated water using the Water Chemistry Control-Auxiliary Systems Program. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state the One-Time Inspection Program will confirm the effectiveness of the Water Chemistry Control-Auxiliary Systems Program. The staff reviewed the applicants Water Chemistry Control Program for auxiliary systems, which manages aging effects for components exposed to treated water. The staff also reviewed the applicants One-Time Inspection Program, which confirms the effectiveness of the Water Chemistry Control Program. The staffs evaluation of these program is documented in SER 3-339

Sections 3.0.3.3.7 and 3.0.3.1.6, respectively. The Water Chemistry Control Program controls contaminants at the lowest practical levels and provides corrosion protection for major systems and components. On this basis, the staff finds that loss of material from carbon steel piping, steam traps and valve bodies exposed to steam is adequately managed using the Water Chemistry Control Program-Auxiliary Systems Program augmented by the One-Time Inspection Program. In LRA Table 3.3.2-13-18, the applicant proposed to manage cracking-fatigue from carbon steel heat exchanger (shell) exposed to steam greater than 220E F using the One-Time Inspection Program. The staff reviewed the applicant's One-Time Inspection Program and its evaluation is documented in SER Section 3.0.3.1.6.The One-Time Inspection Program provides assurance that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly as not to affect the intended function of the component or structure. The staff finds the applicant's One-Time Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M32, "One-Time Inspection" and GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping." On this basis, the staff finds the cracking-fatigue from carbon steel heat exchanger (shell) exposed to steam greater than 220E F is adequately managed using the One-Time Inspection Program. On this basis, the staff finds that management of cracking-fatigue in the house heating boiler system is acceptable. On this basis, the staff finds that management of loss of material in the house heating boiler system is acceptable. 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 Hydraulic Control Units, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-19 The staff reviewed LRA Table 3.3.2-13-19, which summarized the results of AMR evaluations for the hydraulic control units component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-19 are consistent with the GALL Report. 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). 3-340

3.3.2.3.32 High Pressure Coolant Injection System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-20 The staff reviewed LRA Table 3.3.2-13-20, which summarized the results of AMR evaluations for the HPCIS component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-20 are consistent with the GALL Report. 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). 3.3.2.3.33 Heating, Ventilation, and Air Conditioning Systems, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-21 The staff reviewed LRA Table 3.3.2-13-21, which summarized the results of AMR evaluations for the heating, ventilation and air conditioning systems component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-21 are consistent with the GALL Report. 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). 3.3.2.3.34 Instrument Air System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-22 The staff reviewed LRA Table 3.3.2-13-22, which summarized the results of AMR evaluations for the IA system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-22 are consistent with the GALL Report. 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). 3.3.2.3.35 MG Lube Oil System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-23 The staff reviewed LRA Table 3.3.2-13-23, which summarized the results of AMR evaluations for the MG lube oil system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-23 are consistent with the GALL Report. 3-341

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). 3.3.2.3.36 Nitrogen System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-24 The staff reviewed LRA Table 3.3.2-13-24, which summarized the results of AMR evaluations for the nitrogen system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-24 are consistent with the GALL Report. 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). 3.3.2.3.37 Nuclear Boiler System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-25 The staff reviewed LRA Table 3.3.2-13-25, which summarized the results of AMR evaluations for the nuclear boiler system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-25 are consistent with the GALL Report. 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). 3.3.2.3.38 Neutron Monitoring System, Nonsafety-related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-26 The staff reviewed LRA Table 3.3.2-13-26, which summarized the results of AMR evaluations for the neutron monitoring system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-26 are consistent with the GALL Report. 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). 3-342

3.3.2.3.39 Post-Accident Sampling System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-27 The staff reviewed LRA Table 3.3.2-13-27, which summarized the results of AMR evaluations for the post-accident sampling system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-27 are consistent with the GALL Report. 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). 3.3.2.3.40 Primary Containment Atmosphere Control System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-28 The staff reviewed LRA Table 3.3.2-13-28, which summarized the results of AMR evaluations for the PCAC system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-28 are consistent with the GALL Report. 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). 3.3.2.3.41 Potable Water System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-29 The staff reviewed LRA Table 3.3.2-13-29, which summarized the results of AMR evaluations for the potable water system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-29 are consistent with the GALL Report. 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). 3.3.2.3.42 Reactor Building Closed Cooling Water System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-30 The staff reviewed LRA Table 3.3.2-13-30, which summarized the results of AMR evaluations for the reactor building CCWS component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-30 are consistent with the GALL Report. 3-343

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). 3.3.2.3.43 Reactor Core Isolation Cooling System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-31 The staff reviewed LRA Table 3.3.2-13-31, which summarized the results of AMR evaluations for the RCICS component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-31 are consistent with the GALL Report. 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). 3.3.2.3.44 Radwaste, Liquid and Solid, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-32 The staff reviewed LRA Table 3.3.2-13-32, which summarized the results of AMR evaluations for the radwaste, liquid and solid component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-32 are consistent with the GALL Report. 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). 3.3.2.3.45 Residual Heat Removal System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-33 The staff reviewed LRA Table 3.3.2-13-33, which summarized the results of AMR evaluations for the RHRS component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-33 are consistent with the GALL Report. 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). 3-344

3.3.2.3.46 RHR Service Water System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-34 The staff reviewed LRA Table 3.3.2-13-34, which summarized the results of AMR evaluations for the RHRSW system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-34 are consistent with the GALL Report. 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). 3.3.2.3.47 Equipment Retired in Place, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-35 The staff reviewed LRA Table 3.3.2-13-35, which summarized the results of AMR evaluations for the equipment retired in place component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-35 are consistent with the GALL Report. 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). 3.3.2.3.48 Reactor Water Clean-Up System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-36 The staff reviewed LRA Table 3.3.2-13-36, which summarized the results of AMR evaluations for the reactor water clean-up system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-36 are consistent with the GALL Report. 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). 3.3.2.3.49 Standby Fuel Pool Cooling System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-37 The staff reviewed LRA Table 3.3.2-13-37, which summarized the results of AMR evaluations for the standby fuel pool cooling system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-37 are consistent with the GALL Report. 3-345

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). 3.3.2.3.50 Standby Gas Treatment System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-38 The staff reviewed LRA Table 3.3.2-13-38, which summarized the results of AMR evaluations for the SGTS component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-38 are consistent with the GALL Report. 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). 3.3.2.3.51 Stator Cooling System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-39 The staff reviewed LRA Table 3.3.2-13-39, which summarized the results of AMR evaluations for the stator cooling system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-39 are consistent with the GALL Report. 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). 3.3.2.3.52 Standby Liquid Control System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-40 The staff reviewed LRA Table 3.3.2-13-40, which summarized the results of AMR evaluations for the SLC system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-40 are consistent with the GALL Report. 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). 3-346

3.3.2.3.53 Sampling System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-41 The staff reviewed LRA Table 3.3.2-13-41, which summarized the results of AMR evaluations for the sampling system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-41 are consistent with the GALL Report. 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). 3.3.2.3.54 Service Water System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-42 The staff reviewed LRA Table 3.3.2-13-42, which summarized the results of AMR evaluations for the SWS component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-42 are consistent with the GALL Report. 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). 3.3.2.3.55 HD & HV Instruments System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-43 The staff reviewed LRA Table 3.3.2-13-43, which summarized the results of AMR evaluations for the HD 7 HV Instruments System component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-43 are consistent with the GALL Report. 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). 3.3.2.3.56 Air Evacuation System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-44 The staff reviewed LRA Table 3.3.2-13-44, which summarized the results of AMR evaluations for the air evacuation system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-44 are consistent with the GALL Report. 3-347

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). 3.3.2.3.57 Auxiliary System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-45 In LRA Table 3.3.2-13-45, the applicant proposed to manage cracking-fatigue from carbon steel heat exchanger (shell) exposed to treated water greater than 220E F using the One-Time Inspection Program. The staff reviewed the applicant's One-Time Inspection Program and its evaluation is documented in SER Section 3.0.3.1.6. The One-Time Inspection Program provides assurance that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly as not to affect the intended function of the component or structure. The staff finds the applicant's One-Time Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M32, "One-Time Inspection" and GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping." On this basis, the staff finds the cracking-fatigue from carbon steel heat exchanger (shell) exposed to treated water greater than 220E F is adequately managed using the One-Time Inspection Program. On this basis, the staff finds that management of cracking-fatigue in the auxiliary system is acceptable. 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). 3.3.2.3.58 Buildings (drainage system components) System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-46 The staff reviewed LRA Table 3.3.2-13-46, which summarized the results of AMR evaluations for the buildings system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-46 are consistent with the GALL Report. 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). 3-348

3.3.2.3.59 Circulating Water Priming System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-47 The staff reviewed LRA Table 3.3.2-13-47, which summarized the results of AMR evaluations for the buildings system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-47 are consistent with the GALL Report. 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). 3.3.2.3.60 Extraction Steam System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-48 In LRA Table 3.3.2-13-48, the applicant proposed to manage cracking due to fatigue for stainless steel expansion joints exposed to steam or treated water greater than 270EF using metal fatigue TLAA. The staff reviewed the applicant's metal fatigue TLAA for non-Class 1 components and its evaluation is documented in SER Section 4.3.2. The staff finds that the number of thermal cycles for non-Class 1 (ANSI B31.1 Code) piping and components is less than 7000 cycles for 60-years of operation. Therefore, the TLAA for non-Class 1 piping and components remains valid for the period of extended operation in compliance with 10 CFR 54.21(c)(i). 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). 3.3.2.3.61 Heater Drain System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-49 The staff reviewed LRA Table 3.3.2-13-49, which summarized the results of AMR evaluations for the heater drain system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-49 are consistent with the GALL Report. 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). 3-349

3.3.2.3.62 Heater Vents System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-50 The staff reviewed LRA Table 3.3.2-13-50, which summarized the results of AMR evaluations for the heater vents system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-50 are consistent with the GALL Report. 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). 3.3.2.3.63 Hydrogen Water Chemistry System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-51 The staff reviewed LRA Table 3.3.2-13-51, which summarized the results of AMR evaluations for the hydrogen water chemistry system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-51 are consistent with the GALL Report. 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). 3.3.2.3.64 Main Steam System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-52 In LRA Table 3.3.2-13-52, the applicant proposed to manage cracking-fatigue from carbon steel heat exchanger (shell) exposed to steam greater than 270E F using the One-Time Inspection Program. The staff reviewed the applicant's One-Time Inspection Program and its evaluation is documented in SER Section 3.0.3.1.6. The One-Time Inspection Program provides assurance that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly as not to affect the intended function of the component or structure. The staff finds the applicant's One-Time Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M32, "One-Time Inspection" and GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping." On this basis, the staff finds the cracking-fatigue from carbon steel heat exchanger (shell) exposed to steam greater than 270E F is adequately managed using the One-Time Inspection Program. On this basis, the staff finds that management of cracking-fatigue in the main steam system is acceptable. 3-350

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). 3.3.2.3.65 Make-up Demineralizer System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-53 The staff reviewed LRA Table 3.3.2-13-53, which summarized the results of AMR evaluations for the service air system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-53 are consistent with the GALL Report. 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). 3.3.2.3.66 Service Air System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-54 The staff reviewed LRA Table 3.3.2-13-54, which summarized the results of AMR evaluations for the service air system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-54 are consistent with the GALL Report. 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). 3.3.2.3.67 Seal Oil System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-55 The staff reviewed LRA Table 3.3.2-13-55, which summarized the results of AMR evaluations for the seal oil system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-55 are consistent with the GALL Report. 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). 3-351

3.3.2.3.68 Turbine Building Closed Cooling Water System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-56 The staff reviewed LRA Table 3.3.2-13-56, which summarized the results of AMR evaluations for the turbine building closed cooling water system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-56 are consistent with the GALL Report. 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). 3.3.2.3.69 Main Turbine Generator System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-57 In LRA Table 3.3.2-13-57, the applicant proposed to manage cracking-fatigue from carbon steel pump and turbine casing exposed to steam and treated water greater than 270E F using the One-Time Inspection Program. The staff reviewed the applicant's One-Time Inspection Program and its evaluation is documented in SER Section 3.0.3.1.6.The One-Time Inspection Program provides assurance that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly as not to affect the intended function of the component or structure. The staff finds the applicant's One-Time Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M32, "One-Time Inspection" and GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping." On this basis, the staff finds the cracking-fatigue from carbon steel heat exchanger (shell) exposed to steam and treated water greater than 270E F is adequately managed using the One-Time Inspection Program. On this basis, the staff finds that management of cracking-fatigue in the main turbine generator system is acceptable. 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). 3.3.2.3.70 Turbine Lube Oil System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation-LRA Table 3.3.2-13-58 The staff reviewed LRA Table 3.3.2-13-58, which summarized the results of AMR evaluations for the turbine lube oil system component groups. The staff finds that all AMR evaluation results in LRA Table 3.3.2-13-58 are consistent with the GALL Report. 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 3-352

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). 3.3.2.3.71 Aging Effect/Mechanism in Table 3.3.1 That are Not Applicable for VYNPS The staff reviewed LRA Table 3.3.1, which provides a summary of aging management evaluations for the auxiliary systems evaluated in the GALL Report. In LRA Table 3.3.1, Item 3.3.1-10 discussion column, the applicant stated that high strength steel bolting is not used in the auxiliary systems. The staff confirmed that there is no high strength steel bolting in the VYNPS auxiliary systems. On the basis that there is no high strength steel bolting in the auxiliary systems at VYNPS, the staff finds that this aging effect is not applicable at VYNPS. In LRA Table 3.3.1, Item 3.3.1-36, the applicant stated that the reduction of neutron-absorbing capacity of Boraflex spent fuel storage racks neutron-absorbing sheets exposed to treated water due to Boraflex degradation is not applicable at VYNPS. The staff confirmed that Boraflex is not used at VYNPS. On the basis that there is no Boraflex in the auxiliary systems at VYNPS, the staff finds that this aging effect is not applicable to VYNPS. In LRA Table 3.3.1, Item 3.3.1-39, the applicant stated that the cracking of stainless steel BWR spent fuel storage racks exposed to treated water greater than 60EC (greater than140EF) due to SCC is not applicable at VYNPS. The staff confirmed that the temperature of the water to which spent fuel racks are exposed is limited at VYNPS. On the basis that there are no stainless steel spent fuel storage racks exposed to treated water greater than140EF, the staff finds that this aging effect is not applicable at VYNPS. In LRA Table 3.3.1, Item 3.3.1-41, the applicant stated that the cracking of high-strength steel closure bolting exposed to air with steam or water leakage due to cyclic loading and SCC is not applicable at VYNPS. The staff confirmed that VYNPS auxiliary systems uses no high-strength steel closure bolting. On the basis that there is no high-strength steel bolting in the auxiliary systems at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS. In LRA Table 3.3.1, Item 3.3.1-42, the applicant stated that this line item was not used because the loss of material of steel closure bolting due to general corrosion was addressed by other line items. For loss of material due to general corrosion of steel closure bolting exposed to air with steam or water leakage, the GALL Report recommends a program consistent with GALL AMP XI.M18, Bolting Integrity. 3-353

During the audit and review, the staff asked the applicant to clarify how aging of steel closure bolting would be managed in the absence of a Bolting Integrity Program. In a letter dated July 6, 2006, the applicant agreed to prepare and submit an AMP consistent with GALL AMP XI.M18, Bolting Integrity, for approval. In a letter dated October 17, 2006, the applicant revised its LRA. The applicant submitted its Bolting Integrity Program. The staffs evaluation of this program is documented in SER Section 3.0.3.2.19. The staff finds that the applicants Bolting Integrity Program conformed to the recommendations of the GALL Report and encompass all safety-related bolting as delineated in NUREG-1339, which includes the criteria established in the 1995 Edition through the 1996 Addenda of ASME Code, Section XI. With this change, the applicants management of steel closure bolting will be consistent with the GALL Report and therefore acceptable. In LRA Table 3.3.1, Item 3.3.1-44, the applicant stated that this line item was not used because the loss of material due to general, pitting, and crevice corrosion of steel compressed air system closure bolting exposed to condensation was addressed by other line items. For loss of material due to general, pitting, and crevice corrosion of steel compressed air system closure bolting exposed to condensation, the GALL Report recommends a program consistent with GALL AMP XI.M18, Bolting Integrity. During the audit and review, the staff confirmed that all auxiliary system bolting within the scope of license renewal is addressed using other LRA Table 3.3.1 items. During discussions with the applicants technical personnel, the applicant staff stated that a Bolting Integrity Program is in development that will address the aging management of bolting within the scope of license renewal. In a letter dated July 6, 2006, the applicant committed to implement a Bolting Integrity Program which is consistent with GALL AMP XI.M18, Bolting Integrity. In a letter dated October 17, 2006, the applicant revised its LRA. The applicant submitted its Bolting Integrity Program. The staffs evaluation of this program is documented in SER Section 3.0.3.2.19. The staff finds that the applicants Bolting Integrity Program conformed to the recommendations of the GALL Report and encompass all safety-related bolting as delineated in NUREG-1339, which includes the criteria established in the 1995 Edition through the 1996 Addenda of ASME Code, Section XI. With this change, the applicants management of bolting within the scope of license renewal will be consistent with the GALL Report and therefore acceptable. On the basis that loss of material from steel bolting will be managed in a manner consistent with the recommendations of the GALL Report, the staff finds management of this aging effect to be acceptable even if LRA 3.3.1, Item 3.3.1-44 is not referenced. In LRA Table 3.3.1, Item 3.3.1-45, the applicant stated that loss of preload of steel closure bolting exposed to air due to thermal effects, gasket creep, and self-loosening is not applicable at VYNPS. During the audit and review, the staff confirmed that no auxiliary system closure bolting is subjected to temperature or pressure high enough to require aging management for this aging effect. On the basis that no VYNPS auxiliary system closure bolting is subjected to temperature or pressure high enough to require aging management, the staff finds that loss of preload is not applicable at VYNPS for this component type, environment, and aging effect. 3-354

In LRA Table 3.3.1, Item 3.3.1-62, the applicant stated that loss of material due to pitting and crevice corrosion of aluminum piping, piping components, and piping elements exposed to raw water is not applicable at VYNPS because there are no aluminum components with intended functions exposed to raw water in the auxiliary systems. The staff confirmed that aluminum is not used for auxiliary systems SCs within the scope of license renewal at VYNPS. On the basis that aluminum is not used in the auxiliary systems SCs within the scope of license renewal at VYNPS, the staff finds that this aging effect is not applicable. In LRA Table 3.3.1, Item 3.3.1-64, the applicant stated that this line item was not used because loss of material from steel components exposed to fuel oil was addressed by other line items. During the audit and review, the staff confirmed that loss of material from steel components exposed to fuel oil was addressed by other line items. The staffs review of those items is documented in SER Sections 3.3.2.2.9 and 3.3.2.2.12, respectively. On the basis that loss of material from steel components exposed to fuel oil is adequately managed, the staff finds that assignment of components in this category to other items in LRA Table 3.3.1 is acceptable. In LRA Table 3.3.1, Item 3.3.1-65, the applicant stated that this line item was not used because concrete cracking and spalling due to aggressive chemical attack, and reaction with aggregates of reinforced concrete structural fire barriers are evaluated as structural components in LRA Section 3.5. On the basis that reinforced concrete structural fire barriers are evaluated in LRA Section 3.5, the staff finds that assignment of components in this category to other items in LRA Table 3.5.1 is acceptable. In LRA Table 3.3.1, Item 3.3.1-66, the applicant stated that this line item was not used because concrete cracking and spalling due to freeze thaw, aggressive chemical attack, and reaction with aggregates of reinforced concrete structural fire barriers are evaluated as structural components in LRA Section 3.5. On the basis that reinforced concrete structural fire barriers are evaluated in LRA Section 3.5, the staff finds that assignment of components in this category to other items in LRA Table 3.5.1 is acceptable. In LRA Table 3.3.1, Item 3.3.1-67, the applicant stated that this line item was not used because loss of material due to corrosion of embedded steel of reinforced concrete structural fire barriers are evaluated as structural components in LRA Section 3.5. On the basis that reinforced concrete structural fire barriers are evaluated in LRA Section 3.5, the staff finds that assignment of components in this category to other items in LRA Table 3.5.1 is acceptable. 3-355

In LRA Table 3.3.1, Item 3.3.1-74, the applicant stated that this line item was not used because loss of material due to wear of steel crane rails is evaluated in accordance with structural components in LRA Section 3.5. During the audit and review, the staff noted that steel crane structural girders are evaluated as structural components in LRA Section 3.5, however, loss of material due to wear is not explicitly addressed. The applicant's technical personnel stated that reactor building steel crane structural girders used in load handling are inspected in accordance with the Periodic Surveillance and Preventive Maintenance Program identified in (LRA Appendix B). Process facility crane rails and girders are inspected in accordance with the Structures Monitoring Program as identified in (LRA Appendix B). The Structures Monitoring Program will be enhanced, as identified in Appendix B, to address crane rails and girders. Aging management activities for crane rails and girders in accordance with these two programs are consistent with the program elements described for the GALL AMP XI.M23, Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems. The staff finds this consistent with the GALL Report and is therefore acceptable. On the basis that loss of material due to wear of crane rails will be managed in a manner consistent with the recommendations of the GALL Report, the staff finds management of this aging effect acceptable. In LRA Table 3.3.1, Item 3.3.1-75, the applicant stated that the hardening and loss of strength due to elastomer degradation and loss of material due to erosion of elastomer seals and components exposed to raw water is not applicable at VYNPS. The staff confirmed that there are no elastomeric components exposed to raw or untreated water in the auxiliary systems that require aging management. On the basis that there are no elastomeric components in the auxiliary systems at VYNPS that require aging management, the staff finds that, for this component type, this aging effect is not applicable to VYNPS. In LRA Table 3.3.1, Item 3.3.1-78, the applicant stated that loss of material due to pitting and crevice corrosion of stainless steel and copper alloy piping, piping components, and piping elements exposed to raw water are managed in accordance with other items from LRA Table 3.3.1 or in the case of nickel-alloy components, need not be managed because there is no such material within the scope of license renewal for VYNPS auxiliary systems. During the audit and review, the staff confirmed that nickel alloy is not used for auxiliary SSCs within the scope of license renewal at VYNPS. The staff also confirmed that loss of material due to pitting and crevice corrosion of stainless steel and copper alloy piping, piping components, and piping elements exposed to raw water is managed in accordance with other items from LRA Table 3.3.1. The staffs review of those items is documented in SER Section 3.3.2.1. On the basis that pitting and crevice corrosion of stainless steel and copper alloy piping, piping components, and piping elements exposed to raw water is adequately managed, the staff finds that assignment of components in this category to other items in LRA Table 3.3.1 is acceptable. 3-356

In LRA Table 3.3.1, Item 3.3.1-80, the applicant stated that the loss of material of stainless steel and copper alloy piping, piping components, and piping elements exposed to raw water due to pitting, crevice, and MIC is not applicable at VYNPS. The staff confirmed that at VYNPS, EDG system piping, piping components, and piping elements are not exposed to raw water. On the basis that there are no EDG piping components subject to aging management at VYNPS exposed to raw water, the staff finds that, for this component type, this aging effect is not applicable to VYNPS. (Heat exchanger components exposed to raw water are addressed in accordance with other items of LRA Table 3.3.1-1.) In LRA Table 3.3.1, Item 3.3.1-86, the applicant stated that this line item was not used because loss of material due to general, pitting, and crevice corrosion of new fuel storage rack assemblies is evaluated with structural components in LRA Section 3.5. On the basis that reinforced concrete structural steel are evaluated in LRA Section 3.5, the staff finds that assignment of components in this category to other items in LRA Table 3.5.1 is acceptable. In LRA Table 3.3.1, Item 3.3.1-92, the applicant stated that galvanized steel surfaces are evaluated as steel for the auxiliary systems at VYNPS. On the basis that galvanized steel surfaces are evaluated as steel for the auxiliary systems, the staff finds the managed of galvanized steel acceptable. In LRA Table 3.3.1, Item 3.3.1-95, the applicant stated that there are no auxiliary system components exposed to controlled indoor air at VYNPS. On the basis that there is no auxiliary system components exposed to controlled indoor air in the auxiliary systems at VYNPS, the staff finds that this aging effect is not applicable at VYNPS. In LRA Table 3.3.1, Item 3.3.1-98, the applicant stated that dried (treated) air is maintained as an environment as a result of the Instrument Air Quality Program, so aging effects may occur without that program. Because this program is in place, this environment is maintained at VYNPS. On this basis, steel, stainless steel, and copper alloy piping, piping components, and piping elements exposed to dried air does not need to be managed at VYNPS. 3.3.2.3.72 Auxiliary Systems AMR Line Items That Have No Aging Effects (LRA Tables 3.3.2-1 through 3.3.2-13-58) In LRA Tables 3.3.2-1 through 3.3.2-13-58, the applicant identified line items where no aging effects were identified as a result of its aging review process. In LRA Tables 3.3.2-1 through 3.3.2-13-58, the applicant identified no aging effects for component types of various materials exposed to indoor air. This includes a flame arrestor in the fuel oil system fabricated from aluminum; tubing in the fire protection water system made of copper alloy; and nozzles, piping, tubing, siren or valve bodies in the fire protection system made 3-357

of copper alloy. Similarly, the applicant finds no aging effects for stainless steel nozzles, tubing, and valve bodies of the fire protection system; valve bodies of the SWS; as well as diaphragms, dryers, filter housings, heat exchangers, orifices, piping, pump casings, traps, tubing, and valve bodies of the primary containment atmospheric control and containment air dilution system exposed to indoor air. The GALL Report identified that aluminum in an indoor uncontrolled air environment exhibits no aging effect and that the component or structure will therefore remain capable of performing its intended functions consistent with the CLB for the period of extended operation. Aluminum has an excellent resistance to corrosion when exposed to humid air (an uncontrolled indoor environment). The aluminum oxide film is bonded strongly to its surface and that film, if damaged, reforms immediately in most environments. On a surface freshly abraded and then exposed to air, the oxide film is only 5 to 10 nanometers thick but is highly effective in protecting the aluminum from further corrosion. For this reason, the staff finds that aluminum exposed to indoor uncontrolled air environment does not require aging management. The GALL Report identified that copper alloy in an indoor, uncontrolled air environment exhibits no aging effect and that the component or structure will therefore remain capable of performing its intended functions consistent with the CLB for the period of extended operation. This conclusion is based on the fact that comprehensive tests conducted over a 20-year period in accordance with the supervision of ASTM have confirmed the suitability of copper and copper alloys for atmospheric exposure. For this reason, the staff finds that copper alloy exposed to indoor uncontrolled air environment does not require aging management. Finally, the GALL Report identified that stainless steel in an indoor, uncontrolled air environment exhibits no aging effect and that the component or structure will therefore remain capable of performing its intended functions consistent with the CLB for the period of extended operation. This conclusion is based on the fact that stainless steels are highly resistant to corrosion in dry atmospheres in the absence of corrosive species, (which would be reflective of indoor uncontrolled air). Components are not subject to moisture in a dry air environment (and indoor uncontrolled air would have limited humidity and condensation). For this reason, the staff finds that stainless steel exposed to indoor uncontrolled air environment does not require aging management. The staff finds that no aging effects are considered to be applicable to components fabricated from aluminum, copper alloy, or stainless steel exposed to air. The applicant identified no aging effects for a PACCAD system stainless steel diaphragms exposed to silicone. The GALL Report identified that stainless steels are highly resistant to corrosion in dry atmospheres in the absence of corrosive species. On this basis, and considering that silicone does not react with stainless steel, the staff finds that there are no AERM for stainless steel diaphragms of the PACCAD system exposed to silicone. 3-358

The applicant also identified no aging effects for stainless steel bolting in the CW system exposed to outdoor air. During the audit and review, the staff asked the applicant to provide the location of the CW system bolting components at VYNPS and clarify how they are protected from constant wetting and drying conditions. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to state for stainless steel bolting exposed to outdoor air, the loss of material is to be managed by the System Walkdown Program. The staff reviewed the System Walkdown Program, which entails inspections of external surfaces of components subject to an AMR. The staffs evaluation is documented in SER Section 3.0.3.1.9. The program is also credited with managing loss of material from internal surfaces, for situations in which internal and external material and environment combinations are the same such that external surface condition is representative of internal surface condition. On this basis, the staff finds the loss of stainless steel from bolting exposed to air is adequately managed using the System Walkdown Program. The applicant also identified no aging effects for an HVAC system sight glass exposed to condensation. The GALL Report identified that glass in a raw water environment exhibits no aging effect and the component or structure will therefore remain capable of performing its intended functions consistent with the CLB for the period of extended operation. This conclusion is based on the fact that silicate glasses are highly inert and operating experience has demonstrated that there are no aging related failures of glass in this environment. For this reason, the staff finds that glass exposed to condensation does not require aging management. The staff finds that no aging effects are considered to be applicable to an HVAC system sight glass exposed to condensation. The applicant also identified no aging effects for an SLC system sight glass exposed to sodium pentaborate solution. The GALL Report identified that glass in a borated water environment exhibits no aging effect and the component or structure will therefore remain capable of performing its intended functions consistent with the CLB for the period of extended operation. This conclusion is based on the fact that silicate glasses are highly inert and operating experience has demonstrated that there are no aging related failures of glass in this environment. For this reason, the staff finds that glass exposed to condensation does not require aging management. The staff finds that no aging effects are considered to be applicable to an SLC system sight glass exposed to sodium pentaborate solution. The applicant also identified no aging effects for fiberglass piping and tanks exposed to fuel oil. The GALL Report identified that glass in a fuel oil environment exhibits no aging effect, and found that components of glass exposed to fuel oil will remain capable of performing their intended functions consistent with the CLB for the period of extended operation. 3-359

On the basis that fiberglass (comprising glass and polymers) is similarly resistant to chemical attack by fuel oil, the staff finds that fiberglass piping and tanks exposed to fuel oil will exhibit no aging effect requiring aging management. The applicant also identified no aging effects for fiberglass piping and tanks exposed to soil. The GALL Report identified that glass in a raw water environment exhibits no aging effect, and found that components of glass exposed to raw water will remain capable of performing their intended functions consistent with the CLB for the period of extended operation. On the basis that a soil environment is no more aggressive than raw water and that fiberglass (comprising glass and polymers) is similarly resistant to chemical attack, the staff finds that fiberglass piping and tanks buried in soil will exhibit no aging effect requiring aging management. The applicant also identified no aging effects for fiberglass tanks exposed to interstitial fluid (brine). During the audit and review, the applicant was asked to clarify the nature of the interstitial fluid. The applicants technical personnel explained that the interstitial fluid (brine) environment is colored water, treated with antifreeze and located between the inner and outer walls of a double-walled fiberglass fuel oil tank. The fluid is used for leak detection and is provided by the manufacturer of the tank. The GALL Report identifies no aging effect for glass in a treated water environment. The aging effects/mechanisms identified for other non-metallics are not relevant to the function of the fiberglass fuel tank. On this basis, the staff finds no aging effect requiring aging management for fiberglass exposed to interstitial fluid. The applicant also identified no aging effects for fiberglass flexible duct connections exposed to indoor air. For other non-metallic components, the applicant considered degradation from sustained vibratory loading and from wear. During the audit and review, the staff asked the applicant's technical personnel to clarify the basis for concluding that these aging mechanisms are not applicable to flexible duct connections of fiberglass. The applicant stated that wear is the loss of surface layers due to relative motion between two surfaces and that at in the auxiliary systems VYNPS, this specific aging effect is not applicable because the heating, ventilation, and air conditioning elastomer coated fiberglass duct flexible connections are fixed at both ends, precluding wear. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant revised LRA Section 3.3.2.2.13 to state: Wear is the removal of surface layers due to relative motion between two surfaces. At VYNPS, in the auxiliary systems, this specific aging effect is not applicable because the heating, ventilation, and air conditioning elastomer coated fiberglass duct flexible connections are fixed at both ends, precluding wear. This item is not applicable to VYNPS auxiliary systems. 3-360

On the basis of its review, the staff finds that wear is precluded by the system design feature and that this aging effect/mechanism is not applicable to VYNPS auxiliary systems. On this basis, the staff finds no AERM for fiberglass duct flexible connections exposed to indoor air. Conclusion. On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results involving material, environment, AERM, and AMP combinations that are 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 staffs review of the applicants AMR results for the steam and power conversion systems components and component groups of:

• auxiliary steam
• condensate
• main steam
• 101 (main steam, extraction steam, and auxiliary steam instruments) 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 for the Steam and Power Conversion System, is a summary comparison of the applicants AMRs with those evaluated in the GALL Report for the steam and power conversion systems components and component groups.

The applicants 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 applicants 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 whether the applicant 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 3-361

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 conducted an onsite audit of AMRs to ensure the applicants 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. The staffs evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staffs audit evaluation are documented in SER Section 3.4.2.1. In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicants further evaluations were consistent with the SRP-LR Section 3.4.2.2 acceptance criteria. The staffs audit evaluations are documented in SER Section 3.4.2.2. The staff also conducted a technical review of the remaining AMRs that were not consistent with, or not addressed in, the GALL Report. The technical review evaluated whether all plausible aging effects have been identified and whether the aging effects listed were appropriate for the material-environment combinations specified. The staffs evaluations are documented in SER Section 3.4.2.3. Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or monitoring aging for the steam and power conversion systems components. For SSCs which the applicant claimed were not applicable or required no aging management, the staff reviewed the AMR line items and the plants operating experience to verify the applicants claims. Table 3.4-1 summarizes the staffs evaluation of components, aging effects/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 Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Steel piping, Cumulative fatigue TLAA, evaluated in TLAA Fatigue is a TLAA piping damage accordance with (See SER components, 10 CFR 54.21(c) Section 3.4.2.2.1) and piping elements exposed to steam or treated water (3.4.1-1) 3-362

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Steel piping, Loss of material due Water Chemistry Water Chemistry Consistent with piping to general, pitting and One-Time Control-BWR GALL Report, which components, and crevice Inspection Program (B.1.30.2); recommends further and piping corrosion One-Time evaluation (See elements Inspection Program SER exposed to (B.1.21) Section 3.4.2.2.2) steam (3.4.1-2) Steel heat Loss of material due Water Chemistry None Not applicable to exchanger to general, pitting and One-Time BWRs components and crevice Inspection exposed to corrosion treated water (3.4.1-3) Steel piping, Loss of material due Water Chemistry Water Chemistry Consistent with piping to general, pitting and One-Time Control-BWR GALL Report, which components, and crevice Inspection Program (B.1.30.2); recommends further and piping corrosion One-Time evaluation (See elements Inspection Program SER exposed to (B.1.21) Section 3.4.2.2.2) treated water (3.4.1-4) Steel heat Loss of material due Water Chemistry None Not applicable (See exchanger to general, pitting, and One-Time SER components crevice, and Inspection Section 3.4.2.2.9) exposed to galvanic corrosion treated water (3.4.1-5) Steel and Loss of material due Water Chemistry None Not applicable (See stainless steel to general (steel and One-Time SER tanks exposed only) pitting and Inspection Section 3.4.2.2.2) to treated crevice corrosion water (3.4.1-6) Steel piping, Loss of material due Lubricating Oil None Not applicable (See piping to general, pitting Analysis and SER components, and crevice One-Time Section 3.4.2.2.2) and piping corrosion Inspection elements exposed to lubricating oil (3.4.1-7) 3-363

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Steel piping, Loss of material due Plant-specific None Not applicable (See piping to general, pitting, SER components, crevice, and MIC, Section 3.4.2.2.3) and piping and fouling elements exposed to raw water (3.4.1-8) Stainless steel Reduction of heat Water Chemistry Water Chemistry Consistent with and copper transfer due to and One-Time Control-BWR GALL Report, which alloy heat fouling Inspection Program (B.1.30.2); recommends further exchanger One-Time evaluation (See tubes exposed Inspection Program SER to treated (B.1.21) Section 3.4.2.2.4) water (3.4.1-9) Steel, Reduction of heat Lubricating Oil None Not applicable (See stainless steel, transfer due to Analysis and SER and copper fouling One-Time Section 3.4.2.2.4) alloy heat Inspection exchanger tubes exposed to lubricating oil (3.4.1-10) Buried steel Loss of material due Buried Piping and None Not applicable (See piping, piping to general, pitting, Tanks Surveillance SER components, crevice, and MIC Section 3.4.2.2.5) piping or elements, and tanks (with or Buried Piping and without Tanks Inspection coating or wrapping) exposed to soil (3.4.1-11) Steel heat Loss of material due Lubricating Oil None Not applicable (See exchanger to general, pitting, Analysis and SER components crevice, and MIC One-Time Section 3.4.2.2.5) exposed to Inspection lubricating oil (3.4.1-12) 3-364

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Stainless steel Cracking due to Water Chemistry Water Chemistry Consistent with piping, piping SCC and One-Time Control-BWR GALL Report, which components, Inspection Program (B.1.30.2); recommends further piping One-Time evaluation (See elements Inspection Program SER exposed to (B.1.21) Section 3.4.2.2.6) steam (3.4.1-13) Stainless steel Cracking due to Water Chemistry None Not applicable. piping, piping SCC and One-Time (There are no components, Inspection stainless steel piping components elements, exposed to treated tanks, and water with intended heat functions in the exchanger steam and power components conversion exposed to systems.) treated water (See SER > 60EC Section 3.4.2.2.6) (> 140EF) (3.4.1-14) Aluminum and Loss of material due Water Chemistry Water Chemistry Consistent with copper alloy to pitting and and One-Time Control-BWR GALL Report, which piping, piping crevice corrosion Inspection Program (B.1.30.2); recommends further components, One-Time evaluation (See and piping Inspection Program SER elements (B.1.21) Section 3.4.2.2.7) exposed to treated water (3.4.1-15) Stainless steel Loss of material due Water Chemistry None Not applicable. piping, piping to pitting and and One-Time (There are no components, crevice corrosion Inspection stainless steel and piping components elements; exposed to treated tanks, and water with intended heat functions in the exchanger steam and power components conversion exposed to systems.) treated water (See SER (3.4.1-16) Section 3.4.2.2.7) Stainless steel Loss of material due Plant-specific None Not applicable (See piping, piping to pitting and SER components, crevice corrosion Section 3.4.2.2.7) and piping elements exposed to soil (3.4.1-17) 3-365

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Copper alloy Loss of material due Lubricating Oil None Not applicable (See piping, piping to pitting and Analysis and SER components, crevice corrosion One-Time Section 3.4.2.2.7) and piping Inspection elements exposed to lubricating oil (3.4.1-18) Stainless steel Loss of material due Lubricating Oil None Not applicable (See piping, piping to pitting, crevice, Analysis and SER components, and MIC One-Time Section 3.4.2.2.8) piping Inspection elements, and heat exchanger components exposed to lubricating oil (3.4.1-19) Steel tanks Loss of material/ Aboveground Steel None Not applicable. exposed to air general, pitting, and Tanks (There are no steel - outdoor crevice corrosion tanks exposed to (external) outdoor air with (3.4.1-20) intended functions in the steam and power conversion systems.) (See SER Section 3.4.2.3.2) High-strength Cracking due to Bolting Integrity None Not applicable. steel closure cyclic loading, SCC (High-strength steel bolting closure bolting is exposed to air not used in the with steam or steam and power water leakage conversion (3.4.1-21) systems.) (See SER Section 3.4.2.3.2) Steel bolting Loss of material due Bolting Integrity Bolting Integrity Consistent with and closure to general, pitting Program GALL Report. (See bolting and crevice SER exposed to air corrosion; loss of Section 3.4.2.1.6) with steam or preload due to water leakage, thermal effects, air-outdoor gasket creep, and (external), or self-loosening air-indoor uncontrolled (external); (3.4.1-22) 3-366

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Stainless steel Cracking due to Closed-Cycle None Not applicable. piping, piping SCC Cooling Water (There are no components, System stainless steel and piping components elements exposed to exposed to closed-cycle cooling closed-cycle water in the steam cooling water and power > 60EC conversion (> 140EF) systems.) (3.4.1-23) Steel heat Loss of material due Closed-Cycle None Not applicable. exchanger to general, pitting, Cooling Water (There are no steel components crevice, and System heat exchanger exposed to galvanic corrosion components closed-cycle exposed to cooling water closed-cycle cooling (3.4.1-24) water in the steam and power conversion systems.) (See SER Section 3.4.2.3.2) Stainless steel Loss of material due Closed-Cycle Water Chemistry Consistent with piping, piping to pitting and Cooling Water Control-Closed GALL Report. (See components, crevice corrosion System Cooling Water SER piping Program (B.1.30.3) Section 3.4.2.1) elements, and heat exchanger components exposed to closed-cycle cooling water (3.4.1-25) Copper alloy Loss of material due Closed-Cycle None Not applicable. piping, piping to pitting, crevice, Cooling Water (There are no components, and galvanic System copper alloy and piping corrosion components elements exposed to exposed to closed-cycle cooling closed-cycle water in the steam cooling water and power (3.4.1-26) conversion systems.) (See SER Section 3.4.2.3.2) 3-367

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Steel, Reduction of heat Closed-Cycle None Not applicable. stainless steel, transfer due to Cooling Water (There are no heat and copper fouling System exchanger tubes alloy heat exposed to exchanger closed-cycle cooling tubes exposed water in the steam to closed-cycle and power cooling water conversion (3.4.1-27) systems.) Steel external Loss of material due External Surfaces System Walkdown Consistent with surfaces to general corrosion Monitoring Program (B.1.28) GALL Report (See exposed to SER air-indoor Section 3.4.2.1.7) uncontrolled (external), condensation (external), or air-outdoor (external) (3.4.1-28) Steel piping, Wall thinning due to Flow-Accelerated Flow-Accelerated Consistent with piping flow-accelerated Corrosion Corrosion Program GALL Report (See components, corrosion (B.1.13) SER and piping Section 3.4.2.1.8) elements exposed to steam or treated water (3.4.1-29) Steel piping, Loss of material due Inspection of System Walkdown Consistent with piping to general, pitting, Internal Surfaces in Program (B.1.28) GALL Report (See components, and crevice Miscellaneous SER and piping corrosion Piping and Ducting Section 3.4.2.1.9) elements Components exposed to air-outdoor (internal) or condensation (internal) (3.4.1-30) Steel heat Loss of material due Open-Cycle Cooling Periodic Consistent with exchanger to general, pitting, Water System Surveillance and GALL Report (See components crevice, galvanic, Preventive SER exposed to and MIC, and Maintenance Section 3.4.2.1.10) raw water fouling Program (B.1.22) (3.4.1-31) 3-368

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Stainless steel Loss of material due Open-Cycle Cooling Periodic Consistent with and copper to pitting, crevice, Water System Surveillance and GALL Report, (See alloy piping, and MIC Preventive SER piping Maintenance Section 3.4.2.1.11) components, Program (B.1.22) and piping elements exposed to raw water (3.4.1-32) Stainless steel Loss of material due Open-Cycle Cooling None Not applicable. heat to pitting, crevice, Water System (There are no exchanger and MIC, and stainless steel heat components fouling exchanger exposed to components raw water exposed to raw (3.4.1-33) water in the steam and power conversion systems.) (See SER Section 3.4.2.3.2) Steel, Reduction of heat Open-Cycle Cooling None Not applicable. stainless steel, transfer due to Water System There are no heat and copper fouling exchanger tubes alloy heat exposed to raw exchanger water with an tubes exposed intended function of to raw water heat transfer in the (3.4.1-34) steam and power conversion systems.) (See SER Section 3.4.2.3.2) Copper alloy Loss of material due Selective Leaching None Not applicable. > 15 to selective leaching of Materials (There are no percent Zn copper alloy piping, piping components subject components, to selective leaching and piping in the steam and elements power conversion exposed to systems.) closed-cycle (See SER cooling water, Section 3.4.2.3.2) raw water, or treated water (3.4.1-35) 3-369

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Gray cast iron Loss of material due Selective Leaching None Not applicable. piping, piping to selective leaching of Materials (There are no gray components, cast iron and piping components elements exposed to raw exposed to water with intended soil, treated functions in the water, or raw steam and power water conversion (3.4.1-36) systems.) (See SER Section 3.4.2.3.2) Steel, Loss of material due Water Chemistry Water Chemistry Consistent with stainless steel, to pitting and Control-BWR GALL Report (See and crevice corrosion Program (B.1.30.2); SER nickel-based Water Chemistry Section 3.4.2.1.12) alloy piping, Control-Auxiliary piping Systems Program components, (B.1.30.1) and piping elements exposed to steam (3.4.1-37) Steel bolting Loss of material due Boric Acid None Not applicable to and external to boric acid Corrosion BWRs surfaces corrosion exposed to air with borated water leakage (3.4.1-38) Stainless steel Cracking due to Water Chemistry None Not applicable to piping, piping SCC BWRs components, and piping elements exposed to steam (3.4.1-39) Glass piping None None None Not applicable. elements (There are no glass exposed to air, components with lubricating oil, intended functions raw water, and in the steam and treated water power conversion (3.4.1-40) systems.) 3-370

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation Group Mechanism Report (GALL Report Item No.) Stainless None None None Consistent with steel, copper GALL Report. (See alloy, and SER nickel alloy Section 3.4.2.1) piping, piping components, and piping elements exposed to air-indoor uncontrolled (external) (3.4.1-41) Steel piping, None None None Not applicable. piping (There are no steel components, components and piping exposed to elements air-indoor controlled exposed to in the steam and air-indoor power conversion controlled systems.) (external) (3.4.1-42) Steel and None None None Not applicable. stainless steel (There are no steel piping, piping or stainless steel components, components and piping exposed to concrete elements in in the steam and concrete power conversion (3.4.1-43) systems.) Steel, None None None Not applicable. stainless steel, (There are no steel, aluminum, and stainless steel, copper alloy aluminum, or piping, piping copper alloy components, components and piping exposed to gas in elements the steam and exposed to power conversion gas systems.) (3.4.1-44) The staffs 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 3-371

consistent with or not addressed in the GALL Report. The staffs review of AMPs credited to manage or monitor aging effects of the steam and power conversion systems components is documented in SER Section 3.0.3. 3.4.2.1 AMR Results Consistent with the GALL Report Summary of Technical Information in the Application. 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:

• Flow-Accelerated Corrosion Program
• System Walkdown Program
• Water Chemistry Control - BWR Program
• Water Chemistry Control - Closed Cooling Water Program LRA Table 3.4.2-1 summarizes AMRs for the steam and power conversion systems components and indicates AMRs claimed to be consistent with the GALL Report.

Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant claimed consistency with the report and for which it does not recommend further evaluation, the staffs 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 through E indicating 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 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 AMP. The staff audited these line items to verify consistency with the GALL Report and verified that the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also finds whether the applicants AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions. Note C indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified 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 GALL Report. The staff also finds 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. 3-372

Note D indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL 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 identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also finds whether the applicants AMP was consistent with the GALL 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 finds whether the credited AMP would manage the aging effect consistently with the GALL AMP and whether the AMR was valid for the site-specific conditions. 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 staffs evaluation follows. 3.4.2.1.1 Loss of Material Due to General, Pitting, and Crevice Corrosion In LRA Table 3.4.1, Item 3.4.1-2, the applicant stated that the Water Chemistry Control-BWR Program, augmented by the One-Time Inspection Program, to verify program effectiveness, will be used to manage loss of material for steel components exposed to steam in the ESF systems listed in LRA Table 3.2.2 and components in-scope in accordance with 10 CFR 54.4(a)(2) criterion and listed in LRA Tables 3.3.2-13-xx series. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly credited in the system table (Table 3.4.2-1), only the Water Chemistry Control-BWR Program was credited. In a letter dated July 14, 2006, the applicant amended the LRA. The applicant revised its Water Chemistry Control-BWR Program to include the sentence: The One-Time Inspection Program will confirm the effectiveness of the program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and the One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff finds that the applicants Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The staff also finds that the applicants One-Time Inspection Program is used to verify the effectiveness of the Water Chemistry Control-BWR Program consistent with the GALL Report and therefore acceptable. 3.4.2.1.2 Loss of Material Due to General, Pitting, and Crevice Corrosion In LRA Table 3.4.1, Item 3.4.1-4, the applicant stated that the Water Chemistry Control-BWR Program, augmented by the One-Time Inspection Program, to verify program effectiveness, will be used to manage loss of material for steel piping, piping components, and piping elements exposed to treated water and also in the components that are in-scope in accordance with 10 CFR 54.4(a)(2) criterion and listed in LRA Tables 3.3.2-13-xx series. 3-373

During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly credited in the system table (Table 3.4.2-1), only the Water Chemistry Control-BWR Program was credited. In a letter dated July 14, 2006, the applicant amended the LRA. The applicant revised its Water Chemistry Control-BWR Program to include the sentence: The One-Time Inspection Program will confirm the effectiveness of the program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and the One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff finds that the applicants Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The staff also finds that the applicants One-Time Inspection Program is used to verify the effectiveness of the Water Chemistry Control-BWR Program consistent with the GALL Report and therefore acceptable. 3.4.2.1.3 Reduction of Heat Transfer Due to Fouling In LRA Table 3.4.1, Item 3.4.1-9, the applicant stated that the Water Chemistry Control-BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage the reduction of heat transfer in copper alloy heat exchanger tubes exposed to treated water in the steam and power conversion systems. These programs will also be used to manage reduction of heat transfer in the HPCI and RCIC systems as listed in LRA Tables 3.2.2-4 and 3.2.2-5. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly credited in the system table (Table 3.4.2-1), only the Water Chemistry Control-BWR Program was credited. In a letter dated July 14, 2006, the applicant amended the LRA. The applicant revised its Water Chemistry Control-BWR Program to include the sentence: The One-Time Inspection Program will confirm the effectiveness of the program. The staff reviewed the applicant's Water Chemistry Control-BWR Program and the One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff finds that the applicants Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The staff also finds that the applicants One-Time Inspection Program is used to verify the effectiveness of the Water Chemistry Control-BWR Program consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.4.2.1.4 Cracking Due to Stress Corrosion Cracking In LRA Table 3.4.1, Item 3.4.1-13, the applicant stated that the Water Chemistry Control-BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage cracking due to SCC for stainless steel components exposed to steam. 3-374

During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly credited in the system table (Table 3.4.2-1), only the Water Chemistry Control-BWR Program was credited. In a letter dated July 14, 2006, the applicant amended the LRA. The applicant revised its Water Chemistry Control-BWR Program to include the sentence: The One-Time Inspection Program will confirm the effectiveness of the program. The staff reviewed the applicant's Water Chemistry Control - BWR Program and the One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff finds that the applicants Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The staff also finds that the applicants One-Time Inspection Program is used to verify the effectiveness of the Water Chemistry Control-BWR Program consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.4.2.1.5 Loss of Material Due to Pitting and Crevice Corrosion In Table 3.4.1, Item 3.4.1-15, the applicant stated that the Water Chemistry Control-BWR Program, augmented by the One-Time Inspection Program to verify program effectiveness, will be used to manage loss of material of aluminum and copper alloy components exposed to treated water and also in the components that are in-scope in accordance with 10 CFR 54.4(a)(2) criterion and listed in LRA Tables 3.3.2-13-xx series. The application also stated that there are no aluminum components with intended functions in the steam and power conversion systems. During the audit and review, the staff noted that for this aging effect, the One-Time Inspection Program was not explicitly credited in the system table (Table 3.4.2-1), only the Water Chemistry Control-BWR Program was credited. In a letter dated July 14, 2006, the applicant amended the LRA. The applicant revised its Water Chemistry Control-BWR Program to include the sentence: The One-Time Inspection Program will confirm the effectiveness of the program. The staff reviewed the applicant's Water Chemistry Control - BWR Program and the One-Time Inspection Program and its evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.1.6, respectively. The staff finds that the applicants Water Chemistry Control-BWR Program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). The staff also finds that the applicants One-Time Inspection Program is used to verify the effectiveness of the Water Chemistry Control-BWR Program consistent with the GALL Report and therefore acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3-375

3.4.2.1.6 Loss of Material Due to General, Pitting, and Crevice Corrosion and Loss of Preload Due to Thermal Effects, Gasket Creep and Self-Loosening In the discussion column of LRA Table 3.4.1, Item 3.4.1-22, the applicant stated that its System Walkdown Program will manage loss of material for steel bolting through the use of visual inspections performed at least once per refueling cycle. The applicant further stated that loss of preload is not an applicable aging effect. Loss of preload is a design driven effect and not an AERM. During the audit and review, the staff asked the applicant to clarify the basis for using its System Walkdown Program to manage the loss of material for steel bolting instead the AMP recommended by the GALL Report. In a letter dated July 6, 2006, the applicant stated that it will prepare and submit an AMP consistent with GALL AMP XI.M18, Bolting Integrity, for approval. By letter dated October 17, 2006, the applicant provided its Bolting Integrity Program. The staff reviewed the applicants Bolting Integrity Program and its evaluation is documented in SER Section 3.0.3.2.19. The staff finds that the applicants Bolting Integrity Program conformed to the recommendations of the GALL Report and encompass all safety-related bolting as delineated in NUREG-1339, which includes the criteria established in the 1995 Edition through the 1996 Addenda of ASME Code, Section XI. On this basis, the staff finds the applicants Bolting Integrity Program acceptable for managing loss of material for steel bolting. In its October 17, 2006 letter, the applicant also stated that this program applies to all bolting exposed to air with aging effects requiring management, except reactor vessel closure studs. However, in LRA, the applicant stated that loss of preload is not an applicable aging effect and does not requiring an aging management. The applicant was asked to confirm if the program applied to all bolting. By letter dated January 4, 2007, the applicant clarifying that the Bolting Integrity Program applies to bolting and torqueing practices of safety-related and nonsafety-related bolting for pressure retaining components, NSSS support components, and structural joints. On the basis of its review, the staff finds the applicant clarification acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.4.2.1.7 Loss of Material Due to General Corrosion In the discussion column of LRA Table 3.4.1, Item 3.4.1-28, the applicant stated that this item is consistent with the GALL Report and that its System Walkdown Program will be used to manage loss of material for external surfaces of steel components. The staff reviewed the applicant's System Walkdown Program and its evaluation is documented in SER Section 3.0.3.1.9. This program entails inspections of external surfaces of components subject to an AMR. The program is also credited with managing loss of material from internal surfaces where internal and external material-environment combinations are the same and external surface conditions represent internal surface conditions. The staff finds that the applicants System Walkdown Program is consistent with GALL AMP XI.M36. 3-376

On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.4.2.1.8 Wall Thinning Due to Flow-Accelerated Corrosion In the discussion column of LRA Table 3.4.1, Item 3.4.1-29, the applicant stated that this item is consistent with the GALL Report and that its Flow-Accelerated Corrosion Program manages loss of material in steel components exposed to steam. The applicant further stated that there are no steel components exposed to treated water with the intended function in the steam and power conversion systems. The staff reviewed the applicant's Flow-Accelerated Corrosion Program and its evaluation is documented in SER Section 3.0.3.1.2. The staff also confirmed that LRA Table 3.4.2-1 has corresponding AMR line items for carbon steel components exposed to steam greater than 270EF. Consistent with the GALL Reports recommendations, the applicant credits the Flow-Accelerated Corrosion Program for managing loss of material from carbon steel piping, piping components, and piping elements exposed to steam or treated water. The staff finds this acceptable. 3.4.2.1.9 Loss of Material Due to General, Pitting, and Crevice Corrosion In the discussion column of LRA Table 3.4.1, Item 3.4.1-30, the applicant stated that this item is consistent with the GALL Report and that its System Walkdown Program will be used to manage loss of material for steel components internally exposed to outdoor air (internal) or condensation (internal). The applicant further stated that for systems where internal carbon steel surfaces are exposed to the same environment as external surfaces, the external surfaces condition will be representative of the internal surfaces; thus, a loss of material on internal carbon steel surfaces can be managed by its System Walkdown Program. The applicant also stated that LRA Table 3.4.1, Item 3.4.1-30 is applicable to component types listed in LRA Table 3.3.2. During the audit and review, the staff asked the applicant to clarify the basis for using the System Walkdown Program to manage loss of material for steel components internally exposed to outdoor air (internal) or condensation (internal) instead of an AMP consistent with GALL AMP XI.M38, as recommended by the GALL Report. In a letter dated July 14, 2006, the applicant revised its System Walkdown Program to add enhancements to the programs implementing procedure. Specifically, the applicant committed in Commitment #24 and Commitment #35, to have: (1) the System Walkdown guidance document enhanced to perform periodic system engineer inspections of systems in-scope and subject to an AMR for license renewal in accordance with 10 CFR 54.4(a)(1) and (a)(3). Inspections shall include areas surrounding the subject systems to identify hazards to those systems. Inspections of nearby systems that could impact the subject system will include SSCs that are in-scope and subjected to an AMR for license renewal in accordance with 10 CFR 54.4 (a)(2); and (2) to provide within the System Walkdown Training Program a process to document biennial refresher training of Engineers to demonstrate inclusion of the methodology for aging management of plant equipment as described in EPRI Aging Assessment Field Guide or comparable instructional guide. 3-377

With this change, the applicant's management of steel components internally exposed to outdoor air or condensation will be consistent with the GALL Report and therefore acceptable to the staff. The staff reviewed the applicant's System Walkdown Program and its evaluation is documented in SER Section 3.0.3.1.9. This program entails inspections of external surfaces of components subject to an AMR. The program is also credited with managing loss of material from internal surfaces where internal and external material-environment combinations are the same and external surface conditions represent internal surface conditions. During interviews with the applicant's technical personnel, the staff confirmed that the applicant will use its System Walkdown Program and noted that coverage includes all elements as presented in the GALL Reports recommended program and therefore it is acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.4.2.1.10 Loss of Material Due to General, Pitting, Crevice, Galvanic, and Microbiologically-Influenced Corrosion and Fouling For loss of material due to fouling and general, pitting, crevice, galvanic, and MIC in steel heat exchanger components exposed to raw water; the GALL Report recommends programs consistent with GALL AMP XI.M20, Open-Cycle Cooling Water System. In the discussion column of LRA Table 3.4.1, Item 3.4.1-31, the applicant stated that for components of the CW system, its Periodic Surveillance and Preventive Maintenance Program, which is a plant-specific AMP, manages loss of material for steel heat exchanger components exposed to raw water through periodic visual inspections. Moreover, the CW system components to which this GALL Report line item applies are included in-scope for the steam and power conversion systems in accordance with 10 CFR 54.4(a)(2) criterion and listed in accordance with ESF system in LRA Tables 3.3.2-13-xx series. The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1.This program includes periodic inspections and tests that manage aging effects not managed by other AMPs. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. On this basis, the staff determines that loss of material for carbon steel piping, pump casing, valve body, and copper alloy tubing is adequately managed using the Periodic Surveillance and Preventive Maintenance Program. The staff also confirmed that the applicant is managing these components in the LRA Tables 3.3.2-13-xx series using the Periodic Surveillance and Preventive Maintenance Program inspection. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3-378

3.4.2.1.11 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion In the discussion column of LRA Table 3.4.1, Item 3.4.1-32, the applicant stated that its Periodic Surveillance and Preventive Maintenance Program manages loss of material for copper alloy components exposed to raw water through periodic visual inspections. The applicant further stated that there are no stainless steel components exposed to raw water with an intended function of pressure boundary in the steam and power conversion systems. The only components to which this GALL Report line item applies are included in-scope for the steam and power conversion systems in accordance with 10 CFR 54.4(a)(2) criterion and listed in accordance with the ESF system in LRA Tables 3.3.2-13-xx series. During the audit and review, the staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.5. Section 3.0.3.3.5. The applicant's Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 for loss of material for copper alloy components exposed to raw water through periodic visual inspections. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.4.1, Item 3.4.1-32 in the population that is subject to the Periodic Surveillance and Preventive Maintenance Program inspection. This is consistent with the GALL Report and therefore acceptable to the staff. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.4.2.1.12 Loss of Material Due to Pitting, and Crevice Corrosion In the discussion column of LRA Table 3.4.1, Item 3.4.1-37, the applicant stated that its Water Chemistry Control - BWR Program will be used to manage loss of material in stainless steel and steel components in its steam and power conversion systems. The applicant further states that there are no nickel alloy components exposed to steam in the steam and power conversion systems. The staff reviewed the applicant's Water Chemistry Control - BWR Program and its evaluation is documented in SER Section 3.0.3.1.11. The staff finds that the applicants Water Chemistry - BWR Program manages aging effects caused by corrosion and cracking mechanisms. The program monitors and controls water chemistry in accordance with the EPRI report. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.4.1, Item 3.4.1-37 in the population that is subject to the Chemistry Control-BWR Program. This is consistent with the GALL Report and therefore acceptable to the staff. For loss of material due to pitting and crevice corrosion from steel, stainless steel, and nickel-based alloy piping, piping components, and piping elements exposed to steam; the GALL Report recommends programs consistent with GALL AMP XI.M2, Water Chemistry. 3-379

In the discussion column of LRA Table 3.4.1, Item 3.4.1-37, the applicant stated that its Water Chemistry Control-Auxiliary Systems Program will be used to manage loss of material in stainless steel, nickel-based alloy, and steel components in its HVAC system components exposed to steam from the applicant's house heating boiler system. During the audit and review, the staff noted that for this aging effect, the GALL Reports recommended Water Chemistry Control-Auxiliary Systems Program was not explicitly identified in the system table (Table 3.4.2.-1). The staff reviewed the applicant's Water Chemistry Control-Auxiliary Systems Program and its evaluation is documented in SER Section 3.0.3.3.7 The applicant's Water Chemistry Control-Auxiliary Systems Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1.This program manages aging effects for components exposed to treated water. On this basis, the staff finds that loss of material in stainless steel, nickel-based alloy, and steel components in its HVAC system components exposed to steam is adequately managed using the Water Chemistry Control-Auxiliary Systems Program. During interviews with the applicant's technical personnel, the staff confirmed that the applicant included all components in LRA Table 3.4.1, Item 3.4.1-37 in the population that is subject to the Chemistry Control-Auxiliary Systems Program. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. Conclusion. The staff evaluated the applicants claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicants consideration of recent operating experience and proposals for managing the 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 its AMRs. Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for these components 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 AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended Summary of Information in the Application. 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, crevice, and microbiologically-induced corrosion, and fouling
• reduction of heat transfer due to fouling
• loss of material due to general, pitting, crevice, and microbiologically-induced corrosion 3-380
• cracking due to stress-corrosion cracking
• loss of material due to pitting and crevice corrosion
• loss of material due to pitting, crevice, and microbiologically-induced corrosion
• loss of material due to general, pitting, crevice, and galvanic corrosion
• quality assurance for aging management of nonsafety-related components Staff Evaluation. 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 audited and reviewed the applicants evaluation to determine whether it adequately addressed the issues further evaluated. In addition, the staff reviewed the applicants further evaluations against the criteria contained in SRP-LR Section 3.4.2.2. The staffs review of the applicants further evaluation follows.

3.4.2.2.1 Cumulative Fatigue Damage LRA Section 3.4.2.2.1 states that fatigue is a TLAA, as required by 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the staffs review of the applicants evaluation of this TLAA. 3.4.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion The staff reviewed LRA Section 3.4.2.2.2 against the following SRP-LR Section 3.4.2.2.2 criteria: (1) LRA Section 3.4.2.2.2 addresses the loss of material of carbon steel piping and components exposed to treated water or steam due to general, pitting and crevice corrosion. SRP-LR Section 3.4.2.2.2 states that loss of material due to general, pitting, and crevice corrosion may occur in steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to treated water and for steel piping, piping components, and piping elements exposed to steam. The existing AMP monitors and controls water chemistry to manage the effects of loss of material due to general, pitting, and crevice corrosion. However, control of water chemistry does not preclude loss of material due to general, 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 select components and susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The applicant stated, in the LRA, that loss of material due to general, pitting and crevice corrosion for carbon steel piping and components exposed to treated water or steam is an AERM in the steam and power conversion systems at VYNPS, and is managed by the Water Chemistry Control-BWR Program. The effectiveness of the applicants Water 3-381

Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including susceptible locations such as areas of stagnant flow. The staff finds that this combination satisfies the criteria of SRP-LR Section 3.4.2.2.2 and is therefore acceptable. (2) LRA Section 3.4.2.2.2 addresses the loss of material of steel piping and components in steam and power conversion systems exposed to lubricating oil due to general, pitting, and crevice corrosion. SRP-LR Section 3.4.2.2.2 states that loss of material due to general, pitting, and crevice corrosion may occur in steel piping, piping components, and piping elements exposed to lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil contaminant control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of lube oil chemistry control programs. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The staff finds that the steam and power conversion systems at VYNPS have no carbon steel components with intended functions that are exposed to lubricating oil, therefore, this item is not applicable to VYNPS. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.4.2.2.2 criteria. For those line items that apply to LRA Section 3.4.2.2.2, the staff finds 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). 3.4.2.2.3 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced Corrosion and Fouling The staff reviewed LRA Section 3.4.2.2.3 against the criteria in SRP-LR Section 3.4.2.2.3. LRA Section 3.4.2.2.3 addresses the loss of material due to general, pitting, crevice, MIC, and fouling. This aging effect is not applicable to VYNPS. Loss of material due to general, pitting, crevice, MIC, and fouling could occur in steel piping, piping components, and piping elements exposed to raw water. 3-382

SRP-LR Section 3.4.2.2.3 states that loss of material due to general, pitting, and crevice corrosion, and MIC and fouling may occur in steel piping, piping components, and piping elements exposed to raw water. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed. The staff finds that the steam and power conversion systems at VYNPS have no carbon steel components with intended functions that are exposed to raw water, therefore, this item is not applicable to VYNPS. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. 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 SRP-LR Section 3.4.2.2.4 criteria: (1) LRA Section 3.4.2.2.4 addresses the reduction of heat transfer of stainless steel and copper alloy heat exchanger tubes exposed to treated water due to fouling. SRP-LR Section 3.4.2.2.4 states that reduction of heat transfer due to fouling may occur in stainless steel and copper alloy heat exchanger tubes exposed to treated water. The existing AMP controls water chemistry to manage reduction of heat transfer due to fouling. However, control of water chemistry may not always be fully effective in precluding fouling; therefore, the GALL Report recommends that the effectiveness of water chemistry control programs should be verified to ensure that reduction of heat transfer due to fouling does not occur. A one-time inspection is an acceptable method to ensure that reduction of heat transfer does not occur and that component intended functions will be maintained during the period of extended operation. The applicant stated in the LRA that reduction of heat transfer due to fouling could occur for stainless steel and copper alloy heat exchanger tubes exposed to treated water. The steam and power conversion systems at VYNPS have no heat exchanger tubes with an intended function of heat transfer and associated aging effect of fouling. However, reduction of heat transfer is managed by the Water Chemistry Control-BWR Program, for copper alloy heat exchanger tubes in the HPCI and RCICSs. The effectiveness of the applicants Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including susceptible locations such as areas of stagnant flow. The staff finds this combination satisfies the criteria of SRP-LR Section 3.4.2.2.4 and is therefore acceptable. 3-383

(2) LRA Section 3.4.2.2.4 addresses the reduction of heat transfer of steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating oil due to fouling. SRP-LR Section 3.4.2.2.4 states that reduction of heat transfer due to fouling may occur in steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating oil. The existing AMP monitors and controls lube oil chemistry to mitigate reduction of heat transfer due to fouling. However, control of lube oil chemistry may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil contaminant control should be verified to ensure that fouling does not occur. The GALL Report recommends further evaluation of programs to verify the effectiveness of lube oil chemistry control programs. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is slowly progressing such that the components intended functions will be maintained during the period of extended operation. The staff finds that the steam and power conversion systems at VYNPS have no heat exchanger tubes with an intended function of heat transfer and associated aging effect of fouling, therefore, this item is not applicable to VYNPS. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.4.2.2.4 criteria. For those line items that apply to LRA Section 3.4.2.2.4, the staff finds 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 SRP-LR Section 3.4.2.2.5 criteria: (1) LRA Section 3.4.2.2.5 addresses the loss of material due to general, pitting, crevice corrosion, and MIC of carbon steel (with or without coating or wrapping) piping, piping components, piping elements and tanks exposed to soil. SRP-LR Section 3.4.2.2.5 states that loss of material due to general, pitting, and crevice corrosion, and MIC may occur in steel (with or without coating or wrapping) piping, piping components, piping elements, and tanks exposed to soil. The buried piping and tanks inspection program relies on industry practice, frequency of pipe excavation, and operating experience to manage the effects of loss of material from general, pitting, and crevice corrosion, and MIC. The effectiveness of the buried piping and tanks inspection program should be verified to evaluate an applicants inspection frequency and operating experience with buried components and to ensure that loss of material does not occur. 3-384

The staff finds that the steam and power conversion systems at VYNPS have no carbon steel components that are exposed to soil, therefore, this item is not applicable to VYNPS. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. (2) LRA Section 3.4.2.2.5 addresses the loss of material due to general, pitting, crevice corrosion, and MIC of carbon steel heat exchanger components exposed to lubricating oil. SRP-LR Section 3.4.2.2.5 states that loss of material due to general, pitting, and crevice corrosion, and MIC may occur in steel heat exchanger components exposed to lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil contaminant control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of the lube oil chemistry control program. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The staff finds that the steam and power conversion systems at VYNPS have no heat exchanger components with intended functions that are exposed to lubricating oil, therefore, this item is not applicable to VYNPS. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. 3.4.2.2.6 Cracking Due to Stress Corrosion Cracking The staff reviewed LRA Section 3.4.2.2.6 against the criteria in SRP-LR Section 3.4.2.2.6. LRA Section 3.4.2.2.6 addresses cracking of stainless steel components exposed to steam due to SCC. SRP-LR Section 3.4.2.2.6 states that cracking due to SCC may occur in stainless steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to treated water greater than 60 EC (140 EF) and in stainless steel piping, piping components, and piping elements exposed to steam. The existing AMP monitors and controls water chemistry to manage the effects of cracking due to SCC. However, high concentrations of impurities in crevices and with stagnant flow conditions may cause SCC; therefore, the GALL Report recommends that the effectiveness of water chemistry control programs should be verified to ensure that SCC does not occur. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that SCC does not occur and that component intended functions will be maintained during the period of extended operation. 3-385

In LRA Table 3.4.1, Item 3.4.1-14 discussion column, the applicant stated that the cracking due to SCC of stainless steel piping, piping components, tanks, and heat exchanger components exposed to treated water greater than 60EC (greater than140EF) is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that there are no stainless steel components exposed treated water with intended functions in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable to VYNPS. The applicant stated in the LRA that cracking due to SCC in stainless steel components exposed to steam is managed by the Water Chemistry Control-BWR Program. The effectiveness of the applicants Water Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including susceptible locations such as areas of stagnant flow. The staff finds this combination satisfies the criteria of SRP-LR Section 3.4.2.2.6 and is therefore acceptable. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.4.2.2.6 criteria. For those line items that apply to LRA Section 3.4.2.2.6, the staff finds 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). 3.4.2.2.7 Loss of Material Due to Pitting and Crevice Corrosion The staff reviewed LRA Section 3.4.2.2.7 against the following SRP-LR Section 3.4.2.2.7 criteria: (1) LRA Section 3.4.2.2.7 addresses the loss of material of copper alloy components exposed to treated water due to pitting and crevice corrosion. SRP-LR Section 3.4.2.2.7 states that loss of material due to pitting and crevice corrosion may occur in stainless steel, aluminum, and copper alloy piping, piping components, and piping elements and in stainless steel tanks and heat exchanger components exposed to treated water. The existing AMP monitors and controls water chemistry to manage the effects of loss of material due to pitting and crevice corrosion. However, control of water chemistry may not preclude corrosion at locations with stagnant flow conditions; therefore, the GALL Report recommends that the effectiveness of water chemistry programs should be verified to ensure that corrosion does not occur. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The applicant stated in the LRA that loss of material due to pitting and crevice corrosion for copper alloy components exposed to treated water is managed by the Water Chemistry Control-BWR Program. The steam and power conversion systems at VYNPS have no stainless steel components with intended functions that are exposed to treated water (Table 3.4-1, Item 3.4.1-16). There are no aluminum components in the steam and power conversion systems. The effectiveness of the applicants Water Chemistry 3-386

Control-BWR Program will be confirmed by the One-Time Inspection Program, through an inspection of a representative sample of components crediting this program including susceptible locations such as areas of stagnant flow. The staff finds this combination satisfies the criteria of SRP-LR Section 3.4.2.2.7 and is therefore acceptable. (2) LRA Section 3.4.2.2.7 addresses loss of material due to pitting and crevice corrosion of stainless steel piping, piping components, and piping elements exposed to soil. SRP-LR Section 3.4.2.2.7 states that loss of material due to pitting and crevice corrosion may occur in stainless steel piping, piping components, and piping elements exposed to soil. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed. The staff finds that the steam and power conversion systems at VYNPS have no stainless steel components with intended function that are exposed to soil, therefore, this item is not applicable to VYNPS. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. (3) LRA Section 3.4.2.2.7 addresses the loss of material due to pitting and crevice corrosion of copper alloy piping, piping components, and piping elements exposed to lubricating oil. SRP-LR Section 3.4.2.2.7 states that loss of material due to pitting and crevice corrosion may occur in copper alloy piping, piping components, and piping elements exposed to lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil contaminant control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of the lube oil chemistry control program. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The staff finds that the steam and power conversion systems at VYNPS have no copper alloy components with intended functions that are exposed to lubricating oil, therefore, this item is not applicable to VYNPS. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. 3-387

Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.4.2.2.7 criteria. For those line items that apply to LRA Section 3.4.2.2.7, the staff finds 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 The staff reviewed LRA Section 3.4.2.2.8 against the criteria in SRP-LR Section 3.4.2.2.8. LRA Section 3.4.2.2.8 addresses the loss of material due to pitting, crevice, and MIC of stainless steel piping, piping components, piping elements, and heat exchanger components exposed to lubricating oil. SRP-LR Section 3.4.2.2.8 states that loss of material due to pitting and crevice corrosion, and MIC may occur in stainless steel piping, piping components, piping elements, and heat exchanger components exposed to lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil contaminant control should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of the lube oil chemistry control program. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The staff finds that the steam and power conversion systems at VYNPS have no stainless steel components with intended functions that are exposed to lubricating oil, therefore, this item is not applicable to VYNPS. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. 3.4.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Galvanic Corrosion The staff reviewed LRA Section 3.4.2.2.9 against the criteria in SRP-LR Section 3.4.2.2.9. LRA Section 3.4.2.2.9 addresses the loss of material due to general, pitting, crevice, and galvanic corrosion of steel heat exchanger components exposed to treated water. SRP-LR Section 3.4.2.2.9 states that loss of material due to general, pitting, crevice, and galvanic corrosion may occur in steel heat exchanger components exposed to treated water. The existing AMP monitors and controls water chemistry to manage the effects of loss of material due to general, pitting, and crevice corrosion. However, control of water chemistry does not preclude loss of material due to general, pitting, and crevice corrosion at locations with stagnant flow conditions; therefore, the effectiveness of water chemistry control programs should 3-388

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 select components and susceptible locations is an acceptable method to ensure that corrosion does not occur and that component intended functions will be maintained during the period of extended operation. The staff finds that the steam and power conversion systems at VYNPS have no steel heat exchanger components with intended functions that are exposed to treated water, therefore, this item is not applicable to VYNPS. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. 3.4.2.2.10 Quality Assurance for Aging Management of Nonsafety-Related Components SER Section 3.0.4 documents the staffs evaluation of the applicants QA program, which the staff found acceptable. 3.4.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Table 3.4.2-1, 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. These items were reviewed and they are further addressed in SER Section 3.4.2.3. In LRA Table 3.4.2-1, the applicant indicated, via notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided further information about how it will manage the aging effects. Specifically, note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line 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 line item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report. Staff Evaluation. For component type, material, and environment combinations not evaluated in the GALL Report, the staff reviewed the applicants evaluation to determine whether 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. The staffs evaluation is documented in the following sections. 3-389

3.4.2.3.1 Main Condenser and MSIV Leakage Pathway Summary of Aging Management Evaluation-LRA Table 3.4.2-1 The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMR evaluations for the main condenser and MSIV leakage pathway component groups. In LRA Table 3.4.2-1, the applicant proposed to manage cracking-fatigue of condenser components (stainless steel heat exchanger tubes, thermowells, tubing, and valve bodies exposed to steam greater than270EF (internal) using a TLAA-metal fatigue. The staffs review of the TLAA is documented in SER Section 4.3. 3.4.2.3.2 Aging Effect/Mechanism in Table 3.4.1 Which Are Not Applicable for VYNPS The staff reviewed LRA Table 3.4.1, which provides a summary of aging management evaluations for the steam and power conversion systems evaluated in the GALL Report. In LRA Table 3.4.1, Item 3.4.1-20 discussion column, the applicant stated that loss of material of steel tanks exposed to air outdoor (external) due to general, pitting, and crevice corrosion is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that there are no steel tanks exposed to outdoor air with intended functions in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable at VYNPS. In LRA Table 3.4.1, Item 3.4.1-21 discussion column, the applicant stated that cracking of high strength steel closure bolting exposed to air with steam or water leakage due to cyclic loading and SCC is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that high strength steel closure bolting is not used in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable to VYNPS. In LRA Table 3.4.1, Item 3.4.1-23 discussion column, the applicant stated that the cracking of stainless steel piping, piping components, and piping elements exposed to closed cycle cooling water greater than60EC (greater than140EF) due to SCC is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that there are no stainless steel components with intended functions exposed to close-cycle cooling water in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable to VYNPS. In LRA Table 3.4.1, Item 3.4.1-24 discussion column, the applicant stated that the loss of material of steel heat exchanger components exposed to closed-cycle cooling water due to general, pitting, crevice, and galvanic corrosion is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that there are no steel heat exchanger components with intended functions exposed to closed-cycle cooling water in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable at VYNPS. 3-390

In LRA Table 3.4.1, Item 3.4.1-26 discussion column, the applicant stated that the loss of material of copper alloy piping, piping components, and piping elements exposed to closed-cycle cooling water due to pitting, crevice, and galvanic corrosion is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that there are no copper alloy components with intended functions exposed to closed-cycle cooling water in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable at VYNPS. In LRA Table 3.4.1, Item 3.4.1-27 discussion column, the applicant stated that the reduction of heat transfer of steel, stainless steel, and copper alloy heat exchanger tubes exposed to closed-cycle cooling water due to fouling is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that there are no heat exchanger tubes with intended functions exposed to closed-cycle cooling water in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable at VYNPS. In LRA Table 3.4.1, Item 3.4.1-33 discussion column, the applicant stated that the loss of material of stainless steel heat exchanger components exposed to raw water due to fouling and pitting, crevice, and MIC is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that there are no stainless steel heat exchanger components with intended functions exposed to raw water in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable at VYNPS. In LRA Table 3.4.1, Item 3.4.1-34 discussion column, the applicant stated that the reduction of heat transfer of steel, stainless steel, and copper alloy heat exchanger tubes exposed to raw water due to fouling is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that there are no heat exchanger tubes with intended functions exposed to raw water in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable at VYNPS. In LRA Table 3.4.1, Item 3.4.1-35 discussion column, the applicant stated that the loss of material of copper alloy greater than15 percent Zinc piping, piping components, and piping elements exposed to closed-cycle cooling water, raw water, or treated water due to selective leaching is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that the there are no copper alloy with intended functions and subject to selective leaching in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable at VYNPS. In LRA Table 3.4.1, Item 3.4.1-36 discussion column, the applicant stated that the loss of material of gray cast iron piping, piping components, and piping elements exposed to soil, treated water, or raw water due to selective leaching is not applicable at VYNPS. The staff determined, through discussions with the applicant's technical personnel, that there are no gray cast iron components with intended functions exposed to raw water in the steam and power conversion systems at VYNPS. The staff finds that, for this component type, this aging effect is not applicable at VYNPS. 3-391

3.4.2.3.3 Steam and Power Conversion Systems AMR Line Items That Have No Aging Effects-LRA Table 3.4.2-1 The applicant, in LRA Notes for Table 3.4.2-1, Plant-Specific Notes 401, stated: Aging management of the main condenser is not based on analysis of materials, environments and aging effects. Condenser integrity required to perform the post-accident intended function (holdup and plateout of MSIV leakage) is continuously confirmed by normal plant operation. This intended function does not require the condenser to be leak-tight, and the post-accident conditions in the condenser will be essentially atmospheric. Since normal plant operation assures adequate condenser pressure boundary integrity, the post-accident intended function to provide holdup volume and plateout surface is assured. Based on past precedence (NUREG-1796, Dresden and Quad Cities SER Section 3.4.2.4.4, and NUREG-1769, Peach Bottom SER Section 3.4.2.3), the staff concludes that main condenser integrity is continually verified during normal plant operation and no AMP is required to assure the post-accident intended function. The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMR evaluations for the main condenser and MSIV leakage pathway component groups. In LRA Table 3.4.2-1, the applicant proposed to verify the integrity of the following condenser components with the specified material/environment combinations during normal plant operations: C Carbon steel exposed to air (indoor-external) C Carbon steel exposed to steam greater than 270EF C Copper alloy greater than15 percent zinc (inhibited) exposed to raw water C Copper alloy greater than15 percent zinc (inhibited) exposed to steam greater than 270EF C Stainless steel exposed to raw water C Stainless steel exposed to steam greater than 270EF On the basis of its review, the staff finds that above environment and material combinations, if managed during normal plant operations, will not result in aging that would be of concern during the period of extended operation. The staff noted that the plateout function of the condenser will be retained and further concludes that there are no applicable AERM for the above environment and material combinations. 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). 3-392

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 SC Supports This section of the SER documents the staffs review of the applicants AMR results for the SC supports components and component groups of:

• primary containment
• reactor building
• intake structure
• process facilities
• yard structures
• bulk commodities 3.5.1 Summary of Technical Information in the Application LRA Section 3.5 provides AMR results for the SC supports components and component groups.

LRA Table 3.5.1, Summary of Aging Management Evaluations for the Structures and Component Supports, is a summary comparison of the applicants AMRs with those evaluated in the GALL Report for the SC supports components and component groups. The applicants 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 applicants 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 whether the applicant provided sufficient information to demonstrate that the effects of aging for the SC supports 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). The staff conducted an onsite audit of AMRs to ensure the applicants 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. The staffs evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staffs audit evaluation are documented in SER Section 3.5.2.1. 3-393

In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicants further evaluations were consistent with the SRP-LR Section 3.5.2.2 acceptance criteria. The staffs audit evaluations are documented in SER Section 3.5.2.2. The staff also conducted a technical review of the remaining AMRs that were not consistent with, or not addressed in, the GALL Report. The technical review evaluated whether all plausible aging effects have been identified and whether the aging effects listed were appropriate for the material-environment combinations specified. The staffs evaluations are documented in SER Section 3.5.2.3. For SSCs which the applicant claimed were not applicable or required no aging management, the staff reviewed the AMR line items and the plants operating experience to verify the applicants claims. Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or monitoring aging for the structures and component supports components. Table 3.5-1 summarizes the staffs evaluation of components, aging effects/mechanisms, and AMPs listed in LRA Section 3.5 and addressed in the GALL Report. Table 3.5-1 Staff Evaluation for SC Supports in the GALL Report Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) BWR Concrete and Steel (Mark I, II, and III) Containments Concrete elements: Aging of accessible ISI (IWL) and for None Not applicable. walls, dome, and inaccessible inaccessible (VYNPS basemat, ring concrete areas due concrete, an containment is a girder, buttresses, to aggressive examination of Mark I steel containment chemical attack, representative containment.) (as applicable). and corrosion of samples of (3.5.1-1) embedded steel below-grade concrete, and periodic monitoring of groundwater if environment is non-aggressive. A plant-specific program is to be evaluated if environment is aggressive. 3-394

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Concrete elements; Cracks and Structures None Not applicable. All distortion due to Monitoring Program. (VYNPS (3.5.1-2) increased stress If a de-watering containment is a levels from system is relied Mark I steel settlement upon for control of containment.) settlement, then the applicant is to ensure proper functioning of the de-watering system through the period of extended operation. Concrete elements: Reduction in Structures None Not applicable. foundation, foundation strength, Monitoring Program (VYNPS containment subfoundation cracking, differential If a de-watering is a Mark I steel (3.5.1-3) settlement due to system is relied containment.) erosion of porous upon to control concrete erosion of cement subfoundation from porous concrete subfoundations, then the applicant is to ensure proper functioning of the de-watering system through the period of extended operation. Concrete elements: Reduction of A plant-specific None Not applicable. dome, wall, strength and AMP is to be (VYNPS containment basemat, ring modulus of concrete evaluated is a Mark I steel girder, buttresses, due to elevated containment.) containment, temperature concrete fill-in annulus (as applicable) (3.5.1-4) 3-395

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Steel elements: Loss of material due ISI (IWE) and Containment Consistent with Drywell; torus; to general, pitting 10 CFR 50, Inservice Inspection GALL Report, which drywell head; and crevice Appendix J Program (B.1.15.1); recommends further embedded shell and corrosion Containment Leak evaluation (See sand pocket Rate Program SER regions; drywell (B.1.8) Section 3.5.2.2.1 support skirt; torus under the heading, ring girder; Loss of Material downcomers; liner Due to General, plate, ECCS suction Pitting and Crevice header, support Corrosion) skirt, region shielded by diaphragm floor, suppression chamber (as applicable) (3.5.1-5) Steel elements: Loss of material due ISI (IWE) and None Not applicable. steel liner, liner to general, pitting 10 CFR 50, (VYNPS containment anchors, integral and crevice Appendix J is a Mark I steel attachments corrosion containment.) (3.5.1-6) Prestressed Loss of prestress TLAA, evaluated in None Not applicable. containment due to relaxation, accordance with (VYNPS containment tendons shrinkage, creep, 10 CFR 54.21(c) is a Mark I steel (3.5.1-7) and elevated containment.) temperature Steel and stainless Cumulative fatigue TLAA, evaluated in None Not applicable. (See steel elements: vent damage (CLB accordance with SER line, vent header, fatigue analysis 10 CFR 54.21(c) Section 3.5.2.2.1 vent line bellows; exists) under the heading, downcomers; Cumulative Fatigue (3.5.1-8) Damage) Steel, stainless Cumulative fatigue TLAA, evaluated in None Fatigue is a TLAA. steel elements, damage (CLB accordance with (See Section SER dissimilar metal fatigue analysis 10 CFR 54.21(c) 3.5.2.2.1 under the welds: penetration exists) heading, sleeves, penetration Cumulative Fatigue bellows; Damage, and SER suppression pool Section and 4.6) shell, unbraced downcomers (3.5.1-9) 3-396

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Stainless steel Cracking due to ISI (IWE) and None Not applicable (See penetration sleeves, SCC 10 CFR 50, SER penetration bellows, Appendix J, and Section 3.5.2.2.1 dissimilar metal additional under the heading, welds appropriate Cracking Due to (3.5.1-10) examinations/ SCC) evaluations for bellows assemblies and dissimilar metal welds. Stainless steel vent Cracking due to ISI (IWE) and None Not applicable (See line bellows, SCC 10 CFR 50, SER (3.5.1-11) Appendix J, and Section 3.5.2.2.1 additional under the heading, appropriate Cracking Due to examination/ SCC) evaluation for bellows assemblies and dissimilar metal welds. Steel, stainless Cracking due to ISI (IWE) and Containment Consistent with steel elements, cyclic loading 10 CFR 50, Inservice Inspection GALL Report, which dissimilar metal Appendix J, and Program (B.1.15.1); recommends further welds: penetration supplemented to Containment Leak evaluation (See sleeves, penetration detect fine cracks Rate Program SER bellows; (B.1.8) Section 3.5.2.2.1 suppression pool under the heading, shell, unbraced Cracking Due to downcomers Cyclic Loading) (3.5.1-12) Steel, stainless Cracking due to ISI (IWE) and Containment Consistent with steel elements, cyclic loading 10 CFR 50, Inservice Inspection GALL Report, which dissimilar metal Appendix J, and Program (B.1.15.1); recommends further welds: torus; vent supplemented to Containment Leak evaluation (See line; vent header; detect fine cracks Rate Program (B.1.8) SER vent line bellows; Section 3.5.2.2.1 downcomers under the heading, (3.5.1-13) Cracking Due to Cyclic Loading) Concrete elements: Loss of material ISI (IWL). None Not applicable. dome, wall, (Scaling, cracking, Evaluation is (VYNPS basemat ring girder, and spalling) due to needed for plants containment is a buttresses, freeze-thaw that are located in Mark I steel containment moderate to severe containment.) (as applicable) weathering (3.5.1-14) conditions (weathering index > 100 day-inch/yr) (NUREG-1557). 3-397

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Concrete elements: Cracking due to ISI (IWL) for None Not applicable. walls, dome, expansion and accessible areas. (VYNPS basemat, ring reaction with None for containment is a girder, buttresses, aggregate; increase inaccessible areas if Mark I steel containment, in porosity, concrete was containment.) concrete fill-in permeability due to constructed in annulus leaching of calcium accordance with the (as applicable). hydroxide recommendations in (3.5.1-15) ACI 201.2R. Seals, gaskets, and Loss of sealing and ISI (IWE) and Containment Consistent with the moisture barriers leakage through 10 CFR 50, Inservice Inspection GALL Report. (3.5.1-16) containment due to Appendix J Program (B.1.15.1); (See SER deterioration of joint Containment Leak Section 3.5.2.1.4) seals, gaskets, and Rate Program (B.1.8) moisture barriers (caulking, flashing, and other sealants) Personnel airlock, Loss of leak 10 CFR 50, None Not applicable. (See equipment hatch tightness in closed Appendix J and SER and CRD hatch position due to Plant TSs Section 3.5.2.1.5) locks, hinges, and mechanical wear of closure locks, hinges and mechanisms closure (3.5.1-17) mechanisms Steel penetration Loss of material due ISI (IWE) and Containment Consistent with sleeves and to general, pitting, 10 CFR 50, Inservice Inspection GALL Report,(See dissimilar metal and crevice Appendix J Program (B.1.15.1); SER welds; personnel corrosion Containment Leak Section 3.5.2.1.6) airlock, equipment Rate Program hatch and CRD (B.1.8) hatch (3.5.1-18) Steel elements: Cracking due to ISI (IWE) and None Not applicable. (The stainless steel SCC 10 CFR 50, VYNPS suppression suppression Appendix J chamber is carbon chamber shell (inner steel.) surface) (3.5.1-19) Steel elements: Loss of material due ISI (IWE) and None Not applicable. (The suppression to general, pitting, 10 CFR 50, VYNPS suppression chamber liner and crevice Appendix J chamber is carbon (interior surface) corrosion steel.) (3.5.1-20) Steel elements: Fretting or lock up ISI (IWE) None Not applicable (See drywell head and due to mechanical SER downcomer pipes wear Section 3.5.2.1.7) (3.5.1-21) 3-398

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Prestressed Loss of material due ISI (IWL) None Not applicable. containment: to corrosion (VYNPS tendons and containment is a anchorage Mark I steel components containment without (3.5.1-22) prestressed tendons.) Safety-Related and Other Structures; and Component Supports All Groups except Cracking, loss of Structures Structures Consistent with Group 6: interior bond, and loss of Monitoring Program Monitoring Program GALL Report, which and above grade material (spalling, (B.1.27.2) recommends further exterior concrete scaling) due to evaluation (See (3.5.1-23) corrosion of SER embedded steel Section 3.5.2.2.2 under the heading, Aging of Structures Not Covered by Structures Monitoring Program, item 1) All Groups except Increase in porosity Structures Structures Monitoring Consistent with the Group 6: interior and permeability, Monitoring Program Program (B.1.27.2) GALL Report, which and above grade cracking, loss of recommends further exterior concrete material (spalling, evaluation. (3.5.1-24) scaling) due to (See SER aggressive chemical Section 3.5.2.2.2 attack under the heading, Aging of Structures Not Covered by Structures Monitoring Program, item 2) All Groups except Loss of material due Structures Structures Monitoring Consistent with the Group 6: steel to corrosion Monitoring Program. Program (B.1.27.2); GALL Report, which components: all If protective Periodic Surveillance recommends further structural steel coatings are relied and Preventive evaluation. (3.5.1-25) upon to manage the Maintenance (See SER effects of aging, the Program (B.1.22); Section 3.5.2.2.2 structures Fire Protection under the heading, monitoring program Program (B.1.12.1) Aging of Structures is to include Not Covered by provisions to Structures Monitoring address protective Program, item 3) coating monitoring and maintenance. 3-399

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) All Groups except Loss of material Structures Structures Monitoring Consistent with the Group 6: accessible (spalling, scaling) Monitoring Program. Program (B.1.27.2) GALL Report, which and inaccessible and cracking due to Evaluation is recommends further concrete: foundation freeze-thaw needed for plants evaluation. (3.5.1-26) that are located in (See SER moderate to severe Section 3.5.2.2.2 weathering under the heading, conditions Aging of Structures (weathering index Not Covered by

                                           > 100 day-inch/yr)                          Structures Monitoring (NUREG-1557).                               Program, item 4)

All Groups except Cracking due to Structures Structures Monitoring Consistent with the Group 6: accessible expansion due to Monitoring Program. Program (B.1.27.2) GALL Report, which and inaccessible reaction with None for recommends further interior/exterior aggregates inaccessible areas if evaluation. concrete concrete was (See SER (3.5.1-27) constructed in Section 3.5.2.2.2 accordance with the under the heading, recommendations in Aging of Structures ACI 201.2R-77. Not Covered by Structures Monitoring Program, item 5) Groups 1-3, 5-9: All Cracks and Structures None Not applicable. (See (3.5.1-28) distortion due to Monitoring Program. SER increased stress If a de-watering Section 3.5.2.2.2 levels from system is relied under the heading, settlement upon for control of Aging of Structures settlement, then the Not Covered by applicant is to Structures ensure proper Monitoring functioning of the Program, item 6) de-watering system through the period of extended operation. Groups 1-3, 5-9: Reduction in Structures None Not applicable. (See foundation foundation strength, Monitoring Program. SER (3.5.1-29) cracking, differential If a de-watering Section 3.5.2.2.2 settlement due to system is relied under the heading, erosion of porous upon for control of Aging of Structures concrete settlement, then the Not Covered by subfoundation applicant is to Structures ensure proper Monitoring functioning of the Program, item 7) de-watering system through the period of extended operation. 3-400

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Group 4: Radial Lock-up due to wear ISI (IWF) or Structures Consistent with beam seats in BWR Structures Monitoring Program GALL Report, which drywell; RPV Monitoring Program (B.1.27.2) recommends further support shoes for evaluation (See PWR with nozzle SER supports; Steam Section 3.5.2.2.2 generator supports under the heading, (3.5.1-30) Aging of Structures Not Covered by Structures Monitoring Program, item 8) Groups 1-3, 5, 7-9: Increase in porosity Structures Buried Piping Consistent with below-grade and permeability, monitoring Program; Inspection Program GALL Report, which concrete cracking, loss of Examination of (B.1.1); Structures recommends further components, such material (spalling, representative Monitoring Program evaluation (See as exterior walls scaling)/aggressive samples of (B.1.27.2) SER below grade and chemical attack; below-grade Section 3.5.2.2.2 foundation Cracking, loss of concrete, and under the heading, (3.5.1-31) bond, and loss of periodic monitoring Aging Management material (spalling, of groundwater, if of Inaccessible scaling)/corrosion of the environment is Areas) embedded steel non-aggressive. A plant-specific program is to be evaluated if environment is aggressive. Groups 1-3, 5, 7-9: Increase in porosity Structures Structures Consistent with exterior above and and permeability, Monitoring Program Monitoring Program GALL Report, which below grade and loss of strength for accessible (B.1.27.2) recommends further reinforced concrete due to leaching of areas. None for evaluation (See foundations calcium hydroxide inaccessible areas if SER (3.5.1-32) concrete was Section 3.5.2.2.2 constructed in under the heading, accordance with the Aging Management recommendations in of Inaccessible ACI 201.2R-77. Areas) Groups 1-5: Reduction of A plant-specific None (See SER concrete strength and AMP is to be Section 3.5.2.2.2 (3.5.1-33) modulus due to evaluated under the heading, elevated Reduction of temperature Strength and Modulus of Concrete Structures Due to Elevated Temperature) 3-401

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Group 6: Concrete; Increase in porosity Inspection of Buried Piping Consistent with all and permeability, Water-Control Inspection Program GALL Report, which (3.5.1-34) cracking, loss of Structures or (B.1.1); Structures recommends further material due to FERC/US Army Monitoring Program evaluation (See aggressive chemical Corps of Engineers (B.1.27.2) SER attack; cracking, dam inspections Section 3.5.2.2.2 loss of bond, loss of and maintenance under the heading, material due to programs and for Aging Management corrosion of inaccessible of Inaccessible embedded steel concrete, an Areas for Group 6 examination of Structures, item 1) representative samples of below-grade concrete, and periodic monitoring of groundwater, if the environment is non-aggressive. A plant-specific program is to be evaluated if environment is aggressive. Group 6: exterior Loss of material Inspection of Structures Consistent with above and below (spalling, scaling) Water-Control Monitoring Program GALL Report, which grade concrete and cracking due to Structures or (B.1.27.2) recommends further foundation freeze-thaw FERC/US Army evaluation (See (3.5.1-35) Corps of Engineers SER dam inspections Section 3.5.2.2.2 and maintenance under the heading, programs. Aging Management Evaluation is of Inaccessible needed for plants Areas for Group 6 that are located in Structures, item 2) moderate to severe weathering conditions (weathering index

                                        > 100 day-inch/yr)

(NUREG-1557). 3-402

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Group 6: all Cracking due to Accessible areas: Structures Monitoring Consistent with the accessible/ expansion/reaction Inspection of Program (B.1.27.2) GALL Report, which inaccessible with aggregates Water-Control recommends further reinforced concrete Structures or evaluation. (3.5.1-36) FERC/US Army (See SER Corps of Engineers Section 3.5.2.2.2 dam inspections under the heading, and maintenance Aging Management programs. None for of Inaccessible Areas inaccessible areas if for Group 6 concrete was Structures, item 3) constructed in accordance with the recommendations in ACI 201.2R-77. Group 6: exterior Increase in porosity For accessible Structures Monitoring Consistent with the above and below and permeability, areas, Inspection of Program (B.1.27.2) GALL Report, which grade reinforced loss of strength due Water-Control recommends further concrete foundation to leaching of Structures or evaluation. interior slab calcium hydroxide FERC/US Army (See SER (3.5.1-37) Corps of Engineers Section 3.5.2.2.2 dam inspections under the heading, and maintenance Aging Management programs. None for of Inaccessible Areas inaccessible areas if for Group 6 concrete was Structures, item 3) constructed in accordance with the recommendations in ACI 201.2R-77. Groups 7, 8: Tank Cracking due to A plant-specific None Not applicable. (See liners SCC; loss of AMP is to be SER (3.5.1-38) material due to evaluated Section 3.5.2.2.2 pitting and crevice under the heading, corrosion Cracking Due to Stress Corrosion Cracking and Loss of Material Due to Pitting and Crevice Corrosion) Support members; Loss of material due Structures Structures Monitoring Consistent with the welds; bolted to general and Monitoring Program Program (B.1.27.2) GALL Report, which connections; pitting corrosion recommends further support anchorage evaluation. to building structure (See SER (3.5.1-39) Section 3.5.2.2.2 under the heading, Aging of Supports Not Covered by the Structures Monitoring Program) 3-403

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Building concrete at Reduction in Structures Structures Monitoring Consistent with the locations of concrete anchor Monitoring Program Program (B.1.27.2) GALL Report, which expansion and capacity due to local recommends further grouted anchors; concrete evaluation. grout pads for degradation/ (See SER support base plates service-induced Section 3.5.2.2.2 (3.5.1-40) cracking or other under the heading, concrete aging Aging of Supports mechanisms Not Covered by the Structures Monitoring Program) Vibration isolation Reduction or loss of Structures None Not applicable (See elements isolation Monitoring Program SER (3.5.1-41) function/radiation Section 3.5.2.2.2 hardening, under the heading, temperature, Aging of Supports humidity, sustained Not Covered by the vibratory loading Structures Monitoring Program) Groups B1.1, B1.2, Cumulative fatigue TLAA, evaluated in None Not applicable. (See and B1.3: support damage (CLB accordance with SER members: anchor fatigue analysis 10 CFR 54.21(c) Section 3.5.2.2.2 bolts, welds exists) under the heading, (3.5.1-42) Cumulative Fatigue Damage Due to Cyclic Loading) Groups 1-3, 5, 6: all Cracking due to Masonry Wall Masonry Wall Consistent with the masonry block walls restraint shrinkage, Program Program (B.1.27.1); GALL Report. (3.5.1-43) creep, and Fire Protection (See SER aggressive Program (B.1.12.1) Section 3.5.2.1.9) environment Group 6 elastomer Loss of sealing due Structures Structures Monitoring Consistent with the seals, gaskets, and to deterioration of Monitoring Program Program (B.1.27.2) GALL Report. moisture barriers seals, gaskets, and (See SER (3.5.1-44) moisture barriers Section 3.5.2.1.10) (caulking, flashing, and other sealants) Group 6: exterior Loss of material due Inspection of None Consistent with the above and below to abrasion, Water-Control GALL Report. grade concrete cavitation Structures Associated (See SER foundation; interior with Nuclear Power Section 3.5.2.1.11) slab Plants (3.5.1-45) 3-404

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Group 5: Fuel pool Cracking due to Water Chemistry Water Chemistry Consistent with the liners SCC; loss of and monitoring of Control-BWR GALL Report. (3.5.1-46) material due to spent fuel pool Program (B.1.30.2) (See SER pitting and crevice water level in and monitoring of Section 3.5.2.1) corrosion accordance with spent fuel pool water technical level and level of fluid specifications and in the leak chase leakage from the channel leak chase channels. Group 6: all metal Loss of material due Inspection of None Consistent with structural members to general (steel Water-Control GALL Report, which (3.5.1-47) only), pitting and Structures or recommends no crevice corrosion FERC/US Army further evaluation Corps of Engineers (See SER dam inspections Section 3.5.2.1.12) and maintenance. If protective coatings are relied upon to manage aging, protective coating monitoring and maintenance provisions should be included. Group 6: earthen Loss of material, Inspection of None Not applicable. water control loss of form due to Water-Control (VYNPS does not structures-dams, erosion, settlement, Structures Associated have earthen water embankments, sedimentation, frost with Nuclear Power control structures.) reservoirs, action, waves, Plants channels, canals, currents, surface and ponds runoff, Seepage (3.5.1-48) Support members; Loss of Water Chemistry Water Chemistry Consistent with the welds; bolted material/general, and ISI (IWF) Control-BWR GALL Report. connections; pitting, and crevice (B.1.30.2); Inservice (See SER support anchorage corrosion Inspection Program Section 3.5.2.1.13) to building structure (B.1.15.2) (3.5.1-49) Groups B2, and B4: Loss of material due Structures Structures Monitoring Consistent with the galvanized steel, to pitting and Monitoring Program Program (B.1.27.2) GALL Report. aluminum, stainless crevice corrosion (See SER steel support Section 3.5.2.1.14) members; welds; bolted connections; support anchorage to building structure (3.5.1-50) 3-405

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Group B1.1: high Cracking due to Bolting Integrity None Not applicable. strength low-alloy SCC; loss of (High strength bolts material due to bolting is not (3.5.1-51) general corrosion exposed to a corrosive environment or high tensile stresses.) Groups B2, and B4: Loss of mechanical Structures None Not applicable. sliding support function due to Monitoring Program (Loss of mechanical bearings and sliding corrosion, distortion, function due to the support surfaces dirt, overload, listed mechanisms (3.5.1-52) fatigue due to is not an aging vibratory and cyclic effect. Such failures thermal loads typically result from inadequate design or operating events rather than from the effects of aging. Failures due to cyclic thermal loads are rare for structural supports due to their relatively low temperatures.) Groups B1.1, B1.2, Loss of material due ISI (IWF) Inservice Inspection Consistent with the and B1.3: support to general and Program (B.1.15.2) GALL Report. members: welds; pitting corrosion (See SER bolted connections; Section 3.5.2.1.15) support anchorage to building structure (3.5.1-53) Groups B1.1, B1.2, Loss of mechanical ISI (IWF) None Not applicable. and B1.3: Constant function due to (Loss of mechanical and variable load corrosion, distortion, function due to spring hangers; dirt, overload, distortion, dirt, guides; stops; fatigue due to overload, fatigue (3.5.1-54) vibratory and cyclic due to vibratory, and thermal loads cyclic thermal loads are not aging effects requiring management. Such failures typically result from inadequate design or events rather than the effects of aging.) 3-406

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Steel, galvanized Loss of material due Boric Acid None Not applicable to steel, and aluminum to boric acid Corrosion BWRs support members; corrosion welds; bolted connections; support anchorage to building structure (3.5.1-55) Groups B1.1, B1.2, Loss of mechanical ISI (IWF) Inservice Inspection Not applicable. and B1.3: Sliding function due to Program (B.1.15.2); (No aging effects due surfaces corrosion, distortion, Structures Monitoring to lubrite plate design (3.5.1-56) dirt, overload, Program (B.1.27.2) features. VYNPS will fatigue due to manage aging vibratory and cyclic anyway.) thermal loads Groups B1.1, B1.2, Reduction or loss of ISI (IWF) None Not applicable. and B1.3: Vibration isolation function/ (No supports with isolation elements radiation hardening, vibration isolation (3.5.1-57) temperature, elements are humidity, sustained in-scope.) vibratory loading Galvanized steel None None None Consistent with the and aluminum GALL Report. support members; (See SER welds; bolted Section 3.5.2.1.16) connections; support anchorage to building structure exposed to air-indoor uncontrolled (3.5.1-58) Stainless steel None None None Consistent with the support members; GALL Report. welds; bolted (See SER connections; Section 3.5.2.1) support anchorage to building structure (3.5.1-59) The staffs review of the SC supports component groups followed any one of several approaches. One approach, 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 approach, 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 approach, 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. The staffs review of AMPs credited to manage or monitor aging effects of the SC supports components is documented in SER Section 3.0.3. 3-407

3.5.2.1 AMR Results Consistent with the GALL Report Summary of Technical Information in the Application. LRA Section 3.5.2.1 identifies the materials, environments, AERMs, and the following programs that manage aging effects for the SC supports components:

• Containment Leak Rate Program
• Fire Protection Program
• Containment Inservice Inspection Program
• Inservice Inspection Program
• Periodic Surveillance and Preventive Maintenance Program
• Masonry Wall Program
• Structures Monitoring Program
• Vernon Dam Federal Energy Regulatory Commission Inspection
• Water Chemistry Control - BWR Program LRA Tables 3.5.2-1 through 3.5.2-6 summarize AMRs for the SC supports components and indicate AMRs claimed to be consistent with the GALL Report.

Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant claimed consistency with the report and for which it does not recommend further evaluation, the staffs 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 through E indicating 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 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 AMP. The staff audited these line items to verify consistency with the GALL Report and verified that the identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also finds whether the applicants AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific conditions. Note C indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find a listing 3-408

of some system components in the GALL Report; however, the applicant identified 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 GALL Report. The staff also finds 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, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL 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 identified exceptions to the GALL AMPs have been reviewed and accepted. The staff also finds whether the applicants AMP was consistent with the GALL 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 finds whether the credited AMP would manage the aging effect consistently with the GALL AMP and whether the AMR was valid for the site-specific conditions. 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 staffs evaluation follows. 3.5.2.1.1 Loss of Material Due to General, Pitting and Crevice Corrosion For loss of material due to general, pitting and crevice corrosion of carbon steel for 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 and suppression chamber exposed to indoor uncontrolled air or treated water, the GALL Report recommends programs consistent with GALL AMP XI.S1, ASME Section XI, Subsection IWE and GALL AMP XI.S4, 10 CFR Part 50, Appendix J. In LRA Table 3.5.1, Item 3.5.1-5, the applicant stated that loss of material due to general, pitting and crevice corrosion of the carbon steel drywell head, drywell shell, drywell sump liner, drywell to torus vent system, torus manway, torus ring girder, torus shell, and torus thermowell is managed using its Containment Inservice Inspection Program and the Containment Leak Rate Program. During the audit and review, the staff noted that the applicants Containment Inservice Inspection Program is a plant-specific program. 3-409

The staff reviewed the applicants Containment Inservice Inspection Program. This evaluation is documented in SER Section 3.0.3.3.2. The staff finds that the applicants Containment Inservice Inspection Program satisfied criteria of SRP-LR Appendix A.1 and encompasses the ASME Code, Section XI, Subsection IWE requirements for managing the loss of material for the primary containment and its integral attachments. On this basis, the staff concludes that the applicants Containment Inservice Inspection Program is an acceptable AMP for loss of material of the above components. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.5.2.1.2 Cumulative Fatigue Damage (CLB Fatigue Analysis Exists) During the audit and review, the staff noted that in LRA Table 3.5.2-1 (page 3.5-53) for the component torus shell with the aging effect of cracking fatigue, the note assigned is E. Note E is consistent with the GALL Report material, environment, and aging effect but a different AMP is credited. The applicant was asked to explain why this note is E when the AMP shown for this line item is TLAA and the referenced GALL Report Line Item II.B1.1-4 also specifies a TLAA. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.2-1 is revised to change Note E to Note A for torus shell with an aging effect of cracking-fatigue. The aging effect and associated AMP are unchanged. The staff reviewed the applicants response and finds it acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.5.2.1.3 Cracking Due to Cyclic Loading For cracking due to cyclic loading of steel, stainless steel and dissimilar metal welds for penetration sleeves, penetration bellows, suppression pool shell and unbraced downcomers exposed to indoor uncontrolled air or outdoor air, the GALL Report recommends programs consistent with GALL AMP XI.S1, ASME Code, Section XI, Subsection IWE and GALL AMP XI.S4, 10 CFR Part 50, Appendix J. In LRA Table 3.5.1, Item 3.5.1-12, the applicant stated that cracking due to cyclic loading of the carbon steel primary containment mechanical penetrations (includes those with bellows) is managed using the Containment Inservice Inspection Program and the Containment Leak Rate Program. During the audit and review, the staff noted that the applicants Containment Inservice Inspection Program is a plant-specific program. 3-410

The staff reviewed the applicants Containment Inservice Inspection Program and its evaluation is documented in SER Section 3.0.3.3.2. The staff finds that the applicants Containment Inservice Inspection Program satisfied criteria of SRP-LR Appendix A.1 and encompasses the ASME Code, Section XI Subsection IWE Code requirements for managing cracking of the primary containment and its integral attachments. On this basis, the staff concludes that the applicants Containment Inservice Inspection Program is an acceptable AMP for managing cracking of the primary containment mechanical penetrations (includes those with bellows). For cracking due to cyclic loading of steel, stainless steel and dissimilar metal welds for torus, vent line, vent header, vent line bellows and downcomers exposed to indoor uncontrolled air, the GALL Report recommends programs consistent with GALL AMP XI.S1, ASME Code, Section XI, Subsection IWE and GALL AMP XI.S4, 10 CFR Part 50, Appendix J. In LRA Table 3.5.1, Item 3.5.1-13, the applicant stated that cracking due to cyclic loading of the stainless steel drywell to torus vent line bellows is managed using the Containment Inservice Inspection Program and the Containment Leak Rate Program. During the audit and review, the staff noted that the applicants Containment Inservice Inspection Program is a plant-specific program. The staff reviewed the applicants Containment Inservice Inspection Program and its evaluation is documented in SER Section 3.0.3.3.2. The staff finds that the applicants containment Inservice Inspection Program satisfied criteria of SRP-LR Appendix A.1 and encompasses the ASME Code, Section XI Subsection IWE Code requirements for managing cracking of the primary containment and its integral attachments. On this basis, the staff concludes that the applicants plant-specific Containment Inservice Inspection Program is an acceptable AMP for managing cracking of the drywell to torus vent line bellows. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. During the audit and review, the staff noted that in LRA Table 3.5.2-1 (page 3.5-50), for component bellows (reactor vessel and drywell), one of the AMPs shown is the Containment Inservice Inspection-IWE Program, which is a plant-specific AMP. A Note C has been assigned to this AMR line item, the component is different, but consistent with material, environment, aging effect, and AMP for the GALL Report line item. The AMP is consistent with the GALL Reports AMP description. The applicant was asked to provide drawings showing how the LRA line item bellows are different from the GALL Report Table 1, Line Item 3.5.1-13 bellows. The applicant was also asked to explain how the plant-specific VYNPS Containment Inservice Inspection-IWE AMP is consistent with the GALL Reports specified AMP. The applicants staff stated that LRA Table 3.5.2-1 (page 3.5-50), for component bellows (reactor vessel and drywell) is not consistent with the referenced GALL Report Volume 2 item. LRA Table 3.5.2-1 line item Bellows (reactor vessel and drywell) and the corresponding line item in VYNPS Table 2.4-1 should be deleted. The reactor vessel and drywell bellows perform 3-411

no license renewal intended function. These components are not safety-related and are not required to demonstrate compliance with the requirements of 10 CFR 54.4(a)(3). Failure of the bellows will not prevent satisfactory accomplishment of a safety function. Leakage, if any, through the bellows is directed to a drain system that prevents the leakage from contacting the outer surface of the drywell shell. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.2-1 is revised to delete line items for Bellows (reactor vessel and drywell) and also the corresponding line item in LRA Table 2.4-1. The staff reviewed the applicants response and finds it acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.5.2.1.4 Loss of Sealing and Leakage Through Containment Due to Deterioration of Joint Seals, Gaskets, and Moisture Barriers (Caulking, Flashing, and Other Sealants) During the audit and review, the staff noted that in the discussion column of LRA Table 3.5.1, Item 3.5.1-16, the applicant stated that seals and gaskets are not included in the Containment Inservice Inspection Program at VYNPS. One of the components for this item number is moisture barriers. The applicant was asked to explain how VYNPS seals the joint between the containment drywell shell and drywell concrete floor if there is no moisture barrier. The applicant was also asked to explain why the inspection of this joint is not part of the Containment Inservice Inspection Program at VYNPS. The applicants staff stated that VYNPS uses a moisture barrier to seal the joint between the containment drywell shell and drywell concrete floor. Moisture barrier is listed in LRA Table 3.5.2-1 as drywell floor liner seal. Aging effects on the drywell moisture barrier will be managed by its Containment Inservice Inspection-IWE Program. For clarity, drywell floor liner seal will be changed to drywell shell to floor seal (moisture barrier). During the audit and review, the staff noted that in LRA Table 3.5.2-1 (page 3.5-54) for the component drywell floor liner seal, the AMP shown is the Structures Monitoring Program. The applicant was asked to verify that its Containment Inservice Inspection-IWE AMP will not be used instead to manage the aging of the moisture barrier. The applicants staff stated that the aging management activity will be the same whether included in accordance with the umbrella of the Structures Monitoring Program or in accordance with the umbrella of the Containment Inservice Inspection-IWE Program. For clarification, the Containment Inservice Inspection-IWE Program will manage the effects of aging on the moisture barrier through the period of extended operation. Note E remains the correct note since the Containment Inservice Inspection-IWE Program is plant-specific. 3-412

In a letter dated July 14, 2006, the applicant revised its LRA. Specifically, the applicant stated that aging effects on the drywell moisture barrier will be managed in accordance with the Containment Inservice Inspection Program instead of the Structures Monitoring Program. In support of this, the LRA is revised as follows: (1) In the LRA Table 3.5.2-1 line item for Drywell floor liner seal change the aging management program from Structures Monitoring to CII-IWE. For clarification, change drywell floor liner seal to drywell shell to floor seal (moisture barrier). The clarification of this terminology also applies to LRA Table 2.4-1 and Section B.1.27.2. (2) In LRA Table 3.5.1, Line Item 3.5.1-16, the Discussion column is revised to read: The aging effects cited in the GALL Report item are loss of sealing and leakage. Loss of sealing is a consequence of the aging effects cracking and change in material properties. For VYNPS, the Containment Leak Rate Program manages cracking and changes in material properties for the primary containment seal and gaskets. The Inservice Inspection-IWE Program manages cracking and changes in material properties for the drywell shell to floor seal (moisture barrier). (3) In LRA Table 3.5.1, Line Item 3.5.1-5, the Discussion column last paragraph is revised to read The drywell steel shell and the moisture barrier where the drywell shell becomes embedded in the drywell concrete floor are inspected in accordance with the Containment Inservice Inspection (IWE) Program. (4) LRA Section 3.5.2.2.1.4 is revised to delete from the end of the first paragraph, the phrase and Structures Monitoring Program. The drywell to floor moisture barrier will be inspected in accordance with the Containment Inservice Inspection (IWE) Program only. The Structures Monitoring Program is not used. The staff reviewed the applicants response and finds it acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. During the audit and review, the staff noted that in the applicant response above, the applicant stated: In LRA Table 3.5.1, Line Item 3.5.1-16, the Discussion column is revised to read: The aging effects cited in the GALL Report item are loss of sealing and leakage. Loss of sealing is a consequence of the aging effects cracking and change in material properties. For VYNPS, the Containment Leak Rate Program manages cracking and changes in material properties for the primary containment seal and gaskets. The Inservice Inspection-IWE Program manages cracking and changes in material properties for the drywell shell to floor seal (moisture barrier). The staff noted that in LRA Table 3.5.2-6 (page 3.5-80), for component seals and gaskets (doors, man-ways and hatches), material rubber in a protected from weather environment; the aging effects are cracking and change in material properties. The GALL Report line item referenced is II.B4-7 and the LRA Table 1 reference is Line Item 3.5.1-16. However, the AMP shown for this line item is Periodic Surveillance and Preventive Maintenance Program. LRA 3-413

Table 3.5.1, Item 3.5.1-16 relates to primary containment seals and gaskets. The applicant has stated above in the previous paragraph that the Containment Leak Rate Program manages cracking and change in material properties for the primary containment seals and gaskets. The applicant was asked to explain if this Table 2 line item is for containment seals and gaskets and also Class 1 structures seals and gaskets. If it is for both containment seals and gaskets and Class 1 structures seals and gaskets, the applicant was asked to explain why the line is not broken into two AMPs, two GALL items, two Table 1 items and two notes. The AMP for the containment seals and gaskets would be Containment Leak Rate Program with the GALL Report Item II.B4-7, the LRA Table 1 Line Item 3.5.1-16 and a note A. The AMP for the Class 1 structures seals and gaskets would probably be the Periodic Surveillance and Preventive Maintenance Program. The applicants staff stated that LRA Table 3.5.2-6 line item Seals and gaskets on page 3.5-80 is for Class 1 structure seals and gaskets not associated with primary containment boundary. Containment seals and gaskets are addressed in LRA Table 3.5.2-1 line item Primary containment electrical penetration on page 3.5-55. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.1, Item 3.5.1-16 discussion is revised to add the following paragraph: For reactor building seals and gaskets, the Periodic Surveillance and Preventive Maintenance Program manages cracking and change in material properties for the railroad inner and outer lock doors elastomer seals. The staff finds that since the GALL does not have similar line item to LRA Table 3.5.1 line item for Class 1 structures seals and gaskets other than for Group 6, the applicant has chosen to align the component Class 1 structures seals and gaskets with GALL Report Table 3.5.1, Line Item 3.5.1-16, which is for the primary containment seals and gaskets. The staffs evaluation of the use of the Periodic Surveillance and Preventive Maintenance Program to manage cracking and change in material properties for the railroad inner and outer lock doors elastomer seals is therefore provided in SER Section 3.5.2.3.8, Bulk Commodities-Summary of Aging Management Evaluation. For loss of sealing and leakage through containment due to deterioration of elastomer, rubber and other similar material joint seals, gaskets, and moisture barriers (caulking, flashing, and other sealants) exposed to indoor uncontrolled air or outdoor air, the GALL Report recommends programs consistent with GALL AMP XI.S1, ASME Code, Section XI, Subsection IWE and GALL AMP XI.S4, 10 CFR Part 50, Appendix J. The staff noted that the applicant manages cracking and change in material properties due to deterioration of the elastomer drywell shell to floor seal (moisture barrier) exposed to a protected from weather environment using the Containment Inservice Inspection Program (plant-specific) only. The moisture barrier is a containment internal seal and therefore the requirement of 10 CFR 50, Appendix J, does not apply. 3-414

The staff reviewed the applicants Containment Inservice Inspection Program and its evaluation is documented in SER Section 3.0.3.3.2. The Containment Inservice Inspection Program encompasses the ASME Code, Section XI Subsection IWE Code requirements for managing the deterioration (cracking and change in material properties) of the primary containment moisture barrier through visual inspections. Because the applicants plant-specific Containment Inservice Inspection Program includes the same requirements for inspection and detection of deterioration of the VYNPS primary containment moisture barrier through visual inspections as the ASME Code, Section XI Subsection IWE Code, the staff finds it to be an acceptable management program for detecting cracking and change in material properties. For loss of sealing and leakage through containment due to deterioration of elastomer, rubber and other similar material joint seals, gaskets, and moisture barriers (caulking, flashing, and other sealants) exposed to indoor uncontrolled air or outdoor air, the GALL Report recommends programs consistent with GALL AMP XI.S1, ASME Code, Section XI, Subsection IWE and GALL AMP XI.S4, 10 CFR Part 50, Appendix J. The staff noted that for cracking and change in material properties due to deterioration of the elastomer primary containment electrical penetration seals and sealant exposed to a protected from weather environment (LRA page 3.5-55) is managed using only the Containment Leak Rate Program instead of both GALL AMP, GALL AMP XI.S1 and GALL AMP XI.S4. The staff reviewed the applicants Containment Leak Rate Program. This evaluation is documented in SER Section 3.0.3.2.8. The Containment Leak Rate Program is the only AMP needed to detect deterioration of the containment electrical penetration seals and sealant. Although the GALL Report specifies GALL AMP XI.S1, ASME Code, Section XI, Subsection IWE also for this material, environment and aging effect, the 1998 Edition and later editions of ASME Code, Section XI, Subsection IWE do not require the inspection of seals and gaskets. Since the applicant has not assigned two AMPs to manage this aging effect, the applicant has conservatively called the application of only the Containment Leak Rate Program a different program with respect to the GALL Report. On the basis of its review, the staff finds that the applicants Containment Leak Rate Program is consistent with the GALL Report (with exceptions) and the 1998 Edition and later editions of the ASME Code, Section XI, Subsection IWE, do not require the inspection of seals and gaskets. The staff concludes that the applicants Containment Leak Rate Program alone to be an acceptable management program for detecting cracking and change in material properties of containment electrical penetration seals and sealants. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3-415

3.5.2.1.5 Loss of Leak Tightness in Closed Position Due to Mechanical Wear of Locks, Hinges and Closure Mechanisms In the LRA Table 3.5.1, Item 3.5.1-17, the applicant stated that locks, hinges, and closure mechanisms are active components and are therefore not subject to an AMR. During the audit and review, the applicant was asked to provide any license renewal regulatory guidance document or previous NRC SER that has ever stated that locks, hinges, and closure mechanisms are active components. If locks, hinges, and closure mechanisms are active components at VYNPS, the applicant was asked to provide an itemized list of these active components with their qualified life or specified time period of replacement. The applicant was also asked to explain how VYNPS tracks the active life of these components before replacement. The applicants staff stated that it may be a misnomer to refer to these components as active components since the requirement of 10 CFR 54.21(a)(1)(i) does not refer to active or passive components, but rather excludes from an AMR, components with moving parts or with a change in configuration or properties that perform an intended function in accordance with 10 CFR 54.4. Locks, hinges, and closure mechanisms perform their functions with moving parts. This exception is not based on a qualified life or specified time period of replacement for a component. 10 CFR 54.21(a)(1)(ii) requirements provide a separate exclusion for components that are replaced based on a qualified life. Other precedents for locks, hinges, and closure mechanisms as active components that have received approval by the NRC are found in Peach Bottom (NUREG-1769, Section 3.0.3.14.2, page 3-58) and Millstone (NUREG-1838, Section 3.3A.2.1.4, page 3-245). The staff reviewed the Peach Bottom and Millstone SERs which verify that locks, hinges, and other closure mechanisms have been accepted as active components and are excluded from an AMR. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.5.2.1.6 Loss of Material Due to General, Pitting, and Crevice Corrosion For loss of material due to general, pitting and crevice corrosion of steel (and dissimilar metal welds) penetration sleeves, personnel airlock, equipment hatch and CRD hatch exposed to indoor uncontrolled air or outdoor air, the GALL Report recommends programs consistent with GALL AMP XI.S1, ASME Code, Section XI, Subsection IWE and GALL AMP XI.S4, 10 CFR Part 50, Appendix J. The staff noted that loss of material of the carbon steel CRD removal hatch, equipment hatch, personnel airlock, primary containment electrical penetrations, torus electrical penetrations, and torus mechanical penetrations exposed to a protected from weather environment (LRA pages 3.5-50 and 51) is managed using its Containment Inservice Inspection Program, which is a plant-specific AMP, and the Containment Leak Rate Program. 3-416

The staff reviewed the applicants Containment Inservice Inspection Program and its evaluation is documented in SER Section 3.0.3.3.2. The staff finds that the applicants containment Inservice Inspection Program satisfied criteria of SRP-LR Appendix A.1 and encompasses the ASME Code, Section XI Subsection IWE requirements for managing loss of material for primary containment and its integral attachments. On this basis, the staff concludes that the applicants plant-specific Containment Inservice Inspection Program is an acceptable management program for managing loss of material of the above components. The staff finds the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.5.2.1.7 Fretting or Lock Up Due to Mechanical Wear In LRA Table 3.5.1, Item 3.5.1-21, the applicant stated that VYNPS plant operating experience has not identified fretting or lock up due to mechanical wear for the drywell head and downcomers. During the audit and review, the staff noted that plant operating experience does not find fretting or lock up due to mechanical wear but inspections do. The applicant was asked to explain if VYNPS staff currently inspect for wear of the drywell head and downcomer pipes in accordance with the CLB using the Containment Inservice Inspection Program. If VYNPS currently does inspect these components for wear, justify the basis for not performing these same inspections during an extended license period. If required, provide drawings showing the spacial distance between components such that fretting cannot occur. The applicants staff stated condition reports are a primary source of operating experience documentation reviewed for license renewal. Condition reports document negative inspection results. The GALL Report defines neither fretting nor lockup and further confuses the subject by stating that fretting and lockup are caused by mechanical wear which is an aging mechanism resulting in the aging effect loss of material. The definition in GALL AMP IX.E merely states that fretting and lockup is an aging effect along with a cause, but doesnt say what it is or what it looks like. As indicated in the line item for drywell head in LRA Table 3.5.2-1, the Containment Inservice Inspection-IWE Program and the Containment Leak Rate Program manage loss of material. Loss of material is the aging effect caused by mechanical wear. VYNPS inspects the drywell head and downcomers (torus vent system) per the requirements of ASME Code, Section XI. In addition, the drywell head and downcomers are stationary, well-braced components and the spacial distance between connecting components make it unlikely for fretting and lockup to occur. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.5.2.1.8 Loss of Material Due to General and Pitting Corrosion For loss of material due to general, pitting and crevice corrosion of steel support members, welds, bolted connections; and support anchorage to building structure exposed to indoor uncontrolled air or outdoor air, the GALL Report recommends programs consistent with GALL AMP XI.S6, Structures Monitoring Program. 3-417

During the audit and review, the staff noted that loss of material of carbon steel damper framing exposed to a protected from weather environment is managed using the Fire Protection Program (with exceptions to the GALL Report and enhancements). The staff reviewed the applicants Fire Protection Program and its evaluation is documented in SER Section 3.0.3.2.11. The Fire Protection Program will be enhanced in accordance with the parameters monitored/inspected element to specify that fire damper frames in fire barriers shall be inspected for corrosion (loss of material). This requirement will also be added to field procedures. In a letter dated July 6, 2006, the applicant revised its LRA. The applicant revised the VYNPS License Renewal Commitments List to state that procedures will be enhanced to specify that fire damper frames in fire barriers will be inspected for corrosion. Acceptance criteria will be enhanced to verify no significant corrosion. The implementation schedule is before March 21, 2012. On the basis that the applicants Fire Protection Program will be enhanced to include in accordance with parameters monitored/inspected that fire damper frames in fire barriers be inspected for corrosion (loss of material), the staff finds that it is an acceptable management program for managing loss of material of the damper framing in lieu of the recommended GALL AMP XI.S6. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. For loss of material due to general, pitting and crevice corrosion of steel support members, welds, bolted connections; and support anchorage to building structure exposed to indoor uncontrolled air or outdoor air, the GALL Report recommends programs consistent with GALL AMP XI.S6, Structures Monitoring Program. During the audit and review, the staff noted that loss of material of carbon steel fire hose reels exposed to a protected from weather environment is managed using the Fire Water System Program (with exceptions to the GALL Report and enhancements). The staff reviewed the applicants Fire Water System Program evaluation is documented in SER Section 3.0.3.2.12. The Fire Water System Program applies to water-based fire protection systems that consist of sprinklers, nozzles, fittings, valves, hydrants, hose stations (including Fire hose reels), standpipes, and aboveground and underground piping and components. Components are tested in accordance with applicable NFPA codes and standards. Such testing assures that carbon steel Fire hose reels will be inspected for corrosion (loss of material). On the basis that the applicants Fire Water System Program includes hose stations (including fire hose reels) which are tested in accordance with NFPA codes and standards which will detect corrosion, the staff finds that it is an acceptable AMP for managing loss of material of fire hose reels in lieu of the recommended GALL AMP XI.S6. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3-418

3.5.2.1.9 Cracking Due to Restraint Shrinkage, Creep, and Aggressive Environment For cracking due to restraint shrinkage, creep and aggressive environment of concrete block masonry walls exposed to indoor uncontrolled air or outdoor air, the GALL Report recommends programs consistent with GALL AMP XI.S5, Masonry Wall Program. In LRA Table 3.5.2-5 (page 3.5-67), the applicant stated that cracking of concrete brick for Vernon Dam masonry walls exposed to a weather environment is managed using the Vernon Dam FERC Inspection Program. During the audit and review, the staff finds that inspections of the Vernon Dam are not part of a VYNPS AMP but inspections are conducted by the owner of the dam in accordance with FERC oversight. Vernon dam personnel conduct a daily visual inspection of all the project facilities. An operations crew attends the plant daily. Vernon dam engineering performs an annual inspection of all the project structures and divers make a thorough inspection once every five year on both upstream and downstream sides. The operational inspection frequency for licensed and exempt low hazard potential dams is biennial. Reports of operational inspections are filed with the FERC. The staff has finds that mandated FERC inspection programs are acceptable for aging management. On the basis that the inspection and maintenance of the Vernon Dam is in accordance with the regulatory jurisdiction and are conducted by FERC or the US Army Corp of Engineers, the staff finds the aging management of the dam is adequate. The staffs evaluation of the Vernon Dam FERC Inspection Program is documented in SER Section 3.0.3.3.6. The staff finds that FERC Inspection will adequately manage the aging effects for the Vernon Dam and that the management of cracking of concrete brick for Vernon Dam masonry walls exposed to a weather environment is acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.5.2.1.10 Loss of Sealing Due to Deterioration of Seals, Gaskets, and Moisture Barriers (Caulking, Flashing, and Other Sealants) During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-80), for component seals and gaskets (doors, manways and hatches), material rubber in a protected from weather environment; the aging effects are cracking and change in material properties. One of the AMP s shown is the Structures Monitoring Program. The GALL Report line item referenced is III.A6-12 and the LRA Table 1 reference is Line Item 3.5.1-44. The note shown is E, different AMP than shown in the GALL Report. However, the GALL Report Line Item III.A6-12 and LRA Table 1 Line Item 3.5.1-44 both specify the Structures Monitoring Program. The applicant was asked to explain why the note shown is not A instead of E for the lower half of this AMR line item. During the audit and review, the applicants staff stated that LRA Table 3.5.2-6 (page 3.5-80), for component seals and gaskets (doors, manways and hatches), material rubber in a protected from weather environment; the aging effects are cracking and change in material properties. The LRA will be clarified to indicate that note A applies to the line for SMP. 3-419

In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.2-6 is revised to indicate that note A applies to component seals and gaskets (doors, man-ways and hatches) with the Structures Monitoring Program. The staff reviewed the applicants response and finds it acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.5.2.1.11 Loss of Material Due to Abrasion, Cavitation For loss of material due to abrasion and cavitation of reinforced concrete exterior above and below grade foundation and interior slab exposed to flowing water, the GALL Report recommends programs consistent with GALL AMP XI.S7, Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants. During the audit and review, the staff noted that loss of material of reinforced concrete exterior walls below grade (SW area), exterior walls below grade (CWS area), foundation, interior walls below grade, exterior walls above grade, exterior walls below grade and foundation (cooling tower) exposed to a fluid environment is managed using the Structures Monitoring Program (with enhancements) instead of the recommended GALL AMP XI.S7. The staff reviewed the applicants Structures Monitoring Program and its evaluation is documented in SER Section 3.0.3.2.17. VYNPS is not committed to RG 1.127. GALL AMP XI.S7 states that for plants not committed to RG 1.127, Revision 1, aging management of water-control structures may be included in the Structures Monitoring Program. The program elements of GALL AMP XI.S7 applicable to the water control structures at VYNPS have been incorporated into the VYNPS Structures Monitoring Program. On the basis that the applicants Structures Monitoring Program includes the program elements of GALL AMP XI.S7 applicable to the water control structures at VYNPS as recommended by the GALL Report, the staff finds it to be an acceptable AMP for loss of material of the components listed above. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. In LRA Table 3.5.2-5 (page 3.5-67), the applicant stated that loss of material of concrete for the Vernon Dam external walls above/below grade exposed to fluid environment is managed by its Vernon Dam FERC Inspection Program. The referenced GALL Report line item is III.A6-7. The GALL Report Line Item III.A6-7 states the following in accordance with AMP: Chapter XI.S7, Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. Since one of the AMPs in accordance with this GALL Report line item is FERC dam inspections, the applicant was asked to explain why the note assigned to the LRA AMR line item is E instead of A, where note A is consistent with the GALL Report. 3-420

During the audit and review, the staff finds that inspections of the Vernon Dam are not part of a VYNPS AMP but inspections are conducted by the owner of the dam in accordance with FERC oversight. Vernon dam personnel conduct a daily visual inspection of all the project facilities. An operations crew attends the plant daily. Vernon dam engineering performs an annual inspection of all the project structures and divers make a thorough inspection once every five year on both upstream and downstream sides. The operational inspection frequency for licensed and exempt low hazard potential dams is biennial. Reports of operational inspections are filed with the FERC. The staff has finds that mandated FERC inspection programs are acceptable for aging management. On the basis that the inspection and maintenance of the Vernon Dam is in accordance with the regulatory jurisdiction and are conducted by FERC or the US Army Corp of Engineers, the staff finds the aging management of the dam is adequate. The staffs evaluation of the Vernon Dam FERC Inspection Program is documented in SER Section 3.0.3.3.6. The staff finds that FERC Inspection will adequately manage the aging effects for the Vernon Dam and that the loss of material of concrete for the Vernon Dam external walls above/below grade exposed to fluid environment is acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.5.2.1.12 Loss of Material Due to General (Steel Only), Pitting and Crevice Corrosion For loss of material due to general, pitting and crevice corrosion of group six metal structural members exposed to indoor uncontrolled air, outdoor air, flowing water, or standing water the GALL Report recommends programs consistent with GALL AMP XI.S7, Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants. During the audit and review, the staff noted that loss of material of metal Structural steel: beams, columns, plates exposed to a protected from weather or fluid environment; metal anchorage/embedments exposed to a fluid environment; metal manway hatches and hatch covers exposed to a protected from weather or weather environment; and structural bolting exposed to a fluid environment is managed using the Structures Monitoring Program (with enhancements) instead of the recommended GALL AMP XI.S7. The staff reviewed the applicants Structures Monitoring Program and its evaluation is documented in SER Section 3.0.3.2.17. VYNPS is not committed to RG 1.127. GALL AMP XI.S7 states that for plants not committed to RG 1.127, Revision 1, aging management of water-control structures may be included in the Structures Monitoring Program. The program elements of GALL AMP XI.S7 applicable to the water control structures at VYNPS have been incorporated into the VYNPS Structures Monitoring Program. On the basis that the applicants Structures Monitoring Program includes the program elements of GALL AMP XI.S7 applicable to the water control structures at VYNPS as recommended by the GALL Report, the staff finds it is an acceptable management program for managing loss of material of the components listed above. 3-421

On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. In LRA Table 3.5.2-5 (page 3.5-66), the applicant stated that loss of material of carbon steel for the Vernon Dam structural steel protected from weather or exposed to weather or fluid environments is managed by Vernon Dam FERC Inspection Program. The referenced GALL Report line item for all three environments is III.A6-11. The GALL Report Line Item III.A6-11 states the following in accordance with AMP: Chapter XI.S7, Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. Since one of the AMPs in accordance with this GALL Report line item is FERC dam inspections, the applicant was asked to explain why the note assigned to the three LRA AMR line items is E instead of A, where note A is consistent with the GALL Report. During the audit and review, the staff finds that inspections of the Vernon Dam are not part of a VYNPS AMP but inspections are conducted by the owner of the dam in accordance with FERC oversight. Vernon dam personnel conduct a daily visual inspection of all the project facilities. An operations crew attends the plant daily. Vernon dam engineering performs an annual inspection of all the project structures and divers make a thorough inspection once every five year on both upstream and downstream sides. The operational inspection frequency for licensed and exempt low hazard potential dams is biennial. Reports of operational inspections are filed with the FERC. The staff has finds that mandated FERC inspection programs are acceptable for aging management. On the basis that the inspection and maintenance of the Vernon Dam is in accordance with the regulatory jurisdiction and are conducted by FERC or the US Army Corp of Engineers, the staff finds the aging management of the dam is adequate. The staffs evaluation of the Vernon Dam FERC Inspection Program is documented in SER Section 3.0.3.3.6. The staff finds that FERC Inspection will adequately manage the aging effects for the Vernon Dam and that loss of material of carbon steel for the Vernon Dam structural steel protected from weather or exposed to weather or fluid environments is acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.5.2.1.13 Loss of Material/General, Pitting and Crevice Corrosion For loss of material due to general, pitting and crevice corrosion of stainless steel and steel support members; bolted connections; support anchorage to building structure exposed to treated water (less than140EF) the GALL Report recommends programs consistent with GALL AMP XI.M2, Water Chemistry, for BWR water, and GALL AMP XI.S3, ASME Code, Section XI, Subsection IWF. During the audit and review, the staff noted that loss of material of carbon steel and stainless steel anchorage/embedments exposed to a fluid environment is managed using the Water Chemistry Control-BWR Program and the Inservice Inspection Program, which is a plant-specific AMP instead of the GALL AMP XI.S3. 3-422

The staff reviewed the applicants Inservice Inspection Program and its evaluation is documented in SER Section 3.0.3.3.3. The applicants Inservice Inspection Program encompasses the ASME Code, Section XI Subsection IWF requirements for managing the loss of material for ASME Code Class 1, 2, and 3 steel piping supports and steel component supports within containment. On the basis that the applicants plant-specific Inservice Inspection Program includes the same requirements for inspection and detection of loss of material for ASME Code Class 1, 2, and 3 steel piping supports and steel component supports within containment as the ASME Code, Section XI Subsection IWF, the staff finds it to be an acceptable management program for loss of material of carbon steel and stainless steel anchorage/embedments. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.5.2.1.14 Loss of Material Due to Pitting and Crevice Corrosion In LRA Table 3.5.1, Item 3.5.1-50, the applicant stated that loss of material due to pitting and crevice corrosion of Groups B2 and B4 galvanized steel, aluminum, and stainless steel components in an outdoor air environment is not applicable at VYNPS. During the audit and review, the staff noted that NUREG-1833, Technical Bases for Revision to the License Renewal Guidance Documents, on page 93 for Item TP-6 states: An approved precedent exists for adding this material, environment, aging effect, and program combination to the GALL Report. As shown in RNP [Robinson Nuclear Plant] SER Section 3.5.2.4.3.2, galvanized steel and stainless steel in an outdoor air environment could result in loss of material due to constant wetting and drying conditions. Aluminum would also be susceptible to a similar kind of aging effect in the outdoor environment. The applicant was asked to provide a discussion of the actual Group B2 and B4 galvanized steel, aluminum, and stainless steel VYNPS components which are within the scope of license renewal and exposed to an outdoor air environment. In addition, the applicant was asked to discuss the location of these components at VYNPS and how they are protected from constant wetting and drying conditions. The applicants technical personnel stated that loss of material due to pitting and crevice corrosion of aluminum and stainless steel components in an outdoor environment is not applicable if the atmospheric environment is non-aggressive. The ambient environment at VYNPS is not chemically polluted by vapors of sulfur dioxide (SO2) or other similar substances and the external environment does not contain saltwater or high chloride content. In this non-aggressive environment, the occasional wetting and drying from normal outdoor weather does not result in any significant loss of material in aluminum or stainless steel components. The conclusion that no aging effects require management for these materials in an outdoor air environment is supported by operating experience and by previously approved staff positions documented in the Joseph M. Farley SER (NUREG-1825, page 3-314). 3-423

The applicant stated that the components that may be considered in the B2 and B4 grouping consists of those line items in LRA Table 3.5.2-6 including the plant-specific Note 503. Note 503 provides the basis for concluding the environment is non-aggressive and the conclusion that there are no aging effects requiring management. The applicant stated that loss of material is not an applicable aging effect for stainless steel or aluminum components in outdoor air. The ambient environment at VYNPS is not chemically polluted by vapors of SO2 or other similar substances and the external environment does not contain saltwater or high chlorides. Therefore, loss of material due to pitting and crevice corrosion is not an AERM for aluminum and stainless steel components exposed to the external environment. The applicant stated that the AMR results for galvanized steel components in outdoor air should indicate loss of material as an aging effect with structures monitoring as the AMP . In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.1, Item 3.5.1-50 is revised to include the following in the discussion column: Consistent with NUREG-1801 for galvanized steel components in outdoor air. The Structures Monitoring Program will manage loss of material. The staff reviewed the applicants Structures Monitoring Program. This evaluation is documented in SER Section 3.0.3.2.17. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. During the audit and review, the staff noted that in LRA Table 3.5.2-5 (page 3.5-65), for component transmission towers, material galvanized steel in an exposed to weather environment; the aging effect is none. The staff referenced the first question above and asked the applicant to explain how this component is protected from constant wetting and drying conditions. During interviews with the applicants technical personnel, the applicants staff stated that as identified in the response to the first question above, loss of material is the AERM and the Structures Monitoring Program is the AMP. This is consistent with the GALL Report, Volume 2, Item III.B4-7, summarized in LRA Table 3.5.1, Item 3.5.1-50, and note C applies. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to indicate loss of material as an AERM with the Structures Monitoring Program as the AMP and the GALL Report Volume 2 item as III.B4-7 with a Note C in LRA Table 3.5.2-5 for transmission towers with a material of galvanized steel in an exposed to weather environment. The staff review the applicants response and finds it acceptable. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-71), for component conduit, material galvanized steel in an exposed to weather environment; the aging effect is none. The staff referenced the first question above and asked the applicant to explain how this component is protected from constant wetting and drying conditions. 3-424

During interviews with the applicants technical personnel, the applicants staff stated that as identified in the response to the first question above, loss of material is the AERM and the Structures Monitoring Program is the AMP. This is consistent with the GALL Report, Volume 2, Item III.B4-7, summarized in LRA Table 3.5.1, Item 3.5.1-50, and note C applies. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to indicate loss of material as an AERM with the Structures Monitoring Program as the AMP and the GALL Report Volume 2 item as III.B4-7 with a Note C in LRA Table 3.5.2-6 for conduit with a material of galvanized steel in an exposed to weather environment. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-71), for component conduit support, material galvanized steel in an exposed to weather environment; the aging effect is none. The staff referenced the first question above and asked the applicant to explain how this component is protected from constant wetting and drying conditions. During interviews with the applicants technical personnel, the applicants staff stated that as identified in the response to the first question above, loss of material is the AERM and the Structures Monitoring Program is the AMP. This is consistent with the GALL Report, Volume 2, Item III.B4-7, summarized in LRA Table 3.5.1, Item 3.5.1-50, and Note C applies. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to indicate loss of material as an AERM with the Structures Monitoring Program as the AMP and the GALL Report Volume 2 item as III.B4-7 with a Note C in LRA Table 3.5.2-6 for conduit support with a material of galvanized steel in an exposed to weather environment. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-72), for component electrical and instrument panels and enclosures, material galvanized steel in an exposed to weather environment; the aging effect is none. The staff referenced the first question above and asked the applicant to explain how this component is protected from constant wetting and drying conditions. During interviews with the applicants technical personnel, the applicants staff stated that as identified in the response to the first question above, loss of material is the AERM and the Structures Monitoring Program is the AMP. This is consistent with the GALL Report, Volume 2, Item III.B4-7, summarized in LRA Table 3.5.1, Item 3.5.1-50, and note C applies. In a letter dated July 14, 2006, the applicant stated amended its LRA. The applicant stated that the LRA is revised to indicate loss of material as an AERM with the Structures Monitoring Program as the AMP and the GALL Report Volume 2 item as III.B4-7 with a Note C in LRA Table 3.5.2-6 for electrical and instrument panels and enclosures with a material of galvanized steel in an exposed to weather environment. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3-425

During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-78), for component structural bolting, material galvanized steel in an exposed to weather environment; the aging effect is none. The staff referenced the first question above and asked the applicant to explain how this component is protected from constant wetting and drying conditions. During interviews with the applicants technical personnel, the applicants staff stated that as identified in the response to the first question above, loss of material is the AERM and the Structures Monitoring Program is the AMP. This is consistent with the GALL Report, Volume 2, Item III.B4-7, summarized in LRA Table 3.5.1, Item 3.5.1-50, and Note C applies. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA is revised to indicate loss of material as an AERM with the Structures Monitoring Program as the AMP and the GALL Report Volume 2 item as III.B4-7 with a Note C in LRA Table 3.5.2-6 for structural bolting with a material of galvanized steel in an exposed to weather environment. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.5.2.1.15 Loss of Material Due to General and Pitting Corrosion For loss of material due to general and pitting corrosion of steel support members; welds, bolted connections; support anchorage to building structure exposed to indoor uncontrolled air or outdoor air the GALL Report recommends programs consistent with GALL AMP XI.S3, ASME Code, Section XI, Subsection IWF. During the audit and review, the staff noted that loss of material of steel reactor vessel support assembly, reactor vessel stabilizer supports, torus external supports (columns, saddles), anchorage/embedments, base plates, component and piping supports ASME Code Class 1, 2, 3 and MC, anchor bolts, and ASME Code Class 1, 2, 3 and MC supports bolting exposed to a protected from weather environment and anchorage/embedments, base plates, component and piping supports ASME Code Class 1, 2, 3 and MC, anchor bolts, ASME Code Class 1, 2, 3 and MC supports bolting exposed to a weather environment is managed using the Inservice Inspection Program, which is a plant-specific program instead of the recommended GALL AMP XI.S3. The staff reviewed the applicants Inservice Inspection Program and its evaluation is documented in SER Section 3.0.3.3.3. The staff finds that the applicants Inservice Inspection Program satisfied criteria of SRP-LR Appendix A.1 and encompasses the ASME Code, Section XI Subsection IWF requirements for managing the loss of material for ASME Code Class 1, 2, and 3 steel piping supports and steel component supports within containment. On the basis that the applicants plant-specific Inservice Inspection Program includes the same requirements for inspection and detection of loss of material for ASME Code, Class 1, 2, and 3 steel piping supports and steel component supports within containment as the ASME Code, Section XI Subsection IWF, the staff finds it to be an acceptable management program for loss of material of the components listed above. 3-426

For loss of material due to general and pitting corrosion of carbon steel vent header support exposed to fluid environment (LRA page 3.5-54), the GALL Report line item shown is III.B1.1-13, LRA Table 1, Item 3.5.1-53 is referenced, and the AMP shown is the Inservice Inspection-IWF Program. The staff noted that GALL Report Line Item III.B1.1-13 is for an indoor uncontrolled air or outdoor air environment. In RAI 3.5.1-53-W-1, the staff asked the applicant to explain why GALL Report Line Item III.B1.1-11 (treated water environment), LRA Table 1, Item 3.5.1-49, and the Water Chemistry Control - BWR Program are not included in this AMR line item. By letter dated September 5, 2006 the applicant provided its response. The applicant stated that since portions of the carbon steel vent header supports are below the water level in the torus, application of GALL Report Line Item III.B1.1-11 is appropriate for the vent header supports. The applicant has also revised this AMR line item to reflect this change. The staff reviewed the applicants response and determined it acceptable. Therefore, the staff's concern described in RAI 3.5.1-53-W-1 is resolved. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3.5.2.1.16 None (Galvanized Steel and Aluminum Support Members; Welds; Bolted Connections; Support Anchorage to Building Structure) During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-72), for component electrical and instrument panels and enclosures, material galvanized steel in a protected from weather environment, the aging effect is none. The GALL Report line item referenced is III.B3-3, which is for the following components: support members; welds; bolted connections; support anchorage to building structure. The applicant was asked to explain why the LRA AMR line item has a Note A shown instead of a Note C, different component with respect to the GALL Report line item. Or as an alternative, a letter note A with a number note explaining that the component is different. During interviews with the applicants technical personnel, the applicants staff stated that the GALL Report does not mention every type of component that may be subject to AMR (e.g., panel is not in the GALL Report) nor does the terminology used at a specific plant always align with that used in the GALL Report. Consequently, matching plant components to the GALL Report components is occasionally subjective. In this particular case, panels, which have no specific function other than to support and protect electrical equipment, was considered a support member and note A was applied. The use of either note A or C has no real impact on the AMR results. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA Table 3.5.2-6 is revised to change note A to note C for electrical and instrument panels and enclosures with a material of galvanized steel in a protected from weather environment. Aging effect and associated AMP are unchanged. On the basis of its review of the applicants response, the staff finds the response acceptable and the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. 3-427

During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-73), for component flood curb, material galvanized steel in a protected from weather environment, the aging effect is none. The GALL Report line item referenced is III.B5-3, which is for the following components: Support members; welds; bolted connections; support anchorage to building structure. The applicant was asked to explain why the LRA AMR line item has a Note A shown instead of a Note C, different component with respect to the GALL Report line item. Or as an alternative, a letter note A with a number note explaining that the component is different. During interviews with the applicants technical personnel, the applicants staff stated that unlike the conduits and panels compared to supports in other questions, the component flood curb should not have been considered a match. Note C should be applied here; although the use of either note A or C has no real impact on the AMR results. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.2-6 is revised to change note A to note C for flood curb with a material of galvanized steel in a protected from weather environment. Aging effect and associated AMP are unchanged. On the basis of its review of the applicants response, the staff finds the response acceptable and the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. Conclusion. The staff evaluated the applicants claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicants consideration of recent operating experience and proposals for managing the 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 its AMRs. Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for these components 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). 3.5.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended Summary of Information in the Application. In LRA Section 3.5.2.2, the applicant further evaluates aging management, as recommended by the GALL Report, for the SC supports components and provides information concerning how it will manage the following effects of aging: (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 3-428
• loss of prestress due to relaxation, shrinkage, creep, and elevated temperature
• cumulative fatigue damage
• cracking due to stress-corrosion cracking
• 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 structures and components supports:
• aging of structures not covered by the structures monitoring program
• aging management of inaccessible areas
• reduction of strength and modulus of concrete structures due to elevated temperature
• aging management of inaccessible areas for Group 6 structures
• cracking due to stress-corrosion cracking and loss of material due to pitting and crevice corrosion
• aging of supports not covered by the structures monitoring program
• cumulative fatigue damage due to cyclic loading (3) quality assurance for aging management of nonsafety-related components Staff Evaluation. 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 audited and reviewed the applicants evaluation to determine whether it adequately addressed the issues further evaluated. In addition, the staff reviewed the applicants further evaluations against the criteria contained in SRP-LR Section 3.5.2.2. The staffs review of the applicants further evaluation follows.

3.5.2.2.1 PWR and BWR Containments The staff reviewed LRA Section 3.5.2.2.1 against SRP-LR Section 3.5.2.2.1 criteria, which address several areas: Aging of Inaccessible Concrete Areas. The staff reviewed LRA Section 3.5.2.2.1.1 against the criteria in SRP-LR Section 3.5.2.2.1.1. In LRA Section 3.5.2.2.1.1, the applicant addressed 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. SRP-LR Section 3.5.2.2.1.1 states that increases in porosity and permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack, and cracking, loss of bond, and 3-429

loss of material (spalling, scaling) due to corrosion of embedded steel may occur in inaccessible areas of PWR and BWR concrete and steel containments. The existing program relies on ASME Code, Section XI, Subsection IWL to manage these aging effects; however, the GALL Report recommends further evaluation of plant-specific programs to manage the aging effects for inaccessible areas in aggressive environments. The applicant stated, in the LRA, that VYNPS has a Mark I free standing steel containment located within the reactor building. Inaccessible and accessible concrete areas are designed in accordance with ACI specification ACI 318-63, Building Code Requirements for Reinforced Concrete, which results in low permeability and resistance to aggressive chemical solutions by requiring the following:

• high cement content
• low water-to-cement ratio
• proper curing
• adequate air entrainment In addition, as stated in the LRA, VYNPS concrete also meets requirements of later ACI guide ACI 201.2R-77, Guide to Durable Concrete, since both documents use the same ASTM standards for selection, application and testing of concrete.

Furthermore, as stated in the LRA, the below-grade environment is not aggressive (pH greater than 5.5, chlorides less than 500 ppm, and sulfates less than 1,500 ppm). Concrete was provided with air content between 3 percent and 5 percent and a water/cement ratio between 0.44 and 0.60. Therefore, 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 are not applicable for concrete in inaccessible areas. The absence of concrete aging effects is confirmed in accordance with the Structures Monitoring Program. The staff finds that these aging effects are not applicable to the VYNPS Mark I free standing steel containment. The listed possible aging effects apply to concrete elements of PWR containments and concrete BWR containments. The VYNPS Mark I steel containment is located within the concrete reactor building and the previous applicant discussion is for that concrete structure. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.5.2.2.1.1 criteria. For those line items that apply to LRA Section 3.5.2.2.1.1, the staff finds 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). 3-430

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. The staff reviewed LRA Section 3.5.2.2.1.2 against the criteria in SRP-LR Section 3.5.2.2.1.2. In LRA Section 3.5.2.2.1.2, the applicant stated that for the crack 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, this aging effect is not applicable to VYNPS. SRP-LR Section 3.5.2.2.1.2 states that cracks and distortion due to increased stress levels from settlement may occur in PWR and BWR concrete and steel containments. Also, reduction of foundation strength, cracking, and differential settlement due to erosion of porous concrete subfoundations may occur in all types of PWR and BWR containments. The existing program relies on structures monitoring to manage these aging effects. Some plants may rely on a de-watering system to lower the site ground water level. If the plants CLB credits a de-watering system, the GALL Report recommends verification of the continued functionality of the de-watering system during the period of extended operation. The GALL Report recommends no further evaluation if this activity is within the scope of the applicants structures monitoring program. In addition, as stated in the LRA, VYNPS has a Mark I free standing steel containment located within the reactor building and supported by the reactor building foundation. VYNPS does not rely on a de-watering system for control of settlement. Category 1 structures are founded on sound bedrock which prevents significant settlement. Additionally, concrete within five feet of the highest known ground water level is protected by membrane waterproofing. This membrane protects the reactor building concrete against exposure to groundwater. VYNPS was not identified in IN 97-11 as a plant susceptible to erosion of porous concrete subfoundations. Groundwater was not aggressive during plant construction and there is no indication that groundwater chemistry has significantly changed. No changes in groundwater conditions have been observed at VYNPS. As a result, cracking and distortion due to increased stress levels from settlement; reduction of foundation strength, cracking and differential settlement due to erosion of porous concrete subfoundations are not applicable to VYNPS concrete structures. During the audit and review, the applicant stated that the crack 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 are not plausible aging effects due to the nonexistence of these aging mechanisms. The applicant stated that the aging effects due to settlement are not expected at VYNPS for the Mark I steel containment since it is located within the reactor building and supported by the reactor building foundation. The reactor building is founded on sound bedrock which prevents significant settlement. In addition, there is no porous concrete subfoundation below the reactor building of concern. On the basis of its audit and review, the staff determined that crack and distortion due to increased stress levels from settlement; reduction of foundation strength, cracking and differential settlement due to erosion of porous concrete subfoundations are not plausible aging 3-431

effects due to the nonexistence of these aging mechanisms at VYNPS. The staff finds that these aging effects and aging effect mechanisms are not applicable to the VYNPS Mark I free standing steel containment. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.5.2.2.1.2 criteria. For those line items that apply to LRA Section 3.5.2.2.1.2, the staff finds 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). Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature. The staff reviewed LRA Section 3.5.2.2.1.3 against the criteria in SRP-LR Section 3.5.2.2.1.3. In LRA Section 3.5.2.2.1.3, the applicant stated that for the reduction of strength of modulus of concrete structures due to elevated temperature, this aging effect is not applicable to VYNPS. SRP-LR Section 3.5.2.2.1.3 states that reduction of strength and modulus of concrete due to elevated temperatures may occur in PWR and BWR concrete and steel containments. The implementation of the requirements of 10 CFR 50.55a and ASME Code, Section XI, Subsection IWL would not be able to identify the reduction of strength and modulus of concrete due to elevated temperature. ASME Code, Section III, Division 2, Subsection CC-3400, specifies the concrete temperature limits for normal operation or any other long-term period. The GALL Report recommends further evaluation of plant-specific AMPs if any portion of the concrete containment components exceeds specified temperature limits (i.e., general area temperature greater than 60 EC (150 EF) and local area temperature greater than 93 EC (200 EF)). The UFSAR states that the ambient temperature in the drywell is maintained between 135 EF and 165 EF. With a two inch air gap between the drywell shell and the concrete containment, there will be a sufficient temperature drop across the gap so that the concrete will remain well below the 150 EF limit specified in the ASME Code. Transfer of heat across an air gap relies on radiant heat transfer, which is very inefficient. As a result, there will be no reduction in the strength and modulus of the concrete due to elevated temperature as a result of the temperature in the drywell. In addition, the applicant stated, that ASME Code, Section III, Division 2, Subsection CC indicates that aging due to elevated temperature exposure is not significant as long as concrete general area temperatures do not exceed 150EF and local area temperatures do not exceed 200EF. During normal operation, areas within primary containment are within these temperature limits. Therefore, reduction of strength and modulus of concrete structures due to elevated temperature is not an AERM for VYNPS containment concrete. On the basis of its audit and review, the staff determined that the reduction of strength and modulus for concrete structures due to elevated temperature are not plausible aging effects due to the nonexistence of these aging mechanisms. The staff also finds that these aging effects and 3-432

aging effect mechanisms are not applicable to the VYNPS Mark I free standing steel containment. The aging effects due to elevated temperature are not expected at VYNPS for the concrete associated with the Mark I steel containment since general areas temperatures within the primary containment do not exceed 150EF and local area temperatures do not exceed 200EF. On this basis, the staff concludes that these aging effects are not applicable to the VYNPS containment. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.5.2.2.1.3 criteria. For those line items that apply to LRA Section 3.5.2.2.1.3, the staff finds 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). Loss of Material Due to General, Pitting and Crevice Corrosion. The staff reviewed LRA Section 3.5.2.2.1.4 against the criteria in SRP-LR Section 3.5.2.2.1.4. In LRA Section 3.5.2.2.1.4, the applicant addressed the loss of material of steel elements of accessible and inaccessible areas for all types of PWR and BWR containments due to general, pitting and crevice corrosion. SRP-LR Section 3.5.2.2.1.4 states that loss of material due to general, pitting, and crevice corrosion may occur in steel elements of accessible and inaccessible areas for all types of PWR and BWR containments. The existing program relies on requirements of ASME Code, 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. In LRA Section 3.5.2.2.1.4, the applicant addressed loss of material of steel elements of accessible and inaccessible areas for all types of PWR and BWR containments due to general, pitting and crevice corrosion. The applicant stated, in the LRA, that VYNPSs containment is a Mark I steel containment located within the reactor building. VYNPS reactor building concrete in contact with the drywell shell is designed in accordance with specification ACI 318-63. The concrete meets the recommendations of later ACI guide 201.2R-77, since both documents use the same ASTM standards for selection, application and testing of concrete. Concrete is monitored for cracks in accordance with the Structures Monitoring Program. The drywell steel shell and the moisture barrier where the drywell shell becomes embedded in the drywell concrete floor are inspected in accordance with the Containment Inservice Inspection (IWE) Program. 3-433

The applicant also stated that to prevent corrosion of the lower part of the drywell shell, the interior and exterior surfaces are protected from any contact with the atmosphere by complete concrete encasement. It is not credible for ground water to reach the drywell shell, assuming a crack in the concrete, since the concrete at this location is greater than 8 feet thick and poured in multiple separate horizontal planes. The exterior surface of the drywell shell at the sand cushion interface is effectively drained and protected from condensation or water that might enter the air gap from above. Therefore, significant corrosion of the drywell shell is not expected. On the basis of its audit and review, the staff determined that corrosion is not significant for inaccessible areas of the VYNPS containment. In the LRA, the applicant stated that the reactor building concrete in contact with the drywell shell is designed in accordance with ACI 318-63, and meets the recommendations of guideline ACI 201.2R-77. Accessible concrete of the reactor building is monitored for penetrating cracks in accordance with the VYNPS Structures Monitoring Program. In addition, the applicant stated that the accessible portions of the steel drywell and moisture barrier where the drywell shell becomes embedded in the concrete floor are inspected in accordance with the Containment Inservice Inspection (IWE) Program and Structures Monitoring Program. During interviews with the applicants technical personnel, the applicants staff stated that operating experience has demonstrated that the aging effect of loss of material due to corrosion has not been significant for the VYNPS containment. The staff finds that no additional plant-specific AMP was required to manage inaccessible areas of the containment drywell shell and associated components. In the last paragraph of the discussion column of LRA Table 3.5.1, Item 3.5.1-5, the applicant stated that: The drywell steel where the drywell shell is embedded is inspected in accordance with the Containment Inservice Inspection (IWE) Program and Structures Monitoring Program. The staff noted that this is an impossible inspection. During the audit and review, the staff asked the applicant to explain if this statement should have agreed with LRA Section 3.5.2.2.1.4 that stated: The drywell steel shell and the moisture barrier where the drywell shell becomes embedded in the drywell concrete floor are inspected in accordance with the Containment Inservice Inspection (IWE) Program and Structures Monitoring. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.1, Item 3.5.1-5, the discussion column last paragraph is revised to read: The drywell steel shell and the moisture barrier where the drywell shell becomes embedded in the drywell concrete floor are inspected in accordance with the Containment Inservice Inspection (IWE) Program. Also, LRA Section 3.5.2.2.1.4 is revised to delete from the end of the first paragraph, the phrase and Structures Monitoring Program. The drywell to floor moisture barrier will be inspected in accordance with the Containment Inservice Inspection (IWE) Program only. The Structures Monitoring Program is not used. 3-434

On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. Based on the programs identified above, the staff concludes that the applicants meet SRP-LR Section 3.5.2.2.1.4 criteria. For those line items that apply to LRA Section 3.5.2.2.1.4, the staff finds 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). Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature. LRA Section 3.5.2.2.1.5 states that loss of prestress forces due to relaxation, shrinkage, creep, and elevated temperature is a TLAA as required by 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.5 documents the staffs review of the applicants evaluation of this TLAA. SRP-LR Section 3.5.2.2.1.5, stated that loss of prestress forces due to relaxation, shrinkage, creep, and elevated temperature for PWR prestressed concrete containments and BWR Mark II prestressed concrete containments is a TLAA as required by 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c). The applicant stated, in the LRA, that for the loss of prestress due to relaxation, shrinkage, creep, and elevated temperature, this aging effect is not applicable to VYNPS. VYNPS is a Mark I containment structure and does not incorporate prestress concrete in its design. Therefore, loss of prestress due to relaxation, shrinkage, creep, and elevated temperature is not an applicable aging effect. The staff finds that because VYNPS is a BWR with a Mark I containment, the aging effect loss of prestress due to relaxation, shrinkage, creep, and elevated temperature is not applicable to VYNPS. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. Cumulative Fatigue Damage. LRA Section 3.5.2.2.1.6 states fatigue analyses of suppression pool steel shells (including welded joints) and penetrations (including penetration sleeves, dissimilar metal welds, and penetration bellows) are TLAAs as required by 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.6 documents the staffs review of the applicants evaluation of this TLAA. In the discussion column of LRA Table 3.5.1, Item 3.5.1-9, the applicant stated: Not applicable. See Section 3.5.2.2.1.6. However, during the audit and review, the staff noted the following statement was made in LRA Section 3.5.2.2.1.6: Fatigue TLAAs for the steel drywell, torus, and associated penetrations are evaluated and documented in Section 4.6. 3-435

The components associated with LRA Table 3.5.1, Item 3.5.1-9 are: penetration sleeves, penetration bellows; suppression pool shell, unbraced downcomers. The applicant was asked to explain how LRA Table 3.5.1, Item 3.5.1-9 was not applicable when a fatigue TLAA has been performed for the torus and penetrations. Also the applicant was asked to explain why the vent line, vent header and vent line bellows are not listed in LRA Sections 3.5.2.2.1.6 and 4.6 as referenced in LRA Table 3.5.1, Item 3.5.1-8. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.2-1 is revised to add the following line: torus mechanical penetrations, PB, SSR carbon steel, protected from weather, cracking (fatigue), TLAA-metal fatigue, II.B4-4 (C-13), 3.5.1-9, note A. The staff finds that the evaluation of the drywell to torus vent system fatigue analysis finds that it was not a TLAA. The significant contributor to fatigue of the vent system is post-LOCA chugging, a once in plant-life event. As there will still be only one design basis LOCA for the life of the plant, including the period of extended operation, this analysis is not based on a time-limited assumption and is not a TLAA. Since fatigue for the vent system is event driven and is not an age related effect, in a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.2-1 is revised to delete the following line: Drywell to torus vent system, PB, SSR, carbon steel, protected from weather, cracking (fatigue), TLAA-metal fatigue, II.B1.1-4 (C-21), 3.5.1-8, A. Also, the discussion column entry for LRA Table 3.5.1, Item 3.5.1-8 is revised to read as follows: Fatigue analysis is a TLAA for the torus shell. Fatigue of the torus to drywell vent system is event driven and the analysis is not a TLAA. See Section 3.5.2.2.1.6. In addition the discussion column entry of LRA Table 3.5.1, Item 3.5.1-9 is revised to read as follows: Fatigue analysis is a TLAA for the torus penetrations. See Section 3.5.2.2.1.6. Also, the discussion of LRA Section 3.5.2.2.1.6 is revised to read as follows: TLAA are evaluated in accordance with 10 CFR 54.21(c) as documented in Section 4. Fatigue TLAAs for the torus and associated penetrations are evaluated and documented in Section 4.6. 3-436

LRA Section 3.5.2.3, Time-Limited Aging Analyses, is revised to read as follows: TLAA identified for structural components and commodities include fatigue analyses for the torus and torus penetrations. These topics are discussed in Section 4.6. On the basis of its review, the staff finds that the applicant appropriately addressed the aging effect/mechanism, as recommended by the GALL Report. Cracking Due to SCC. The staff reviewed LRA Section 3.5.2.2.1.7 against the criteria in SRP-LR Section 3.5.2.2.1.7. In LRA Section 3.5.2.2.1.7, the applicant stated that for cracking due to SCC, this aging effect is not applicable to VYNPS. SRP-LR Section 3.5.2.2.1.7 states that cracking due to SCC of stainless steel penetration sleeves, penetration bellows, and dissimilar metal welds may occur in all types of PWR and BWR containments. Cracking due to SCC also may occur in stainless steel vent line bellows for BWR containments. The existing program relies on the requirements of ASME Code, Section XI, Subsection IWE and 10 CFR Part 50, Appendix J, to manage this aging effect. The GALL Report recommends further evaluation of additional appropriate examinations/evaluations implemented to detect these aging effects for stainless steel penetration sleeves, penetration bellows and dissimilar metal welds, and stainless steel vent line bellows. The applicant stated, in the LRA, that for the cracking due to SCC, this aging effect is not applicable to VYNPS. The GALL Report recommends further evaluation of inspection methods to detect cracking due to SCC, since visual VT-3 examinations may be unable to detect this aging effect. Potentially susceptible components at VYNPS are penetration sleeves and bellows. The applicant also stated that SCC becomes significant for stainless steel if tensile stresses and a corrosive environment exist. The stresses may be applied (external) or residual (internal). The normal environment inside the drywell is dry. The penetration components are not exposed to corrosive environments. Therefore, SCC is not an AERM for the penetration sleeves and bellows, since the conditions necessary for SCC do not exist. On the basis of its review, the staff finds that cracking due to SCC for penetration sleeves and bellows is not applicable to VYNPS since the conditions necessary for SCC do not exist. In LRA Table 3.5.1, Item 3.5.1-10, the applicant stated that cracking due to SCC for stainless steel penetration sleeves and penetration bellows is not applicable. Also, in LRA Table 3.5.1, Item 3.5.1-11, the applicant stated that cracking due to SCC for stainless steel vent line bellows is not applicable. 3-437

During the audit and review, the applicant was asked to explain if the VYNPS Containment Inservice Inspection Program and Containment Leak Rate Program are used currently to detect cracking of stainless steel penetration sleeves, penetration bellows and vent line bellows by inspection and testing. The applicant was also asked to explain why it is not more appropriate to take credit for these two programs to detect cracking without the need for additional enhanced examinations then to say not applicable. The applicant staff stated that the GALL Reports referenced programs involve visual inspections and leak testing which are not optimum methods for managing SCC. Therefore, when possible, it is more appropriate to assess the conditions and identify whether the applicable aging effects require management. As stated in LRA Section 3.5.2.2.1.7, SCC is not an AERM for the penetration sleeves and bellows, since the conditions necessary for SCC do not exist. However, these components are evaluated for aging effects (such as cracking) requiring management as shown in LRA Table 3.5.2-1. On the basis that VYNPS does not have the conditions necessary for this aging effect, the staff finds that this aging effect is not applicable to VYNPS. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.5.2.2.1.7 criteria. For those line items that apply to LRA Section 3.5.2.2.1.7, the staff finds 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). Cracking Due to Cyclic Loading. The staff reviewed LRA Section 3.5.2.2.1.8 against the criteria in SRP-LR Section 3.5.2.2.1.8. In LRA Section 3.5.2.2.1.8, the applicant addressed cracking of penetration sleeves, penetration bellows, and torus pool steel due to cyclic loading. SRP-LR Section 3.5.2.2.1.8 states that cracking due to cyclic loading of suppression pool steel and stainless steel shells (including welded joints) and penetrations (including penetration sleeves, dissimilar metal welds, and penetration bellows) may occur in all types of PWR and BWR containments and BWR vent header, vent line bellows, and downcomers. The existing program relies on the requirements of ASME Code, Section XI, Subsection IWE and 10 CFR Part 50, Appendix J, to manage this aging effect; however, visual examination (VT-3) may not detect fine cracks. The GALL Report recommends further evaluation for detection of this aging effect. The applicant stated, in the LRA, that cyclic loading can lead to cracking of penetration sleeves, penetration bellows, and torus pool steel. If a CLB analysis does not exist, further evaluation is recommended of inspection methods to detect cracking due to cyclic loading since visual VT-3 examinations may be unable to detect this aging effect. The analysis of cracking due to cyclic loading of the drywell, torus, and associated penetrations is a TLAA which is evaluated as documented in LRA Section 4.6. 3-438

In the discussion column of LRA Table 3.5.1, Items 3.5.1-12 and 3.5.1-13, the applicant did not make reference to LRA Section 3.5.2.2.1.8 for further evaluation. During the audit and review, the applicant was asked to explain why this link was not made to the further evaluation section. Also the applicant was asked to explain the need for augmented ultrasonic exams to detect fine cracks since a CLB fatigue analysis does exist. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA is revised as follows: (1) For clarification, the discussion column of VYNPS Table 3.5.1, Line Items 3.5.1-12 and 3.5.1-13 is revised to add the following statement at the end of the existing information. See Section 3.5.2.2.1.8. (2) LRA Section 3.5.2.2.1.8 is revised to read as follows: Cyclic loading can lead to cracking of steel and stainless steel penetration bellows, and dissimilar metal welds of BWR containments and BWR suppression pool shell and downcomers. Cracking due to cyclic loading is not expected to occur in the drywell, torus and associated penetration bellows, penetration sleeves, unbraced downcomers, and dissimilar metal welds. A review of plant operating experience did not identify cracking of the components, and primary containment leakage has not been identified as a concern. Nonetheless the existing Containment Leak Rate Program with augmented ultrasonic exams and Containment Inservice Inspection-IWE, will continue to be used to detect cracking. Observed conditions that have the potential for impacting an intended function are evaluated or corrected in accordance with the corrective action process. The Containment Inservice Inspection-IWE and Containment Leak Rate programs are described in Appendix B. Based on the programs identified above, staff concludes that the applicants programs meet the SRP-LR Section 3.5.2.2.1.8 criteria. For those line items that apply to LRA Section 3.5.2.2.1.8, the staff finds 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). Loss of Material (Scaling, Cracking, and Spalling) Due to Freeze-Thaw. The staff reviewed LRA Section 3.5.2.2.1.9 against the criteria in SRP-LR Section 3.5.2.2.1.9. In LRA Section 3.5.2.2.1.9, the applicant stated that for the loss of material (scaling, cracking, and spalling) due to freeze-thaw, this aging effect is not applicable to VYNPS. 3-439

SRP-LR Section 3.5.2.2.1.9 states that loss of material (scaling, cracking, and spalling) due to freeze-thaw may occur in PWR and BWR concrete containments. The existing program relies on ASME Code, Section XI, Subsection IWL to manage this aging effect. The GALL Report recommends further evaluation of this aging effect for plants located in moderate to severe weather conditions. The applicant stated, in the LRA, that for the loss of material (scaling, cracking, and spalling) due to freeze-thaw, this aging effect is not applicable to VYNPS. VYNPS has a Mark I free standing steel containment located within the reactor building. Loss of material (scaling, cracking, and spalling) due to freeze-thaw is applicable only to concrete containments. Therefore, loss of material and cracking due to freeze-thaw do not apply. The staff finds that since VYNPS is a BWR with a Mark I containment, the aging effect loss of material (scaling, cracking, and spalling) due to freeze-thaw is not applicable to VYNPS. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.5.2.2.1.9 criteria. For those line items that apply to LRA Section 3.5.2.2.1.9, the staff finds 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). Cracking Due to Expansion and Reaction with Aggregate and Increase in Porosity and Permeability Due to Leaching of Calcium Hydroxide. The staff reviewed LRA Section 3.5.2.2.1.10 against the criteria in SRP-LR Section 3.5.2.2.1.10. In LRA Section 3.5.2.2.1.10, the applicant stated that for the cracking due to expansion and reaction with aggregate, and increase in porosity and permeability due to leaching of calcium hydroxide, this aging effect is not applicable to VYNPS. SRP-LR Section 3.5.2.2.1.10 states that cracking due to expansion and reaction with aggregate and increase in porosity and permeability due to leaching of calcium hydroxide may occur in concrete elements of PWR and BWR concrete and steel containments. The existing program relies on ASME Code, Section XI, Subsection IWL to manage these aging effects. The GALL Report recommends further evaluation if concrete was not constructed in accordance with ACI 201.2R-77 recommendations. The applicant stated, in the LRA, that for the cracking due to expansion and reaction with aggregate, and increase in porosity and permeability due to leaching of calcium hydroxide, this aging effect is not applicable to VYNPS. VYNPS has a Mark I free standing steel containment located within the reactor building. In accordance with the GALL Report, aging management is 3-440

not required because VYNPS containment concrete (basemat) is designed in accordance with specification ACI 318-63, which requires that the potential reactivity of aggregates be acceptable based on testing in accordance with ASTM C-289 and C-295. The staff finds that since VYNPS is a BWR with a Mark I containment, the aging effect cracking due to expansion and reaction with aggregate, and increase in porosity and permeability due to leaching of calcium hydroxide is not applicable to VYNPS. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.5.2.2.1.10 criteria. For those line items that apply to LRA Section 3.5.2.2.1.10, the staff finds 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). 3.5.2.2.2 Safety-Related and Other SC Supports The staff reviewed LRA Section 3.5.2.2.2 against SRP-LR Section 3.5.2.2.2 criteria, which address several areas: Aging of Structures Not Covered by Structures Monitoring Program. The staff reviewed LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1. In LRA Section 3.5.2.2.2.1, the applicant addresses the aging of structures not covered by the Structures Monitoring Program. SRP-LR Section 3.5.2.2.2.1 states that the GALL Report recommends further evaluation of certain structure-aging effect combinations not covered by structures monitoring programs, including: (1) cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel for Groups 1-5, 7, and 9 structures, (2) increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due to aggressive chemical attack for Groups 1-5, 7, and 9 structures, (3) loss of material due to corrosion for Groups 1-5, 7, and 8 structures, (4) loss of material (spalling, scaling) and cracking due to freeze-thaw for Groups 1-3, 5, and 7-9 structures, (5) cracking due to expansion and reaction with aggregates for Groups 1-5 and 7-9 structures, (6) cracks and distortion due to increased stress levels from settlement for Groups 1-3 and 5-9 structures, and (7) reduction in foundation strength, cracking, and differential settlement due to erosion of porous concrete subfoundation for Groups 1-3 and 5-9 structures. The GALL Report recommends further evaluation only for structure-aging effect combinations not within structures monitoring programs. In addition, lock-up due to wear may occur in Lubrite radial beam seats in BWR drywells, RPV support shoes for PWR with nozzle supports, steam generator supports, and other sliding support bearings and sliding support surfaces. The existing program relies on structures monitoring or ASME Code, Section XI, Subsection IWF, 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. 3-441

The staff finds that the applicant has included the eight SRP-LR Section 3.5.2.2.2.1 structure/aging effect combinations in its Structures Monitoring Program and no further evaluation is required as recommended by the GALL Report. However, although not required, the applicant has elected to provide further evaluation for each of the eight aging effects. The staff finds this additional evaluation acceptable. The staffs review of the eight aging effects follows. (1) Cracking, Loss of Bond, and Loss of Material (Spalling, Scaling) Due to Corrosion of Embedded Steel for Groups 1-5, 7, 9 Structures The staff reviewed item 1 in LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1. The applicant stated in the LRA this aging effect is not applicable to VYNPS. The aging mechanisms associated with cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel are applicable only to below-grade concrete/grout structures owing to the slightly acidic pH of groundwater. The below-grade environment for VYNPS is not aggressive and concrete is designed in accordance with specification ACI 318-63, Building Code Requirements for Reinforced Concrete, which results in low permeability and resistance to aggressive chemical solutions by providing a high cement, low water/cement ratio (between 0.44 and 0.60), proper curing and adequate air content between 3 percent and 5 percent. Therefore, cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel are not aging effects requiring management for VYNPS Groups 1-5, 7, 9 structures. The staff finds that the cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel for Groups 1-5, 7, 9 structures are not plausible aging effects at VYNPS due to the lack of aggressive groundwater and the concrete being designed in accordance with ACI 318-63 with a high cement, low water/cement ratio and adequate air content between 3 and 5 percent. Since corrosion of the embedded steel could become significant if exposed to an aggressive environment, components in these groups are included in the Structures Monitoring Program. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.1 for further evaluation. (2) Increase in Porosity and Permeability, Cracking, Loss of Material (Spalling, Scaling) Due to Aggressive Chemical Attack for Groups 1-5, 7, 9 Structures The staff reviewed item 2 in LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1. The applicant stated, in the LRA, that this aging effect is not applicable to VYNPS. Aggressive chemical attack becomes significant to concrete exposed to an aggressive environment. Resistance to mild acid attack is enhanced by using a dense concrete with low permeability and a low water-to-cement ratio of less than 0.50. These groups of structures at VYNPS use a dense, low permeable concrete with an average water-to-cement ratio of 0.48, which provides 3-442

an acceptable degree of protection against aggressive chemical attack. Water chemical analysis results confirm that the site groundwater is considered to be non-aggressive. VYNPS concrete is constructed in accordance with the recommendations in ACI 201.2R-77 for durability. VYNPS below-grade environment is not aggressive. Therefore, increase in porosity and permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack are AERMs requiring management for VYNPS Groups 1-5, 7, 9 concrete structures. The staff finds that the increase in porosity and permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack for Groups 1-5, 7, 9 structures are not plausible aging effects at VYNPS due to the lack of aggressive groundwater and the concrete being constructed in accordance with the recommendations in ACI 201.2R-77 for durability with a high cement, low water/cement ratio. Since aggressive chemical attack could become significant for concrete exposed to an aggressive environment, components in these groups are included in the Structures Monitoring Program. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.1 for further evaluation. (3) Loss of Material Due to Corrosion for Groups 1-5, 7, 8 Structures The staff reviewed item 3 in LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1. The applicant stated, in the LRA, that this aging effect is applicable to VYNPS. The Structures Monitoring Program will be used to manage this AERM for VYNPS Groups 1-5, 7, 8 structures. The staff finds that the loss of material due to corrosion for Groups 1-5, 7, 8 structures is an aging effect which will be managed by the applicants Structures Monitoring Program. The staff finds that, based on the program identified above, the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.1 for further evaluation. (4) Loss of Material (Spalling, Scaling) and Cracking Due to Freeze-Thaw for Groups 1-3, 5, 7-9 Structures The staff reviewed item 4 in LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1. The applicant stated, in the LRA, that this aging effect is not applicable to VYNPS. Aggregates were in accordance with specifications and materials conforming to ACI and ASTM standards. VYNPS structures are constructed of a dense, durable mixture of sound coarse aggregate, fine aggregate, cement, water, and admixture. Water/cement ratios are within the limits in accordance with ACI 318-63, and air entrainment percentages were within the range prescribed in the GALL Report. Therefore, loss of material (spalling, scaling) and cracking due to freeze thaw are not AERMs for VYNPS Groups 1-3, 5, 7-9 structures. 3-443

The staff finds that the loss of material (spalling, scaling) and cracking due to freeze-thaw for Groups 1-3, 5, 7-9 structures are not plausible aging effects at VYNPS due to concrete being constructed in accordance with ACI and ASTM standards with a high cement, low water/cement ratio. Since evaluation is needed for plants that are located in moderate to severe weathering conditions, components in these groups are included within the Structures Monitoring Program. In the discussion column of LRA Table 3.5.1, Item 3.5.1-26, the applicant stated that freeze-thaw is not an applicable aging mechanism for these groups of structures at VYNPS. During the audit and review, the staff asked the applicant to provide documentation showing the weathering conditions (weathering index) for VYNPS and the specification requiring concrete to have an air content of 3 percent to 6 percent and water to cement ratio of 0.35 to 0.45. During interviews with the applicants technical personnel, the applicants staff stated that VYNPS inaccessible and accessible concrete areas are designed in accordance with specification ACI 318-63. The applicant states that VYNPS concrete also meets recommendations of later guide ACI 201.2R-77, since both documents use the same ASTM standards for selection, application and testing of concrete. VYNPS concrete was provided with air content between 3 percent and 5 percent and a water/cement ration between 0.44 and 0.60, as documented in the Audit and Review Report. VYNPS is located in a severe weathering region (weathering index greater than100 day-inch/yr) as indicated in ASTM C33, FIG. 1. Although the water/cement ratio falls outside the listed range of 0.35 to 0.45, given all the parameters associated with a concrete mix design VYNPS concrete meets the quality requirements of ACI to ensure acceptable concrete is obtained. Nonetheless concrete be will managed in accordance with the AMP s identified in the LRA 3.5.2 -1 through 3.5.2-6. tables. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.1. (5) Cracking Due to Expansion and Reaction with Aggregates for Groups 1-5, 7-9 Structures The staff reviewed item 5 in LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1. The applicant stated, in the LRA, that this aging effect is not applicable to VYNPS. Aggregates were selected locally and were in accordance with specifications and materials conforming to ACI and ASTM standards at the time of construction, which are in accordance with the recommendations in ACI 201.2R-77 for concrete durability. VYNPS structures are constructed of a dense, durable mixture of sound coarse aggregate, fine aggregate, cement, water, and admixture. Water/cement ratios are within the limits specified in ACI 318-63, and air entrainment percentages were within the range prescribed in the GALL Report. Therefore, cracking due to expansion and reaction with aggregates for Groups 1-3, 5, 7-9 structures is not an AERM for VYNPS concrete. 3-444

The staff finds through discussions with the applicants technical personnel that cracking due to expansion and reaction with aggregates for Groups 1-5, 7-9 structures are not plausible aging effects at VYNPS due to concrete being constructed in accordance with ACI and ASTM standards with a high cement, low water/cement ratio. Since evaluation is needed for concrete not constructed in accordance with ACI 201.2R-77, components in this group are included within the Structures Monitoring Program. During the audit and review, the staffed asked the applicant to provide documentation showing that inaccessible areas concrete was constructed in accordance with the recommendations in ACI 201.2R-77. During interviews with the applicants technical personnel, the applicants staff stated that for construction of concrete, VYNPS site specification, as documented in the Audit and Review Report, identifies the same ASTM standards for achieving durable concrete as those specified in ACI 201.2R-77. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.1 for further evaluation. (6) Cracks and Distortion Due to Increased Stress Levels from Settlement for Groups 1-3, 5-9 Structures The staff reviewed item 6 in LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1. The applicant stated, in the LRA, that this aging effect is not applicable to VYNPS. Class 1 structures at VYNPS are founded on sound bedrock or supported by steel pilings which prevent significant settlement. Therefore, cracks and distortion due to increased stress levels from settlement are not aging effects requiring management for VYNPS Groups 1-3, 5-9 structures. The staff finds that the cracks and distortion due to increased stress levels from settlement for Groups 1-3, 5-9 structures not plausible aging effects due to the nonexistence of these aging mechanisms. The VYNPS Class 1 structures are founded on sound bedrock or supported by steel pilings which prevents significant settlement. The staff finds that these aging effects are not applicable to VYNPS Class 1 structures. Since evaluation to ensure proper functioning of a de-watering is needed if a de-watering system is relied upon to control settlement through the period of extended operation, components in this group are included within the Structures Monitoring Program. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. (7) Reduction in Foundation Strength, Cracking, Differential Settlement Due to Erosion of Porous Concrete Subfoundation for Groups 1-3, 5-9 Structures The staff reviewed item 7 in LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1. 3-445

The applicant stated, in the LRA, that this aging effect is not applicable to VYNPS. Structures at VYNPS are not constructed of porous concrete. Concrete was provided in accordance with ACI 318-63 requirements resulting in dense, well-cured, high-strength concrete with low-permeability. Therefore, reduction in foundation strength, cracking, differential settlement due to erosion of porous concrete subfoundation are not aging effects requiring management for VYNPS Groups 1-3, 5-9 structures. The staff finds through discussions with the applicants technical personnel that the reduction in foundation strength, cracking, differential settlement due to erosion of porous concrete subfoundation for Groups 1-3, 5-9 structures are not plausible aging effects due to the nonexistence of these aging mechanisms. Since there are no porous concrete subfoundations of concern below these structures, the staff finds that these aging effects are not applicable to VYNPS Groups 1-3 and 5-9 structures. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. (8) Lock Up Due to Wear for Lubrite Radial Beam Seats in BWR Drywell and Other Sliding Support Surfaces The staff reviewed item 8 in LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1. The applicant stated, in the LRA, that this aging effect is not applicable to VYNPS. Owing to the wear-resistant material used, the low frequency (number of times) of movement, and the slow movement between sliding surfaces, lock-up due to wear is not considered to be an AERM at VYNPS. The staff finds through discussions with the applicants technical personnel that the lock up due to wear for Lubrite radial beam seats in BWR drywell and other sliding support surfaces are not plausible aging effects at VYNPS due to the wear-resistant material used, the low frequency (number of times) of movement, and the slow movement between sliding surfaces. Since the absence of this aging effects needs to be confirmed, components in this group are included within the Structures Monitoring Program and Inservice Inspection (IWF) Program. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.1. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.5.2.2.2.1 criteria. For those line items that apply to LRA Section 3.5.2.2.2.1, the staff finds 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). 3-446

Aging Management of Inaccessible Areas. The staff reviewed LRA Section 3.5.2.2.2.2 against the following SRP-LR Section 3.5.2.2.2.2 criteria: (1) LRA Section 3.5.2.2.2.2 addresses the same accessible area discussion in SER Section 3.5.2.2.2.1 item 4 above for inaccessible areas. SRP-LR Section 3.5.2.2.2.2 states that loss of material (spalling, scaling) and cracking due to freeze-thaw may occur in below-grade inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures. The GALL Report recommends further evaluation of this aging effect for inaccessible areas of these groups of structures for plants located in moderate to severe weather conditions. The staffs evaluation remains the same as provided in SER Section 3.5.2.2.2.1 item 4 for inaccessible areas. (2) LRA Section 3.5.2.2.2.2 addresses the same accessible area discussion in SER Section 3.5.2.2.2.1 item 5 above for inaccessible areas. SRP-LR Section 3.5.2.2.2.2 states that cracking due to expansion and reaction with aggregates may occur in below-grade inaccessible concrete areas for Groups 1-5 and 7-9 structures. The GALL Report recommends further evaluation of inaccessible areas of these groups of structures if concrete was not constructed in accordance with ACI 201.2R-77 recommendations. The staffs evaluation remains the same as provided in SER Section 3.5.2.2.2.1 item 5 for inaccessible areas. (3) LRA Section 3.5.2.2.2.2 addresses the same accessible area discussion in SER Section 3.5.2.2.2.1 item 7 above for Groups 1-3, 5 and 7-9 inaccessible areas. SRP-LR Section 3.5.2.2.2.2 states that 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 may occur in below-grade inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures. The existing program relies on structures monitoring to manage these aging effects. Some plants may rely on de-watering systems to lower site ground water level. If the plants CLB credits a de-watering system, the GALL Report recommends verification of the systems continued functionality during the period of extended operation. The GALL Report recommends no further evaluation if this activity is included in the scope of the applicants structures monitoring program. The staffs evaluation remains the same as provided in SER Section 3.5.2.2.2.1 item 7 for inaccessible areas. 3-447

(4) LRA Section 3.5.2.2.2.2 addresses the aging management of inaccessible areas, these aging effects are not applicable to VYNPS. SRP-LR Section 3.5.2.2.2.2 states that 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 may occur in below-grade inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures. The GALL Report recommends further evaluation of plant-specific programs to manage these aging effects in inaccessible areas of these groups of structures in aggressive environments. The staffs evaluation of the above aging effect is provided below. (5) LRA Section 3.5.2.2.2.2 addresses the aging management of inaccessible areas, these aging effects are not applicable to VYNPS. SRP-LR Section 3.5.2.2.2.2 states that increases in porosity and permeability and loss of strength due to leaching of calcium hydroxide may occur in below-grade inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures. The GALL Report recommends further evaluation of this aging effect for inaccessible areas of these groups of structures for concrete not constructed in accordance with ACI 201.2R-77 recommendations. LRA Section 3.5.2.2.2.2 addresses both items 4 and 5 in SRP-LR Section 3.5.2.2.2.2. The applicant stated in the LRA, that VYNPS concrete for Group 1-3, 5 and 7-9 inaccessible concrete areas was provided in accordance with specification ACI 318-63, Building Code Requirements for Reinforced Concrete, which requires the following, resulting in low permeability and resistance to aggressive chemical solution.

• high cement content
• low water permeability
• proper curing
• adequate air entrainment The applicant also stated that VYNPS concrete also meets recommendations of later ACI guide ACI 201.2R-77, since both documents use the same ASTM standards for selection, application and testing of concrete. Inspections of accessible concrete have not revealed degradation related to corrosion of embedded steel. VYNPS below-grade environment is not aggressive (pH greater than 5.5, chlorides less than 500 ppm, and sulfates less than 1,500 ppm). Therefore, corrosion of embedded steel is not an AERM for VYNPS concrete.

The staff finds through discussions with the applicants technical personnel that the aging management of inaccessible areas due to aggressive chemical attack for Groups 1-5, 7 and 9 structures are not plausible aging effects at VYNPS due to the lack of aggressive groundwater and the concrete being constructed in accordance with the recommendations in ACI 201.2R-77 for durability with a high cement, low water/cement ratio. The applicant will perform opportunistic inspections of below-grade concrete in accordance with the Buried Piping Inspection Program and perform sampling monitoring of groundwater for aggressiveness in accordance with the Structures Monitoring Program. 3-448

Based on the programs identified above, the applicant has met the staff concludes that the applicants programs meet criteria of SRP-LR Section 3.5.2.2.2.2 criteria. For those line items that apply to LRA Section 3.5.2.2.2.2, the staff finds 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). Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature. The staff reviewed LRA Section 3.5.2.2.2.3 against the criteria in SRP-LR Section 3.5.2.2.2.3. In LRA Section 3.5.2.2.2.3, the applicant stated that for the reduction of strength and modulus of concrete structures due to elevated temperature, this aging effect is not applicable to VYNPS. SRP-LR Section 3.5.2.2.2.3 states that reduction of strength and modulus of concrete due to elevated temperatures may occur in PWR and BWR Groups 1-5 concrete structures. For concrete elements that exceed specified temperature limits, further evaluations are recommended. Appendix A to ACI 349-85 specifies the concrete temperature limits for normal operation or any other long-term period. Temperatures shall not exceed 150 EF except for local areas allowed to have temperatures not to exceed 200 EF. The GALL Report recommends further evaluation of a plant-specific program if any portion of the safety-related and other concrete structures exceeds specified temperature limits (i.e., general area temperature greater than 66 EC (150 EF) and local area temperature greater than 93 EC (200 EF)). The applicant stated, in the LRA, that for the reduction of strength and modulus of concrete structures due to elevated temperature, this aging effect is not applicable to VYNPS. Group 1-5 concrete elements do not exceed the temperature limits associated with aging degradation due to elevated temperature. Therefore, reduction of strength and modulus of concrete due to elevated temperatures is not an AERM for VYNPS. The applicant also stated, during the audit and review, that the aging effects due to elevated temperature are not expected at VYNPS for the concrete associated with Group 1-5 structures since general areas temperatures within the primary containment do not exceed 150EF and local area temperatures do not exceed 200EF. The staff agrees with the applicant that these aging effects are not applicable to the VYNPS Group 1-5 structures concrete. During the audit and review, the staff asked the applicant to provide the maximum temperatures that concrete experiences in Group 1 through 5 structures. The applicants staff stated that the VYNPS concrete is expected to experience average general area temperature of 150EF and local area maximum temperature less than 200EF. The drywell cooling system recirculates the drywell atmosphere through heat exchangers to maintain ambient temperature in the drywell between 135EF and 165EF (average 150EF). (Reference UFSAR Sections 5.2.3.2 and 10.12.3). The concrete around piping penetrations for high temperature lines, such as the steam lines and other reactor system lines is protected by piping insulation and air gaps. The staff finds that the reduction of strength and modulus of concrete structures due to elevated temperatures are not plausible aging effects due to the nonexistence of these aging mechanisms. A plant-specific AMP will be evaluated if temperature limits are exceeded. 3-449

The staff finds that the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.3. For those line items that apply to LRA Section 3.5.2.2.2.3, the staff finds 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). Aging Management of Inaccessible Areas for Group 6 Structures. The staff reviewed LRA Section 3.5.2.2.2.4 against the following SRP-LR Section 3.5.2.2.2.4 criteria: (1) In LRA Section 3.5.2.2.2.4, the applicant stated that for the increase in porosity and permeability, cracking, loss of material (spalling, scaling)/aggressive chemical attack; and cracking, loss of bond, and loss of material (spalling, scaling)/corrosion of embedded steel in below-grade inaccessible concrete areas of Group 6 structures, this aging effect is not applicable to VYNPS. SRP-LR Section 3.5.2.2.2.4 states that increase in porosity and permeability, cracking, loss of material (spalling, scaling)/aggressive chemical attack and cracking, loss of bond, and loss of material (spalling, scaling)/corrosion of embedded steel may occur in below-grade inaccessible concrete areas of Group 6 structures. The GALL Report recommends further evaluation of plant-specific programs to manage these aging effects in inaccessible areas in aggressive environments. The applicant stated, in the LRA, that for the increase in porosity and permeability, cracking, loss of material (spalling, scaling)/aggressive chemical attack; and cracking, loss of bond, and loss of material (spalling, scaling)/corrosion of embedded steel in below-grade inaccessible concrete areas of Group 6 structures, this aging effect is not applicable to VYNPS. Below-grade exterior reinforced concrete at VYNPS is not exposed to an aggressive environment (pH less than 5.5), or to chloride or sulfate solutions beyond defined limits (greater than 500 ppm chloride, or greater than 1500 ppm sulfate). Therefore, increase in porosity and permeability, cracking, loss of material (spalling, scaling)/aggressive chemical attack; and cracking, loss of bond, and loss of material (spalling, scaling)/corrosion of embedded steel are not aging effects requiring management for below-grade inaccessible concrete areas of VYNPS Group 6 structures. The staff finds that the increase in porosity and permeability, cracking, loss of material (spalling, scaling)/aggressive chemical attack; and cracking, loss of bond, and loss of material (spalling, scaling)/corrosion of embedded steel in below-grade inaccessible concrete areas of Group 6 structures are not plausible aging effects at VYNPS due to the lack of aggressive groundwater and the concrete being constructed in accordance with the recommendations in ACI 201.2R-77 for durability with a high cement, low water/cement ratio. The applicant will perform opportunistic inspections of below-grade concrete in accordance with the Buried Piping Inspection Program and perform sample monitoring of groundwater for aggressiveness in accordance with the Structures Monitoring Program. 3-450

During the audit and review, the staff noted that in the discussion column of LRA Table 3.5.1, Item 3.5.1-34, the applicant did not make reference to LRA Section 3.5.2.2.2.4, item 1 for further evaluation. The applicant was asked to explain why this link was not made to the further evaluation section. The applicants staff stated that SRP-LR, Item 3.5.1-34 indicates that further evaluation is necessary only for aggressive environments. No reference was provided to further evaluation in LRA Section 3.5.2.2.2.4, item 1 since the VYNPS environment is not aggressive as noted in LRA Table 3.5.1, item 3.5.1-34, in accordance with the discussion column. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.1, Line Item 3.5.1-34 discussion column is revised to add See Section 3.5.2.2.2.4 (1). The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.4 for further evaluation. (2) In LRA Section 3.5.2.2.2.4, the applicant stated that for the loss of material (spalling, scaling) and cracking due to freeze-thaw in below-grade inaccessible concrete areas of Group 6 structures, this aging effect is not applicable to VYNPS. SRP-LR Section 3.5.2.2.2.4 states that loss of material (spalling, scaling) and cracking due to freeze-thaw may occur in below-grade inaccessible concrete areas of Group 6 structures. The GALL Report recommends further evaluation of this aging effect for inaccessible areas for plants located in moderate to severe weather conditions. The applicant stated, in the LRA, that for the loss of material (spalling, scaling) and cracking due to freeze-thaw in below-grade inaccessible concrete areas of Group 6 structures, this aging effect is not applicable to VYNPS. Aggregates were selected locally and were in accordance with specifications and materials conforming to ACI and ASTM standards at the time of construction. VYNPS structures are constructed of a dense, durable mixture of sound coarse aggregate, fine aggregate, cement, water, and admixture. Water/cement ratios are within the limits provided in ACI 318-63, and air entrainment percentages were within the range prescribed in the GALL Report. Therefore, loss of material (spalling, scaling) and cracking due to freeze thaw are not aging effects requiring management for VYNPS Group 6 structures below-grade. The staff finds that the loss of material (spalling, scaling) and cracking due to freeze-thaw in below-grade inaccessible concrete areas of Group 6 structures are not plausible aging effects at VYNPS due to concrete being constructed in accordance with ACI and ASTM standards with a high cement, low water/cement ratio. Since evaluation is needed for plants that are located in moderate to severe weathering conditions, components in these groups are included within the Structures Monitoring Program. During the audit and review, the staff noted that in the discussion column of LRA Table 3.5.1, Item 3.5.1-35, the applicant did not make reference to LRA Section 3.5.2.2.2.4 item 2 for further evaluation. The applicant was asked to explain why this link was not made to the further evaluation section. Also, the applicant was asked to 3-451

provide a copy of ACI 301 as listed in accordance with the discussion column. The applicants staff stated that due to an administrative error, the reference to ACI should have been ACI 318-63 and not ACI 301. The applicant stated that the LRA Table 3.5.1, Item 3.5.1-35 discussion column will be revised to refer to ACI 318-63. For clarification, a reference to (LRA Section 3.5.2.2.2.4.2) will also be added to the discussion column. In a letter dated July 14, 2006, the applicant amended its LRA. The applicant stated that the LRA Table 3.5.1-35 discussion column is revised to replace ACI 301 with ACI 18-63 and add See Section 3.5.2.2.2.4 (2) at the end of the existing discussion column. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.4. (3) In LRA Section 3.5.2.2.2.4, the applicant stated that for cracking due to expansion and reaction with aggregates, increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide in below-grade inaccessible concrete areas of Group 6 structures, this aging effect is not applicable to VYNPS. SRP-LR Section 3.5.2.2.2.4 states that cracking due to expansion and reaction with aggregates and increased porosity and permeability and loss of strength due to leaching of calcium hydroxide may occur in below-grade inaccessible reinforced concrete areas of Group 6 structures. The GALL Report recommends further evaluation of inaccessible areas for concrete not constructed in accordance within ACI 201.2R-77 recommendations. The applicant stated, in the LRA, that for cracking due to expansion and reaction with aggregates, increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide in below-grade inaccessible concrete areas of Group 6 structures, this aging effect is not applicable to VYNPS. Aggregates were selected locally and were in accordance with specifications and materials conforming to ACI and ASTM standards at the time of construction, which are in accordance with the recommendations in ACI 201.2R-77 for concrete durability. VYNPS structures are constructed of a dense, durable mixture of sound coarse aggregate, fine aggregate, cement, water, and admixture. Water/cement ratios are within the limits provided in ACI 318-63, and air entrainment percentages were within the range prescribed in the GALL Report. VYNPS below-grade environment is not aggressive (pH greater than 5.5, chlorides less than 500 ppm, and sulfates less than 1,500 ppm). Therefore, cracking due to expansion and reaction with aggregates, increase in porosity and permeability due to leaching of calcium hydroxide in below grade inaccessible concrete areas of Group 6 structures is not an aging mechanism for VYNPS concrete. The staff finds that cracking due to expansion and reaction with aggregates, increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide in below-grade inaccessible concrete areas of Group 6 structures are not plausible aging effects at VYNPS due to concrete being constructed in accordance with ACI and ASTM 3-452

standards with a high cement, low water/cement ratio and the below grade environment non-aggressive. Since evaluation is needed for concrete not constructed in accordance with ACI 201.2R-77, components in this group are included within the Structures Monitoring Program. During the audit and review, the staff noted that in the discussion column of LRA Table 3.5.1, Item 3.5.1-36, the applicant did not make reference to LRA Section 3.5.2.2.2.4 item 3 for further evaluation. The applicant was asked to explain why this link is not made to the further evaluation section. Also, the statement: See Section 3.5.2.2.2.1.5 for additional discussion needs further clarification that this section is for Groups 1-5, 7-9, however it would apply to accessible Group 6 concrete. Further the applicant was asked to explain why LRA Section 3.5.2.2.2.4 item 3 lists cracking of concrete due to SCC. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA Table 3.5.1, Item 3.5.1-36, discussion column is revised to read as follows: Reaction with aggregates is not an applicable aging mechanism for VYNPS concrete components. See Section 3.5.2.2.2.1(5) (although for Groups 1-5, 7, 9 this discussion is also applicable for Group 6). See Section 3.5.2.2.2.4(3) additional discussion. Nonetheless, the Structures Monitoring Program will confirm the absence of aging effects requiring management for VYNPS Group 6 concrete components. Also, to correct an administrative error, the heading of LRA Section 3.5.2.2.2.4(3) is revised to begin with Cracking Due to Expansion and Reaction with Aggregates. The term stress corrosion cracking is deleted from the heading as it does not apply to this section. During the audit and review, the staff noted that in the discussion column of LRA Table 3.5.1, Item 3.5.1-37, the applicant stated not applicable and makes reference to Section 3.5.2.2.2.4 item 3. Section 3.5.2.2.2.4 item 3. This item discusses inaccessible areas only. The staff asked the applicant to explain why the discussion column for LRA Table 3.5.1, Item 3.5.1-37 did not state: Nonetheless, the Structures Monitoring Program will confirm the absence of aging effects requiring management for VYNPS Group 6 concrete components. This would apply to above grade concrete, like in LRA Table 3.5.1, Item 3.5.1-36 for accessible concrete. In a letter dated July 14, 2006, the applicant its amended the LRA. The applicant stated that the LRA Table 3.5.1, Item 3.5.1-37, discussion column is revised to state the following: Not applicable. Nonetheless the Structures Monitoring Program will confirm the absence of aging effects requiring management for VYNPS Group 6 concrete components. See Section 3.5.2.2.2.4(3). 3-453

Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.5.2.2.2.4.criteria. For those line items that apply to LRA Section 3.5.2.2.2.4, the staff finds 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). Cracking Due to Stress Corrosion Cracking and Loss of Material Due to Pitting and Crevice Corrosion. The staff reviewed LRA Section 3.5.2.2.2.5 against the criteria in SRP-LR Section 3.5.2.2.2.5. In LRA Section 3.5.2.2.2.5, the applicant stated that for the cracking due to SCC and loss of material due to pitting and crevice corrosion, this aging effect is not applicable to VYNPS. No tanks with stainless steel liners are included in the structural AMRs. Tanks subject to an AMR are evaluated with their respective mechanical systems. SRP-LR Section 3.5.2.2.2.5 states that cracking due to SCC and loss of material due to pitting and crevice corrosion may occur in Groups 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 finds that the cracking due to SCC and loss of material due to pitting and crevice corrosion are not aging effects requiring management at VYNPS since there are no tanks with stainless steel liners included in the structural AMRs. Tanks subject to an AMR are evaluated with their respective mechanical systems. On the basis that VYNPS does not have any components from this group, the staff finds that this aging effect is not applicable to VYNPS. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.5.2.2.2.5 criteria. For those line items that apply to LRA Section 3.5.2.2.2.5, the staff finds 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). Aging of Supports Not Covered by the Structures Monitoring Program. The staff reviewed LRA Section 3.5.2.2.2.6 against the criteria in SRP-LR Section 3.5.2.2.2.6. In LRA Section 3.5.2.2.2.6, the applicant addressed aging of supports not covered by the Structures Monitoring Program. SRP-LR Section 3.5.2.2.2.6 states that the GALL Report recommends further evaluation of certain component support-aging effect combinations not covered by structures monitoring programs, including: (1) loss of material due to general and pitting corrosion for Groups B2-B5 supports, (2) reduction in concrete anchor capacity due to degradation of the surrounding concrete for Groups B1-B5 supports, and (3) reduction/loss of isolation function due to 3-454

degradation of vibration isolation elements for Group B4 supports. Further evaluation is necessary only for structure-aging effect combinations not covered by the applicants structures monitoring program. The applicant stated, in the LRA, that the GALL Report recommends further evaluation of certain component support/aging effect combinations if they are not covered by the applicant's Structure Monitoring Program. Components supports at VYNPS are included in the Structures Monitoring Program for Groups B2 through B5 and Inservice Inspection (IWF) Program for Group B1. (1) Reduction in concrete anchor capacity due to degradation of the surrounding concrete for Groups B1 through B5 supports VYNPS concrete anchors and surrounding concrete are included in the Structures Monitoring Program (Groups B2 through B5) and Inservice Inspection (IWF) Program (Group B1). (2) Loss of material due to general and pitting corrosion, for Groups B2-B5 supports Loss of material due to corrosion of steel support components is an AERM at VYNPS. This aging effect is managed by the Structures Monitoring Program. (3) Reduction/loss of isolation function due to degradation of vibration isolation elements for Group B4 supports The VYNPS AMR did not identify any component support structure/aging effect combination corresponding to the GALL Report, Volume 2, Item III.B4-12. The staff finds that the applicant has included the above aging effect/mechanism combinations within the scope of its Structures Monitoring Program or Inservice Inspection (IWF) Program and agreed that no further evaluation is required. The staff finds that reduction/loss of isolation function due to degradation of vibration isolation elements for Group B4 supports is not an AERM at VYNPS since there are no vibration isolation components within the scope of license renewal. The staff reviewed the applicants Structures Monitoring Program and Inservice Inspection (IWF) Program and its evaluations are documented in SER Sections 3.0.3.2.17 and 3.0.3.3.3, respectively. The staff finds the applicants Structures Monitoring Program and Inservice Inspection (IWF) Program acceptable for managing the above aging effect/mechanism combinations of component supports for the GALL Report component support Groups B1 through B5, as those combinations are applicable. During the audit and review, the staff noted that in the discussion column of LRA Table 3.5.1, Item 3.5.1-40, the applicant stated: Plant experience has not identified reduction in concrete anchor capacity or other concrete aging mechanisms. Nonetheless, the Structures Monitoring Program will confirm absence of aging effects requiring management for VYNPS concrete components. 3-455

The staff was not able to find an AMR line item in Table 2 for this component (Building concrete at locations of expansion and grouted anchors; grout pads for support base plates). During the audit and review, the applicant was asked to provide the Table 2 number, LRA page number, and component for where this AMR line item is evaluated and shown. The applicant stated that building concrete at locations of expansion and grouted anchors; grout pads for support base plates are shown as foundation and Reactor vessel support pedestal in LRA Table 3.5.2-1 (page 3.5-54), foundation in LRA Tables 3.5.2-2 through 3.5.2-5 (pages 3.5-58, 3.5-60, 3.5-62, and 3.5-66), and as Equipment pads/foundations in LRA Table 3.5.2-6 (page 3.5-78). Further evaluation is provided in LRA Section 3.5.2.2.2.6.1 (page 3.5-14). In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that the LRA Table 3.5.1, Item 3.5.1-40 discussion column is revised to add See Section 3.5.2.2.2.6(1). During the audit and review, the staff noted that in the discussion column of LRA Table 3.5.1, Item 3.5.1-41, the applicant stated: No vibration isolation elements at VYNPS are in-scope and subject to an AMR. During the audit and review, the applicant was asked to explain the lack of vibration isolation elements for HVAC system components, the EDG and miscellaneous mechanical equipment. The applicants staff stated that LRA Table 3.5.1 relates only to structures and structural supports. Thus, the statement that no vibration isolation elements are in-scope and subject to an AMR applies only to structural vibration isolation elements. Vibration isolation elements for mechanical system components are subject to an AMR. For example, LRA Table 3.3.2-4 contains expansion joint in the EDG system and LRA Table 3.3.2-10 contains duct flexible connections and expansion joints in heating, ventilation, and air conditioning systems. The staff reviewed the applicant response and asked a followup question. The applicant was asked to verify that there are no non-metalic (rubber) vibration isolation elements used to structurally support the EDG, HVAC system equipment, and miscellaneous mechanical equipment and that all vibration isolation to systems attached to these components is by expansion joints and flexible connections. The applicants staff stated that as stated in LRA Table 3.5.1, Item 3.5.1-41, there are no non-metallic (rubber) vibration isolation elements used to structurally support the EDG, HVAC system equipment, and miscellaneous mechanical equipment that is within the scope of license renewal. Vibration isolation to systems attached to these components is by expansion joints and flexible connections. Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.5.2.2.2.6. criteria. For those line items that apply to LRA Section 3.5.2.2.2.6, the staff finds 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). 3-456

Cumulative Fatigue Damage Due to Cyclic Loading. LRA Section 3.5.2.2.2.7 states that fatigue of component support members, anchor bolts, and welds for Groups B1.1, B1.2, and B1.3 component supports is a TLAA, as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the staffs review of the applicants evaluation of this TLAA. The applicant stated, in LRA Section 3.5.2.2.2.7, that for component support members, anchor bolts, and welds for Groups B1.1, B1.2, and B1.3, this aging effect is not applicable to VYNPS. During the process of identifying TLAAs in the VYNPS CLB , no fatigue analyses were identified for these components. The staff finds that there are no CLB fatigue analyses for component support members, anchor bolts, and welds for Groups B1.1, B1.2, and B1.3 and therefore cumulative fatigue damage can not be evaluated as an aging effect for these components. On the basis that VYNPS does not have any components from this group with fatigue analyses, the staff finds that this aging effect is not applicable to VYNPS. 3.5.2.2.3 Quality Assurance for Aging Management of Nonsafety-Related Components SER Section 3.0.4 documents the staffs evaluation of the applicants QA program. Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for which the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff finds that the applicant adequately addressed the issues that were further evaluated. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.5.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Tables 3.5.2-1 through 3.5.2-6, 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 3.5.2-1 through 3.5.2-6, the applicant indicated, via notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided further information about how it will manage the aging effects. Specifically, note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line 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 line item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report. 3-457

Staff Evaluation. For component type, material, and environment combinations not evaluated in the GALL Report, the staff reviewed the applicants evaluation to determine whether 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. The staffs evaluation is documented in the following sections. 3.5.2.3.1 Primary Containment Summary of Aging Management Evaluation-LRA Table 3.5.2-1 The staff reviewed LRA Table 3.5.2-1, which summarizes the results of AMR evaluations for the primary containment component groups. The staff finds that all AMR evaluation results in LRA Table 3.5.2-1 are consistent with the GALL Report, or if not consistent, previously discussed in SER Sections 3.5.2.1 or 3.5.2.2, respectively. The staffs review of the applicants AMR evaluations identified areas in which additional information was necessary to complete the review. The staff identified ten RAIs (3.5-1 through 3.5-10), which were sent them to the applicant. During a teleconference, the applicant indicated that five of the (RAIs 3.5-1, 3.5-3, 3.5-4, 3.5-8, and 3.5-10) had been resolved with the NRC audit team and evidence of their resolutions was provided. The applicant responded to RAIs 3.5-2, 3.5-5, 3.5-6, 3.5-7, and 3.5-9 as discussed below. In RAI 3.5-2 dated September 28, 2006, the staff stated that LRA Table 3.5.2-1 does not list downcomers as a component; however, downcomers are listed in LRA Table 3.5.1 tem 3.5.1-13. The staff requested that the applicant explain why there is neither an AMP nor an AMR provided for downcomers in LRA Table 3.5.2-1. In its response dated October 31, 2006, the applicant stated that downcomers are included in LRA Table 3.5.2-1, line item for the Drywell to torus vent system, with the Containment Inservice Inspection Program and the Containment Leak Rate Program. Based on its review, the staff finds the applicants response to RAI 3.5-2 acceptable because the applicant provided proper AMPs for downcomers. The staffs concern described in RAI 3.5-2 is resolved. RAI 3.5-5 dated September 16, 2006, the staff stated that LRA Section B.1.15 for Inservice Inspection Program, states that "for containment inservice inspection, including applicable relief requests, general visual and detailed visual examinations are used in addition to visual testing examinations, in accordance with10 CFR 50.55a. The staff requested that the applicant describe the difference between the general visual, detailed visual, and visual testing examinations. The staff also requested that the applicant state the relief requests referenced in LRA Section B.1.15. 3-458

In its response dated October 31, 2006, the applicant stated the following: General visual examinations are performed either directly or remotely with sufficient illumination and resolution to assess the general condition of the accessible containment surfaces (inside and outside). Detailed visual examinations are VT-1 visual examinations. VT-1 visual examinations are conducted with sufficient illumination and access to the containment surface to detect discontinuities and imperfections including such conditions as cracks, wear, corrosion, erosion, or physical damage. As specified in 10 CFR 50.55a, dated September 26, 2002, VT-1 examinations will be conducted in lieu of "detailed visual" examinations of ASME Code Section XI, IWE-2310(c) for Examination Category E-C Item E4.11 (augmented examinations). VT-3 visual examinations are conducted to determine the general mechanical and structural condition of components and their supports, such as verification of clearances, settings, physical displacements, loosed or missing parts, debris, corrosion, wear, erosion, or the loss of integrity at bolted or welded connections. As specified in 10 CFR 50.55a, dated September 26, 2002, VT-3 inspections are conducted in lieu of the "general visual" examinations of ASME Code Section XI, IWE-2310 (b) for Examination Category E-A Items E1.12 (torus below water level) and E1.20 (vent system) and the bolting of Item E1.11 (drywell and torus above water level). Presently, no relief requests have been implemented for the VYNPS CII Program. Since ASME code relief requests have their own process under 10 CFR 50.55a, reference to relief requests in the LRA is unnecessary. References to relief requests are hereby deleted from LRA Section B.1.15. Based on its review, the staff finds the applicants response to RAI 3.5-5 acceptable because the applicant provided clarifications on the general visual, detailed visual, and visual testing examinations, and stated that relief requests were deleted from LRA Section B.1.15. The staffs concern described in RAI 3.5-5 is resolved. In RAI 3.5-6 dated September 28, 2006, the staff stated that the Inservice Inspection Program and the Containment Inservice Inspection Program both state that, "The program includes augmented ultrasonic exams to measure wall thickness of the containment structure." The staff requested that the applicant explain the difference between the augmented portion of the ultrasonic exams performed in these two programs mentioned and that of the ASME Code Section XI, Inservice Inspection Program. In its response dated October 31, 2006, the applicant stated: ASME Code, Section XI, IWE-1240 "Surface Areas Requiring Augmented Examination" establishes criteria for determining the need for augmented examinations. This sentence was included in the description of the Inservice 3-459

Inspection-Containment Inservice Inspection Program in LRA Sections A.2.1.16 and B.1.15.2 to indicate that the option for augmented examination exists if necessary. There is no difference between the augmented portion of the ultrasonic exams performed in the VYNPS Containment Inservice Inspection Program mentioned and that of the ASME Code, Section XI, Inservice Inspection Program. As of May 2006, no surface areas have been determined subject to the requirements of Paragraph IWE-1240. This determination was also provided in letter number BVY 06-043, dated May 15, 2006, from Entergy to USNRC, "Vermont Yankee Nuclear Power Station, License No. DPR-28, License Renewal Application. Based on its review, the staff finds the applicants response to RAI 3.5-6 acceptable because the applicant clarified that its augmented portion of the ultrasonic exams is identical to that of the ASME Code Section XI, Inservice Inspection Program. The staffs concern described in RAI 3.5-6 is resolved. In RAI 3.5-7 dated September 28, 2006, the staff stated that LRA Section 3.5.2.2.1.1 states that the below-grade environment is not aggressive. The staff requested that the applicant provide actual values of pH, chlorides, and sulfates in the groundwater/soil adjacent to structures in order to verify the claim of a nonaggressive below-grade environment. In its response dated December 4, 2006, the applicant revised its response to RAI 3.5-7 dated October 31, 2006. The applicant stated that the December 4, 2006, response supersedes the October 31, 2006 response. In the revised response, the applicant provided sample data from April 2002 through April 2006 in the tables below. Table 3.5-2 Groundwater and Soil Sample Data from April 2002 Through April 2006 April 2002 October 2002 April 2003 October 2003 Parameter Well 3301 Well 3401 Well 3301 Well 3401 Well 3301 Well 3401 Well 3301 Well 3401 pH 6.4 6.0 6.6 6.0 6.7 6.0 6.8 6.8 chloride (ppm) 237 54.30 237 57.30 225 70.30 260 111 April 2004 October 2004 April 2005 April 2005 Parameter Well 3301 Well 3401 Well 3301 Well 3401 Well 3301 Well 3401 Well 3301 Well 3401 pH 6.4 6.0 6.7 6.9 7.1 7.5 6.6 7.3 chloride (ppm) 399 118 410 78.1 325 92.2 388 103 April 2006 Parameter Well 3301 Well 3401 pH 6.2 6.6 chloride (ppm) 322 145 3-460

The applicant stated that the sulfate values are not available because the stations indirect discharge permit does not require measurement of sulfate levels. The applicant further stated that its commitment (Commitment #33) ensures that groundwater samples will continue to be evaluated on a periodic basis to assess the aggressiveness of groundwater on concrete. The applicant also revised Commitment #33 as follows: Included within the Structures Monitoring Program are provisions that will ensure an engineering evaluation is made on a periodic basis (at least once every five years) of groundwater samples to assess aggressiveness of groundwater to concrete. Samples will be evaluated for sulfate, pH and chloride levels. Finally, in its response, the applicant stated that the Vermont Agency of Natural Resources has attributed the difference in chloride levels between Well 3301 and Well 3401 to road salt influence given the close proximity of Well 3301 to a roadway within the plant boundaries. Based on its review, the staff finds the applicants response to RAI 3.5-7 acceptable because the measured chloride values at the site are less than 500 ppm, as specified in the GALL Report, and the pH values are greater than 5.5 as required in the GALL Report. The applicant also stated the reason for not having the sulfate value, and made commitment (Commitment #33) to measure the sulfate value in the future. With this commitment, the staffs concern described in RAI 3.5-7 is resolved. In RAI 3.5-9 dated September 28, 2006, the staff requested the applicant confirm whether the aggregates used for the concrete basemat supporting the steel containment have been tested for reactivity in accordance with ASTM C-289 and C-295. In its response dated October 31, 2006, the applicant stated that aggregates used for the concrete foundation that support the steel containment (drywell) have been tested for reactivity in accordance with ASTM C-289 and C-295. Based on its review, the staff finds the applicants response to RAI 3.5-9 acceptable because aggregates were tested for reactivity. The staffs concern described in RAI 3.5-9 is resolved. 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). 3.5.2.3.2 Reactor Building Summary of Aging Management Evaluation-LRA Table 3.5.2-2 The staff reviewed LRA Table 3.5.2-2, which summarizes the results of AMR evaluations for the reactor building component groups. In LRA Table 3.5.2-2, the applicant proposed to manage loss of material of stainless materials for component types of spent fuel pool storage racks exposed to a fluid environment using the Water Chemistry Control-BWR. 3-461

During the audit and review, the staff noted that in LRA Table 3.5.2-2, for component spent fuel pool storage racks, material stainless steel in an exposed to fluid environment; the aging effect is loss of material. The applicant was asked to explain by what aging mechanism loss of material occurs and why the aging effect is not cracking. The applicant stated that as shown in LRA Table 3.5.2-2, the aging effect for component spent fuel pool storage racks is loss of material. The specific aging mechanism is pitting and crevice corrosion because stainless steels are susceptible to this aging mechanism when exposed to oxygenated water in a treated water environment. Cracking is not an AERM for stainless steel in the spent fuel pool because cracking due to stress corrosion is dependent on temperature (greater than140EF). The spent fuel pool treated water environment is less than 140EF. The staff reviewed the applicants Water Chemistry Control-BWR Program and its evaluation is documented in SER Section 3.0.3.1.11. The objective of the program is to manage aging effects caused by corrosion and cracking mechanisms. The program relies on monitoring and control of water chemistry based on BWRVIP-130. EPRI guidelines in BWRVIP-130 include recommendations for controlling water chemistry in the spent fuel pool. The staff accepted the position that loss of material exhibited by the stainless steel spent fuel pool storage racks exposed to a fluid environment is properly managed by the Water Chemistry Control-BWR Program, which through the addition of chemicals will reduce the amount of dissolved oxygen in the spent fuel pool treated water and reduce pitting and crevice corrosion of stainless steel. On the basis of its review, the staff finds the aging effect of loss of material of stainless steel material exposed to a fluid environment is adequately managed using the Water Chemistry Control-BWR Program. On this basis, the staff finds that management of loss of material of stainless steel spent fuel pool storage racks in the reactor building acceptable. 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). 3.5.2.3.3 Intake Structure Summary of Aging Management Evaluation-LRA Table 3.5.2-3 The staff reviewed LRA Table 3.5.2-3, which summarizes the results of AMR evaluations for the intake structure component groups. The staff finds all AMR evaluation results in LRA Table 3.5.2-3 are consistent with the GALL Report, or if not consistent, previously discussed in SER Sections 3.5.2.1 or 3.5.2.2, respectively. 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). 3-462

3.5.2.3.4 Process Facilities Summary of Aging Management Evaluation-LRA Table 3.5.2-4 The staff reviewed LRA Table 3.5.2-4, which summarizes the results of AMR evaluations for the process facilities component groups. In LRA Table 3.5.2-4, the applicant proposed to manage loss of material, cracking and change in material properties of wood materials for component types cooling cell No. 2-1, cooling cell No. 2-2 and pipe supports exposed to a fluid or weather environment using the Structures Monitoring Program. The staff reviewed the applicants Structures Monitoring Program and its evaluation is documented in SER Section 3.0.3.2.17. The applicants Structures Monitoring Program is in accordance with 10 CFR 50.65 (Maintenance Rule) and based on RG 1.160 and NUMARC 93-01. These two documents provided the guidance for development of the Structures Monitoring Program to monitor the condition of structures and structural components within the scope of the Maintenance Rule, such that there is no loss of structure or structural component intended function. The staff finds that loss of material, cracking, and change in material properties exhibited by the wood for cooling cell no. 2-1, cooling cell No. 2-2 and pipe supports exposed to a fluid or weather environment are properly managed by the Structures Monitoring Program, which through an enhancement to program element Detection of Aging Effects will provide guidance for performing structural examinations of wood to identify loss of material, cracking, and change in material properties. On the basis of its review, the staff finds the aging effects of loss of material, cracking and change in material properties of wood material exposed to a fluid or weather environment are adequately managed using the Structures Monitoring Program. On this basis, the staff finds that management of loss of material, cracking and change in material properties of wood for cooling cell No. 2-1, cooling cell No. 2-2 and pipe supports in Process Facilities acceptable. In addition, in LRA Table 3.5.2-4, the applicant proposed to manage cracking and change in material properties of PVC materials for component types cooling tower fill exposed to a fluid environment using the Structures Monitoring Program. The staff reviewed the applicants Structures Monitoring Program and its evaluation is documented in SER Section 3.0.3.2.17. The Structures Monitoring Program is in accordance with 10 CFR 50.65 (Maintenance Rule) and based on RG 1.160 and NUMARC 93-01. These two documents provided the guidance for development of the Structures Monitoring Program to monitor the condition of structures and structural components within the scope of the Maintenance Rule, such that there is no loss of structure or structural component intended function. The staff finds that cracking and change in material properties exhibited by the PVC for cooling tower fill exposed to a fluid environment are properly managed by the Structures Monitoring Program, which through an enhancement to program element Detection of Aging Effects will provide guidance for performing structural examinations of PVC cooling tower fill to identify cracking and change in material properties. On the basis of its review, the staff finds the aging effect of cracking and change in material properties of PVC material exposed to a fluid environment are adequately managed using the Structures Monitoring Program. On this basis, the staff finds that management of cracking and change in material properties of PVC for cooling tower fill in process facilities acceptable. 3-463

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). 3.5.2.3.5 Yard Structures Summary of Aging Management Evaluation-LRA Table 3.5.2-5 The staff reviewed LRA Table 3.5.2-5, which summarizes the results of AMR evaluations for the yard structures component groups. The staff finds all AMR evaluation results in LRA Table 3.5.2-5 are consistent with the GALL Report, or if not consistent, previously discussed in SER Sections 3.5.2.1 or 3.5.2.2, respectively. 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). 3.5.2.3.6 Bulk Commodities Summary of Aging Management Evaluation - LRA Table 3.5.2-6 The staff reviewed LRA Table 3.5.2-6, which summarizes the results of AMR evaluations for the bulk commodities component groups. In LRA Table 3.5.2-6, the applicant proposed to manage cracking and delamination separation of cera blanket materials for component types of fire stops exposed to a protected from weather environment using Fire Protection. The staff reviewed the Fire Protection Program and its evaluation is documented in SER Section 3.0.3.2.11. The applicants Fire Protection Program includes fire barrier inspection and diesel-driven fire pump inspection. The fire barrier inspection requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests of fire rated doors to ensure that their operability is maintained. The diesel-driven fire pump inspection requires that the pump be periodically tested to ensure that the fuel supply line can perform its intended function. The staff finds that cracking and delamination separation exhibited by cera blanket materials for fire stops exposed to a protected from weather environment is properly managed by the Fire Protection Program, which in accordance with program element Detection of Aging Effects will perform examinations of cera blanket fire stops to identify cracking and delamination separation. On the basis of its review, the staff finds the aging effects of cracking and delamination separation of cera blanket material exposed to a protected from weather environment are effectively managed using the Fire Protection Program. On this basis, the staff finds that management of cracking and delamination separation of cera blanket fire stops in bulk commodities is acceptable. 3-464

In addition, in LRA Table 3.5.2-6, the applicant proposed to manage loss of material of cerafiber and cera blanket materials for component types of fire wrap exposed to a protected from weather environment using Fire Protection. The staff reviewed the applicants Fire Protection Program and its evaluation is documented in SER Section 3.0.3.2.11. The Fire Protection Program includes fire barrier inspection and diesel-driven fire pump inspection. The fire barrier inspection requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests of fire rated doors to ensure that their operability is maintained. The diesel-driven fire pump inspection requires that the pump be periodically tested to ensure that the fuel supply line can perform its intended function. The staff finds that loss of material exhibited by cerafiber and cera blanket materials for fire wraps exposed to a protected from weather environment is properly managed by the Fire Protection Program, which in accordance with program element Detection of Aging Effects will perform examinations of cerafiber and cera blanket fire wraps to identify loss of material. On the basis of its review, the staff finds the aging effects of loss of material of cerafiber and cera blanket material exposed to a protected from weather environment are effectively managed using the Fire Protection Program. On this basis, the staff finds that management of loss of material of cerafiber and cera blanket fire wraps in bulk commodities is acceptable. In LRA Table 3.5.2-6, the applicant proposed to manage cracking and change in material properties for component types seals and gaskets (doors, manways and hatches) of Class I structures other than Group 6 [Note: The actual components are the reactor building railroad inner and outer lock doors elastomer seals] exposed to a protected from weather environment using Periodic Surveillance and Preventive Maintenance. The staff reviewed the applicants Periodic Surveillance and Preventive Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.5. The applicants Periodic Surveillance and Preventive Maintenance Program is a plant-specific AMP which satisfies the criteria of SRP-LR Appendix A.1 that includes periodic inspections and tests that manage aging effects not managed by other AMPs. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. The staff finds that cracking and change in material properties of seals and gaskets (actual components are the reactor building railroad inner and outer lock doors elastomer seals) exposed to a protected from weather environment is properly managed by the Periodic Surveillance and Preventive Maintenance Program, which in accordance with program element Detection of Aging Effects will perform leakage tests on the reactor building railroad inner and outer doors to verify the absence of significant cracking and change in material properties for the rubber seals. Inspection and testing intervals are dependent on component material and environment and take into consideration industry and plant-specific operating experience and manufacturers recommendations. Each inspection or test occurs at least once every ten years. On this basis, the staff finds that management of cracking and change in material properties of seals and gaskets (doors, manways and hatches) of Class I structures other than Group 6 in bulk commodities is adequately managed using the Periodic Surveillance and Preventive Maintenance Program. 3-465

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). 3.5.2.3.7 Aging Effect/Mechanism in LRA Table 3.5.1 That are Not Applicable for VYNPS The staff reviewed LRA Table 3.5.1, which provides a summary of aging management evaluations for the structures and component supports evaluated in the GALL Report. In the LRA Table 3.5.1, Item 3.5.1-19, the applicant stated that cracking of steel elements: stainless steel suppression chamber shell (inner surface) due to SCC is not applicable at VYNPS. The VYNPS suppression chamber is carbon steel. On the basis that there is no stainless steel suppression chamber shell in the structures and component supports at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS. In LRA Table 3.5.1, Item 3.5.1-20, the applicant stated that loss of material of steel elements: suppression chamber liner (interior surface) due to general, pitting, and crevice corrosion is not applicable at VYNPS. The applicant further stated that the GALL Report referencing this item are associated with concrete containment. The VYNPS containment is a Mark I steel containment. The staff finds that LRA Table 3.5.1, Item 3.5.1-20 is applicable only to concrete containments. On the basis that there is no suppression chamber liner in the structures and component supports at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS. In LRA Table 3.5.1, Item 3.5.1-22, the applicant stated that the loss of material of prestressed containment: tendons and anchorage components due to corrosion is not applicable at VYNPS. The applicant further stated that the VYNPS containment is a Mark I steel containment without prestressed tendons. The staff finds that LRA Table 3.5.1, Item 3.5.1-22 is applicable only to concrete containments. On the basis that there are no tendons and anchorage components in the structures and component supports at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS. In LRA Table 3.5.1, Item 3.5.1-48, the applicant stated that the loss of material and loss of form of Group 6: earthen water control structures-dams, embankments, reservoirs, channels, canals, and ponds due to erosion, settlement, sedimentation, frost action, waves, currents, surface runoff, and seepage is not applicable at VYNPS. The applicant further stated that VYNPS does not have any earthen water control structures. 3-466

On the basis that there are no earthen water control structures-dams, embankments, reservoirs, channels, canals, and ponds in the structures and component supports at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS. In LRA Table 3.5.1, Item 3.5.1-51, the applicant stated that cracking and loss of material of Group B1.1: high strength low-alloy bolts due to stress corrosion and general corrosion is not applicable at VYNPS. SCC of high strength anchor bolts is not an AERM at VYNPS for two reasons: (1) high strength bolting at VYNPS is not exposed to a corrosive environment or high tensile stresses and (2) high strength structural bolts are installed with friction-type contact surfaces via the turn-of-the-nut method; therefore, for bolts greater than 1" in diameter, a significant preload (in the order of 70percent of ultimate strength) is not practical to develop. The Inservice Inspection (IWF) Program manages loss of material for high strength low-alloy bolts. The staff finds that cracking of high strength low-alloy bolts due to stress corrosion can occur for Group B1.1 components. In its letter, dated January 4, 2006, the applicant clarified its Bolting Integrity Program to address all bolts. The staff finds managing aging of bolts with the Bolting Integrity Program, in addition to the Inservice Inspection Program, acceptable because it is consistent with the GALL Report. In LRA Table 3.5.1, Item 3.5.1-52, the applicant addressed loss of mechanical function of Groups B2, and B4: sliding support bearing and sliding support surfaces due to corrosion, distortion, dirt, overload, fatigue due to vibratory and cyclic thermal loads. The applicant stated that loss of mechanical function due to the listed mechanisms is not an aging effect. Proper design prevents distortion, overload, and fatigue due to vibratory and cyclic thermal loads. During the audit and review, the staff asked the applicant to: Explain how loss of mechanical function due to corrosion is not an aging effect which needs to be managed for the period of extended operation.

• If proper design prevents distortion, overload, and fatigue due to vibratory and cyclic thermal loads, explain if there has never been a component failure at VYNPS due to any of these conditions.
• Explain if there has never been a component failure in the nuclear industry due to any of these conditions.
• Explain where sliding support bearing and sliding support surfaces are used in component groups B2 and B4 at VYNPS and provide the environment they are exposed to.

During interviews with the applicants technical personnel, the applicant stated that loss of material due to corrosion is an aging effect that can cause a loss of intended function. Loss of mechanical function would be considered a loss of intended function. Loss of mechanical function is not an aging effect, but is the result of aging effects. There have been component failures in the industry due to distortion, overload, and excessive vibration. Such failures typically result from inadequate design or events rather than the effects of aging. Failures due to cyclic thermal loads are very rare for structural supports due to their relatively low temperatures. 3-467

The applicant also stated that the sliding surface material used at VYNPS is lubrite, which is a corrosion resistant material. Components are inspected in accordance with ISI-IWF for torus saddle supports and Structures Monitoring Program for the lubrite components of radial beam seats. Plant operating experience has not identified failure of lubrite components used in structural applications. No current industry experience has identified failure associated with lubrite sliding surfaces. Components associated with B2 grouping are limited to the torus radial beam seats and support saddles. There are no sliding support surfaces associated with the B4 component grouping for sliding surfaces at VYNPS. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.1, Item 3.5.1-52 discussion column is revised to read as follows: Loss of mechanical function due to the listed mechanisms is not an aging effect. Such failures typically result from inadequate design or operating events rather than from the effects of aging. Failures due to cyclic thermal loads are rare for structural supports due to their relatively low temperatures. The staff finds that loss of mechanical function due to distortion, dirt, overload, fatigue due to vibratory, and cyclic thermal loads are not aging effects requiring management. Such failures do typically result from inadequate design or events rather than the effects of aging. On the basis that the mechanisms provided in LRA Table 3.5.1, Item 3.5.1-52, other than corrosion, are not aging mechanisms which cause aging effects for Group B2 and B4 components in the structures and component supports at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS. In LRA Table 3.5.1, Item 3.5.1-54, the applicant addressed loss of mechanical function of Groups B1.1, B1.2, and B1.3: constant and variable load spring hangers; guides and stops due to corrosion, distortion, dirt, overload, fatigue due to vibratory and cyclic thermal loads. The applicant stated that loss of mechanical function due to the listed mechanisms is not an aging effect. Proper design prevents distortion, overload, and fatigue due to vibratory and cyclic thermal loads. During the audit and review, the staff asked the applicant to:

• Explain how loss of mechanical function due to corrosion is not an aging effect which needs to be managed for the period of extended operation.
• If proper design prevents distortion, overload, and fatigue due to vibratory and cyclic thermal loads, explain if there has never been a component failure at VYNPS due to any of these conditions.

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• Explain if there has never been a component failure in the nuclear industry due to any of these conditions.
• Explain what VYNPS inspects for during VT-3 visual examinations of groups B1.1, B1.2 and B1.3 components in accordance with its Inservice Inspection Program during its current license and also anticipated VT-3 visual examinations during its possible extended license period.

During interviews with the applicants technical personnel, the applicant stated that the discussion for LRA Table 3.5.1, Item 3.5.1-54 was not saying that failures have not occurred, but that loss of mechanical function is not an aging effect. For license renewal, Entergy identifies a number of aging effects that can cause loss of intended function. Loss of intended function includes loss of mechanical function. The loss of function is not considered an aging effect. Aging effects that could cause loss of mechanical function for components in LRA Table 3.5.1, Item 3.5.1-54 are addressed elsewhere in the AMRs. For example, loss of material due to any mechanism is addressed in LRA Table 3.5.2-6 under listings for component and piping supports ASME Code Class 1, 2, 3 and MC (page 3.5-70), and component and piping supports (page 3.5-71). Component failures at VYNPS and in the nuclear industry have certainly occurred due to overload (typically caused by an event such as waterhammer) or vibratory and cyclic thermal loads. Because of the low operating temperatures, failures due to cyclic thermal loads are extremely rare for structural commodities. Failures due to distortion or vibratory loads have also occurred due to inadequate design, but rarely if ever, due to the normal effects of aging. In a letter dated July 14, 2006, the applicant revised its LRA. The applicant stated that LRA Table 3.5.1, Item 3.5.1-54 discussion is revised to read as follows: Loss of mechanical function due to distortion, dirt, overload, fatigue due to vibratory, and cyclic thermal loads are not aging effects requiring management. Such failures typically result from inadequate design or events rather than the effects of aging. Loss of material due to corrosion, which could cause loss of mechanical function, is addressed under LRA Table 3.5.1, Item 3.5.1-53 for Groups B1.1, B1.2, and B1.3 support members. The staff finds that loss of mechanical function due to distortion, dirt, overload, fatigue due to vibratory, and cyclic thermal loads are not aging effects requiring management. Such failures do typically result from inadequate design or events rather than the effects of aging. On the basis that the mechanisms provided in LRA Table 3.5.1, Item 3.5.1-54, other than corrosion, are not aging mechanisms which cause aging effects for group B1.1, B1.2, and B1.3 components in the structures and component supports at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS. In LRA Table 3.5.1, Item 3.5.1-57, the applicant addressed the reduction or loss of isolation function of Groups B1.1, B1.2, and B1.3: vibration isolation elements due to radiation hardening, temperature, humidity, and sustained vibratory loading. The applicant stated that no supports with vibration isolation elements have been identified in the scope of license renewal for VYNPS. 3-469

The staff finds that VYNPS does not have Group B1.1, B1.2, and B1.3 vibration isolation elements in the scope of license renewal. On the basis that there are no Group B1.1, B1.2, and B1.3 vibration isolation elements in the structures and component supports at VYNPS, the staff finds that, for this component type, this aging effect is not applicable to VYNPS. 3.5.2.3.8 Structures and Component Supports AMR Line Items That Have No Aging Effects (LRA Tables 3.5.2-1 through 3.5.2-6) In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified AMR line items where no aging effects were identified as a result of its aging review process. Specifically, instances in which the applicant stated that no aging effects were identified occurred when components fabricated from concrete material are exposed to a protected from weather, weather or fluid environment. In the LRA the applicant states that inaccessible and accessible concrete areas are designed in accordance with ACI 318-63, which results in low permeability and resistance to aggressive chemical solutions by requiring the following:

• high cement content
• low water-to-cement ratio
• proper curing
• adequate air entrainment The applicant also stated that VYNPS concrete also meets guidelines of later guide ACI 201.2R-77, since both ACI documents use the same ASTM standards for selection, application and testing of concrete. The below-grade environment is not aggressive (pH greater than 5.5, chlorides less than 500 ppm, and sulfates less than 1,500 ppm). Concrete was provided with air content between 3percent and 5percent and in general a water/cement ratio between 0.44 and 0.60. Therefore, increase in porosity and permeability due to leaching of calcium hydroxide, 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 are not applicable for concrete in accessible and inaccessible areas.

Aggregates used at VYNPS were in accordance with specifications and materials conforming to ACI and ASTM standards. VYNPS concrete structures are constructed of a dense, durable mixture of sound coarse aggregate, fine aggregate, cement, water, and admixture. Therefore, loss of material (spalling, scaling) and cracking due to freeze thaw; and cracking due to expansion and reaction with aggregates are not aging effects requiring management for VYNPS structures. ASME Code, Section III, Division 2, Subsection CC, indicates that aging due to elevated temperature exposure is not significant as long as concrete general area temperatures do not exceed 150EF and local area temperatures do not exceed 200EF. During normal operation, areas within the VYNPS primary containment and other structures are within these temperature limits. Therefore, reduction of strength and modulus of concrete structures due to elevated temperature is not an AERM for VYNPS concrete. The staff finds that the quality of the reinforced concrete used at VYNPS meets the codes and standards referenced in the GALL Report such that concrete is not susceptible to the aging effects listed above. The below-grade environment was finds not to be aggressive at VYNPS with continuing groundwater monitoring to occur during the period of extended license. 3-470

Therefore, no aging effects are considered to be applicable to components fabricated from concrete material protected from weather, exposed to weather or exposed to fluid environments. Since the absence of this concrete aging effects needs to be confirmed, concrete components and structures are included within the Structures Monitoring Program. On the basis of its review of current industry research and operating experience, the staff finds that protected from weather, weather or fluid on concrete will not result in aging that will be of concern during the period of extended operation. The staff finds that the applicants AMR evaluations that concrete protected from weather, exposed to weather or fluid environments will have no identified aging effects that actually occur, acceptable. Therefore, the staff finds that there are no applicable aging effects requiring management for concrete components exposed to protected from weather, exposed to weather or exposed to fluid environments. During the audit and review, the staff noted that in LRA Table 3.5.2-5 (page 3.5-67), for component Vernon Dam external walls, floor slabs and interior walls, material concrete in a protected from weather environment; the aging effect shown is none with the AMP shown as Vernon Dam FERC Inspection. VYNPS discusses throughout its LRA Section 3.5 further evaluations that VYNPS concrete does not have aging effects because the quality of the concrete used during construction was to the standards of ACI 18-63 and ACI 201.2R-77. Vernon Dam is a very old structure and was not built by the owners of VYNPS. The staff asked the applicant to provide documentation and justification that the quality of the concrete used at Vernon Dam is also to the standards of ACI 318-63 and ACI 2012.R-77, such that the AMR statement None for aging effects of the Dam concrete is justified. During interviews with the applicants technical personnel, the applicants staff stated since quality of concrete used at Vernon Dam has not been confirmed, it would have been more appropriate to show the associated aging effects for the line items in question. However, the same aging management activity, the FERC inspection, is still appropriate to manage aging effects associated with the Vernon Dam concrete components. The staff found that the acceptance of the Vernon Dam FERC Inspection Program along with associated LRA questions are issues that will require further evaluation. The staff issued RAI 3.6.2.2-N-08 to address this concern, which is evaluated in SER Section 3.0.3.3.6. In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified line items where no aging effects were identified as a result of its aging review process. In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified AMR line items where no aging effects were identified as a result of its aging review process. Specifically, instances in which the applicant states that no aging effects were identified occurred when components fabricated from lubrite plate material were in a protected from weather environment. The applicant also stated that Lubrite plates are used in the drywell beam seats and the torus support saddles at VYNPS. Lubrite materials for nuclear applications are designed to resist deformation, have a low coefficient of friction, resist softening at elevated temperatures, resist corrosion, withstand high intensities of radiation, and not score or mar; therefore, they are not susceptible to aging effects requiring management. Due to the wear-resistant material used, the low frequency (number of times) of movement, and the slow movement between sliding surfaces, lock-up and loss of mechanical function of lubrite plates from wear, corrosion, distortion, dirt, overload, fatigue due 3-471

to vibratory and cyclic thermal loads are not considered to be aging effects requiring management at VYNPS. Nonetheless, Lubrite plates are included within the Structures Monitoring Program and Inservice Inspection (IWF) Program. Industry operating experience and VYNPS ISI inspection reports for slide bearing plates have identified no recordable degradation due to any aging effects. Therefore, no aging effects are considered to be applicable to components fabricated from lubrite plate material exposed to a protected from weather environment. On the basis of its review of current industry research and operating experience, the staff finds that a protected from weather environment on lubrite plate will not result in aging that will be of concern during the period of extended operation. The staff finds that the applicants AMR evaluations that lubrite plate in a protected from weather environment will have no identified aging effects that actually occur, acceptable. Therefore, the staff concludes that there are no applicable aging effects requiring management for lubrite plate components exposed to a protected from weather environment. In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified AMR line items where no aging effects were identified as a result of its aging review process. Specifically, instances in which the applicant states that no aging effects were identified occurred when components fabricated from aluminum material were in a exposed to weather environment. In the LRA the applicant states that the ambient environment at VYNPS is not chemically polluted by vapors of SO2 or other similar substances and the external environment does not contain saltwater or high chlorides. In this non-aggressive environment, the occasional wetting and drying from normal outdoor weather does not result in any significant loss of material for aluminum components. Therefore, loss of material due to pitting and crevice corrosion is not an AERM for aluminum components exposed to a weather environment. Industry operating experience and previously approved staff positions documented in the Farley SER (NUREG-1825, page 3-314) support the conclusion that there are no aging effects for aluminum in a weather environment. Therefore, no aging effects are considered to be applicable to components fabricated from aluminum material exposed to a weather environment. On the basis of its review of current industry operating experience and approved staff positions, the staff finds that a weather environment on aluminum at VYNPS will not result in aging that will be of concern during the period of extended operation. The staff finds that the applicants AMR evaluations that aluminum in a weather environment will have no identified aging effects that actually occur, acceptable. Therefore, the staff finds that there are no applicable aging effects requiring management for aluminum components exposed to a weather environment. In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified AMR line items where no aging effects were identified as a result of its aging review process. Specifically, instances in which the applicant states that no aging effects were identified occurred when components fabricated from stainless steel material were in a exposed to weather environment. In the LRA the applicant stated that the ambient environment at VYNPS is not chemically polluted by vapors of SO2 or other similar substances and the external environment does not contain saltwater or high chlorides. In this non-aggressive environment, the occasional wetting and drying from normal outdoor weather does not result in any significant loss of material for 3-472

stainless steel components. Therefore, loss of material due to pitting and crevice corrosion is not an AERM for stainless steel components exposed to a weather environment. Industry operating experience and previously approved staff positions documented in the Farley SER (NUREG-1825, page 3-314) support the conclusion that there are no aging effects for stainless steel in a weather environment. Therefore, no aging effects are considered to be applicable to components fabricated from stainless steel material exposed to a weather environment. On the basis of its review of current industry operating experience and approved staff positions, the staff finds that a weather environment on stainless steel at VYNPS will not result in aging that will be of concern during the period of extended operation. The staff finds that the applicants AMR evaluations that stainless steel in a weather environment will have no identified aging effects that actually occur, acceptable. Therefore, the staff finds that there are no applicable aging effects requiring management for stainless steel components exposed to a weather environment. In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified AMR line items where no aging effects were identified as a result of its aging review process. Specifically, instances in which the applicant stated that no aging effects were identified occurred when components fabricated from carbon steel material were exposed to weather environment. During the audit and review the staff noted that in LRA Table 3.5.2-4 (page 3.5-61), for component steel piles, material carbon steel exposed to weather environment; the aging effect is none. Note 504 discusses steel piles driven into soils (a soil environment, not a weather environment) with no significant effects due to corrosion. The applicant was asked to explain how the soil environment relates to the weather environment to justify no aging effect. During interviews with the applicants technical personnel, the applicants staff stated that as identified in LRA Table 3.5.2-4 (page 3.5-61), for steel piles, material carbon steel exposed to weather environment; the aging effect is none. Although a soil environment is not identified, the listed environment, exposed to weather, is intended to include both an above grade environment and a below grade environment as described in LRA Table 3.0-2. The below grade environment applies to the steel piles. As such the statement made in Note 504 is applicable. In the LRA, the applicant states that carbon steel piles driven in undisturbed soils show no significant effects due to corrosion, regardless of the soil type or soil properties. Likewise, piles driven in disturbed soil above the water table zone do not reflect any significant corrosion. Therefore, aging management is not required of carbon steel exposed to a weather environment (non-aggressive soil environment). Industry operating experience supports the conclusion that there are no aging effects for carbon steel in a weather environment (non-aggressive soil environment). Therefore, no aging effects are considered to be applicable to components fabricated from carbon steel material exposed to a weather environment (non-aggressive soil environment). On the basis of current industry research and operating experience, the staff finds that a weather environment (non-aggressive soil environment) on carbon steel at VYNPS will not result in aging that will be of concern during the period of extended operation. The staff finds that the 3-473

applicants AMR evaluations that carbon steel in a weather environment (non-aggressive soil environment) will have no identified aging effects that actually occur, acceptable. Therefore, the staff finds that there are no applicable aging effects requiring management for carbon steel components exposed to a weather environment (non-aggressive soil environment). In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified AMR line items where no aging effects were identified as a result of its aging review process. Specifically, instances in which the applicant stated that no aging effects were identified occurred when components fabricated from pyrocrete material were in a protected from weather environment. During the audit and review, the staff noted that in LRA Table 3.5.2-6 (page 3.5-78), for component fire proofing, material Pyrocrete in a protected from weather environment; the aging effect is none. The applicant was asked to provide a technical basis why Pyrocrete does not have any aging effects in the environment listed. During interviews with the applicants technical personnel, the applicants staff stated that Pyrocrete (used for fire proofing) is cement base composite material. Pyrocrete is not identified in the GALL Report. As such, VYNPSs technical evaluation of pyrocrete in determining applicable aging effects was the same as that for concrete which is based on EPRI 1002950, Aging Effects for Structures And Structural Components (Structural Tools), Revision 1, Section 5. Accordingly, no aging effects were determined for pyrocrete protected from weather. However, as indicated in LRA Table 3.5.2-6 (page 3.5-78), the Fire Protection Program and Structures Monitoring Program will confirm the absence of significant aging effects throughout the period of extended operation. The staff finds pyrocrete to be a cementitious material that like concrete in a protected from weather environment will not experience aging effects. Industry operating experience supports the conclusion that there are no aging effects for pyrocrete in a protected from weather environment. Therefore, no aging effects are considered to be applicable to components fabricated from pyrocrete material exposed to a protected from weather environment. Nonetheless, pyrocrete is included within the Fire Protection Program and Structures Monitoring Program to ensure aging effects such as cracking or loss of material are not occurring. On the basis of current industry research and operating experience, the staff finds that a protected from weather environment on pyrocrete at VYNPS will not result in aging that will be of concern during the period of extended operation. The staff finds that the applicants AMR evaluations that pyrocrete in a protected from weather environment will have no identified aging effects that actually occur, acceptable. Therefore, the staff concludes that there are no applicable aging effects requiring management for pyrocrete components exposed to a protected from weather environment. In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified AMR line items where no aging effects were identified as a result of its aging review process. Specifically, instances in which the applicant stated that no aging effects were identified occurred when components fabricated from fiberglass, calcium silicate or Stratafab material were in a protected from weather environment. In the LRA, the applicant stated that loss of insulating characteristics due to insulation degradation is not an AERM for insulation material. Insulation products, which are made from fiberglass fiber, calcium silicate, stainless steel, and similar materials, that are protected from 3-474

weather do not experience aging effects that would significantly degrade their ability to insulate as designed. A review of site operating experience identified no aging effects for insulation used at VYNPS. No aging effects are considered to be applicable to components fabricated from fiberglass, calcium silicate or Stratafab material exposed to a protected from weather environment. On the basis of its review of current industry research and operating experience, the staff finds that a protected from weather environment on fiberglass, calcium silicate or Stratafab will not result in aging that will be of concern during the period of extended operation. Therefore, the staff concludes that there are no applicable aging effects requiring management for fiberglass, calcium silicate or Stratafab components exposed to protected from weather environments. In LRA Tables 3.5.2-1 through 3.5.2-6, the applicant identified AMR line items where no aging effects were identified as a result of its aging review process. Specifically, instances in which the applicant states that no aging effects were identified occurred when components fabricated from PVC material were exposed to a protected from weather environment. During the audit and review the staff noted that in LRA Table 3.5.2-6 (page 3.5-80), for component water stops, material PVC in a protected from weather environment; the aging effect is none. By definition the component stops water, so it could be exposed to water. In LRA Table 3.5.2-4 (page 3.5-64) for component cooling tower fill, material PVC, environment exposed to fluid environment, the aging effects listed are cracking and change in material properties. The applicant was asked to provide a technical basis why PVC water stops do not have any aging effects which need aging management when they could be exposed to a fluid environment also. The applicant was also asked to provide the specification that called for PVC water stops during construction instead of rubber. During interviews with the applicants technical personnel, the applicants staff stated that the PVC water stops identified in LRA Table 3.5.2-6 (page 3.5-80) are used in the cooling tower reinforced concrete basin and are not exposed to the same environment as the cooling tower fill material. Therefore, the aging effects are not the same. The aging effects attributed to PVC water stops are evaluated based upon EPRI 1002950, Section 7.0, Structural Tools. Exposure to water for these commodities is insignificant, since the concrete encapsulating the PVC water stop and the protection provided by the surrounding concrete, provides ample protection such that aging management is not required. UFSAR Figure 12.2-33 (G-200357) Cooling Tower No.2 Basin Plan View identifies the use of PVC water stops at VYNPS. On the basis that PVC water stops are almost totally encapsulated in concrete to protect them from a fluid environment and expose them only to a protected from weather environment, the staff finds that a protected from weather environment on PVC will not result in aging that will be of concern during the period of extended operation. Therefore, the staff concludes that there are no applicable aging effects requiring management for PVC components exposed to a protected from weather environment. 3-475

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). 3.5.3 Conclusion The staff concludes that the applicant has provided sufficient information to demonstrate that the effects of aging for the SC supports 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). 3.6 Aging Management of Electrical and Instrumentation and Controls System This section of the SER documents the staffs review of the applicants AMR results for the electrical and instrumentation and control (I&C) system components and component groups of:

• insulated cables and connections
• transmission conductors
• switchyard bus
• high-voltage insulators 3.6.1 Summary of Technical Information in the Application LRA Section 3.6 provides AMR results for the electrical and I&C system components and component groups. LRA Table 3.6.1, Summary of Aging Management Evaluations for the Electrical and I&C Components, is a summary comparison of the applicants AMRs with those evaluated in the GALL Report for the electrical and I&C system components and component groups.

The applicants 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 applicants 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 whether the applicant provided sufficient information to demonstrate that the effects of aging for the electrical and I&C system 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). The staff conducted an onsite audit of AMRs to ensure the applicants 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 3-476

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The staffs evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staffs audit evaluation are documented in SER Section 3.6.2.1. In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicants further evaluations were consistent with the SRP-LR Section 3.6.2.2 acceptance criteria. The staffs audit evaluations are documented in SER Section 3.6.2.2. The staff also conducted a technical review of the remaining AMRs that were not consistent with, or not addressed in, the GALL Report. The technical review evaluated whether all plausible aging effects have been identified and whether the aging effects listed were appropriate for the material-environment combinations specified. The staffs evaluations are documented in SER Section 3.6.2.3. For SSCs which the applicant claimed were not applicable or required no aging management, the staff reviewed the AMR line items and the plants operating experience to verify the applicants claims. Table 3.6-1 summarizes the staffs evaluation of components, aging effects/mechanisms, and AMPs listed in LRA Section 3.6 and addressed in the GALL Report. Table 3.6-1 Staff Evaluation for Electrical and I&C Components in the GALL Report Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Electrical equipment Degradation due to Environmental TLAA Consistent with subject to various aging Qualification of GALL Report, which 10 CFR 50.49 mechanisms Electric Environmental recommends further Environmental Components Qualification of evaluation (See Qualification Electric SER Requirements Components Section 3.6.2.2.1) (3.6.1-1) Program (B.1.10) Electrical cables, Reduced insulation Electrical Cables Non-Environmental Consistent with connections and resistance and and Connections Qualification GALL Report. (See fuse holders electrical failure due Not Subject to Insulated Cables SER (insulation) not to various physical, 10 CFR 50.49 and Connections Section 3.6.2.1) subject to thermal, radiolytic, Environmental Program (B.1.19) 10 CFR 50.49 photolytic, and Qualification Environmental chemical Requirements Qualification mechanisms Requirements (3.6.1-2) 3-477

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Conductor Reduced insulation Electrical Cables Non-Environmental Consistent with insulation for resistance and And Connections Qualification GALL Report. (See electrical cables and electrical failure due Used In Instrumentation SER connections used in to various physical, Instrumentation Circuits Test Review Section 3.6.2.1) instrumentation thermal, radiolytic, Circuits Not Subject Program (B.1.18) circuits not subject photolytic, and To 10 CFR 50.49 to 10 CFR 50.49 chemical Environmental Environmental mechanisms Qualification Qualification Requirements requirements that are sensitive to reduction in conductor insulation resistance (IR) (3.6.1-3) Conductor Localized damage Inaccessible Non-Environmental Consistent with insulation for and breakdown of Medium Voltage Qualification GALL Report. (See inaccessible insulation leading to Cables Not Subject Inaccessible SER medium voltage electrical failure due to 10 CFR 50.49 Medium-Voltage Section 3.6.2.1) (2 kV to 35 kV) to moisture Environmental Cable Program cables intrusion, water Qualification (B.1.17) (e.g., installed in trees Requirements conduit or direct buried) not subject to 10 CFR 50.49 Environmental Qualification Requirements (3.6.1-4) Connector contacts Corrosion of Boric Acid None Not applicable to for electrical connector contact Corrosion BWRs connectors exposed surfaces due to to borated water intrusion of borated leakage water (3.6.1-5) Fuse Holders Fatigue due to Fuse Holders None AMR results that are (Not Part of a Larger ohmic heating, not consistent with Assembly): Fuse thermal cycling, the GALL Report or holders - metallic electrical transients, not addressed in the clamp frequent GALL Report. (See (3.6.1-6) manipulation, SER vibration, chemical Section 3.6.2.3) contamination, corrosion, and oxidation Metal-Enclosed Loosening of bolted Metal-Enclosed Bus Metal-Enclosed Bus AMR results that are Bus - connections due to Program not consistent with Bus/connections thermal cycling and the GALL Report or (3.6.1-7) ohmic heating not addressed in the GALL Report. (See SER Section 3.6.2.3) 3-478

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Metal-Enclosed Embrittlement, Metal-Enclosed Bus Metal-Enclosed Bus AMR results that are Bus - cracking, melting, Program not consistent with Insulation/insulators discoloration, the GALL Report or (3.6.1-8) swelling, or loss not addressed in the dielectric strength GALL Report. (See leading to reduced SER insulation Section 3.6.2.3) resistance; electrical failure due to thermal/ thermoxidative degradation of organics/ thermoplastics, radiation-induced oxidation; moisture/debris intrusion, and ohmic heating Metal-Enclosed Loss of material due Structures Metal-Enclosed Bus AMR results that are Bus - Enclosure to general corrosion Monitoring Program Program not consistent with assemblies the GALL Report or (3.6.1-9) not addressed in the GALL Report. (See SER Section 3.6.2.3) Metal-Enclosed Hardening and loss Structures Metal-Enclosed Bus AMR results that are Bus - Enclosure of strength due to Monitoring Program Program not consistent with assemblies elastomers the GALL Report or (3.6.1-10) degradation not addressed in the GALL Report. (See SER Section 3.6.2.3) High-voltage Degradation of A plant-specific None Consistent with the insulators insulation quality AMP is to be GALL Report, which (3.6.1-11) due to presence of evaluated recommends further any salt deposits evaluation. and surface (See SER contamination; Loss Section 3.6.2.2.2) of material caused by mechanical wear due to wind blowing on transmission conductors 3-479

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation (GALL Report Mechanism Report Item No.) Transmission Loss of material due A plant-specific None Consistent with the conductors and to wind induced AMP is to be GALL Report, which connections; abrasion and evaluated recommends further switchyard bus and fatigue; loss of evaluation. connections conductor strength (See SER (3.6.1-12) due to corrosion; Section 3.6.2.2.3) increased resistance of connection due to oxidation or loss of preload Cable Connections - Loosening of bolted Electrical Cable None AMR results that are Metallic parts connections due to Connections Not not consistent with (3.6.1-13) thermal cycling, Subject To the GALL Report or ohmic heating, 10 CFR 50.49 not addressed in the electrical transients, Environmental GALL Report. (See vibration, chemical Qualification SER contamination, Requirements Section 3.6.2.3) corrosion, and oxidation Fuse Holders None None None AMR results not (Not Part of a Larger consistent with Assembly)]]