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{{#Wiki_filter:Safety Evaluation Report Related to the License Renewal of Vogtle Electric Generating Plant, Units 1 and 2 Docket Nos. 50-424 and 50-425
{{#Wiki_filter:}}
 
Southern Nuclear Operating Company, Inc.
 
United States Nuclear Regulatory Commission Office of Nuclear Reactor Regulation March 2009
 
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iii ABSTRACT This safety evaluation report (SER) documents the technical review of the Vogtle Electric
 
Generating Plant (VEGP), Units 1 and 2, license renewal application (LRA) by the United
 
States (US) Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated
 
June 29, 2007, Southern Nuclear Operating Company, Inc. (SNC 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." SNC
 
requests renewal of the Units 1 and 2 operating licenses (Facility Operating License
 
Numbers NPF-68 and NPF-81, respectively) fo r a period of 20 years beyond the current expiration date of January 16, 2027, for Unit 1, and February 9, 2029, for Unit 2.
 
VEGP is located approximately 26 miles southeast of Augusta, GA. The NRC issued the
 
construction permits for Unit 1 on June 28, 1974, and on June 28, 1974, for Unit 2. The
 
NRC issued the operating licenses for Unit 1 on March 16, 1987, and on March 31, 1989, for Unit 2. Units 1 and 2 are of a dry ambient containment pressurized water reactor design.
 
Westinghouse Electric supplied the nuclear steam supply system and Georgia Power
 
Company originally designed and constructed the balance of the plant with the assistance
 
of its agent, Southern Services and Bechtel. The licensed power output of each unit is
 
3625.6 megawatt thermal with a gross electrical output of approximately 1250 megawatt
 
electric.
 
This SER presents the status of the staff's review of information submitted through
 
February 16,  2009, the cutoff date for consideration in the SER. The staff identified no
 
open or confirmatory items that would require a formal response from the applicant. SER
 
Section 6 provides the staff's final conclusion of its LRA review.
 
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v TABLE OF CONTENTS ABSTRACT..............................................................................................................iii ABBREVIATIONS..................................................................................................xv 1  INTRODUCTION AND GENERAL DISCUSSION.............................................1-1 1.1  Introduction.................................................................................................1-1 1.2  Regulatory Evaluation.................................................................................1-2 1.2.1  Background..................................................................................1-2 1.2.2  Safety Review...............................................................................1-3 1.2.3  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.................................................1-7 2  STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW.....................................................................................2-1 2.1  Scoping and Screening Methodology.........................................................2-1 2.1.1  Introduction...................................................................................2-1 2.1.2  Summary of Technical Information in the Application..................2-1 2.1.3  Scoping and Screening Program Review.....................................2-2 2.1.3.1  Implementation Procedures and Documentation Sources Used for Scoping and Screening...............2-3 2.1.3.2  Quality Controls Applied to LRA Development........2-5 2.1.3.3  Training....................................................................2-6 2.1.3.4  Scoping and Screening Program Review  Conclusion...............................................................2-6 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)...................................................2-7 2.1.4.2  Application of the Scoping Criteria in  10 CFR 54.4(a)(2).................................................2-10 2.1.4.3 Application of the Scoping Criteria in  10 CFR 54.4(a)(3).................................................2-15 2.1.4.4 Plant-Level Scoping of Systems and Structures.....2-18 2.1.4.5 Mechanical Component Scoping............................2-20 2.1.4.6 Structural Scoping..................................................2-21
 
vi 2.1.4.7 Electrical Component Scoping................................2-22 2.1.4.8  Scoping Methodology Conclusion.........................2-23 2.1.5 Screening Methodology...............................................................2-24 2.1.5.1 General Screening Methodology............................2-24 2.1.5.2 Mechanical Component Screening.........................2-25 2.1.5.3 Structural Component Screening............................2-26 2.1.5.4 Electrical Component Screening............................2-28 2.1.5.5 Screening Methodology Conclusion.......................2-29 2.1.6 Summary of Evaluation Findings.................................................2-29 2.1.7 References..................................................................................2-29 2.2  Plant-Level Scoping Results.....................................................................2-30 2.2.1  Technical Information in the Application.....................................2-30 2.2.2  Staff Evaluation..........................................................................2-30 2.2.3  Conclusion..................................................................................2-31 2.3  Scoping and Screening Results: Mechanical Systems.............................2-32 2.3.1  Reactor Vessel, Reactor Vessel Internals, and  Reactor Coolant System............................................................2-33 2.3.1.1  Reactor Vessel......................................................2-34 2.3.1.2  Reactor Vessel Internals........................................2-35 2.3.1.3  Reactor Coolant System and Connected Lines.....2-36 2.3.1.4  Pressurizer.............................................................2-37 2.3.1.5  Steam Generators.................................................2-38 2.3.2  Engineered Safety Features.......................................................2-40 2.3.2.1  Containment Spray System...................................2-40 2.3.2.2  Emergency Core Cooling Systems........................2-41 2.3.2.3  Containment Isolation System...............................2-44 2.3.3  Auxiliary Systems.......................................................................2-44 2.3.3.1  Fuel Storage Racks - New and Spent Fuel...........2-47 2.3.3.2  Spent Fuel Cooling and Purification System.........2-48 2.3.3.3  Overhead Heavy and Refueling  Load Handling System..........................................2-50 2.3.3.4  Nuclear Service Cooling Water Systems (NSCW).................................................................2-51 2.3.3.5  Component Cooling Water System.......................2-54 2.3.3.6  Auxiliary Component Cooling Water System.........2-56 2.3.3.7  Turbine Plant Cooling Water System.....................2-57 2.3.3.8  River Intake Structure System...............................2-58 2.3.3.9  Compressed Air System........................................2-59 2.3.3.10  Chemical and Volume Control and    Boron Recycle Systems......................................2-60 2.3.3.11  Ventilation Systems - Control Building................2-63 2.3.3.12  Ventilation Systems - Auxiliary Building..............2-65 2.3.3.13  Ventilation Systems - Containment Building.......2-68 2.3.3.14  Ventilation Systems - Fuel Handling Building.....2-72 2.3.3.15  Ventilation Systems - Diesel Generator  Building................................................................2-75 2.3.3.16  Ventilation Systems - Auxiliary Feedwater    Pump House........................................................2-77 2.3.3.17  Ventilation Systems - Miscellaneous..................2-78
 
vii 2.3.3.18  Ventilation Systems - Radwaste Buildings  HVAC...................................................................2-82 2.3.3.19  Fire Protection System........................................2-84 2.3.3.20  Emergency Diesel Generator System..................2-98 2.3.3.21  Demineralized Water System............................2-104 2.3.3.22  Hydrogen Recombiner and Monitoring    System...............................................................2-106 2.3.3.23  Drain Systems...................................................2-107 2.3.3.24  Potable and Utility Water Systems....................2-110 2.3.3.25  Radiation Monitoring System (1609).................2-111 2.3.3.26  Reactor Makeup Water Storage System...........2-114 2.3.3.27  Sampling Systems.............................................2-116 2.3.3.28  Auxiliary Gas Systems.......................................2-119 2.3.3.29  Chilled Water Systems......................................2-121 2.3.3.30  Waste Management Systems............................2-124 2.3.3.31  Thermal Insulation.............................................2-130 2.3.3.32  Miscellaneous Leak Detection System..............2-132 2.3.4  Steam and Power Conversion Systems...................................2-133 2.3.4.1  Main Steam System.............................................2-133 2.3.4.2  Feedwater System...............................................2-135 2.3.4.3  Steam Generator Blowdown System...................2-137 2.3.4.4  Auxiliary Feedwater System................................2-138 2.3.4.5  Auxiliary Steam System.......................................2-140 2.3.4.6  Electrohydraulic Control System..........................2-142 2.4  Scoping and Screening Results - Structures..........................................2-143 2.4.1  Containment Structures............................................................2-144 2.4.1.1  Summary of Technical Information in  the Application.....................................................2-144 2.4.1.2  Staff Evaluation....................................................2-145 2.4.1.3  Conclusion...........................................................2-149 2.4.2  Auxiliary, Control, Fuel Handling, and Equipment Buildings....2-149 2.4.2.1  Summary of Technical Information in  the Application.....................................................2-149 2.4.2.2  Staff Evaluation....................................................2-151 2.4.2.3  Conclusion...........................................................2-151 2.4.3  Emergency Diesel Generator Structures..................................2-151 2.4.3.1  Summary of Technical Information in  the Application.....................................................2-151 2.4.3.2  Staff Evaluation....................................................2-152 2.4.3.3  Conclusion...........................................................2-152 2.4.4  Turbine Building.......................................................................2-152 2.4.4.1  Summary of Technical Information in  the Application.....................................................2-152 2.4.4.2  Staff Evaluation....................................................2-153 2.4.4.3  Conclusion...........................................................2-154 2.4.5  Tunnels and Duct Banks..........................................................2-154 2.4.5.1  Summary of Technical Information in  the Application.....................................................2-154 2.4.5.2  Staff Evaluation....................................................2-155 2.4.5.3  Conclusion...........................................................2-155
 
viii 2.4.6  Nuclear Service Cooling Water Structures...............................2-155 2.4.6.1  Summary of Technical Information in  the Application.....................................................2-155 2.4.6.2  Staff Evaluation....................................................2-156 2.4.6.3  Conclusion...........................................................2-156 2.4.7  Concrete Tank And  Valve House Structures...........................................................2-157 2.4.7.1  Summary of Technical Information  in the Application.................................................2-157 2.4.7.2  Staff Evaluation....................................................2-157 2.4.7.3  Conclusion...........................................................2-158 2.4.8  Switchyard Structures..............................................................2-158 2.4.8.1  Summary of Technical Information  in the Application.................................................2-158 2.4.8.2  Staff Evaluation....................................................2-158 2.4.8.3  Conclusion...........................................................2-159 2.4.9  Fire Protection Structures.........................................................2-159 2.4.9.1  Summary of Technical Information in  the Application.....................................................2-159 2.4.9.2  Staff Evaluation....................................................2-159 2.4.9.3  Conclusion...........................................................2-160 2.4.10  Radwaste Structures..............................................................2-160 2.4.10.1  Summary of Technical Information in  the Application.....................................................2-160 2.4.10.2  Staff Evaluation..................................................2-161 2.4.10.3  Conclusion.........................................................2-162 2.4.11  Auxiliary Feedwater Pumphouse Structures..........................2-162 2.4.11.1  Summary of Technical Information in  the Application.....................................................2-162 2.4.11.2  Staff Evaluation..................................................2-162 2.4.11.3  Conclusion.........................................................2-163 2.4.12  Component Supports and Bulk Commodities.........................2-163 2.4.12.1  Summary of Technical Information in  the Application.....................................................2-163 2.4.12.2  Staff Evaluation..................................................2-164 2.4.12.3  Conclusion.........................................................2-165 2.5  Scoping and Screening Results - Electrical and  Instrumentation and Controls Systems..................................................2-165 2.5.1  Summary of Technical Information in the Application..............2-166 2.5.2  Staff Evaluation........................................................................2-168 2.5.3  Conclusion................................................................................2-168 2.6  Conclusion for Scoping and Screening...................................................2-169 3  AGING MANAGEMENT REVIEW RESULTS...................................................3-1 3.0  Applicant's Use of the Generic Aging Lessons Learned Report.................3-1 3.0.1  Format of the License Renewal Application.................................3-2 3.0.1.1  Overview of Table 1s...............................................3-2 3.0.1.2  Overview of Table 2s...............................................3-3
 
ix 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......................................................3-6 3.0.3.1  AMPs Consistent with the GALL Report................3-11 3.0.3.2  AMPs Consistent with the GALL Report with Exceptions or Enhancements..................................................3-37 3.0.3.3  AMPs Not Consistent with or Not Addressed in  the GALL Report..................................................3-130 3.0.4  Quality Assurance Program Attributes Integral to Aging Management............................................................................3-222 3.0.4.1  Summary of Technical Information in Application...........................................................3-222 3.0.4.2  Staff Evaluation....................................................3-223 3.0.4.3  Conclusion...........................................................3-224 3.1  Aging Management of Reactor Vessel, Reactor Vessel Internals,  and Reactor Coolant System..................................................................3-224 3.1.1  Summary of Technical Information in the Application..............3-224 3.1.2  Staff Evaluation........................................................................3-224 3.1.2.1  AMR Results Consistent with the GALL Report..3-244 3.1.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended.......3-260 3.1.2.3  AMR Results Not Consistent with or  Not Addressed in the GALL Report.....................3-283 3.1.3  Conclusion................................................................................3-294 3.2  Aging Management of Engineered Safety Features System..................3-294 3.2.1  Summary of Technical Information in the Application..............3-295 3.2.2  Staff Evaluation........................................................................3-295 3.2.2.1  AMR Results Consistent with the GALL Report..3-305 3.2.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended..3-310 3.2.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report............................3-318 3.2.3  Conclusion................................................................................3-323 3.3  Aging Management of Auxiliary Systems................................................3-324 3.3.1  Summary of Technical Information in the Application..............3-324 3.3.2  Staff Evaluation........................................................................3-325 3.3.2.1  AMR Results Consistent with the GALL Report..3-342 3.3.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report............................3-387 3.3.3  Conclusion................................................................................3-442 3.4  Aging Management of Steam and Power Conversion Systems..............3-442 3.4.1  Summary of Technical Information in the Application..............3-442
 
x 3.4.2  Staff Evaluation........................................................................3-443 3.4.2.1  AMR Results Consistent with the GALL Report..3-450 3.4.2.2  AMR Results Consistent with the GALL Report  for Which Further Evaluation is Recommended..3-459 3.4.2.3  AMR Results Not Consistent with or  Not Addressed in the GALL Report.....................3-482 3.4.3  Conclusion................................................................................3-504 3.5  Aging Management of Containments, Structures, and  Component Supports..............................................................................3-504 3.5.1  Summary of Technical Information in the Application..............3-504 3.5.2  Staff Evaluation........................................................................3-505 3.5.2.1  AMR Results Consistent with the GALL Report..3-517 3.5.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended..3-519 3.5.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report............................3-540 3.5.3  Conclusion................................................................................3-546 3.6  Aging Management of Electrical and Instrumentation and  Controls System......................................................................................3-547 3.6.1  Summary of Technical Information in the Application..............3-547 3.6.2  Staff Evaluation........................................................................3-547 3.6.2.1  AMR Results Consistent with the GALL Report..3-551 3.6.2.2  AMR Results Consistent with the GALL Report  for Which Further Evaluation is Recommended..3-554 3.6.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report..............................................3-560 3.6.3  Conclusion................................................................................3-562 3.7  Conclusion for Aging Management Review Results...............................3-563 4  TIME-LIMITED AGING ANALYSES..................................................................4-1 4.1  Identification of Time-Limited Aging Analyses............................................4-1 4.1.1  Summary of Technical Information in the Application..................4-1 4.1.2  Staff Evaluation............................................................................4-2 4.1.3  Conclusion....................................................................................4-3 4.2  Reactor Vessel Neutron Embrittlement.......................................................4-3 4.2.1  Neutron Fluence...........................................................................4-4 4.2.1.1  Summary of Technical Information in the Application...............................................................4-4 4.2.1.2  Staff Evaluation........................................................4-4 4.2.1.3  UFSAR Supplement................................................4-6 4.2.1.4  Conclusion...............................................................4-6 4.2.2  Upper Shelf Energy Analysis........................................................4-6 4.2.2.1  Summary of Technical Information in the Application...............................................................4-6 4.2.2.2  Staff Evaluation........................................................4-7
 
xi 4.2.2.3  UFSAR Supplement................................................4-8 4.2.2.4  Conclusion...............................................................4-8 4.2.2  Pressurized Thermal Shock.........................................................4-8 4.2.3.1  Summary of Technical Information in the Application...............................................................4-8 4.2.3.2  Staff Evaluation........................................................4-9 4.2.3.3  UFSAR Supplement..............................................4-10 4.2.3.3  Conclusion.............................................................4-10 4.2.2  Adjusted Reference Temperature..............................................4-11 4.2.4.1  Summary of Technical Information in the Application.............................................................4-11 4.2.4.2  Staff Evaluation......................................................4-11 4.2.4.3  UFSAR Supplement..............................................4-12 4.2.4.4  Conclusion.............................................................4-12 4.2.2  Pressure Temperature Limits.....................................................4-12 4.2.5.1  Summary of Technical Information in the Application.............................................................4-12 4.2.5.2  Staff Evaluation......................................................4-13 4.2.5.3  UFSAR Supplement..............................................4-13 4.2.5.4  Conclusion.............................................................4-13 4.3  Metal Fatigue............................................................................................4-13 4.3.1  Fatigue of ASME Class 1 Components......................................4-14 4.3.1.1  Class 1 Piping and Component Design Transient Cycles....................................................4-14 4.3.1.2  CUF Monitoring - SG Main and Auxiliary Feedwater Nozzles................................................4-15 4.3.1.3  CUF Monitoring - Charging Nozzles.....................4-17 4.3.1.4  Thermal Stratification of the Surge Line and Lower Pressurizer Head........................................4-18 4.3.1.5  Effects of Reactor Coolant System Environment on Fatigue Life of Piping and Components..........................................................4-20 4.3.1.6  Full Structural Weld Overlays on Pressurizer Spray Nozzles, Safety and Relief Nozzles, and Surge Nozzles.......................................................4-23 4.3.1.7  High-Energy Line-Break Postulated Locations Based on Fatigue Cumulative Usage Factor.........4-25 4.3.2  Fatigue of ASME Non-Class 1 Components..............................4-27 4.3.2.1  Summary of Technical Information in the Application.............................................................4-27 4.3.2.2  Staff Evaluation......................................................4-28 4.3.2.3  UFSAR Supplement..............................................4-29 4.3.2.4  Conclusion.............................................................4-30 4.3.3  Fatigue of the Reactor Coolant Pump Flywheel.........................4-30 4.3.3.1  Summary of Technical Information in the Application.............................................................4-30 4.3.3.2  Staff Evaluation......................................................4-30 4.3.3.3  UFSAR Supplement..............................................4-30 4.3.3.4  Conclusion.............................................................4-30 4.3.4  Fatigue of Reactor Vessel Supports...........................................4-31
 
xii 4.3.4.1  Summary of Technical Information in the Application.............................................................4-31 4.3.4.2  Staff Evaluation......................................................4-31 4.3.4.3  UFSAR Supplement..............................................4-31 4.3.4.4  Conclusion.............................................................4-32 4.3.5  Fatigue of Steam Generator Secondary Manway and Handhole Bolts...........................................................................4-32 4.3.5.1  Summary of Technical Information in the Application.............................................................4-32 4.3.5.2  Staff Evaluation......................................................4-32 4.3.5.3  UFSAR Supplement..............................................4-33 4.3.5.4  Conclusion.............................................................4-33 4.3.6  Fatigue of Reactor Vessel Internals...........................................4-33 4.3.6.1  Summary of Technical Information in the Application.............................................................4-33 4.3.6.2  Staff Evaluation......................................................4-34 4.3.6.3  UFSAR Supplement..............................................4-34 4.3.6.4  Conclusion.............................................................4-34 4.4  Environmental Qualification of Equipment................................................4-34 4.4.1  Summary of Technical Information in the Application................4-35 4.4.2  Staff Evaluation..........................................................................4-35 4.4.3  UFSAR Supplement...................................................................4-36 4.4.4  Conclusion..................................................................................4-36 4.5  Concrete Containment Tendon Prestress.................................................4-36 4.5.1  Summary of Technical Information in the Application................4-36 4.5.2  Staff Evaluation..........................................................................4-37 4.5.3  UFSAR Supplement...................................................................4-38 4.5.4  Conclusion..................................................................................4-38 4.6  Penetration Load Cycles...........................................................................4-38 4.6.1  Summary of Technical Information in the Application................4-38 4.6.2  Staff Evaluation..........................................................................4-39 4.6.3  UFSAR Supplement...................................................................4-40 4.6.4  Conclusion..................................................................................4-40 4.7  Other Plant Specific Analysis....................................................................4-40 4.7.1  Leak-Before-Break Analysis.......................................................4-40 4.7.1.1  Summary of Technical Information in the Application.............................................................4-40 4.7.1.2  Staff Evaluation......................................................4-41 4.7.1.3  UFSAR Supplement..............................................4-43 4.7.1.4  Conclusion.............................................................4-43 4.7.2  Fuel Oil Storage Tank Corrosion Allowance..............................4-43 4.7.2.1  Summary of Technical Information in the Application.............................................................4-43 4.7.2.2  Staff Evaluation......................................................4-43 4.7.2.3  UFSAR Supplement..............................................4-47 4.7.2.4  Conclusion.............................................................4-48 4.7.3  Steam Generator Tube, Loss of Material...................................4-48
 
xiii 4.7.3.1  Summary of Technical Information in the Application.............................................................4-48 4.7.3.2  Staff Evaluation......................................................4-49 4.7.3.3  UFSAR Supplement..............................................4-50 4.7.3.4  Conclusion.............................................................4-50 4.7.4  Cold Overpressure Protection System.......................................4-50 4.7.4.1  Summary of Technical Information in the Application.............................................................4-50 4.7.4.2  Staff Evaluation......................................................4-51 4.7.4.3  UFSAR Supplement..............................................4-52 4.7.4.4  Conclusion.............................................................4-52 4.7.5  Underclad Cracking of the Reactor Pressure Vessel.................4-52 4.7.2.1  Summary of Technical Information in the Application.............................................................4-52 4.7.5.2  Staff Evaluation......................................................4-52 4.7.5.3  UFSAR Supplement..............................................4-54 4.7.5.4  Conclusion.............................................................4-55 4.8  Conclusion for TLAAs...............................................................................4-55 REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS.....5-1 CONCLUSION......................................................................................................6-1 VEGP UNITS 1 AND 2 LICENSE RENEWAL COMMITMENTS..........................A-1 CHRONOLOGY...................................................................................................B-1 PRINCIPAL CONTRIBUTORS.............................................................................C-1 REFERENCES.....................................................................................................D-1 Tables Table 1.4-1  Current Interim Staff Guidance.........................................................1-7 Table 3.0.3-1  VEGP 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.......................3-225 Table 3.2-1  Staff Evaluation for Engineered Safety Features System Components in the GALL Report......................................................................3-296 Table 3.3-1  Staff Evaluation fo r Auxiliary System Components  in the GALL Report...........................................................................................3-325 Table 3.4-1  Staff Evaluation for Steam and Power Conversion Systems Components in the GALL Report......................................................................3-443
 
xiv Table 3.5-1  Staff Evaluation for Containments, Structures, and  Component Supports in the GALL Report........................................................3-505 Table 3.6-1  Staff Evaluation for Electrical and Instrumentation and Controls in the GALL Report......................................................................3-548 Table 4.7.2-1:  Summary of the Corrosion Allowance Analysis for 
 
the Diesel Fuel Oil Storage Tanks and Associated Fuel Oil Delivery Piping.......................................................................................4-45
 
xv ABBREVIATIONS
 
AB  auxiliary building ACI  American Concrete Institute ACRS  Advisory Committee on Reactor Safeguards ADAMS Agencywide Document Access and Management System AERM  aging effect requiring management AFW  auxiliary feedwater AISC  American Institute of Steel Construction AMP  aging management program AMR  aging management review AMSAC ATWS mitigation system actuation circuitry ANSI  American National Standards Institute ART  adjusted reference temperature ASME  American Society of Mechanical Engineers ASTM  American Society for Testing and Materials ATWS  anticipated transient without scram AWWA  American Water Works Association
 
BAC  boric acid corrosion BWR  boiling water reactor B&PV  boiler and pressure vessel
 
CASS  cast austenitic stainless steel CCW  component cooling water CET  core exit thermocouple CF  chemistry factor
 
CFR  Code of Federal Regulations CI  confirmatory item CLB  current licensing basis COPS  cold overpressure protection system CRDM  control rod drive mechanism CR  condition report CRGT  control rod guide tube CS  containment spray CST  condensate storage tank CTMT  containment CTB  containment building CUF  cumulative usage factor CVCS  chemical and volume control system
 
DAW  dry active waste DBA  design basis accident DBE  design basis event DC  direct current DW  demineralized water
 
ECCS  emergency core cooling system EDG  emergency diesel generator EFPY  effective full-power year xvi EHC  electrohydraulic control EOL  end of life EPRI  Electric Power Research Institute EQ  environmental qualification ESF  engineered safety feature
 
FAC  flow-accelerated corrosion
 
F en  environmental fatigue life correction factor FP  fire protection FPP  fire protection plan FR  Federal Register FRRADS flood-retaining rooms, alarms, and drain system FW  feedwater
 
GALL  Generic Aging Lessons Learned Report GDC  general design criteria or general design criterion GEIS  Generic Environmental Impact Statement GL  generic letter GPC  Georgia Power Company GSI  generic safety issue
 
HAZ  heat-affected zone HELB  high-energy line break HE/ME  high energy/moderate energy HJTC  heated junction thermocouple HVAC  heating, ventilation, and air conditioning HX  heat exchanger
 
I&C  instrumentation and controls IASCC  irradiation assisted stress corrosion cracking IEEE  Institute of Electrical and Electronics Engineers IGA  intergranular attack IN  information notice INPO  Institute of Nuclear Power Operations IPA  integrated plant assessment ISG  interim staff guidance ISO  International Organization for Standardization ISI  inservice inspection
 
LBB  leak-before-break LOCA  loss of coolant accident LOSP  loss of offsite power LR  license renewal LRA  license renewal application
 
MPL  master parts list MSLB  main steam line break MWe  megawatts electric MWt  megawatts thermal
 
NDE  nondestructive examination xvii NEI  Nuclear Energy Institute NPS  nominal pipe size (in inches)
NRC  U.S. Nuclear Regulatory Commission NSCW  nuclear service cooling water NSR  nonsafety-related NSSS  nuclear steam supply system
 
OBE  operating basis earthquake ODSCC outside-diameter stress corrosion cracking OI  open item
 
P&ID  piping and instrumentation diagram PRF  penetration room filtration PSRF  nonsafety-related that can prevent a safety-related function PTLR  pressure-temperature limits report PTS  pressurized thermal shock PVC  polyvinyl chloride PW  pipe whip PWR  pressurized water reactor PWSCC primary water stress corrosion cracking
 
RAI  request for additional information RCP  reactor coolant pump RCPB  reactor coolant pressure boundary RCS  reactor coolant system RG  regulatory guide RHR  residual heat removal RI-ISI  risk-informed inservice inspection RMWST reactor makeup water storage tank RPV  reactor pressure vessel
 
RT NDT  reference temperature for nil ductility transition RT PTS  reference temperature for pressurized thermal shock RTS  reactor trip system RVCH  reactor vessel closure head RVLIS  reactor vessel level indicating system RWST  refueling water storage tank RV  reactor vessel
 
SBO  station blackout SCs  structures and components SCC  stress-corrosion cracking SER  safety evaluation report SFP  spent fuel pool SG  steam generator SGBD  steam generator blowdown SI  safety injection SMP  structural monitoring program SNC  Southern Nuclear Operating Company, Inc.
SOC  statement of consideration SR  safety-related SRP  Standard Review Plan xviii SRP-LR Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants SSCs  systems, structures, and components SSE  safe-shutdown earthquake SW  service water
 
TLAA  time-limited aging analysis TS  technical specifications TSP  trisodium phosphate
 
UFSAR updated final safety analysis report USE  upper-shelf energy UT  ultrasonic testing UV  ultraviolet
 
VEGP  Vogtle Electric Generating Plant
 
WCAP  Westinghouse Commercial Atomic Power WOG  Westinghouse Owner's Group 1-1 SECTION 1 INTRODUCTION AND GENERAL DISCUSSION
 
===1.1 Introduction===
This document is a safety evaluation report (SER) on the license renewal application (LRA)
 
for Vogtle Electric Generating Plant (VEGP), Units 1 and 2, as filed by the Southern
 
Nuclear Operating Company, Inc. (SNC or the applicant). By letter dated June 29, 2007, SNC submitted its application to the U.S. Nuclear Regulatory Commission (NRC) for
 
renewal of the VEGP operating licenses for an additional 20 years. The NRC staff (the
 
staff) prepared this report to summarize the results of its safety review of the LRA for
 
compliance with Title 10, Part 54, "Requirements for Renewal of Operating Licenses for
 
Nuclear Power Plants," of the Code of Federal Regulations (10 CFR Part 54). The NRC project manager for the license renewal review is Donnie Ashley. Mr. Ashley may be
 
contacted by telephone at 301-415-3191 or by el ectronic mail at Donnie.Ashley@nrc.gov.
Alternatively, written correspondence may be sent to the following address:
 
Division of License Renewal
 
U.S. Nuclear Regulatory Commission
 
Washington, DC 20555-0001
 
Attention: Donnie Ashley, Mail Stop 011-F1
 
In its June 27, 2007, submission letter, the applicant requested renewal of the operating
 
licenses issued under Section 103 (Operating License Nos. NPF-68 and NPF-81) of the
 
Atomic Energy Act of 1954, as amended, for Units 1 and 2 for a period of 20 years beyond the current expiration date of January 16, 2027, for Unit 1, and February 9, 2029, for Unit 2.
 
Although the Unit 2 license only has 18 years experience, the applicant requested and was
 
granted an exemption on January 9, 2007, (ML062770492) to that requirement prior to the
 
submittal of the application for both units. VEGP is located approximately 26 miles
 
southeast of Augusta, Georgia. The NRC issued the construction permits for Unit 1 on
 
June 28, 1974, and on June 28, 1974, for Unit 2. The NRC issued the operating licenses for
 
Unit 1 on March 16, 1987, and on March 31, 1989, for Unit 2. Units 1 and 2 are a dry
 
ambient containment pressurized water reactor design. Westinghouse Electric supplied the
 
nuclear steam supply system and Georgi a Power Company originally designed and constructed the balance of the plant with the assistance of its agent, Southern Services and
 
Bechtel. The licensed power output of each unit is 3565 megawatt thermal with a gross
 
electrical output of approximately 1208 megawatt electric. The updated final safety analysis
 
report (UFSAR) shows 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 VEGP license renewal is based on the applicant's LRA and on its
 
responses to the staff's requests for additional information (RAIs). The applicant
 
supplemented the LRA and provided clarifications through its responses to the staff's RAIs
 
in audits, meetings, and docketed correspondence. Unless otherwise noted, the staff
 
reviewed and considered information submitted through February 16, 2009. The public may 1-2 view the LRA and all pertinent information and materials, including the UFSAR, at the NRC Public Document Room, located on the first floor of One White Flint North, 11555 Rockville
 
Pike, Rockville, MD 20852-2738 (301-415-4737 / 800-397-4209), and at the Burk County
 
Library, 130 Highway 24 South, Waynesboro, Georgia 30830. 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 staff's 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 licenses. The
 
staff reviewed the LRA in accordance with NRC regulations and the guidance in NUREG-
 
1800, Revision 1, "Standard Review Plan for Review of License Renewal Applications for
 
Nuclear Power Plants" (SRP-LR), dated September 2005.
 
SER Sections 2 through 4 address the staff's evaluation of license renewal issues
 
considered during the review of the application. SER Section 5 is reserved for the report of
 
the Advisory Committee on Reactor Safeguards (ACRS). The conclusions of this SER are
 
in Section 6.
 
SER Appendix A is a table showing the applicant's commitments for renewal of the
 
operating licenses. SER Appendix B is a chronology of the principal correspondence
 
between the staff and the applicant regarding the LRA review. SER Appendix C is a list of
 
principal contributors to the SER and Appendix D is a bibliography of the references in
 
support of the staff's review.
 
In accordance with 10 CFR Part 51, the staff prepared a draft plant-specific supplement to
 
NUREG-1437, "Generic Environmental Impact Statement for License Renewal of Nuclear
 
Plants (GEIS)." This supplement discusses the environmental considerations for license
 
renewals for Units 1 and 2. The staff issued draft, plant-specific GEIS Supplement 34, "Generic Environmental Impact Statement for License Renewal of Nuclear Plants, Supplement 34, Regarding Vogtle Electric Generating Plant, Units 1 and 2, Draft Report for
 
Comment," on April 22, 2008. 
 
1.2  Regulatory Evaluation
 
====1.2.1 Background====
Pursuant to the Atomic Energy Act of 1954, as amended, and NRC regulations, operating
 
licenses for commercial power reactors are issued for 40 years and can be renewed for up
 
to 20 additional years. The original 40-year license term was selected based on economic
 
and antitrust considerations rather than on technical limitations; however, some individual
 
plant and equipment designs may have been engineered for an expected 40-year service
 
life.
 
In 1982, the staff anticipated interest in license renewal and held a workshop on nuclear
 
power plant aging. This workshop led the NRC to establish a comprehensive program plan
 
for nuclear plant aging research. From the results of that research, a technical review group
 
concluded that many aging phenomena are readily manageable and pose no technical issues precluding life extension for nuclear power plants. In 1986, the staff published a
 
request for comment on a policy statement that would address major policy, technical, and
 
procedural issues related to license renewal for nuclear power plants.
1-3 In 1991, the staff published 10 CFR Part 54, the License Renewal Rule (Volume 56, page 64943, of the Federal Register (56 FR 64943), dated December 13, 1991). The staff participated in an industry-sponsored demonstration program to apply 10 CFR Part 54 to a
 
pilot plant and to gain the experience nece ssary 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 finds that adverse aging effect s on plant systems and components are managed during the period of initial license and that the scope of the review did not allow sufficient
 
credit for management programs, particularly the implementation of 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,"
 
which regulates management of plant-aging phenomena. As a result of this finding, the
 
Commission amended 10 CFR Part 54 in 1995. As published May 8, 1995, in 60 FR 22461, amended 10 CFR Part 54 establishes a regulatory process that is simpler, more stable, and
 
more predictable than the previous 10 CFR Part 54. In particular, as amended, 10 CFR Part 54 focuses on the management of adverse aging effects rather than on the
 
identification of age-related degradation unique to license renewal. The rule changes were
 
initiated to ensure that important systems, structures, and components (SSCs) will continue to perform their intended functions during the period of extended operation. In addition, the
 
amended 10 CFR Part 54 clarifies and simplifies the integrated plant assessment process
 
to be consistent with the revised focus on passive, long-lived structures and components (SCs).
 
Concurrent with these initiatives, the NRC pursued a separate rulemaking effort
 
(61 FR 28467, June 5, 1996) and amended 10 CFR Part 51 to focus the scope of the
 
review of environmental impacts of license renewal in order to fulfill NRC responsibilities
 
under the National Environmental Policy Act of 1969.
 
1.2.2  Safety Review License renewal requirements for power reactors are based on two key principles:
 
(1) The regulatory process is adequate to ensure that the licensing bases of all currently operating plants maintain an acceptable level of safety with the possible
 
exceptions of the detrimental aging effects on the functions of certain SSCs, as well
 
as a few other safety-related issues, during the period of extended operation. (2) The plant-specific licensing basis must be maintained during the renewal term in the same manner and to the same extent as during the original licensing term.
 
In implementing these two principles, 10 CFR 54.4, "Scope," defines the scope of license
 
renewal as including those SSCs that (1) are safety-related, (2) whose failure could affect
 
safety-related functions, or (3) are relied on to demonstrate compliance with the NRC's
 
regulations for fire protection, environmental qualification (EQ), pressurized thermal shock (PTS), anticipated transient without scram (ATWS), and station blackout (SBO).
 
Pursuant to 10 CFR 54.21(a), a license renewal applicant must review all SSCs within the
 
scope of 10 CFR Part 54 to identify SCs subject to an aging management review (AMR).
 
Those SCs subject to an AMR perform an intended function without moving parts or without
 
change in configuration or properties and are not subject to replacement based on a
 
qualified life or specified time period. Pursuant to 10 CFR 54.21(a), a license renewal
 
applicant must demonstrate that the aging effects will be managed such that the intended 1-4 function(s) of those SCs will be maintained consistent with the current licensing basis (CLB) for the period of extended operation. However, active equipment is considered to be
 
adequately monitored and maintained by existing programs. In other words, detrimental
 
aging effects that may affect active equipment can be readily identified and corrected
 
through routine surveillance, performance monitoring, and maintenance. Surveillance and
 
maintenance programs for active equipment, as well as other maintenance aspects of plant
 
design and licensing basis, are required throughout the period of extended operation.
 
Pursuant to 10 CFR 54.21(d), the LRA is required to include a UFSAR supplement with a
 
summary description of the applicant's programs and activities for managing aging effects
 
and an evaluation of time-limited aging analyses (TLAAs) for the period of extended
 
operation.
 
License renewal also requires TLAA identification and updating. During the plant design
 
phase, certain assumptions about the length of time the plant can operate are incorporated
 
into design calculations for several plant SSCs. In accordance with 10 CFR 54.21(c)(1), the
 
applicant must either show that these calculations will remain valid for the period of
 
extended operation, project the analyses to the end of the period of extended operation, or
 
demonstrate that the aging effects on these SSCs will be adequately managed for the
 
period of extended operation.
 
In 2005, the NRC revised Regulatory Guide (RG) 1.188, "Standard Format and Content for
 
Applications to Renew Nuclear Power Plant Operating Licenses." This RG endorses
 
Nuclear Energy Institute (NEI) 95-10, Revision 6, "Industry Guideline for Implementing the
 
Requirements of 10 CFR Part 54 - The License Renewal Rule," issued in June 2005.
 
NEI 95-10 details an acceptable method of implementing 10 CFR Part 54. The staff also
 
used the SRP-LR to review the LRA.
 
In the LRA, the applicant fully utilized the process defined in NUREG-1801, Revision 1, "Generic Aging Lessons Learned (GALL) Report," dated September 2005. The GALL
 
Report summarizes staff-approved aging managem ent programs (AMPs) for many SCs subject to an AMR. If an applicant commits to implementing these staff-approved AMPs, the
 
time, effort, and resources for LRA review 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 of the SCs used throughout the industry. The report is also a quick reference for both
 
applicants and staff reviewers to AMPs and activities that can manage aging adequately
 
during the period of extended operation.
 
1.2.3  Environmental Review Part 51 of 10 CFR contains regulations on environmental protection regulations. In
 
December 1996, the staff revised the environmental protection regulations to facilitate the
 
environmental review for license renewal. The staff prepared the "Draft Generic
 
Supplemental Environmental Impact Statement, Vogtle Electric Generating Plant Site, Supplement 34, NUREG-1437", (ML081900016) (GEIS), to document its evaluation of
 
possible environmental impacts associated with nuclear power plant license renewals. For certain types of environmental impacts, the GEIS contains generic findings that apply to all
 
nuclear power plants and are codified in Appendix B, "Environmental Effect of Renewing
 
the Operating License of a Nuclear Power Plant," to Subpart A, "National Environmental
 
Policy Act - Regulations Implementing Section 102(2)," of 10 CFR Part 51. Pursuant to 1-5 10 CFR 51.53(c)(3)(i), a license renewal applicant may incorporate these generic findings in its environmental report. In accordance with 10 CFR 51.53(c)(3)(ii), an environmental
 
report also must include analyses of environmental impacts that must be evaluated on a
 
plant-specific basis (i.e., Category 2 issues).
 
In accordance with the National Environmental Policy Act of 1969 and 10 CFR Part 51, the
 
staff reviewed the plant-specific environmental impacts of license renewal, including
 
whether there was new and significant information not considered in the GEIS. As part of its
 
scoping process, the staff held a public meeting on September 27, 2007, in Waynesboro, Georgia, to identify plant-specific environmental issues. The draft, plant-specific GEIS
 
Supplement 34 documents the results of the env ironmental review and makes a preliminary recommendation as to the license renewal action. The staff held another public meeting on
 
June 3, 2008, in Waynesboro, Georgia, to discuss draft, plant-specific GEIS
 
Supplement 34. After considering comments on the draft, the staff published the final, plant-
 
specific GEIS Supplement 34, on December 11, 2008.
 
1.3  Principal Review Matters 10 CFR Part 54 describes the requirements for renewal of operating licenses for nuclear
 
power plants. The staff's technical review of the LRA was in accordance with NRC
 
guidance and 10 CFR Part 54 requirements. Section 54.29 of 10 CFR, "Standards for
 
Issuance of a Renewed License," sets forth the license renewal standards. This SER
 
describes the results of the staff's safety review.
 
Pursuant to 10 CFR 54.19(a), the NRC requires a license renewal applicant to submit
 
general information, which the applicant provided in LRA Section 1. The staff reviewed LRA
 
Section 1 and finds that the applicant has submitted the required information.
 
Pursuant to 10 CFR 54.19(b), the NRC requires that the LRA include "conforming changes
 
to the standard indemnity agreement, 10 CFR 140.92, Appendix B, to account for the
 
expiration term of the proposed renewed license." On this issue, the applicant stated in the
 
LRA:
The original Indemnity Agreement for VEGP, which was effective as of
 
August 21, 1986, provides that such agreement "shall terminate at the time
 
of expiration of that license specified in Item 3 of the Attachment, which is
 
the last to expire." The license originally listed in Item 3 of the Attachment
 
was SNM-1967. Since August 21, 1986, however, the Indemnity Agreement
 
has been amended in order to add license numbers NPF-61, NPF-68, SNM-
 
1981, NPF-79 and NPF-81 to Item 3 of the Attachment. As a consequence
 
of these amendments, the existing Indem nity Agreement is presently due to terminate at midnight, February 9, 2029, as the last of these licenses
 
expires. SNC requests that conforming changes be made to Item 3 of the
 
Attachment to the Indemnity Agreement (and any other applicable provisions of the Indemnity Agreement and/or the Attachment) in order to make clear
 
that the Indemnity Agreement is extended until the last expiration date of the
 
renewed VEGP operating licenses issued by the Commission in response to
 
this application.
 
1-6 The staff intends to maintain the original license numbers upon issuance of the renewed licenses, if approved. Therefore, conforming changes to the indemnity agreement need not
 
be made and the 10 CFR 54.19(b) requirements have been met.
 
Pursuant to 10 CFR 54.21, "Contents of Application - Technical Information," the NRC
 
requires that the LRA contain (a) an integrated plant assessment, (b) a description of any
 
CLB changes during the staff's review of the LRA, (c) an evaluation of TLAAs, and (d) an
 
UFSAR supplement. LRA Sections 3 and 4 and Appendix B address the license renewal
 
requirements of 10 CFR 54.21(a), (b), and (c). LRA Appendix A satisfies the license
 
renewal requirements of 10 CFR 54.21(d).
 
Pursuant to 10 CFR 54.21(b), the NRC requires that, each year following submission of the
 
LRA and at least three months before the scheduled completion of the staff's review, the
 
applicant submit an LRA amendment identifying any CLB changes to the facility that affect
 
the contents of the LRA, including the UFSAR supplement. By letter dated June 26, 2008, the applicant submitted an LRA update which summarize the CLB changes that have
 
occurred during the staff's review of the LRA. This submission satisfies 10 CFR 54.21(b)
 
requirements and is still under staff review.
 
Pursuant to 10 CFR 54.22, "Contents of Application - Technical Specifications," the NRC
 
requires that the LRA include changes or additions to the technical specifications (TSs) that
 
are necessary to manage aging effects during the period of extended operation. In LRA
 
Appendix D, the applicant stated that it had not identified any TS changes necessary for
 
issuance of the renewed VEGP operating licenses. 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 staff's evaluation of the LRA technical information.
 
As required by 10 CFR 54.25, "Report of the Advisory Committee on Reactor Safeguards (ACRS)," the ACRS will issue a report documenting its evaluation of the staff's LRA review
 
and SER. SER Section 5 is reserved for the ACRS report when it is issued. SER Section 6
 
documents the findings required by 10 CFR 54.29.
 
1.4  Interim Staff Guidance License renewal is a living program. The staff, industry, and other interested stakeholders
 
gain experience and develop lessons learned with each renewed license. The lessons
 
learned address the staff's performance goals of maintaining safety, improving
 
effectiveness and efficiency, reducing regulatory burden, and increasing public confidence.
 
Interim staff guidance (ISG) is documented for use by the staff, industry, and other
 
interested stakeholders until incorporated into such license renewal guidance documents
 
as the SRP-LR and GALL Report.
 
Table 1.4-1 shows the current set of ISGs, as well as the SER sections in which the staff
 
addresses them.
1-7 Table 1.4-1  Current Interim Staff Guidance" ISG Issue (Approved ISG Number)
Purpose SER Section Nickel-alloy components in the reactor coolant pressure boundary (LR-ISG-19B)
Cracking of nickel-alloy components in the reactor pressure 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.
3.0.3.3.5 Corrosion of drywell shell in Mark I containments (LR-ISG-2006-01)
To address concerns related to corrosion of drywell shell in Mark I
 
containments. Not Applicable to VEGP 1.5  Summary of Open Items As a result of its review of the LRA, including additional information submitted through
 
February 16, 2009, the staff concludes that no open items exist which would require a
 
formal response from the applicant.
 
1.6  Summary of Confirmatory Items As a result of its review of the LRA, including additional information submitted through
 
February 16,2009, the staff concludes that no confirmatory items exist which would require
 
a formal response from the applicant.
 
1.7  Summary of Proposed License Conditions Following the staff's review of the LRA, including subsequent information and clarifications
 
from the applicant, the staff identified three proposed license conditions.
 
The first license condition requires the applicant to include the UFSAR supplement required
 
by 10 CFR 54.21(d) in the next UFSAR update required by 10 CFR 50.71(e) following the
 
issuance of the renewed licenses.
 
The second license condition requires that all capsules in the reactor vessel that are
 
removed and tested meet the requirements of American Society for Testing and Materials (ASTM) E 185-82 to the extent practicable for the configuration of the specimens in the
 
capsule. Any changes to the capsule withdraw al 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.
 
1-8 The third license condition requires the applicant to complete the commitments in the UFSAR supplement, and notify the NRC in writing when implementation of those activities
 
required prior to the period of extended operations are complete and can be verified by
 
NRC inspection.
2-1  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 (10 CFR 54.21), A Contents of Application Technical Information," requires that each application for license renewal contain an integrated plant assessment (IPA). Furthermore, the IPA must list and identify
 
those structures and components (SCs) that are subject to an aging management review (AMR) from all of the systems, structures , and components (SSCs) that are within the scope of license renewal in accordance with 10 CFR 54.4.
 
In Section 2.1 of the license renewal application (LRA) "Scoping and Screening
 
Methodology," the applicant described the scoping and screening methodology used to
 
identify the SSCs at Vogtle Electric Generating Plant (VEGP), Units 1 and 2, that are within
 
the scope of license renewal and the SCs that are subject to an AMR. The staff reviewed
 
the Southern Nuclear Operating Company, Inc., (SNC or the applicant), scoping and
 
screening methodology to determine if it is consistent with the scoping requirements stated
 
in 10 CFR 54.4(a) and the screening requirements stated in 10 CFR 54.21.
 
In developing the scoping and screening methodology for the LRA, the applicant
 
considered the requirements of 10 CFR 54, A Requirements for Renewal of Operating Licenses for Nuclear Power Plants,@ (the Rule), the statements of consideration related to the Rule, and the guidance provided in Nuclear Energy Institute (NEI) 95-10, A Industry Guideline for Implementing the Requirements of 10 CFR 54 - The License Renewal Rule,@ Revision 6. Additionally, in developing this methodology, the applicant considered the correspondence between the U.S. Nuclear Regulatory Commission (NRC) and other
 
applicants, and NEI.
2.1.2  Summary of Technical Information in the Application LRA Sections 2.0 and 3.0 provided the technical information required by 10 CFR 54.21(a).
 
In LRA Section 2.1, the applicant described the process used to identify the SSCs that
 
meet the license renewal scoping criteria under 10 CFR 54.4(a), and the process used to
 
identify the SCs that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
Additionally, Section 2.2, A Plant-Level Scoping Results,@  Section 2.3, A Scoping and Screening Results - Mechanical Systems;
@ Section 2.4, A Scoping and Screening Results -
Structural Systems;
@ and Section 2.5, A Scoping and Screening Results - Electrical and Instrumentation and Control (I&C) Systems;
@ of the LRA, provided the results of the process used to identify the SCs that are subject to an AMR. Section 3.0, A Aging Management Review Results,@ of the LRA, contained the following information: Section 3.1, A Aging Management of Reactor Vessel, Internals and Reactor Coolant System;
@ Section 3.2, A Aging Management of Engineered Safety Features Systems;
@ Section 3.3, A Aging 2-2 Management of Auxiliary Systems;
@ Section 3.4, A Aging Management of Steam and Power Conversion Systems;
@ Section 3.5, A Aging Management of Containment, Structures and Component Supports;
@ and Section 3.6, A Aging Management of Electrical and Instrumentation and Controls (I&C) Components.
@  Section 4.0 of the LRA, A Time-Limited Aging Analyses (TLAA),@ contained the applicant
=s identification and evaluation of TLAA.
2.1.3  Scoping and Screening Program Review The staff evaluated the LRA scoping and screening methodology in accordance with the
 
guidance contained in Section 2.1, A Scoping and Screening Methodology,@ of NUREG-1800, A Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants,@ Revision 1 (SRP-LR). The following regulations form the basis for the acceptance criteria for the scoping and screening methodology review:
$ 10 CFR 54.4(a), as it relates to the identification of plant SSCs within the scope of the Rule.
$ 10 CFR 54.4(b), as it relates to the identification of the intended functions of plant structures and systems determined to be within the scope of the Rule. 
$ 10 CFR 54.21(a)(1) and (a)(2), as they relate to the methods utilized by the applicant to identify plant SCs subject to an AMR.
As part of the review of the applicant
=s scoping and screening methodology, the staff reviewed the activities described in the following sections of the LRA using the guidance contained in the SRP-LR:
 
Section 2.1 to ensure that the applicant described a process for identifying SSCs that are within the scope of license renewal, in accordance with the requirements of
 
10 CFR 54.4(a). Section 2.2 to ensure that the applicant described a process for determining the SCs that are subject to an AMR in accordance with the requirements of
 
10 CFR 54.21(a)(1) and (a)(2).
In addition, the staff conducted a scoping and screening methodology audit at the
 
applicant=s corporate facility, located near Birmingham, Alabama, during the week of September 17-21, 2007. The audit focused on ensuring that the applicant had developed and implemented adequate guidance to conduct the scoping and screening of SSCs in
 
accordance with the methodologies described in the LRA and the requirements of the Rule.
 
The staff reviewed implementation of the project level guidelines and topical reports
 
describing the applicant
=s scoping and screening methodology. In addition, the staff conducted detailed discussions with the applicant on the implementation and control of the license renewal program and reviewed adminis trative control documentation and selected design documentation used by the applicant during the scoping and screening process.
 
The staff reviewed training for personnel that developed the LRA, and quality practices
 
used by the applicant to develop the LRA. Additionally, the staff evaluated the quality
 
attributes of the applicant
=s aging management program activities described in Appendix A, A Final Safety Analysis Report Supplement,@ and Appendix B, "Aging Management 2-3 Programs and Activities,@ of the LRA. The staff reviewed scoping and screening results reports for the main steam system (MSS), em ergency core cooling system (ECCS), and the nuclear service cooling water tower (NSCW) to ensure that the applicant had appropriately
 
implemented the methodology outlined in the admin istrative controls and that the results were consistent with the current licensing basis (CLB) documentation.
 
2.1.3.1  Implementation Procedures and Documentation Sources Used for Scoping and Screening The staff reviewed the applicant's scoping and screening implementation procedures as
 
documented in the Scoping and Screening Methodology audit report, dated March 17, 2008 (ML080640502), to verify that the process used to identify 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 process used by the applicant to ensure that CLB
 
commitments were appropriately considered and that the applicant had adequately
 
implemented the procedural guidance during the scoping and screening process.
 
2.1.3.1.1  Technical Information in the Application
 
LRA Section 2.1, "Scoping and Screening Methodology," states that the applicant reviewed
 
the following information sources during the license renewal scoping and screening
 
process:
$ Design Criteria Documents
$ Update Final Safety Analysis Report (UFSAR)
$ Plant drawings
$ Maintenance Rule Scoping Documents
$ Technical Specifications and Bases
$ Safety Evaluation Reports
$ Equipment Databases
$ Master List of Environmental Qualification (EQ) Equipment
$ Station Blackout (SBO) Analysis Report
$ Licensing correspondence
$ Vendor documents
 
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.
 
2.1.3.1.2  Staff Evaluation
 
Scoping and Screening Implementation Procedures The staff reviewed the applicant
=s scoping and screening methodology implementation procedures, including license renewal guidelines, documents, reports, and AMR reports, as documented in the audit report, to
 
ensure the guidance was consistent with the requirements of the Rule, the SRP-LR and the
 
NEI 95-10. The staff finds the overall process used to implement the 10 CFR 54
 
requirements described in the implementing doc uments and AMRs was consistent with the Rule and industry guidance. Guidance for determining plant SSCs within the scope of the
 
Rule, and for determining which component types of the SCs, within the scope of license 2-4 renewal, were subject to an AMR, were contained in the applicant
=s implementing documents. 
 
During the review of the implementing documents, the staff focused on the consistency of
 
the detailed procedural guidance with information in the LRA, including the implementation
 
of NRC staff guidance documented in SRP-LR, and the information in request for addition
 
information (RAI) responses dated February 27, 2008.
 
After reviewing the LRA and supporting documentation, the staff finds that the scoping and
 
screening methodology instructions were consistent with Section 2.1 of the LRA. The
 
applicant=s methodology contained sufficient detail to provide concise guidance on the scoping and screening implementation process to be followed during the LRA activities.
 
Sources of Current Licensing Basis Information The staff reviewed the scope and depth of the applicant's CLB review to verify that the methodology was sufficiently comprehensive to
 
identify SSCs within the scope of license renewal, as well as component types requiring an
 
AMR. As defined in 10 CFR 54.3(a), the CLB is the set of NRC requirements applicable to a
 
specific plant and a applicant's written commitments for ensuring compliance with, and
 
operation within, applicable NRC requirements and the plant-specific design bases that are
 
docketed and in effect. The CLB includes certain NRC regulations, orders, license
 
conditions, exemptions, Technical Specificati ons, design-basis information documented in the most recent UFSAR, and applicant's commitments remaining in effect that were made
 
in docketed licensing correspondence such as applicant responses to NRC bulletins, generic letters, and enforcement actions, as well as applicant commitments documented in
 
NRC safety evaluations or licensee event reports.
 
During the audit, the staff reviewed pertinent information sources utilized by the applicant
 
that included the UFSAR, license renewal boundary diagrams, and maintenance rule
 
information. In addition, the applicant
=s license renewal process identified additional potential sources of plant information pertinent to the scoping and screening process, including, design criteria documents, Technical Specifications and bases, safety evaluation
 
reports, equipment databases, the EQ master list, SBO analysis report, licensing
 
correspondence, piping and instrumentation drawings (P&IDs), plant layout drawings, and
 
vendor documents. The staff verified that the applicant
=s detailed license renewal program guidelines required use of the CLB source information in developing scoping evaluations. 
 
The VEGP Design Criteria DC-1000-G and the Maintenance Rule list of systems were the
 
applicant=s primary repository for system identification and classification information. During the audit, the staff reviewed the applicant
=s administrative controls for the VEGP design criteria, maintenance rule information and other information sources used to verify system information. These controls are descri bed and implementation is governed by plant administrative procedures. Based on a review of the administrative controls, and a sample
 
of the system identification and classification information contained in the applicable VEGP
 
documentation, the NRC staff concluded that the applicant had established adequate
 
measures to control the integrity and reliability of VEGP system identification and
 
classification data, and therefore, the staff concludes that the information sources used by
 
VEGP during the scoping and screening process provided a sufficiently controlled source of
 
system and component data to support scoping and screening evaluations.
 
During the staff
=s review of the applicant
=s CLB evaluation process, the applicant provided the staff with a discussion regarding the incorporation of updates to the CLB and the 2-5 process used to ensure those updates are adequately incorporated into the license renewal process. The staff concludes that Section 2.1 of the LRA provided a description of the CLB
 
and related documents used during the scoping and screening process that is consistent
 
with the guidance contained in the SRP-LR. In addition, the staff reviewed the implementing
 
procedures and results reports used to support identification of SSCs relied upon to
 
demonstrate compliance with the safety-related criteria, nonsafety-related criteria and the
 
regulated events criteria referenced in 10 CFR 54.4(a). The applicant's license renewal
 
program guidelines provided a comprehensive listing of documents used to support scoping and screening evaluations. The staff finds these design documentation sources to be useful
 
for ensuring that the initial scope of SSCs identified by the applicant was consistent with the
 
plant's CLB.
 
2.1.3.1.3  Conclusion
 
On the basis of a review of information provided in Section 2.1 of the LRA, a review of the
 
applicant's 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 considered CLB information consistent with the SRP-LR and
 
10 CFR 54 and is therefore acceptable.
 
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 used in the LRA were adequately implemented. Although the
 
applicant did not develop the LRA under a 10 CFR 50, Appendix B, QA program, the
 
applicant applied the following quality assurance (QA) processes during the LRA
 
development:
 
The applicant developed written procedures to govern the implementation of the scoping and screening methodology. The applicant incorporated lessons learned from prior license renewal applications. Previous NRC requests for additional information were also
 
reviewed to ensure that applicable issues were addressed. The applicant used a review system to verify and validate the controlling documents. The LRA was reviewed by the applicant's on-site and corporate personnel and industry peers, prior to submittal to the NRC. The applicant
=s QA organization performed an internal audit as an independent review of the LRA. The purpose of the audit was to ensure that the license renewal documents, procedures and technical information were
 
developed in accordance with the requirements of 10 CFR 54.4.
2-6 2.1.3.2.2  Conclusion The staff reviewed reports, LRA development guidance, and discussed the quality controls
 
applied to the LRA development with the applicant
=s license renewal staff. The staff concludes that the quality assurance activities met current regulatory requirements and provided additional assurance that LRA development activities were performed consistently with the applicant
=s LRA program requirements.
2.1.3.3  Training 2.1.3.3.1  Staff Evaluation
 
The staff reviewed the applicant
=s training process to ensure the guidelines and methodology for the scoping and screening activities would be performed in a consistent and appropriate manner. The license renewal scoping and screening activities and LRA
 
development were accomplished by the applicant
=s corporate staff and VEGP site staff.
The applicant
=s training process provided both instruction and written guidance documents to the personnel involved with LRA development in order to ensure that the personnel had an understanding of the license renewal procedures, industry guidance and regulations
 
applicable to the scoping and screening activities and LRA development. The applicant
 
developed a checklist used as a tracking system as a basis for the personnel training
 
record which listed the completed training sessions and the documents reviewed. Both
 
corporate and site license renewal personnel were also qualified in plant support which
 
focused on core plant training and how to support the plant in license renewal. In addition, the applicant provided training on design modification, plant support, components and
 
systems in the mechanical, electrical and civil disciplines. The applicant developed
 
technical training in scoping and screening methodology to establish the necessary
 
knowledge and understanding of the license renewal process and the terminology used to
 
support the license renewal review. The applicant
=s management and staff also participated in industry groups and task forces.
 
2.1.3.3.2  Conclusion
 
The staff reviewed completed qualification and training records and completed checklists of
 
several of the applicant's license renewal personnel and concluded that the records
 
adequately documented the training for the applicant
=s staff. Additionally, based on discussions with the applicant's license renewal personnel, the staff concludes that personnel were knowledgeable regarding the license renewal process requirements and
 
the specific technical issues within their areas of responsibility.
 
2.1.3.4  Scoping and Screening Program Review Conclusion On the basis of a review of information provided in Section 2.1 of the LRA, a review of the
 
applicant=s detailed scoping and screening implementation procedures, discussions with the applicant
=s license renewal personnel and the results from the scoping and screening audit, the staff concludes that the applicant
=s scoping and screening program was consistent with the SRP-LR and 10 CFR 54 and is therefore acceptable.
 
2-7 2.1.4  Plant Systems, Structures, and Components Scoping Methodology In LRA Section 2.1, the applicant described the methodology used to scope SSCs pursuant
 
to the requirements of the 10 CFR 54.4(a) scoping criteria. The applicant described the
 
scoping process for the plant in terms of sy stems and structures. Specifically, the scoping process consisted of developing a list of plant systems and structures, identifying their
 
intended functions, and determining which functions meet one or more of the three criteria
 
of 10 CFR 54.4(a). The systems list was developed using design criteria and maintenance
 
rule system information. Additional info rmation on mechanical system functions was obtained from the UFSAR, plant layout drawings and P&IDs. Structural functions were
 
identified using UFSAR, the maintenance rule basis documents for structures, the plant
 
seismic categorization information, and structur al drawings. All electrical and I&C systems, and electrical and I&C components in mechanical systems, were included within in the
 
scope of license renewal.
2.1.4.1  Application of the Scoping Criteria in 10 CFR 54.4(a)(1) 2.1.4.1.1  Technical Information in the Application
 
LRA Section 2.1.2.1, A 10 CFR 54.4(a)(1) - Safety-Related,@ describes the scoping methodology as it relates to the safety-related criterion in accordance with 10 CFR 54.4(a)(1). With respect to the safety-related criterion, the applicant stated that the
 
safety-related systems and structures are init ially identified based on a review of the VEGP project classification designators (VEGP UFSAR Section 3.2.2.1) which are used in the
 
plant documentation, the safety design bases discussions in the design criteria documents, the safety evaluation discussions in the UFSAR, and the safety-related determination
 
results for the Maintenance Rule scoping. Systems and structures whose intended
 
functions met one or more of the criteria in 10 CFR 54.4(a)(1) were included within the
 
scope of license renewal. The applicant confirmed that all plant conditions, including
 
conditions of normal operation, design basis accidents, external events, and natural
 
phenomena for which the plant must be designed, were considered for license renewal scoping under 10 CFR 54.4(a)(1) criteria. 
 
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 the
 
following functions: (i) the integrity of the reactor coolant pressure boundary; (ii) the
 
capability to shut down the reactor and maintain it in a safe shutdown condition; or (iii) the
 
capability to prevent or mitigate the consequences of accidents that could result in potential
 
offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1),
10 CFR 50.67(b)(2), or Part 100.11 of the Code of Federal Regulations.
 
With regard to identification of DBEs, Section 2.1.3, A Review Procedures,@ of the SRP-LR 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 2-8 Commission's regulations, NRC orders, exemptions, or license conditions within the CLB. These sources should also be reviewed to identify SSCs relied upon to remain
 
functional during and following DBEs (as defined in 10 CFR 50.49(b)(1)) to ensure the
 
functions described in 
 
10 CFR 54.4(a)(1).
 
During the audit the applicant stated that it evaluated the types of events listed in NEI 95-10 (i.e., anticipated operational occurrences, design basis accidents, external events and
 
natural phenomena) that were applicable to VEGP. The applicant identified the documents
 
that described the events, which are contained in the UFSAR and system design criteria
 
which discussed events such as internal and external flooding tornados, and missiles. The
 
applicant also reviewed licensing correspondence and design criteria. 
 
The staff concludes that the applicant
=s evaluation of DBEs was consistent with the SRP-LR.
The applicant performed scoping of SSCs for the 54.4(a)(1) criterion in accordance with the
 
license renewal implementing documents whic h 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 the implementing documents governing
 
the applicant
=s evaluation of safety-related SSCs, and sampled the applicant
=s 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
 
applicant's personnel who were responsible for these evaluations.
 
The staff reviewed the applicant
=s evaluation of the rule and CLB definitions pertaining to 10 CFR 54.4(a)(1) and concluded that the VEGP CLB definition of safety-related did not contain references to 10 CFR 50.34 or 10 CFR 50.67(b)(2) as specified in the Rule. The
 
applicant=s definition of safety-related and exceptions to the definition in the Rule are documented in LRA Section 2.1.2.1. Based on this review, the staff verified that 10 CFR 50.34(a)(1) is not applicable to VEGP, Units 1 or 2, as it concerns applicants for a
 
construction permit. The staff concludes that 10 CFR 50.67(b)(2), which concerns the use
 
of an alternate source term in the dose analysis, is not applicable to VEGP, Units 1 or 2, which has not applied for the use of an alternate source term. 
 
The staff reviewed a sample of the license renewal scoping results for the MSS, ECCS, and
 
the NSCW tower to provide additional assurance that the applicant adequately
 
implemented their scoping methodology with respect to 10 CFR 54.4(a)(1). The staff
 
verified 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 verified 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.
 
The staff concludes that additional information would be required to complete the review of
 
the applicant
=s scoping methodology. RAI 2.1-1, dated January 28, 2008, stated that during the NRC audit, the staff noted that source documents used to identify the SSCs which met the scoping criteria of 10 CFR 54.4(a)(1), including the VEGP updated safety analysis
 
report Section 3.2, and procedures AP 05-007, Section 6.1.4, and AP 23M-001, Section
 
4.17.1, had differing definitions of safety-related and also cited superseded regulatory text
 
in establishing the scoping criteria to be used in identifying VEGP SSCs in accordance with 2-9 10 CFR 54.4(a)(1) requirements. Therefore, the staff requested that the applicant provide a written evaluation that addresses the impact, if any, of the use of differing definitions of
 
safety-related.
In the response to RAI 2.1-1 dated February 27, 2008, the applicant stated, 
 
A The VEGP definition of safety related for current design activities is defined in procedure ENG-016 which reads:
Any structure, system, component, or part used in a nuclear power plant that is
 
relied upon during or following design basis events to assure
 
$ The integrity of the reactor coolant pressure boundary, $ The capability to shut down the reactor and maintain it in safe shutdown condition, or
$ The capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposures comparable to the guideline exposures of
 
10 CFR 100.11."
As noted in the question, wording in historic procedures has not always been section
 
specific, but the intent and application was consistent. The CLB classification of VEGP
 
SSCs was based on design criteria documents. The applicant's governing procedure for
 
creation of these documents (PS-VS-001) was the primary source of the wording
 
discrepancy in that it defined safety related as: 
 
Equipment, components, or structures perform a safety-related function if that
 
function is required to:
 
$ Maintain the integrity of the reactor coolant pressure boundary.
$ Shut down the plant and maintain the plant in a safe shutdown condition.
$ Prevent accidents or mitigate their consequences.
 
This definition could not be used without further clarification because it did not define which
 
accidents or consequences had been considered. However, the staff understood that this
 
paragraph referred to accidents defined by limits in 10 CFR 100. This inference was
 
demonstrated in the applicant's procedure (DC-1010), which was the section of the design
 
manual that defined the safety classification of the VEGP SSCs. This section defined safety
 
related as: 
 
Systems, structures, and components important to safety are defined as those items necessary to ensure:
$ The integrity of the reactor coolant pressure boundary. 
$ The capability to shut down the reactor and maintain it in a safe shutdown condition.
2-10 $ The capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposures comparable to the guideline exposures of
 
10 CFR 100.
While this reference does not include the specific section (10 CFR 100.11), the section of
 
the 10 CFR 100 that defined "potential off site exposures" during initial classification of
 
VEGP SSCs was Section 11. Therefore, the CLB definition of safety related SSCs for
 
VEGP has been consistently applied and meets the criteria of 10 CFR 54.4(a)(1). (As noted
 
in the VEGP LRA, 10 CFR 50.34(1)(1) and 10 CFR 50.67(b)(2) do not apply to VEGP).
The staff reviewed the applicant
=s response to RAI 2.1-1 and determined that the applicant had provided a description of an adequate process used to ensure that SSCs had been appropriately included within the scope of license renewal, in accordance with
 
10 CFR 54.4(a)(1) and that the definitions for safety-related used to classify SSCs, as
 
described in the response to RAI 2.1-1, was consistent with 10 CFR 54.4(a)(1).
 
2.1.4.1.3  Conclusion
 
On the basis of a review of systems sampled, discussions with the applicant, review of the
 
applicant's scoping process, and the applicant
=s response to RAI 2.1-1, the staff concludes that the applicant's methodology for identifying systems and structures is consistent with the SRP-LR and 10 CFR 54.4(a)(1), and is therefore acceptable.   
 
2.1.4.2  A pplication of the Scoping Criteria in 10 CFR 54.4(a)(2) 2.1.4.2.1  Technical Information in the Application
 
LRA Section 2.1.2.2, A 10 CFR 54.4(a)(2) - Nonsafety-Related SSCs Affecting Safety-Related SSCs,@ the applicant described the scoping methodology as it related to the nonsafety-related criteria in accordance with 10 CFR 54.4(a)(2). Also, the applicant
=s 10 CFR 54.4(a)(2) scoping methodology was based on guidance provided in Appendix F of NEI 95-10, Rev. 6. The applicant evaluated the impacts of nonsafety-related SSCs that met
 
10 CFR 54.4(a)(2) criteria by considering functional failures and physical failures. 
 
Functional Failure of Nonsafety-Related SSCs LRA 2.1.2.2.1, A Nonsafety-Related SSCs That Perform A Required Function In Support Of Safety-Related Functions,@ stated that SSCs required to perform a function in suppor t of safety-related components are generally classified as safety-related and are included within the scope of license renewal in
 
accordance with 10 CFR 54.4(a)(1). 
 
For the few exceptions where nonsafety-related components are required to remain
 
functional to support a safety function, this system intended function was identified and the
 
components were included within the scope of license renewal in accordance with the
 
requirements of 10 CFR 54.4(a)(2). 
 
Nonsafety-Related SSCs directly connected to Safety-Related SSCs LRA 2.1.2.2.2, A Nonsafety- Related SSCs Directly Connected To Safety-Related SSCs and Relied Upon For Structural Support Of Safety-Related SSCs,@ stated that nonsafety-related piping and supports are included within the scope of license renewal up to and including the seismic anchor as identified in the stress analysis, or to an equivalent anchor, or one of the other 2-11 methods provided for in NEI 95-10, Appendix F. The LRA defined equivalent anchor as a combination of restraints or supports such that the nonsafety-related piping and associated
 
SCs attached to safety-related piping is included in scope up to a boundary point that
 
encompasses two (2) supports (restraints) in each of the three (3) orthogonal directions.
 
The other methods used to define a scoping boundary included bounding conditions
 
discussed in NEI 95-10, including ending at a base mounted component, flexible
 
connection, or to include the entire piping run.
 
Nonsafety-Related SSCs With the Potential for Spatial Interaction With Safety-Related SSCs LRA 2.1.2.2.3, "Nonsafety-Related SSCs Whose Failure Could Result In a Potential Spatial Interaction with Safety-Related SSCs That Could Prevent Accomplishment of a
 
Safety Function,@ stated that nonsafety-related systems and nonsafety-related portions of safety-related systems are identified as in scope under 10 CFR 54.4(a)(2) if there is a potential for spatial interactions with safety-related equipment. Spatial failures were defined
 
as failures of nonsafety-related SSCs that are located in the vicinity of safety-related SSCs
 
creating the potential for interaction between the SSCs due to physical impact, pipe whip, jet impingement, a harsh environment resulting from a piping rupture, or damage due to leakage or spray that could impede or prevent the accomplishment of the safety-related
 
functions of a safety-related SSC. Also included were nonsafety-related SSCs which
 
provide protection from temperature extrem es, or detect flooding and leaks. Mitigative features, such as missile barriers, flood barriers, and spray shields, were included within
 
the scope of license renewal in accordance with 10 CFR 54.4(a)(2). In addition, the
 
preventive option described in Appendix F of NEI 95-10 was used to determine the scope
 
of license renewal with respect to the protection of safety-related SSCs from spatial
 
interactions that are not addressed in the CLB. This scoping process required an evaluation
 
based on equipment location and the related SSCs and if fluid-filled system components
 
are located in the same space as safety-related equipment. A "space" was defined as
 
barriers composed of walls, floors and ceilings which prevented interaction between safety-
 
related and nonsafety-related SSCs.
 
2.1.4.2.2  Staff Evaluation Pursuant to 10 CFR 54.4(a)(2), the applicant must consider all nonsafety-related SSCs
 
whose failure could prevent satisfactory a ccomplishment of safety-related SSCs relied upon to remain functional during and following a DBE to ensure the following functions: (i) the
 
integrity of the reactor coolant pressure boundary; (ii) the capability to shut down the
 
reactor and maintain it in a safe shutdown condition; or (iii) the capability to prevent or
 
mitigate the consequences of accidents that could result in potential offsite exposures
 
comparable to those referred to in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or
 
10 CFR 100.11.
 
NRC Regulatory Guide 1.188, A Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses,@ Revision 1, (Reg. Guide 1.188) provided NRC endorsement of the use of NEI 95-10, Revision 6, which discusses in Appendix F, the NRC staff position on 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 preventative options related to nonsafety-
 
related and safety-related SSCs interactions. 
 
2-12 In addition, the NRC staff position (as discussed NEI 95-10, Rev. 6) states that applicants should not consider hypothetical failures, but rather should base their evaluation on the
 
plant=s CLB, engineering judgment and analyses, and relevant operating experience. NEI 95-10 further describes operating experience as all documented plant-specific and industry-wide experience that can be used to determine the plausibility of a failure.
 
Documentation would include NRC generic communications and event reports, plant-specific condition reports, industry reports such as safety operational event reports, and engineering evaluations. The staff reviewed LRA Section 2.1.2.2, where the applicant
 
described the scoping methodology as it related to the application of the 10 CFR 54.4(a)(2)
 
nonsafety-related criteria. In addition, the staff reviewed the applicant
=s results report which documented the guidance and corresponding results of the applicant
=s 10 CFR 5.4.4(a)(2) scoping review which had been performed in accordance with the guidance contained in NEI 95-10, Revision 6, Appendix F. 
 
Nonsafety-Related SSCs Required to Perform a Function that Supports a Safety-Related SSC The staff concludes that nonsafety-related SSCs required to remain functional to support a safety-related function were included within the scope of license renewal as
 
safety-related in accordance with the requirements of 10 CFR 54.4(a)(1) with several
 
exceptions, which were included within the scope of license renewal in accordance with
 
10 CFR 54.4(a)(2). This evaluating criteria was discussed in the applicant
=s 10 CFR 54.4(a)(2) report. The staff finds 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 Directly Connected to Safety-Related SSCs The staff concludes that in order to identify the nonsafety-related SSCs connected to safety-related SSCs and
 
required to be structurally sound to maintain the integrity of the safety-related SSCs, the
 
applicant used a combination of the information contained in the VEGP structural analysis (to identify the structural boundary), equivalent anchors and the bounding approach as
 
described in NEI 95-10, Appendix F. The applicant reviewed the safety-related to
 
nonsafety-related interfaces for each mechanical system in order to identify the nonsafety-
 
related components located between the interface and the structural boundary. The staff
 
concludes that the applicant had included all nonsafety-related SSCs within the structural
 
boundary within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). 
 
If a seismic support could not be located using the structural boundary, the applicant
 
identified the portion of the nonsafety-related piping up to, and including, an equivalent
 
anchor or a bounding condition such as a base-mounted component, flexible connection, or
 
the end of the piping run, in accordance with the guidance of NEI 95-10, Appendix F, which
 
was included within the scope of license renewal. The LRA and the applicant
=s implementing procedures defined an equivalent anchor as two supports in each of the three orthogonal directions. 
 
Nonsafety-Related SSCs with the Potential for Spatial Interaction with Safety-Related SSCs The applicant considered physical impact (pipe whip, jet impingement), harsh
 
environments, flooding, spray, and leakage when evaluating the potential for spatial
 
interactions between nonsafety-related sy stems and safety-related SSCs. The applicant used a "spaces approach" to identify the portions of nonsafety-related systems with the
 
potential for spatial interaction with safety-related SSCs. The spaces approach focused on
 
the interaction between nonsafety-related and safety-related SSCs that are located in the 2-13 same space, which was defined as a room or cubicle that is separated from other spaces by substantial objects (such as wall, floors, and ceilings).
Physical Impact or Flooding the applicant had considered situations where nonsafety-related supports for non-seismic piping systems with potential for spatial interaction
 
with safety-related SSCs for inclusion within the scope of license renewal in
 
accordance with 10 CFR 54.4(a)(2). The applicant had identified the nonsafety-related
 
SSCs by performing a review of the UFSAR, CLB documents, industry guidance, equipment layout drawings, composite drawi ngs, isometric drawings and by performing walkdowns. Piping and equipments supports and components were addressed in a
 
commodity fashion within civil/structural AMR reports. The applicant
=s review of earthquake experience identified no occurrence of welded steel pipe segments falling due to a strong motion earthquake. The applicant concluded that as long as the effects
 
of aging on supports for piping systems are managed, falling of piping systems is not credible (except due to flow accelerated corrosion as considered in the high energy
 
line break (HELB) analysis for high energy systems) and the piping sections are not
 
required to be included within the scope of license renewal in accordance with
 
10 CFR 54.4(a)(2) due to a physical impact hazard. The applicant evaluated the
 
missiles that could be generated from internal or external events such as failure of
 
rotating equipment. The nonsafety-related design features which protect safety-related
 
SSCs from such missiles were included within the scope of license renewal. All
 
nonsafety-related cranes, monorails and hoists (overhead-handling systems) were
 
included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2) as
 
structural commodities due to the potential for interaction with safety-related SSCs.
 
Pipe Whip, Jet Impingement, and Harsh Environment The applicant had evaluated nonsafety-related portions of high energy lines against the10 CFR 54.4(a)(2) criteria.
 
The applicant
=s evaluation was based on a review of documents such as the UFSAR, design criteria documents and relevant site documentation. The applicant
=s high energy systems were evaluated to ensure ident ification of components that are part of nonsafety-related high energy lines that can effect safety-related equipment. If the
 
applicant=s 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 within the scope of license renewal in
 
accordance with 10 CFR 54.4(a)(2) and subject to an AMR in order to provide
 
assurance that those assumptions remain valid through the period of extended
 
operation. Also, as discussed in the VEGP 10 54.4(a)(2) report, the applicant reviewed
 
the reference documents, primarily the UFSAR and the VEGP Technical Requirements Manual, that contained HELB analysis for inside and outside containment and which
 
identified high energy lines. Many of the i dentified systems were safety-related or required for a regulated event and included within the scope of license renewal in
 
accordance with 10 CFR 54.4(a)(1). The remaining nonsafety-related, high energy
 
lines, which were determined to have the potential for interaction with safety-related
 
SSCs, were included within the scope of license renewal in accordance with
 
10 CFR 54.4(a)(2).
Spray and Leakage The applicant evaluated moderate and low energy systems which have the potential for spatial interactions due to spray or leakage. Nonsafety-related
 
systems, and nonsafety-related portions of sa fety-related systems, with the potential for spray or leakage that could prevent safety-related SSCs from performing their
 
required safety function were considered within the scope of license renewal. The 2-14 applicant used a spaces approach to identify the nonsafety-related SSCs which were located within the same space as safety-related SSCs. As described in the LRA, a
 
space was defined as barriers composed of walls, floors and ceilings which prevented
 
interaction between safety-related and nonsafety-related SSCs. Following identification
 
of the applicable mechanical systems, the applicant reviewed the system functions to
 
determine whether the system contained fluid, air or gas. Based on plant and industry 
 
operating experience, the applicant excluded the nonsafety-related SSCs containing
 
air or gas from the scope of license renewal with the exception of lines containing
 
hydrogen gas whose failure were determined to have a potential impact on safety-
 
related SSCs. The applicant then determined whether the system had any components located within a space containing safety-related SSCs. Those nonsafety-related SSCs
 
determined to contain fluid or hydrogen gas, and located within a space containing
 
safety-related SSCs, were included within the scope of license renewal in accordance
 
with 10 CFR 54.4(a)(2).
 
The staff concludes that additional information would be required to complete the review of
 
the applicant
=s scoping methodology. During the on-site audit the staff reviewed the applicant's technical evaluation for nonsafety-related affecting safety-related SSCs which discussed the consideration of components located in the turbine building and identified as
 
safety-related in the UFSAR. The applicant concluded in the technical evaluation that, although the turbine building contains components identified as safety-related in the
 
UFSAR, these components are not vulnerable to the effects of a failure of nonsafety-related
 
SSCs in the non-seismic areas within the limits of the CLB. Therefore, no additional SSCs
 
located in the turbine building were included within the scope of license renewal based on
 
the requirements of 10 CFR 54.4(a)(2). In RAI 2.1-2, dated January 28, 2008, the staff
 
requested that the applicant provide the rationale and basis for not including nonsafety-
 
related SSCs in the vicinity of safety-related SSCs in the turbine building within the scope of
 
license renewal.
 
In the response to RAI 2.1-2 dated February 27, 2008, the applicant stated the following: 
 
The following components in the turbine building are classified as safety related:
$ Turbine impulse pressure transmitters
$ Turbine steam bypass valve (steam dum p valve) air supply solenoid valves
$ High pressure turbine steam stop valve limit switches
$ High pressure turbine steam control valve [electrohydraulic control] oil pressure transmitters and manual isolation valves The applicant stated that although these components are conservatively classified as
 
safety-related they (1) perform no safety function, (2) are not credited in the accident
 
analysis, and (3) meet the VEGP CLB for preventing interactions from propagating back
 
into the reactor protection system and they c an not prevent satisfactory accomplishment of any of the safety related functions discussed in 10 CFR 54.4, paragraphs (a)(1) (i), (ii), or (iii). Based on the review of the functions of the components classified as safety related in
 
the turbine building, the applicant determined that there were no nonsafety-related
 
components located in the turbine building whose failure could prevent the performance of
 
a safety-related function. 
 
Therefore, no components located within the turbine building were included within the
 
scope of license renewal in accordance with 10 CFR 54.4(a)(2).
 
2-15 The staff reviewed the applicant
=s response to RAI 2.1-2 and determined that the applicant had provided a description of an adequate process to review the functions of the components classified as safety-related and located in the turbine building. The staff
 
concludes that the applicant had adequately performed and documented a review to
 
determine that certain components located in the turbine building had been conservatively
 
classified as safety-related although they did not perform a safety-function as defined in the
 
CLB and, therefore, there were no nonsafety-related components located in the turbine
 
building whose failure could prevent the performance of safety-related function.
 
Protective Features The applicant evaluated protective features such as whip restraints, spray shields, supports, missile and flood barriers installed to protect safety-related SSCs
 
against spatial interaction with nonsafety-related SSCs due to fluid leakage, spray, or
 
flooding. Such protective features credited in the plant design were included within the
 
scope of license renewal in accordance with 10 CFR 54.4(a)(2).
 
2.1.4.2.3 Conclusion
 
On the basis of a review of the applicant's scoping process and sample systems, discussions with the applicant, and review of the information provided in the response to
 
RAI 2.1-2, the staff concludes that the applicant's methodology for identifying and including
 
nonsafety-related SSCs, which could affect the performance of a safety-related SSCs, within the scope of license renewal, is consistent with the scoping criteria of
 
10 CFR 54.4(a)(2), and is therefore acceptable.
2.1.4.3  Application of the Scoping Criteria in 10 CFR 54.4(a)(3) 2.1.4.3.1 Summary of Technical Information in the Application 
 
LRA Section 2.1.2.3 , A 10 CFR 54.4(a)(3) - Regulated Events,@ describes the methodology for identifying those systems and structures within the scope of license renewal in accordance with the Commission
=s criteria for five regulated events: (1) 10 CFR 50.48, A Fire Protection;
@ (2) 10 CFR 50.49, A Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants;
@ (3) 10 CFR 50.61, A Fracture Toughness Requirements for Protection Against Pressurized Thermal Shock Events;
@ (4) 10 CFR 50.62, A Requirements for Reduction of Risk from Anticipated Transients Without Scram (ATWS)
Events for Light-Water-Cooled Nuclear Power Plants;
@ and (5) 10 CFR 50.63, A Loss of All Alternating Current Power.
@  Fire Protection LRA Section 2.1.2.3.1, A 10 CFR 50.48 - Fire Protection,@ described scoping of systems and structures relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the fire protection criterion. The LRA stated the
 
SSCs relied upon in safety analyses or plant evaluations to perform a function that
 
demonstrates compliance with 10 CFR 50.48, A Fire Protection,@ were included in the scope of license renewal under the 10 CFR 54.4(a)(3) criterion. 
 
The VEGP CLB documents applicable to the VEGP Fire Protection Program, such as the
 
UFSAR Section 9.5.1 and Appendices 9A and 9B, were reviewed to determine the SSCs
 
relied upon in safety analyses or plant evaluations to perform a function that demonstrates
 
compliance with 10 CFR 50.48. Based on the CLB, the applicant included the SSCs
 
credited with fire prevention, detection, and mitigation for areas containing equipment
 
important to safety and for certain radioactive waste areas (as required by the CLB), within 2-16 the scope of license renewal. The applicant also included in the scope of license renewal those SSCs relied upon in the CLB to maintain the ability to perform reactor plant safe
 
shutdown functions in the event of a fire. 
 
Environmental Qualification LRA Section 2.1.2.3.2, A 10 CFR 50.49 - Environmental Qualification (EQ),@ describes the scoping of systems and structures relied on in safety analyses or plant evaluations to perform a function in compliance with the EQ criterion. The LRA stated that the master list of safety-related equipment located in a harsh environment (EQ master list) defines the electrical equipment subject to the requirements of
 
10 CFR 50.49. The electrical components on the EQ master list have been included in the
 
scope of license renewal in accordance with 10 CFR 54.4(a)(3).
 
Pressurized Thermal Shock LRA Section 2.1.2.3.3, A 10 CFR 50.61 - Pressurized Thermal Shock (PTS),@ describes the scoping of systems and structures relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the PTS criterion. The LRA stated that SSCs relied on in safety analyses or plant evaluations to
 
perform a function that demonstrates compliance with 10 CFR 50.61, A Fracture Toughness Requirements for Protection Against Pressurized Thermal Shock Events,@ are within the scope of license renewal. Based upon a review of design basis documentation, only the reactor vessels and the reactor vessel internals credited to reduce fast neutron fluence are
 
relied upon for protection against PTS. The reactor vessels and the reactor vessel internals
 
structures credited to reduce fast neutron fluence have been included within the scope of
 
license renewal for PTS in accordance with 10 CFR 54.4(a)(3).
 
Anticipated Transient Without Scram LRA Section 2.1.1.3.4, A Commission's Regulations for Anticipated Transients without Scram (10 CFR 50.62),@ describes the scoping of systems and structures relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the ATWS criterion. The LRA stated that the ATWS
 
mitigation system actuation circuitry (AMSAC) was required to meet the 10 CFR 50.62
 
requirements. The AMSAC is described in UFSAR Section 7.7.1.11. The AMSAC and other
 
SSCs relied on in analyses or plant evaluations to sense, initiate, and perform these
 
required functions have been included within the scope of license renewal for ATWS in
 
accordance with 10 CFR 54.4(a)(3).
 
Station Blackout LRA Section 2.1.1.3.5, A Commission's Regulations for Station Blackout (10 CFR 50.63),@ describes the scoping of systems and structures relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the SBO criterion. The LRA stated that the functions relied upon during the SBO coping phase
 
were described in UFSAR Section 8.4. The SSCs relied on in the analyses and plant
 
evaluations for coping with an SBO event, and the systems containing these components, have been included within the scope of license renewal in accordance with
 
10 CFR 54.4(a)(3). In addition the SSCs required to recover from a SBO event were also
 
included within the scope of license renewal in accordance with 10 CFR 50.63.
 
2.1.4.3.2 Staff Evaluation 
 
The staff reviewed the applicant
=s approach to identifying mechanical systems and structures relied upon to perform functions meeting the requirements of the fire protection, EQ, PTS, ATWS, and SBO regulations. As part of this review the staff discussed the
 
methodology with the applicant, reviewed the documentation developed to support the 2-17 approach, and evaluated a sample of the mechanical systems and structures indicated as within the scope of license renewal under the 10 CFR 54.4(a)(3) criteria. 
 
The applicant
=s implementing procedures describe the process for indentifying systems and structures within the scope of license renewal. The procedures state that all mechanical systems and structures that perform functions addressed in 10 CFR 54.4(a)(3) are to be
 
included within the scope of license renewal and that the results are to be documented in
 
scoping results reports. 
 
The results reports reference the information sources used for determining the systems and
 
structures credited for compliance with the regulated events.
 
Fire Protection The applicant
=s scoping results reports indicate that it considered CLB documents to identify in-scope systems and structures. These documents include the UFSAR, design criteria and fire protection P&IDs. The staff reviewed the scoping results
 
reports in conjunction with the LRA and the CLB information to validate the methodology for
 
including the appropriate SSCs within the scope of license renewal. The staff finds that the
 
scoping results reports indicated which of the mechanical systems and structures are
 
included within the scope of license renewal because they perform intended functions
 
meeting 10 CFR 50.48 requirements. The staff concludes that the applicant
=s scoping methodology was adequate for including SSCs credited in performing fire protection functions.
 
Environmental Qualification The applicant had used the EQ master list to identify SSCs meeting the requirements of 10 CFR 50.49. The EQ master list included system
 
information, component identification numbers and descriptions. The staff reviewed the
 
LRA, implementing procedures, scoping results reports, and the EQ master list to verify that
 
the applicant had identified SSCs within the scope of license renewal. The staff concludes
 
that the applicant
=s scoping methodology was adequate for identifying EQ SSCs within the scope of license renewal.
 
Pressurized Thermal Shock The applicant addressed PTS requirements for these components in a TLAA report. The staff reviewed the TLAA report and scoping report and
 
determined that the methodology is appropriate for identifying SSCs with functions credited
 
for complying with the PTS regulation and within the scope of license renewal. For this
 
requirement the applicant identified the reactor vessel and certain vessel internal
 
components within the scope of license renewal.
 
Anticipated Transient Without Scram The applicant
=s scoping results report indicated the mechanical systems were included within the scope of license renewal because they perform intended functions meeting 10 CFR 50.62 requirements. The applicant determined
 
the intended functions based on CLB information and identified most in-scope components
 
as electrical equipment. For scoping electrical equipment, the applicant
=s bounding methodology included within the scope of license renewal all electrical and I&C systems in mechanical systems by default. The applicant also included mechanical systems with ATWS intended functions based on CLB information. The staff concludes that this scoping
 
methodology was adequate for identifying SSCs with functions credited for complying with
 
the ATWS regulation. 
 
Station Blackout The scoping results reports indicate the mechanical systems and structures credited with performing intended functions to comply with the SBO requirement.
2-18 During the scoping process the applicant considered CLB information, including the UFSAR, design criteria, plant drawings and the SBO analysis report. The applicant included
 
within the scope of license renewal electrical equipment, mechanical systems, and
 
structures with intended functions meeting SBO requirements. For scoping electrical
 
equipment, the applicant
=s bounding methodology included within the scope of license renewal all electrical and I&C systems by default. The mechanical systems and structures within the scope of license renewal are those relied on in the CLB for the SBO coping
 
duration phase and for the SBO recovery phase. The staff concludes that this scoping
 
methodology was adequate for identifying SSCs with functions credited for complying with
 
the SBO regulation. The staff review and conclusion of the results of the implementation of
 
the SBO scoping methodology is contained in Section 2.5.
 
2.1.4.3.3 Conclusion
 
The staff concludes 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. This conclusion is based on sample reviews, discussions with the applicant, and review of the
 
applicant=s scoping process as discussed above.
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 the LRA, guidance
 
documents and scoping and screening reports. The applicant's approach to system and
 
structure scoping provided in the site guidance and implementing documents was
 
consistent with the methodology described in Section 2.1 of the LRA. Specifically, the
 
guidance documents specified that the personnel performing license renewal scoping use
 
CLB documents and describe the system or structure, including a list of functions that the
 
system or structure is required to accomplish. Sources of information included the UFSAR, design criteria, maintenance rule information, plant drawings, equipment databases 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). If any part of a system or structure met any of the license
 
renewal scoping criteria, the system or structure was included in the scope of license
 
renewal. The system and structure scoping resu lts included an overall system/structure description, an evaluation of each of the 10 CFR 54.4 scoping criteria and the basis for the
 
conclusion reached. The applicant developed evaluation boundaries to document the
 
system and structure level scoping determinations and to define the in-scope SSCs to
 
support the subsequent screening and AMR processes. The boundaries for the in-scope
 
systems and structures were defined and documented in a manner for each discipline that
 
assured the in-scope SSCs were included in the screening process.
 
Component Level Scoping After the applicant identified the intended functions of systems or structures within the scope of license renewal, a review was performed to determine
 
which components and structures support the system
=s license renewal intended functions.
The components that support intended functions were considered within the scope of license renewal and screened to determine if an AMR was required. The applicant
 
considered three groups of SCs during this stage of the scoping methodology: (1)
 
mechanical, (2) structural, and (3) electrical.
 
2-19 Commodity Groups Scoping The applicant applied commodity group scoping to structural and electrical SCs as discussed in Sections 2.1.4.6 and 2.1.4.7.
 
Insulation LRA Section 2.1.2.2.3 stated that insulation was included with the mechanical scoping. Piping insulation in containment penetrations was identified as being required to keep the local concrete temperatures below 200F. Also, for certain HVAC systems, thermal insulation is credited in the calculations that assure that the HVAC systems will
 
perform their safety-related functions. Insulation was included within the scope of license
 
renewal in accordance with 10 CFR 54.4(a)(2).
 
Consumables LRA Section 2.1.2.3, A Screening,@ discusses consumables. The information in Table 2.1-3 of the SRP-LR 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.
 
Group (a) Packing, gaskets, component mechanical seals, and O-rings are typically used to
 
provide a leak proof seal when components are mechanically joined together. These items are commonly found in components such as valves, pumps, heat exchangers, ventilation units or ducts, and piping segments. Based on ANSI B31.1 and the ASME B&PV Code
 
Section III, the subcomponents of these pressure retaining components are not pressure-
 
retaining parts. Therefore, these subcomponents are not relied on to perform a pressure
 
boundary intended function and were not subject to an AMR.
 
Group (b) Elastomers and other materials used as structural sealants are subject to an
 
AMR if they are not periodically replaced and they perform an intended function, typically supporting a pressure boundary, flood barrier, or rated fire barrier. Compressible joints and
 
seals, seismic joint filler, and roof membranes were included in the AMR of bulk
 
commodities. Sealants with a pressure boundary function were included in the AMR of the
 
containment buildings.
 
Group (c) Oil, grease, and component filters have been treated as consumables because
 
either (1) they are periodically replaced or (2) they are monitored and replaced based on condition and were not subject to an AMR.
 
Group (d) Components such as system filters, fire hoses, fire extinguishers, self-contained
 
breathing apparatus (SCBA), and SCBA cylinders are considered consumables and are
 
routinely tested, inspected, and replaced when necessary. Periodic inspection procedures
 
specify the replacement criterion of these components that are routinely checked by tests
 
or inspections. Therefore, while these consumables are in the scope of license renewal, they are not subject to an AMR.
 
2.1.4.4.2 Staff Evaluation
 
The staff reviewed the applicant
=s 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 systems and components within the scope of license renewal was
 
documented in implementing procedures and scoping results reports for mechanical
 
systems. The scoping process defined the plant in terms of systems and structures.
Specifically, the implementing procedures ident ified the systems and structures that are subject to 10 CFR 54.4 review, described the processes for capturing the results of the 2-20 review, and were used to determine if the system or structure performed an intended function 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 applicant documented the results of the plant-level scoping process in accordance with
 
the guidance documents. The results were provided in the systems and structures
 
documents and reports which contained information including a description of the structure
 
or system, a listing of functions performed by the system or structure, 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 audit, the staff reviewed a sampling of the documents and reports and
 
concluded that the applicant's scoping results contained an appropriate level of detail to
 
document the scoping process.
 
2.1.4.4.3 Conclusion
 
Based on its review of the LRA, scoping and screening implementation procedures, and a
 
sampling of system scoping results during the audit, the staff concludes that the applicant
=s methodology identifies SSC types, and commodity groups within the scope of license renewal and their intended functions in accordance with the requirements of 
 
10 CFR 54.4.
 
2.1.4.5  Mechanical Component Scoping 2.1.4.5.1 Summary of Technical Information in the Application
 
In addition to the information previously discussed in Section 2.1.4.4.1, LRA Section 2.1.2
 
stated that for the mechanical scoping effort, summary-level boundary descriptions were
 
developed, along with a set of license renewal mechanical boundary drawings. The
 
mechanical boundary drawings were developed from the VEGP piping and instrumentation
 
diagrams and show the mechanical components within the scope of license renewal, including those components that are only within the scope of license renewal in accordance
 
with 10 CFR 54.4(a)(2), using color-coding. End points for the portions within the scope of
 
license renewal were clearly delineated. Notes were added to the drawings as necessary to
 
clarify the endpoints when they do not occur at a component or feature already depicted on
 
the drawing.
 
2.1.4.5.2 Staff Evaluation
 
The staff evaluated LRA Section 2.1.2 and the guidance in the implementing project
 
documents and reports to perform the review of mechanical scoping process. The project
 
documents and reports provided instructions for identifying the evaluation boundaries.
 
Determination of the mechanical system evaluation boundary required an understanding of
 
system operations in support of intended functions. 
 
This process was based on the review of design criteria documents, UFSAR, plant drawings
, maintenance rule scoping documents, technical specifications and bases,
 
safety evaluation reports,
 
equipment databases
,
master list of EQ equipment
, SBO analysis
: report, licensing correspondence
 
, and vendor documents. The evaluation boundaries for mechanical systems were documented on license renewal boundary drawings that were
 
created by marking mechanical piping and instrumentation diagrams to indicate the 2-21 components within the scope of license renewal. Components within the evaluation boundary were reviewed to determine whether they perform an intended function. Intended
 
functions were established based on whether a particular function of a component was
 
necessary to support the system functions that meet the scoping criteria.
 
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 concludes that the applicant's proceduralized methodology was
 
consistent with the description provided in the LRA Section 2.1 and the guidance contained
 
in the SRP-LR, Section 2.1, and was adequately implemented. 
 
The staff reviewed the applicant's methodology for identifying MSS and ECCS mechanical
 
component types 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 verified that the applicant had
 
identified and used pertinent engineering and licensing information in order to determine
 
the MSS and ECCS mechanical component types required to be within the scope of license
 
renewal. As part of the review process, the staff evaluated each system intended function
 
identified for the MSS and ECCS, the basis for inclusion of the intended function, and the
 
process used to identify each of the system component types. The staff verified that the
 
applicant had identified and highlighted system P&IDs to develop the license renewal
 
boundaries in accordance with the procedural guidance. The applicant was knowledgeable
 
about the process and conventions for establishing boundaries as defined in the license
 
renewal implementation procedures. Additionally, the staff verified that the applicant had
 
independently verified the results in accordance with the governing procedures.
 
Specifically, other 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.
 
2.1.4.5.3 Conclusion
 
Based on its review of the LRA, scoping implementation procedures, the systems sampled, and discussions with the applicant, the staff concludes that the applicant
=s methodology for identifying mechanical systems within the scope of license renewal is in accordance with the requirements of 10 CFR 54.4.
 
2.1.4.6 Structural Scoping 2.1.4.6.1 Technical Information in the Application
 
In addition to the information previously discussed in Section 2.1.4.4.1, LRA Section 2.1.2
 
stated that the structural scoping effort, summary-level boundary descriptions were
 
developed. Generally, the VEGP scoping process used a A spaces@ approach in establishing 2-22 the evaluation boundaries. With few exceptions, the scoping for a building or structure was the entire building. Individual license renewal drawings were not created for structures and
 
were not necessary since the spaces approach was being used. A single boundary drawing
 
based on the site plot plan drawing was created, however. This license renewal structural
 
boundary drawing showed the in scope structures using color-coding, and displays the
 
spatial relationship of the plant structures to one another.
 
2.1.4.6.2 Staff Evaluation
 
The staff reviewed the applicant
=s approach for identifying structures relied upon to perform the functions described in 10 CFR 54.4(a). As part of this review, the staff discussed the methodology with the applicant, reviewed the documentation developed to support the
 
review, and evaluated the scoping results for several structures that were identified within
 
the scope of license renewal. 
 
The applicant had identified and developed a list of plant structures and the structures
 
intended functions through a review of design criteria documents, UFSAR, plant drawings, maintenance rule scoping documents, technical specifications and bases, safety evaluation
 
reports, equipment databases, licensing correspondence, and vendor documents. Each structure was evaluated against the criteria of 10 CFR 54.4 (a)(1), (a)(2) and (a)(3). 
 
The staff reviewed selected portions of the UFSAR, maintenance rule documents, design
 
criteria, and structural drawings, implementing procedures and selected AMR reports to
 
verify the adequacy of the methodology. In addition, staff reviewed the scoping results, including information contained in the source documentation, for the NSCW cooling tower
 
building to verify that application of the methodology would provide the results as
 
documented in the LRA. The staff reviewed the applicant's methodology for identifying
 
structures 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 verified that the applicant had identified and used
 
pertinent engineering and licensing information in order to determine the NSCW tower
 
structure and components required to be within the scope of license renewal. As part of the
 
review process, the staff evaluated the intended functions identified for the NSCW tower
 
and components, the basis for inclusion of the intended function, and the process used to
 
identify each of the component types. Additionally, the staff verified that the applicant had
 
independently verified the results in accordance with the governing procedures. 
 
2.1.4.6.3 Conclusion
 
Based on the staff's review of information in the LRA, scoping implementation procedures, and a sampling review of structural scoping results, the staff concludes that the applicant's
 
methodology for identification of the structures within the scope of license renewal is in
 
accordance with the requirements of 10 CFR 54.4.
 
2.1.4.7 Electrical Component Scoping 2.1.4.7.1 Technical Information in the Application
 
LRA Section 2.1.2, states that for the electrical scoping effort, boundary drawings were not
 
needed since the screening was performed using a A Plant-Wide Spaces Approach.
@  LRA Section 2.5.1, A Plant-Wide Electrical,@ states that plant-wide electrical was the designation 2-23 used by VEGP in the LRA for the sole purpose of grouping electrical components into one system grouping for scoping, screening, and an AMR. Identification of in-scope electrical
 
and I&C components was performed on a generic component type basis. The electrical and
 
I&C component types associated with the in-scope electrical and I&C systems and in-scope mechanical systems and civil structures, were also identified generically.
 
2.1.4.7.2 Staff Evaluation
 
The staff evaluated LRA Sections 2.1.2 and 2.5.1 and the applicants implementing
 
procedures and AMR reports that governed the electrical scoping methodology. The
 
applicant had reviewed the electrical and I&C systems in accordance with the requirements
 
of 10 CFR 54.4 and determined which systems were to be included within the scope of
 
license renewal. During the scoping process, the applicant used the design criteria
 
documents, UFSAR
 
, plant drawings, maintenance rule scoping documents, technical specifications and bases
,
safety evaluation reports,
 
equipment databases
,
master list of EQ equipment
, SBO analysis report, licensing correspondence
 
, and vendor documents.
All electrical and I&C components contained in plant systems and electrical systems contained in mechanical or structural systems were included within the scope of license
 
renewal. The applicant reviewed fuse-holders using the plant fuse documentation and
 
drawings and did not identify any fuse holders to be included within the scope of license
 
renewal. The applicant reviewed the application of tie-wraps to determine if credit had been
 
taken in the CLB for tie-wrap use or if nonsafety-related tie-wraps could affect a safety-
 
related function, but did not identify any tie-wraps to be included within the scope of license
 
renewal. The staff reviewed selected portions of the data sources and selected several
 
examples of components for which the applicant demonstrated the process used to
 
determine electrical components were within the scope of license renewal. The results of
 
the staff=s review of the implementation of the SBO scoping methodology is discussed in Section 2.5.
 
2.1.4.7.3 Conclusion
 
On the basis of the review of information contained in the LRA, scoping implementation
 
procedures, and a sampling review of electrical scoping results, the staff concludes that the
 
applicant=s methodology for identification of electrical components within the scope of license renewal is in accordance with the requirements of 10 CFR 54.4.
2.1.4.8 Scoping Methodology Conclusion On the basis of a review of the LRA and the scoping implementation procedures, the staff
 
concludes that the applicant's scoping methodology is consistent with the guidance
 
contained in the SRP-LR and identifies those SSCs (1) that are safety-related, (2) whose
 
failure could affect safety-related functions, and (3) that are necessary to demonstrate
 
compliance with the NRC's regulations for Fire Protection, Environmental Qualification, Pressurized Thermal Shock, Anticipated Transient Without Scram and Station Blackout.
 
The staff concludes that the applicant
=s methodology is consistent with the requirements of 10 CFR 54.4(a), and is therefore, acceptable.
 
2-24 2.1.5 Screening Methodology 2.1.5.1 General Screening Methodology 2.1.5.1.1 Technical Information in the Application
 
In LRA Section 2.1.3, A Screening Methodology,@ the applicant discussed the process for determining which components and structural elements require an AMR. Screening identifies SCs within the scope of license renewal that perform an intended function as
 
described in 10 CFR 54.4, without moving parts or without a change in configuration or
 
properties and that are not subject to replacement based on a qualified life or specified time
 
period. The screening process determines the SCs subject to an AMR by:
 
$ Listing the in-scope SCs by component type using the scoping results for a particular system or structure;
$ A Screening@ the component types for the passive and long-lived criteria; and
$ Identifying the intended function(s) performed by the passive and long-lived SCs by component type for the in-scope system or structure.
The result was a tabulation of the in-scope passive long-lived SCs that perform intended
 
functions and therefore require an AMR. The screening process grouped SCs into
 
component groups (component types) based on similarity of design and purpose. Use of
 
component groups enables evaluation of entire groups of SCs in a single screening
 
evaluation. The screening process followed the recommendations of NEI 95-10.
A Active@ and A short-lived
@ determinations were made consistent with NEI 95-10. Components or structural elements that were either active or subject to replacement based on a qualified life were "screened out
@ as not subject to an AMR.
2.1.5.1.2 Staff Evaluation
 
Pursuant to 10 CFR 54.21, each LRA must contain an Integrated Plant Assessment (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 under all design
 
conditions imposed by the plant specific CLB for the period of extended operation.
 
The staff reviewed the methodology used by the applicant to determine if mechanical and
 
structural components and electrical commodity groups within the scope of license renewal
 
should be subject to an AMR. The applicant implemented a process for determining which
 
SCs were subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1). In
 
LRA Section 2.1.3, the applicant discussed these screening activities as they related to the
 
component types and commodity groups within the scope of license renewal.
 
2-25 The screening process evaluated the component types and commodity groups, included within the scope of license renewal, to determine which ones were long-lived and passive
 
and therefore subject to an AMR. The staff reviewed Section 2.3, Section 2.4, and Section
 
2.5 of the LRA 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 MSS and ECCS and the NSCW tower.
 
The applicant provided the staff with a detailed discussion of the processes used for each
 
discipline and provided administrative doc umentation that described the screening methodology. Specific methodology for mechanical, electrical, and structural is discussed
 
below.
 
2.1.5.1.3 Conclusion
 
On the basis of a review of the LRA, the screening implementation procedures and a
 
sampling of screening results, the staff concludes that the applicant
=s screening methodology was consistent with the guidance contained in the SRP-LR and was capable of identifying passive, long-lived components in-scope of license renewal that are subject to
 
an AMR. The staff concludes that the applicant
=s process for determining which component types and commodity groups subject to an AMR is consistent with the requirements of 10 CFR 54.21.
2.1.5.2 Mechanical Component Screening 2.1.5.2.1 Summary of Technical Information in the Application
 
LRA Section 2.1.3.1, A Screening of Mechanical Systems,@ discusses 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. For mechanical systems, a sy stematic process was used to identify the components that require an AMR. The mechanical component screening included the
 
following steps: (1) identifying the in-scope SCs and associated component types using the
 
license renewal mechanical boundary information and drawings created during the scoping
 
process; (2) evaluating the component types against the active/passive and long-
 
lived/short-lived criteria of 10 CFR 54.21(a)(1)(i) and (ii); and (3) identifying the component
 
intended functions for the passive and long-lived component types. For each system, the
 
applicable component types for the components and component groups were identified and
 
listed. The criteria of 10 CFR 54.21(a)(1)(i) and (ii) were applied to identify the passive long-
 
lived component types. Component intended functions were also identified. The
 
components that contribute to the performance of a system intended function, and perform
 
their function without moving parts and without a change in configuration or properties, and
 
are not subject to replacement based on a qualified life or specified time period were
 
subject to an AMR.
 
2.1.5.2.2 Staff Evaluation
 
The staff evaluated the mechanical screening methodology discussed and documented in
 
LRA Section 2.1.3.1, the implementing guidance documents, the AMR reports, and the
 
license renewal drawings. The mechanical system screening process began with the
 
results from the scoping process. The applicant reviewed each system evaluation boundary 2-26 as illustrated on P&IDs to identify passive and long-lived components. Within the system evaluation boundaries, all passive, long-lived components that perform or support an
 
intended function were subject to an AMR. The results of the review are documented in the
 
AMR reports. The AMR reports contain information such as the information sources
 
reviewed and the system intended functions.
 
The staff reviewed the results of the boundary evaluations and discussed the process with
 
the applicant. The staff verified that mechanical system evaluation boundaries were
 
established for each system within the scope of license renewal and that the boundaries
 
were determined by mapping the system intended function boundary onto P&IDs. The
 
applicant reviewed the components within the system intended function boundary to
 
determine if the component supported the system intended function. Those components
 
that supported the system intended function were reviewed to determine if the component
 
was passive and long lived and therefore subject an AMR.
 
The staff reviewed selected portions of design criteria documents, UFSAR,
 
plant drawings, maintenance rule scoping documents, and selected AMR reports. The staff conducted
 
detailed discussions with the applicant
=s license renewal team and reviewed documentation pertinent to the screening process. The staff assessed if the mechanical screening methodology outlined in the LRA and procedures was appropriately implemented and if the
 
scoping results were consistent with CLB requirements. The staff also reviewed the
 
mechanical screening results for the MSS and ECCS to verify proper implementation of the
 
screening process. Based on these audit activities, the staff did not identify any
 
discrepancies between the methodology documented and the implementation results. 
 
2.1.5.2.3 Conclusion
 
Based on its review of the LRA, the screening implementation procedures, and a sample of
 
the MSS and ECCS screening results, the staff concludes that the applicant
=s mechanical component screening methodology is consistent with SRP-LR guidance. The staff concludes that the applicant
=s methodology for identification of passive, long lived mechanical components within the scope of license renewal and subject to an AMR is in accordance with the requirements of 10 CFR 54.21(a)(1).
2.1.5.3 Structural Component Screening 2.1.5.3.1 Technical Information in the Application
 
LRA Section 2.1.3.2, A Screening of Structures,@ states that the screening process was applied to in-scope buildings and civil structures to identify the structural elements to be evaluated in the AMRs. Screening evaluation boundaries were established based on the
 
scoping boundary results. A A Component Supports and Bulk Commodities
@ screening evaluation boundary was also established to address common components within the in-scope structures. The scoping and screening process used a A spaces@ approach in establishing the evaluation boundaries and with few exceptions, the scoping and screening boundary for a building or structure was the entire building. The listing of structural
 
elements was facilitated by grouping components into component groups since structural
 
components and commodities often do not have unique identifiers such as those given to
 
mechanical components. Structural components and commodities were identified based on
 
materials of construction and functional applications to categorize them for AMRs. A list of
 
structural components and component groups was developed for each structural evaluation 2-27 boundary. Since structures are inherently passive, and with few exceptions long-lived, the screening of structural components and commodi ties was based primarily on whether or not they perform an intended function. 
 
Structural components that perform an intended function without moving parts and without
 
a change in configuration or properties, and that are not subject to replacement based on a
 
qualified life or specified time period were subject to an AMR.
2.1.5.3.2 Staff Evaluation
 
The staff reviewed the applicant
=s 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 within the scope of license renewal. 
 
The staff reviewed the applicant's methodology used for structural screening described in
 
LRA Section 2.1.3.2 and in the applicant's implementing guidance and AMR reports. The
 
applicant had performed the screening review in accordance with the implementation
 
guidance and captured pertinent structure design information, component, materials, environments, and aging effects. The staff verified that the applicant had determined that
 
structures are inherently passive and long-lived, such that the screening of structural
 
components and commodities was based primar ily on whether they perform an intended function. Structural components were grouped as commodities based on materials of
 
construction. The primary task performed by the applicant during the screening process
 
was to evaluate structural components to identify intended functions as they relate to
 
license renewal. 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 reviewed selected portions of the design criteria documents, UFSAR,
 
plant drawings, maintenance rule scoping documents, structural drawings, implementing
 
procedures and selected AMR reports. The staff conducted detailed discussions with the
 
applicant=s LR team and reviewed documentation pertinent to the screening process. The staff assessed if the screening methodology outlined in the LRA and procedures was appropriately implemented and if the scoping results were consistent with CLB
 
requirements. The staff also reviewed structural screening results for the NSCW tower to
 
verify proper implementation of the screening process. Based on these audit activities, the
 
staff did not identify any discrepancies between the methodology documented and the
 
implementation results. 
 
2.1.5.3.3 Conclusion
 
On the basis of the staff
=s review of information contained in the LRA, the applicant's detailed screening implementation procedures, and a sampling review of structural screening results, the staff concludes that the applicant's methodology for identification of
 
structural components within the scope of license renewal and subject to an AMR is in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
 
2-28 2.1.5.4 Electrical Component Screening 2.1.5.4.1 Technical Information in the Application
 
LRA Section 2.1.3.3 stated that VEGP used a "plant-wide spaces" approach for electrical
 
and I&C screening. Electrical component types were screened on a plant-wide basis
 
without regard to plant system. The spaces approach used was consistent with the
 
approach described in NEI 95-10, Revision 6. A screening evaluation boundary was
 
created which included all of the in-scope electrical and I&C systems, and the electrical 
 
and I&C portions of the in-scope mechanical systems. This plant-wide electrical boundary
 
permitted the screening evaluation to be consolidated under one system boundary.
The electrical and I&C component types in use at VEGP were identified and listed. The
 
listing provided by NEI 95-10 Appendix B, as well as plant-specific document reviews were
 
the basis for this list. Electrical component types were organized into component groups.
 
The electrical and I&C component groups were identified from a review of plant documents, drawings, equipment databases, and interface with the parallel mechanical and
 
civil/structural screening efforts. Following the identification of the electrical and I&C
 
component commodity groups, the Apassive@ screening criterion of 10 CFR 54.21(a)(1)(i) was applied to identify component groups that perform their intended function(s) without moving parts or without a change in configuration or properties. These passive components
 
were identified utilizing the guidance of NEI 95-10 and the Electric Power Research
 
Institute (EPRI) License Renewal Electrical Handbook. 
 
The A short-lived
@ screening criterion of 10 CFR 54.21(a)(1)(ii) was then applied to those specific component groups that were not previously eliminated. The A short-lived
@ screening criterion found in 10 CFR 54.21(a)(1)(ii) excludes those components or commodity groups that are subject to replacement based on a qualified life or specific time period from the
 
requirements of an AMR. Electrical com ponents included in the plant EQ program are replaced on a specified interval based on a qualified life. Therefore, components in the EQ
 
program do not meet the A long-lived
@ criteria of 10 CFR 54.21(a)(1)(ii) and are A short-lived
@ per the regulatory definition. 
 
The passive component types that are not subject to replacement based on a qualified life
 
or specified time period and were subject to an AMR were determined to include cables, connectors, fuse holders, and various switchyard components.
 
2.1.5.4.2 Staff Evaluation
 
The staff reviewed the applicant
=s methodology used for electrical screening in LRA Sections 2.1.3.3 of the LRA and the applicant's implementation procedures and AMR 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 information
 
contained in NEI 95-10, plant documents and drawings, the EQ master list, and the EPRI
 
License Renewal Electrical Handbook as data sources to identify the electrical and I&C
 
components.
The applicant identified two commodity groups which were determined to meet the passive
 
criteria in accordance with NEI 95-10. The applicant evaluated the identified, passive
 
commodities to identify whether they were subject to replacement based on a qualified life
 
or specified time period (short-lived), or not subject to replacement based on a qualified life 2-29 or specified time period (long-lived). The remaining passive, long lived components were determined to be subject to an AMR. The staff reviewed the screening of selected
 
components to verify the correct implementation of the methodology. 
 
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 concludes that the applicant
=s methodology was consistent with the description provided in LRA and the applicant
=s implementing procedures. On the basis of a review of information contained in the LRA, the applicant
=s screening implementation procedures, and a sampling review of electrical screening results, the staff concludes that the applicant
=s methodology for identification of electrical commodity groups within the scope of license renewal and subject to an AMR is in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.1.5.5 Screening Methodology Conclusion On the basis of a review of the LRA, the screening implementation procedures, discussions
 
with the applicant
=s staff, and a sample review of screening results, the staff concludes that the applicant's screening methodology was consistent with the guidance contained the SRP-LR and identified those passive, long-lived components within the scope of license
 
renewal that are subject to an AMR. The staff concludes that the applicant
=s methodology is consistent with the requirements of 10 CFR 54.21(a)(1), and is therefore acceptable.
2.1.6 Summary of Evaluation Findings The staff review of the information presented in LRA Section 2.1, the supporting information
 
in the scoping and screening implementation procedures and reports, the information
 
presented during the scoping and screening methodology audit, and the applicant
=s responses to the staff
=s RAIs dated February 27, 2008, formed the basis of the staff
=s determination. The staff verified that the applicant
=s scoping and screening methodology was consistent with the requirements of the Rule. From this review, the staff concludes that the applicant
=s methodology for identifying SSCs within the scope of license renewal and SCs requiring an AMR is consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1), and is therefore acceptable.
2.1.7 References
: 1. LRA, Vogtle Electric Generating Plant, Units 1 and 2, dated June 29, 2007. 
: 2. NUREG-1800, A Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants,@ Revision 1, dated September 2005.
: 3. NEI 95-10, A Industry Guideline for Implementing the Requirements of 10 CFR 54 - The License Renewal Rule,@ Revision 6, dated September 2005.
: 4. Scoping and Screening Methodology audit Trip Report Regarding the Southern Nuclear Operating Company, Inc., License Renewal Application for the Vogtle Electric
 
Generating Plant, Units 1 and 2, dated June 29, 2007.
 
2-30 2.2 Plant-Level Scoping Results 2.2.1. Technical Information in the Application In LRA Table 2.2-1 the applicant listed plant me chanical systems, structural systems, and electrical and instrumentation and controls systems within the scope of license renewal.
 
Based on the DBEs considered in the plant's CLB, other CLB information relating to
 
nonsafety-related systems and structures, and certain regulated events, the applicant
 
identified plant-level systems and structures within the scope of license renewal as defined
 
by 10 CFR 54.
 
2.2.2 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 staff's review focused on the implementation results shown in LRA Tables 2.2-1, and 2.2-2 to confirm that there
 
were no omissions of plant-level systems and structures within the scope of license
 
renewal.
 
The staff concludes whether the applicant proper ly identified the systems and structures within the scope of license renewal in accordance with Title 10 of the Code of Federal Regulations (10 CFR) Part 54.4. The staff reviewed selected systems and structures that the applicant identified as not 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 staff's review of the applicant's implementation was
 
conducted in accordance with the guidance in SRP-LR Section 2.2, "Plant-Level Scoping
 
Results."
 
The staff's review of LRA Section 2.2 identified areas in which additional information was
 
necessary to complete the review of the applicant's scoping and screening results. 
 
The applicant responded to the staff's RAIs as discussed below.
 
In RAI 2.2-1, dated January 28, 2008, the staff noted that the LRA Table 2.2-2 defines the
 
circulating water (CW) system, System No. 1401, as not within the scope of license
 
renewal. Similar plant designs have identified their CW systems as being within scope
 
based on 10 CFR 54.4(a)(2). The applicant was asked to provide additional information to
 
justify exclusion of the CW system with respect to the applicable requirements of
 
10 CFR 54.4(a).
 
In its response, dated February 27, 2008, the applicant stated:
 
The CW system components are located entirely within the Turbine
 
Building, or in outside areas remote from any safety related systems, structures, or components (SCs). The CW system is not attached to any
 
safety related SCs. Refer to the answer to RAI 2.1-2 for discussion
 
regarding non-safety related components in the Turbine Building. The
 
Circulating Water System components in the outside areas are physically located such that there is no potential for interaction with a safety related 2-31 SC. Therefore, the CW system is not in scope for the 10 CFR 54.4(a)(2) scoping criteria.
 
Based on its review, the staff finds the applicant's response to RAI 2.2-1 acceptable, because the applicant provided clarification as to why the CW system is not in scope with
 
respect to the applicable requirement of 10 CFR 54.4(a); therefore, the staff's concern
 
described in RAI 2.2-1 is resolved. 
 
In RAI 2.2-2, dated January 28, 2008, the staff noted that LRA Table 2.2-2 defines the
 
turbine plant closed cooling water system, System No. 1404, as not within the scope of
 
license renewal. However, the turbine plant cooling water system (System No. 1405), LRA
 
section 2.3.3.7, is identified as being within the scope of license renewal based on
 
10 CFR 54.4(a)(2). It appears these two systems are very similar. The applicant was asked
 
to provide additional information to justify exclusion of the turbine plant closed cooling water
 
system with respect to the applicable requirements of 10 CFR 54.4(a).
In its response, dated February 27, 2008, the applicant stated:
The Turbine Plant Cooling Water System, System No. 1405, is in scope
 
based on 10 CFR 54.4(a)(2) because it supplies cooling water to the
 
CVCS Chiller, the Steam Generator Blowdown Trim Heat Exchangers, and corrosion product monitors which are located in the Auxiliary
 
Building. With certain exceptions based on location, those portions of the
 
Turbine Plant Cooling Water System which are located in the Auxiliary
 
Building are in scope for potential spatial interaction. - the Turbine Plant
 
Cooling Water System components which are located in Room 124, the
 
CVCS Chiller Pumps Room, are not in scope-There are no safety
 
related components in Room 124, therefore, there is no potential for
 
spatial interaction, so the components located in this room are not within
 
the scope of license renewal for 10 CFR 54.4(a)(2).
 
The Turbine Plant Closed Cooling Water System, System No. 1404, is
 
not in scope based on 10 CFR 54.4(a)(2) because its components are
 
located entirely within the Turbine Building. Refer to the answer to RAI
 
2.1-2 for discussion regarding non-safety related components in the
 
Turbine Building.
 
Based on its review, the staff finds the applicant's response to RAI 2.2-2 acceptable, because the applicant provided clarification as to why the Turbine Plant Closed Cooling
 
Water System is not in scope with respect to the applicable requirement of 10 CFR 54.4(a).
 
Therefore, the staff's concern described in RAI 2.2-2 is resolved.
 
2.2.3 Conclusion The staff reviewed LRA Section 2.2, the RAI responses, 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 the applicant has adequately identified, in accordance with
 
10 CFR 54.4, the systems and structures within the scope of license renewal.
 
2-32 2.3 Scoping and Screening Results - Mechanical Systems This section documents the staff's review of the applicant's scoping and screening results
 
for mechanical systems. Specifically, this section discusses:
 
reactor vessel, reactor vessel internals, and 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 applicant must list passive, long-lived SCs within the scope of license renewal and subject to an AMR. To verify that
 
the applicant properly implemented its methodology, the staff's review focused on the
 
implementation results. This focus allowed the staff to confirm that there were no omissions
 
of mechanical system components that meet the scoping criteria and are subject to an
 
AMR.
 
The staff's 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 mechanical
 
systems that appear to meet the license renew al scoping criteria. Similarly, the staff evaluated the applicant's screening results to verify that all passive, long-lived components
 
are 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 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 delineated under 10 CFR 54.4(a). The
 
staff also reviewed the licensing basis documents to determine whether the LRA specified
 
all intended functions delineated under 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 applicant's screening results.
 
For those SCs with intended functions delineated under 10 CFR 54.4(a), 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 described in 10 CFR 54.21(a)(1). For those meeting neither of
 
these criteria, the staff sought to confirm that these SCs are 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) Branch Systems
 
There are 98 mechanical systems identified as within scope in the LRA, of which 51
 
systems are BOP systems. Thes e 51 systems include most of the auxiliary systems and all the steam and power conversion systems. The st aff performed a two-tier scoping review for the BOP systems. 
 
2-33 A Tier 1 review is a less detailed review where the staff reviews the LRA and UFSAR to determine if the applicant failed to identify any component type that is typically found within
 
the scope of license renewal. During this review the staff evaluated the system's function(s)
 
described in the LRA and UFSAR to verify the applicant has not omitted from the scope of
 
license renewal any component types with the intended functions delineated under 10 CFR
 
54.4(a).
 
A Tier 2 review is a detailed review of the LRA, UFSAR, and license renewal boundary
 
drawings to determine if the applicant failed to identify any components within the scope of
 
license renewal and any components subject to an AMR. During this review the staff
 
evaluated the system's function(s) described in the LRA and UFSAR to verify the applicant
 
did not omit from the scope of license renewal any components with intended functions
 
delineated under 10 CFR 54.4(a). The staff then reviews those components that the
 
applicant has identified as within the scope of license renewal to verify that the applicant
 
has not omitted any passive, long-lived components subject to an AMR in accordance with
 
10 CFR 54.21.
 
In determining the level of review (i.e., Tier 1 vs. Tier 2), the staff reviewed the LRA and the
 
UFSAR description for each BOP system, focu sing on the system's intended function(s).
Tier 2 reviews were performed on systems that have:
 
safety significance or risk significance o high safety significant systems o common cause failure of redundant trains  operating experience indicating likely passive failure  previous LRA experience
 
Examples of safety important or risk signifi cant systems are the diesel generator (DG) and support systems and the emergency service water (ESW) system. An example of a system whose failure could result in common cause failure of redundant trains is a drain system
 
providing flooding protection. Examples of systems with operating experience indicating likely passive failures include the main steam system (MSS), feedwater system, and service water system. Examples of systems with i dentified omissions in previous LRA reviews include spent fuel cooling system and mak eup water sources to safety systems.
2.3.1  Reactor Vessel, Reactor Vessel Internals, and Reactor Coolant System LRA Section 2.3.1 identifies the reactor vessel, reactor vessel internals, and reactor coolant
 
system (RCS) SCs subject to an AMR for license renewal. The applicant described the
 
supporting SCs of the reactor vessel, internals, and RCS in the following LRA sections:
 
2.3.1.1  Reactor vessel  2.3.1.2  Reactor vessel internals 2.3.1.3  RCS and connected lines 2.3.1.4  Pressurizer 2.3.1.5  Steam generators
 
The reactor vessel, reactor vessel internals, and RCS contain safety-related components
 
relied upon to remain functional during and following DBEs. The failure of nonsafety-related
 
SCs in the RCS potentially could prevent the satisfactory accomplishment of a safety-2-34 related function. In addition, the RCS performs functions that support fire protection, PTS, SBO, and EQ.
 
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: 
 
The reactor vessel system boundary includes the reactor vessel and system
 
portions, including the control rod drive mechanism pressure boundary
 
components and pressure boundary components for both incore flux and
 
core cooling monitoring instrumentation, effectively constituting a part of the
 
reactor coolant pressure boundary. The cylindrical reactor vessel has a
 
welded hemispherical bottom head and a hemispherical upper closure head
 
and contains the core, core supporting structures, control rods, and other
 
core parts addressed in the next section. The upper closure head has
 
penetrations for control rod drive mechanisms (CRDMs), thermocouples, reactor vessel level instrumentation system instruments, and a head vent.
 
The vessel shell has inlet and outlet nozzles in a horizontal plane just below
 
the reactor vessel flange but above the top of the core. The bottom head has
 
penetrations for connection and entry of nuclear incore instrumentation.
 
Conduits extend from the nuclear incore instrumentation penetrations down
 
through the concrete shield area and up to a thimble seal table. The conduits
 
and seal table mechanical seals provide the pressure barrier between the
 
reactor coolant and the containment atmosphere.
 
LRA Table 2.3.1.1 identifies reactor vessel component types within the scope of license
 
renewal and subject to an AMR. The intended functions of the reactor vessel component
 
types within the scope of license renewal include: 
 
pressure-retaining boundary structural/functional support for safety-related/nonsafety-related components with maintenance of physical integrity and flow path
 
considerations 2.3.1.1.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.1.1 and UFSAR Sections 5.3, 7.7.2.7, and 7.7.2.8
 
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."
 
During 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 delineated under 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2-35 In RAI- 2.3.1-1 dated January 28, 2008, the staff requested the applicant to verify that the "hold-down spring", listed in LRA Table 2.3.1.2 is the same spring described in UFSAR
 
3.9.5.1.2, Upper Core Support Assembly, which restrains axial movements of the upper and
 
lower core support assemblies. In its response dated February 27, 2008, the applicant
 
verified the spring was the same. The staff finds this response acceptable because the components are included in-scope for license renewal.
2.3.1.1.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether
 
the applicant failed to identify any SCs within the scope of license renewal. The staff finds
 
no such omissions. In addition, the staff's 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 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 consisting of the lower core
 
support, the upper core support, and the incore instrumentation support structures and
 
including the fuel and control rod drive assemblies. The reactor vessel internals support the
 
core, maintain fuel alignment, limit fuel assembly movement, maintain alignment between
 
fuel assemblies and CRDMs, direct coolant flow past the fuel elements and to the pressure
 
vessel head, provide gamma and neutron shielding and provide guides for the incore
 
instrumentation.
 
The lower core support structure consists of the core barrel, the core baffle, the lower core plate and support columns, the neutron shield pads, and the
 
core support, which is welded to the core barrel. The lower core support
 
structure is supported at its upper flange from a ledge in the reactor vessel
 
and restrained at its lower end by a radial support system attached to the
 
vessel wall. The upper core support structure consists of the upper support, the upper core plate, the support columns, and the guide tube assemblies.
 
The incore instrumentation support structures consist of an upper system to
 
convey and support thermocouples penetrating the vessel through the head
 
and a lower system to convey and suppor t flux thimble tubes penetrating the vessel through the bottom.
 
LRA Table 2.3.1.2 identifies reactor vessel internals component types within the scope of
 
license renewal and subject to an AMR. The intended functions of the reactor vessel
 
internals component types within the scope of license renewal include:
 
reactor core support and orientation  control rod assembly support, orientation, guidance, and protection  passageway for the distribution of reactor coolant to the reactor core 2-36  passageway for incore instrumentation support, guidance, and protection  secondary core support to limit core support structure downward displacement  reactor vessel gamma and neutron shielding 2.3.1.2.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.1.2 and UFSAR Section 3.9.5 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.1.2.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 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 System and Connected Lines 2.3.1.3.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.1.3 describes the RCS and connected lines:
 
The RCS consists of four similar heat transfer loops connected in parallel to
 
the reactor pressure vessel. Each loop has a reactor coolant pump (RCP),
steam generator, piping, and valves. In addition, the system includes a
 
pressurizer, pressurizer relief and safety valves, the reactor vessel head vent
 
system, interconnecting piping, reactor vessel level instrumentation system
 
instruments, and instrumentation for operational control. The pressurizer and
 
steam generators are addressed separately in following sections. All these
 
components are located in the containment building. During operation, the
 
RCS transfers the heat generated in the core to the steam generators that
 
drive the turbine-generator. Borated demineralized water circulating in the
 
RCS at a flow rate and temperature for reactor core thermal-hydraulic
 
performance acts as a neutron moderator and reflector and as a solvent for
 
the neutron absorber for chemical shim control. The design of the RCS
 
pressure boundary that provides a barrier against the release of radioactivity 2-37 generated within the reactor is for high integrity throughout the life of the plant.
The pressurizer controls RCS pressure by electrical heaters and water sprays that maintain
 
water and steam at saturation conditions. Steam can be formed (by the heaters) or
 
condensed (by the pressurizer spray) to minimize pressure variations due to contraction
 
and expansion of the reactor coolant. Spring-loaded safety and power-operated relief
 
valves of the pressurizer discharge from the RCS steam then piped to the pressurizer relief
 
tank (pressurizer relief discharge system), mixed with quench water, condensed, and
 
cooled.
 
LRA Table 2.3.1.3 identifies RCS and connected lines component types within the scope of
 
license renewal and subject to an AMR. The intended functions of the reactor coolant
 
system and connected lines component types within the scope of license renewal include:
 
prevention of flame propagation from i gnition of vent pipe vapors back to the source  restriction of process flow  pressure-retaining boundary 2.3.1.3.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.1.3 and UFSAR Section 7.7.2.8 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.1.3.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 the applicant has adequately identified the reactor coolant
 
system and connected lines 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).
 
2.3.1.4  Pressurizer 2.3.1.4.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.1.4 describes the pressurizer, which controls RCS pressure by maintaining
 
water and steam in equilibrium by electrical heaters and coolant sprays. Steam can be 2-38 formed or condensed to minimize pressure variations caused by contraction or expansion of the reactor coolant. The pressurizer upper head has spring-loaded safety and power-
 
operated relief valves. The pressurizer is a vertical, cylindrical vessel with hemispherical top
 
and bottom heads. Spray line nozzles and relief and safety valve connections are located in
 
the top head. The pressurizer surge line connects the pressurizer bottom nozzle to a
 
reactor coolant hot leg. 
 
Removable electric heaters are installed in the bottom head. 
 
LRA Table 2.3.1.4 identifies pressurizer component types within the scope of license
 
renewal and subject to an AMR. The intended functions of the pressurizer component types
 
within the scope of license renewal include:
 
pressure-retaining boundary  structural/functional support for safety-related/nonsafety-related components with maintenance of physical integrity and flow path considerations 2.3.1.4.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.1.4 and UFSAR Section 5.4.10 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). 
 
The staff then reviewed those components that the applicant 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 in accordance with the requirements of
 
10 CFR 54.21(a)(1).
 
2.3.1.4.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 the applicant has adequately identified the pressurizer
 
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).
 
2.3.1.5  Steam Generators 2.3.1.5.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.1.5 describes the steam generators, four installed in each unit, one in each
 
reactor coolant loop. All steam generators are Westinghouse Model F, vertical U-tube
 
steam generators with moisture-separating equipment. On the primary side, reactor coolant
 
flows through the inverted U-tubes, entering and exiting through the nozzles in the 2-39 hemispherical steam generator bottom head divided into inlet and outlet chambers by a vertical partition plate extending from the head to the tube sheet.
 
On the secondary side, feedwater flows directly into the annulus formed by the outer shell
 
and tube bundle wrapper before entering the boiler section of the steam generator. The
 
water and steam mixture then flows upward through the tube bundle and into the steam
 
drum section. Centrifugal moisture separators, located above the tube bundle, remove most
 
of the moisture entrained in the steam. Steam dryers further improve the steam quality.
 
LRA Table 2.3.1.5 identifies steam generators component types within the scope of license
 
renewal and subject to an AMR. The intended functions of the steam generators
 
component types within the scope of license renewal include:
 
heat exchange between fluid media  spray shield or curbs for flow direction  Flow pattern or distribution provision  restriction of process flow  physical integrity maintenance to prevent generation of debris or loose parts which could interfere with a safety-related function  pressure-retaining boundary  structural/functional support for safety-related/nonsafety-related components with maintenance of physical integrity and flow path considerations 2.3.1.5.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.1.5 and UFSAR Section 5.4.2 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.1.5.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 the applicant has adequately identified the steam
 
generators 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).
2-40  2.3.2  Engineered Safety Features LRA Section 2.3.2 identifies the engineered safety features SCs subject to an AMR for
 
license renewal.
 
The applicant described the supporting SCs of the engineered safety features in the
 
following LRA sections:
 
Containment Spray System  Emergency Core Cooling Systems  Containment Isolation Systems 2.3.2.1  Containment Spray System 2.3.2.1.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.2.1 describes the containment spray system, which provides borated
 
water for removing decay heat and iodine from the containment atmosphere in post-
 
accident conditions. The system consists of two trains, each with a pump, spray ring header
 
and spray nozzles, valves, and connecting piping. Baskets with trisodium phosphate
 
located on the containment floor control post-accident sump pH by mixing with the
 
recirculating borated water. Containment emergency sumps located in containment collect
 
borated water to provide suction to the containment spray pumps for recirculation after
 
initial injection.
 
Water from the refueling water storage tank (RWST) provides suction to the containment
 
spray pumps for initial injection. At the latter stages of the injection phase, operators initiate
 
a manual switch-over to recirculation in which the containment spray pumps take suction
 
from the containment emergency sumps. Each sump has a suction strainer to prevent
 
debris from entering the containment spray system, which is designed to operate over an extended period of time in environmental condi tions following a reactor coolant system failure.
 
The containment spray system contains safety-related components relied upon to remain
 
functional during and following DBEs. The failure of nonsafety-related SCs in the
 
containment spray system potentially could pr event the satisfactory accomplishment of a safety-related function. In addition, the containment spray system performs functions that
 
support EQ.
 
LRA Table 2.3.2.1 identifies containment spra y system component types within the scope of license renewal and subject to an AMR: 
 
capillary tubing (sealed) for Containment (CTMT) pressure sensors  closure bolting  eductors - CTMT spray  encapsulation vessels  flow orifice/elements  motor coolers - CTMT spray pumps (channel heads)  motor coolers - CTMT spray pumps (shells) 2-41  motor coolers - CTMT spray pumps (tubes)  motor coolers - CTMT spray pumps (tubesheets)  piping components  piping components - pipe spools for startup strainers  pump casings - CTMT spray pumps  spray nozzles  tank - spray additive tank (Unit 2 only)  valve bodies The intended functions of the containment spray system component types within the scope
 
of license renewal include:
 
heat exchange between fluid media  flow pattern or distribution provision  pressure-retaining boundary  structural/functional support for safety-related/nonsafety-related components with maintenance of physical integrity and flow path considerations 2.3.2.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.2.1 and UFSAR Section 6.2.2.2 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.2.1.3  Conclusion
 
The staff reviewed the LRA, UFSAR and drawings to determine whether the applicant failed
 
to identify any SCs within the scope of license renewal. The staff finds no such omissions.
 
In addition, the staff's 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 the applicant has adequately identified the containment
 
spray 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  Emergency Core Cooling Systems 2.3.2.2.1  Summary of Technical Information in the Application
 
LRA Section 2.3.2.2 describes the ECCS, which include the safety injection system, safety injection portion of the chemical volume and control system (CVCS), and residual heat 2-42 removal (RHR) system. The primary ECCS function following an accident is removal of the stored and fission product decay heat from the reactor core. The ECCS consists of passive
 
injection by the safety injection accumulators, high-head active injection by the centrifugal
 
charging and safety injection pumps, and low-head active injection by the RHR pumps.
 
Long-term recirculation and cooling of ECCS is by RHR pumps and heat exchangers.
 
The RWST supplies emergency borated cooling water to the high-head safety injection, low-head safety injection, and containment spray during the injection mode. The RWST is
 
designed to hold enough dilute boric acid solution to fill the refueling canal prior to refueling
 
operations and to provide injection water to support the safety injection system. The RWST
 
also can fill the refueling cavity via the refueling water purification pump.
 
The safety-injection system consists of two safety-injection pumps, four accumulators, piping, and valves. The system provides post-accident, high-head and portions of low-head
 
safety injection for emergency core cooling to limit core damage and fission product release
 
for adequate shutdown margin and includes passive injection of coolant via the safety
 
injection accumulators. 
 
The RHR system consists of two trains of one pump, one heat exchanger, piping, and
 
valves. The system transfers heat from the RCS to the NSCW via the component cooling
 
water system to reduce reactor coolant temperature to the cold shutdown level at a
 
controlled rate during the second part of normal plant cooldown and maintains this
 
temperature until the plant starts up again. During RCS low-temperature operation, RHR
 
system relief valves in the RHR pump suction lines mitigate RCS overpressure transients.
RHR system portions also serve as ECCS parts for accident mitigation. Following a loss-of-
 
coolant accident (LOCA) the RHR system is aligned initially to take suction from the RWST
 
and inject into the RCS if RCS pressure is low enough for low-head safety injection. When
 
the ECCS switches from the injection to the recirculation phase, the RHR pumps take
 
suction from the containment emergency sumps and recirculate sump borated water to the
 
RCS at low pressure or provide suction to the safety-injection and charging pumps for high-
 
head recirculation. Each containment emergency sump has a strainer to prevent debris
 
from entering the ECCS. 
 
The ECCS contains safety-related components relied upon to remain functional during and
 
following DBEs. The failure of nonsafety-related SCs in the ECCS potentially could prevent
 
the satisfactory accomplishment of a safety-related function. In addition, the ECCS
 
performs functions that support fire protection and EQ.
 
LRA Table 2.3.2.2 identifies ECCS component types within the scope of license renewal
 
and subject to an AMR. The intended functions of the ECCS component types within the
 
scope of license renewal include:
 
heat exchange between fluid media  restriction of process flow  pressure-retaining boundary  structural/functional support for safety-related/nonsafety-related components with maintenance of physical integrity and flow path considerations 2-43  2.3.2.2.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.2.2 and UFSAR Sections 5.2.2.10, 5.4.7, 6.2.2, and 6.3
 
using the evaluation methodology described in Safety Evaluation Report (SER) Section 2.3
 
and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
In RAI 2.3.2.2-1, dated January 28, 2008, the staff requested additional information on the ECCS sump screens, which were designed in LRA Drawings 1X4LD122 and 131 as not in-
 
scope components. The applicant responded that the ECCS sump screens are in scope
 
components. They are categorized as structural components. Refer to LRA section 2.4.1, Table 2.4.1, and Table 3.5.2-1, Item 12. The staff finds this response acceptable because
 
the components are included in-scope for license renewal.
 
The staff also requested that the applicant verify the LRA status of the boron injection surge
 
tank because the tank is listed as an ECCS component in UFSAR Table 6.3.2-4. In its
 
response dated February 27, 2008, the applicant responded that the boron injection surge
 
tank on Unit 1 has been retired in place. Since it has no functions and is empty it is not in scope (refer to boundary drawing 1X4LD119). A boron injection surge tank was never installed on Unit 2 (refer to boundary drawing 2X4LD119). 
 
The staff also requested that the applicant verify the status of the boric acid batching tank.
In LRA Drawing 1X4LD118, the tank is highlighted but not listed in Table 2.3.2.2 or
 
discussed in text. The applicant responded that the boric acid batching tanks are in scope
 
components. These tanks are listed in LRA Table 3.3.2-10, Items 38a & 38b. The staff finds
 
this response acceptable because the components are included in-scope for license
 
renewal.
The staff also requested that the applicant verify the status of portions of the RWST liner. In
 
LRA Table 2.3.2.2, the RWST tank liner is listed. In UFSAR 6.3.2.2.9; the tank is described
 
as reinforced concrete tank with a stainless steel liner. 
 
The applicant responded that the RWST tank liner is categorized as a mechanical
 
component and is listed in LRA Table 2.3.2.2, Item 32. 
 
As discussed in LRA section 2.3.2.2, the concrete shell, roof, and base slab which provide
 
structural support for the tank liner are evaluated in the Structural scoping for the Concrete
 
Tank and Valve House Structures, Section 2.4.7. The staff finds this response acceptable
 
because the components are included in-scope for license renewal. 
 
2.3.2.2.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether
 
the applicant failed to identify any SCs within the scope of license renewal. The staff finds 2-44 no such omissions. In addition, the staff's 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 the applicant has adequately identified the
 
ECCS 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  Containment Isolation System 2.3.2.3.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.2.3 describes the containment isolation system, an engineered safety
 
feature that allows appropriate process fluids to pass through the containment boundary
 
during normal and accident conditions while isolating containment barrier penetrations as
 
required to preserve containment barrier integrity during accident conditions to prevent
 
uncontrolled or unmonitored leakage of radioactive materials to the environment. The
 
containment isolation system is not comp letely independent. Each piping system which penetrates the containment has containment isolation features which minimize the release
 
of fission products following a design-basis accident. These features are scoped and
 
evaluated in their respective mechanical process systems rather than in the containment
 
isolation system.
 
2.3.2.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.2.3 and UFSAR Sections 6.2.4, and 15.6.5.4 using the
 
evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR
 
Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.2.3.3  Conclusion The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 the applicant has adequately identified the containment
 
isolation 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  Auxiliary Systems LRA Section 2.3.3 identifies the auxiliary systems SCs subject to an AMR for license renewal.
 
2-45 The applicant described the supporting SCs of t he auxiliary systems in the following LRA sections: (NOTE: Systems marked with "*" are Balance of Plant systems)
 
LRA Section System
 
2.3.3.1*  new fuel storage  2.3.3.1*  spent fuel storage 2.3.3.2*  spent fuel cooling and purification system 2.3.3.3*  containment building polar bridge crane 2.3.3.3*  fuel handling & RV servicing equipment 2.3.3.3*  spent fuel cask bridge crane 2.3.3.4*  nuclear service cooling water 2.3.3.4*  nuclear service cooling water chemical injection 2.3.3.5*  component cooling water 2.3.3.6*  auxiliary component cooling water 2.3.3.7*  turbine plant cooling water 2.3.3.8*  river intake structure 2.3.3.9*  instrument air 2.3.3.9*  instrument, service, and breathing air 2.3.3.10*  boron recycle 2.3.3.10*  CVCS (non-ECCS portions) 2.3.3.10  CVCS (non-ECCS portions) 2.3.3.11  CB control room area HVAC 2.3.3.11  CB safety feature electrical equipment room HVAC 2.3.3.11  CB wing area, levels A, B, 1 and 2 normal HVAC 2.3.3.11  CB lab hood and laboratory area ventilation 2.3.3.11  CB locker and toilet exhaust 2.3.3.11  CB cable spreading rooms HVAC 2.3.3.11  electrical penetration filter exhaust 2.3.3.11  TSC HVAC 2.3.3.12  AB outside air supply and normal HVAC 2.3.3.12  AB radwaste area filter exhaust and continuous exhaust 2.3.3.12  AB engineered safety features room coolers 2.3.3.12  piping penetration filter exhaust 2.3.3.13  containment building air cooling 2.3.3.13  CTB lower level air circulation 2.3.3.13  CTB preaccess filter 2.3.3.13  CTB minipurge supply and normal preaccess purge supply 2.3.3.13  CTB minipurge exhaust and normal access purge exhaust 2.3.3.13  CTB post LOCA purge exhaust 2.3.3.13  CTB cavity cooling 2.3.3.13  CTB reactor support cooling 2.3.3.13  CTB auxiliary air cooling 2.3.3.13  CTB post-LOCA cavity purge 2.3.3.14  FHB normal HVAC 2.3.3.14  FHB post-accident exhaust 2.3.3.15  ventilation system - diesel generator building 2.3.3.16  ventilation system - auxiliary feedwater pump house 2.3.3.17  electrical tunnel ventilation 2.3.3.17  piping penetration ventilation 2.3.3.17  fire protection facilities HVAC 2-46 2.3.3.18  ventilation systems - radwaste buildings 2.3.3.19  fire protection water 2.3.3.19  fire protection seismic category I water 2.3.3.19  fire protection halon 2.3.3.20*  emergency diesel generator system 2.3.3.21*  demineralized water system 2.3.3.22  hydrogen recombiner and monitoring 2.3.3.23*  auxiliary building drain system - nonradioactive 2.3.3.23*  auxiliary building flood-retaining rooms, alarms, and drains 2.3.3.23*  containment and auxiliary bu ilding drain system - radioactive  2.3.3.23*  control building drains 2.3.3.23*  fuel handling building drains 2.3.3.23*  sanitary waste and vent 2.3.3.23*  turbine building drain 2.3.3.24*  potable water 2.3.3.24*  utility water 2.3.3.25*  radiation monitoring system 2.3.3.26*  reactor makeup water storage tank and degasifier 2.3.3.27*  nuclear sampling system - gaseous 2.3.3.27*  nuclear sampling system - liquids 2.3.3.27*  post-accident sampling 2.3.3.27*  turbine plant sampling 2.3.3.28*  auxiliary gas system - H2 2.3.3.28*  auxiliary gas system - N2 2.3.3.29*  essential chilled water 2.3.3.29*  normal chilled water 2.3.3.29*  special chilled water 2.3.3.30*  backflushable filter 2.3.3.30*  condensate cleanup 2.3.3.30*  waste processing system, gas 2.3.3.30*  waste processing system, liquid 2.3.3.31  thermal insulation 2.3.3.32*  miscellaneous leak detection In accordance with Section 2.3, "Scoping and Screening Results - Mechanical Systems,"
 
the staff identified the following BOP systems for Tier 1 reviews:
 
LRA Section System
 
2.3.3.23 sanitary waste and vent 2.3.3.23 turbine building drain system 2.3.3.24 potable water 2.3.3.24 utility water 2.3.3.28 auxiliary gas system - H2 2.3.3.30 backflushable filter system 2.3.3.30 condensate cleanup system
 
As part of the staff's review, the following RAIs identified instances of drawing errors where
 
the continuation notation for piping on one drawing to another drawing was incorrect:
 
RAI 2.3.3.4-4 2-47  RAI 2.3.3.4-5  RAI 2.3.3.6-1  RAI 2.3.3.6-2  RAI 2.3.3.23-1  RAI 2.3.3.26-1
 
In its response, dated February 27, 2008, the applicant identified the correct locations.
 
Based on its review, the staff finds the applicant's responses to these RAIs acceptable
 
because the applicant provided the correct drawing continuation references. Therefore, the
 
staff's concerns described in the RAIs are resolved.
The staff's findings for the auxiliary systems are discussed below.
2.3.3.1  Fuel Storage Racks - New and Spent Fuel 2.3.3.1.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.1 describes the fuel storage racks for new and spent fuel. The fuel
 
handling building houses the new fuel storage area and the spent fuel pool. The new fuel
 
storage area houses new fuel storage racks for temporary dry storage of new fuel
 
assemblies. Each rack is composed of individual vertical cells that can be fastened together
 
in any number to form a module that can be bolt ed firmly to anchors in the floor of the new fuel storage area. The new fuel storage rack design includes storage for 162 fuel
 
assemblies at a center-to-center spacing of 21 inches for minimal separation between
 
adjacent fuel assemblies of 12 inches, sufficient to maintain a subcritical array even when
 
the building is flooded with unborated water or during any DBE.
 
Spent fuel is stored in high-density racks. Each rack in the Unit 1 spent fuel pool consists of
 
several cells welded together to form the rack top grid and at the bottom to a supporting
 
grid structure. The Unit 2 spent fuel pool consists of an assemblage of cells interconnected
 
along their contiguous corners in a honeycomb cellular structure. None of these free-
 
standing modules are anchored to the floor or braced to the wall. The design of the racks
 
with the soluble boron in the fuel storage pool is relied upon to keep the stored fuel
 
subcritical for all analyzed events as described in the UFSAR. There are storage locations
 
for 1476 assemblies in the Unit 1 pool and 2098 in the Unit 2 pool. 
 
The fuel storage racks - new and spent fuel contain safety-related components relied upon
 
to remain functional during and following DBEs. 
 
LRA Table 2.3.3.1 identifies fuel storage racks - new and spent fuel component types within
 
the scope of license renewal and subject to an AMR: 
 
failed fuel rod storage basket  new fuel storage rack assembly  spent fuel storage racks The intended functions of the fuel storage racks - new and spent fuel component types
 
within the scope of license renewal include:
 
reactivity control 2-48  structural/functional support for safety-related/nonsafety-related components with maintenance of physical integrity and flow path considerations 2.3.3.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.1 and UFSAR Sections 4.3.2.6.1 and 9.1 using the
 
evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR
 
Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.3.1.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 the applicant has adequately identified the fuel storage
 
racks - new and spent fuel 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).
 
2.3.3.2  Spent Fuel Cooling and Purification System 2.3.3.2.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.2 describes the spent fuel cooling and purification system, which
 
removes decay heat generated by spent fuel assemblies stored in the spent fuel pool and
 
which can maintain water clarity and purity in the spent fuel pool, the fuel transfer canal, the
 
refueling cavity, and the RWST.
 
The spent fuel cooling and purification system consists of two cooling trains, each with one
 
heat exchanger and pump, piping, and valves. O ne purification loop, with demineralizer, filter, piping, valving, and instrumentation, services both cooling loops. There is also a
 
surface skimmer loop. Each cooling train is designed to maintain spent fuel pool
 
temperatures and heat loads as described in the UFSAR.
 
The spent fuel cooling and purification system contains safety-related components relied
 
upon to remain functional during and following DBEs. The failure of nonsafety-related SCs
 
in the spent fuel cooling and purification syst em potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the spent fuel cooling and
 
purification system performs functions that support EQ.
 
LRA Table 2.3.3.2 identifies spent fuel cooling and purification system component types
 
within the scope of license renewal and subject to an AMR: 
 
2-49  closure bolting  demineralizer vessels  flow orifice/elements  heat exchangers - SFP HXs (channel heads)  heat exchangers - SFP HXs (shells)  heat exchangers - SFP HXs (tubes)  heat exchangers - SFP HXs (tubesheets)  piping components  piping components - piping spools for startup strainers  pump casings - refuel water purification pumps  pump casings - SFP pumps  pump casings - SFP skimmer pumps  strainer elements  strainer housings  valve bodies The intended functions of the spent fuel cooling and purification system component types
 
within the scope of license renewal include:
 
protection from debris  heat exchange between fluid media  pressure-retaining boundary
 
2.3.3.2.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.2 and UFSAR Section 9.1.3 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.3.2.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 the applicant has adequately identified the spent fuel
 
cooling and purification 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).
 
2-50 2.3.3.3  Overhead Heavy and Refueling Load Handling System 2.3.3.3.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.3 describes the overhead heavy and refueling load handling system, which includes the containment building (reactor) polar bridge crane, spent fuel cask bridge
 
crane, and fuel handling and reactor vessel servicing equipment. 
 
The containment building (reactor) polar bridge crane is a steel double-box girder, electric, overhead, top-running, motorized bridge crane with a 134-foot span mounted on a circular
 
runway rail supported by the containment build ing superstructure. The bridge consists of two asymmetrical, welded plate box girders with full-depth diaphragms held together by
 
structural end tie girders. The primary function of the polar crane is hoisting as required for
 
the reactor head and internals during refueling and servicing operations.
 
The crane's rated operational load capacity is based on the integrated reactor head, the
 
heaviest refueling lift requirement.
 
The primary function of the spent fuel cask bridge crane is to transport spent fuel casks
 
between the railcar loading and unloading area and the spent fuel storage area. The crane
 
may be in use during normal plant operation or when the plant is shut down for refueling or
 
maintenance. The crane is also for unpacking and transporting new fuel to the new fuel pit
 
and for construction and maintenance lifts as required in the fuel handling and auxiliary
 
buildings.
 
The fuel handling and reactor vessel servicing equipment for core alterations (fuel shuffle
 
and fuel movement, core unload and reload), the refueling machine in the containment
 
building and the fuel handling machine bridge crane in the fuel handling building are
 
designed to protect against fuel damage during handling and transfer operations. 
 
The overhead heavy and refueling load handling system contains safety-related
 
components relied upon to remain functional during and following DBEs. The failure of
 
nonsafety-related SCs in the overhead heavy and refueling load handling system potentially could prevent the satisfactory accomplishment of a safety-related function. 
 
LRA Table 2.3.3.3 identifies overhead heavy and refueling load handling system
 
component types within the scope of license renewal and subject to an AMR: 
 
base plates and anchors for attachment to structures, and retaining clips  crane (including bridge & trolley) structural girders  crane rails 2.3.3.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.3 and UFSAR Sections 9.1.4 and 9.1.5 using the
 
evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR
 
Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then 2-51 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.3.3.3  Conclusion
 
The staff reviewed the LRA, and UFSAR to determine whether the applicant failed to
 
identify any SCs within the scope of license renewal. The staff finds no such omissions. In
 
addition, the staff's 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 the applicant has adequately identified the overhead heavy
 
and refueling load handling 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).
2.3.3.4  Nuclear Service Cooling Water Systems (NSCW) 2.3.3.4.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.4 describes the NSCW systems, which include the NSCW and the
 
NSCW chemical injection systems. The NSCW system, composed of two redundant, completely independent, full-capacity flow trains, provides essential cooling to safety-
 
related equipment and to some nonsafety-related auxiliary components. Each train has
 
three 50-percent capacity vertical centrifugal pumps, one forced-draft cooling tower, piping, and valves. The system supplies cooling water for the containment coolers, control building
 
essential chiller condensers, various engineered safety feature (ESF) pump coolers, standby diesel generator jacket water coolers, and the component cooling water (CCW)
 
and auxiliary component cooling water (ACCW) heat exchangers.
 
The NSCW cooling towers, the ultimate heat sink for the plant, are required for safe
 
shutdown. They remove heat from the NSCW system during normal operation, safe
 
shutdown or cooldown of the reactor, or accident conditions. Each cooling tower consists of
 
a basin which contains the ultimate heat sink water and of an upper structure which
 
transfers the NSCW heat loads to the atmosphere. The upper structure is a vertical, circular, concrete mechanical draft tower with motor-driven fans for heat transfer to the
 
atmosphere by direct contact of water droplets from spray manifolds with forced air flow. 
 
The combined storage capacity of the two tower basins per unit meets short-term (30 days)
 
storage requirements for the ultimate heat sink without makeup. The mechanical portion of
 
the NSCW cooling towers includes the piping, valves, and mechanical draft fans.
 
The NSCW chemical injection system, which injects biocide, dispersant, and corrosion
 
inhibitor solutions to the NSCW system to inhibit biological growth, prevent deposition of
 
suspended solids, and reduce copper tube corrosion, is comprised of chemical injection
 
pumps, chemical mixing and storage tanks, drums, or both, and piping components for
 
transferring chemical solutions to the injection points downstream of the NSCW pumps at
 
the NSCW cooling tower basins. The chemical injection equipment is located in the NSCW
 
chemical control building.
 
The NSCW systems contain safety-related components relied upon to remain functional
 
during and following DBEs. The failure of nonsafety-related SCs in the NSCW systems 2-52 potentially could prevent the satisfactory acco mplishment of a safety-related function. In addition, the NSCW systems perform functions that support fire protection and EQ.
 
LRA Table 2.3.3.4 identifies NSCW systems component types within the scope of license
 
renewal and subject to an AMR: 
 
closure bolting  flow orifice/elements  oil coolers - NSCW pumps thrust bearings (coils)  piping components  pump casings - NSCW system pumps  pump casings - NSCW transfer pumps  spray nozzles  valve bodies
 
The intended functions of the NSCW systems component types within the scope of license
 
renewal include:
 
heat exchange between fluid media  flow pattern or distribution provision  restriction of process flow pressure-retaining boundary
 
2.3.3.4.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.4 and UFSAR 9.2.1 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
The staff's review of LRA Section 2.3.3.4 identified areas in which additional information
 
was necessary to complete the review of the applicant's scoping and screening results. In
 
addition to the RAIs 2.3.3.4-4 and 2.3.3.4-5 related to drawing continuation errors described
 
in Section 2.3.3, the applicant responded to the staff's RAIs as discussed below.
In RAI 2.3.3.4-1, dated January 28, 2008, the staff noted that drawings 1X4LD133-1, 1X4LD133-2, 2X4LD133-1, and 2X4LD133-2, locations G-6, G-7, and G-8 show NSCW
 
cooling tower fans as within the scope of license renewal based on criterion
 
10 CFR 54.4(a)(1). However, the fan casings/housings are not included in LRA Table
 
2.3.3.4 as a component type subject to an AMR. The applicant was requested to provide
 
additional information to explain why the NSCW tower fan casings/housings are not
 
included in LRA Table 2.3.3.4 as component types subject to an AMR.
 
In its response, dated February 27, 2008, the applicant stated:
 
2-53 The NSCW fan, composed of the motor driver, gearbox, shaft, hub assembly and blades, is an active assembly, not subject to an AMR. The
 
stack that forms the fan's housing for flow direction control is constructed
 
of concrete and is an integral part of the NSCW cooling tower structure.
 
The housing is in scope and is included in Table 2.4.6 as NSCW cooling
 
tower stack.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.4-1 acceptable
 
because the applicant provided clarification that the fan housing in question is within the
 
scope of license renewal and is included in Table 2.4.6 as part of the "NSCW cooling tower
 
stack." Therefore, the staff's concern described in RAI 2.3.3.4-1 is resolved.
 
In RAI 2.3.3.4-2, dated January 28, 2008, the staff noted that drawings 1X4LD133-1 and 2X4LD133-1 (D-4) show pipe sections 131-1" and 130-1" and drawings 1X4LD133-2 and 2X4LD133-2 (D-4) show pipe sections 132-1" and 369-1" that are within the scope of
 
license renewal based on criterion 10 CFR 54.4(a)(2). None of these pipelines show in-
 
scope anchoring that assures these pipelines are adequately anchored for spatial
 
interaction. 
 
The applicant was requested to provide additional information explaining how the pipelines
 
listed above are adequately anchored to prevent spatial interaction.
 
In its response, dated February 27, 2008, the applicant stated:
 
The above pipe lines are in scope for attached or connected piping
 
(10 CFR 54.4(a)(2)). In this case, attached piping bounds spatial
 
interaction - the entire lines out to their termination points are in the
 
scope of license renewal and are age managed. These lines terminate at
 
either a blind flange or welded pipe cap and thus the (a)(2) concerns
 
associated with them do not prop a gate into other systems or to other nonsafety-related segments of the NSCW system. As part of the plant's
 
CLB, these lines are seismically analyzed and seismically supported, with the pipe supports being in the scope of license renewal and age
 
managed. These segments of nonsafety-related piping cannot fail in a
 
way that would compromise safety-related equipment, either by failure of
 
attached piping or a pressure boundary breech resulting in a spatial
 
interaction. 
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.4-2 acceptable
 
because the applicant stated that the subject pipe sections, as part of the plant's CLB, are
 
seismically analyzed and supported. Therefore, the staff's concern described in RAI
 
2.3.3.4-2 is resolved.
In RAI 2.3.3.4-3, dated January 28, 2008, the staff noted that drawings 1X4LD133-1, 2X4LD133-1, 1X4LD133-2, and 2X4LD133-2 (D-4) show pipe sections 505-2", 057-2", 007-
 
2", and 007-2", respectively, that are within the scope of license renewal based on criterion
 
10 CFR 54.4(a)(2). None of these pipe sections show in-scope anchoring that assures
 
these pipe sections are adequately anchored for spatial interaction. The applicant was
 
requested to provide additional information explaining how these pipelines are adequately
 
anchored to prevent spatial interaction.
 
2-54 In its response, dated February 27, 2008, the applicant stated:
The above pipe lines are in scope for attached or connected piping
 
(10 CFR 54.4(a)(2)). In this case, attached piping bounds spatial interaction -
 
the entire lines out to their termination points are in the scope of license
 
renewal and are age managed. These lines terminate at a blind flange and
 
thus the (a)(2) concerns associated with them do not propagate into other
 
systems or to other nonsafety-relat ed segments of the NSCW system. As part of the plant's CLB, these lines are seismically analyzed and seismically
 
supported, with the pipe supports being in the scope of license renewal and
 
age managed. 
 
These segments of nonsafety-related piping cannot fail in a way that would
 
compromise safety-related equipment, either by failure of attached piping or
 
a pressure boundary breech resulting in a spatial interaction.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.4-3
 
acceptable because the applicant stated that the subject pipe sections, as part of
 
the plant's CLB, are seismically analyzed and supported. Therefore, the staff's
 
concern described in RAI 2.3.3.4-3 is resolved.
 
2.3.3.4.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether
 
the applicant failed to identify any components within the scope of license renewal. The
 
staff finds no such omissions. In addition, the staff's 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 the applicant has adequately
 
identified the nuclear service cooling 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).
2.3.3.5  Component Cooling Water System 2.3.3.5.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.5 describes the closed-loop CCW system as an intermediate heat
 
transfer system between potentially radioacti ve heat sources and the NSCW system to reduce the probability of radioactive releases to the environment from a leaking component.
 
The CCW system cools the spent fuel pool heat exchangers, the RHR heat exchangers, and the RHR pump seal coolers.
 
The CCW system, consisting of two redundant trains, each with one heat exchanger, three
 
50-percent centrifugal pumps, one surge tank, piping, and valves, is designed to operate at
 
lower pressure than is the NSCW system to prevent potentially contaminated CCW water
 
from entering the NSCW system, which is open to atmosphere through the NSCW cooling
 
towers.
 
The CCW system contains safety-related components relied upon to remain functional
 
during and following DBEs. The failure of nonsafety-related SCs in the CCW system 2-55 potentially could prevent the satisfactory acco mplishment of a safety-related function. In addition, the CCW system performs functions that support fire protection.
 
LRA Table 2.3.3.5 identifies CCW system component types within the scope of license
 
renewal and subject to an AMR: 
 
closure bolting  flow orifice/elements  heat exchangers - CCW HXs (channel heads)  heat exchangers - CCW HXs (shells)  heat exchangers - CCW HXs (tubes)  heat exchangers - CCW HXs (tubesheets)  motor coolers - CCW pumps (channel heads)  motor coolers - CCW pumps (shells)  motor coolers - CCW pumps (tubes)  motor coolers - CCW pumps (tubesheets)  piping components  piping components - pipe spools for startup strainers  pump casings - CCW pumps  tanks - CCW chemical addition feeder tanks  tanks - CCW surge tanks  valve bodies
 
The intended functions of the CCW system component types within the scope of license
 
renewal include:
 
heat exchange between fluid media restriction of process flow  pressure-retaining boundary
 
2.3.3.5.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.5 and UFSAR Section 9.2.2 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.3.5.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 the applicant has adequately identified the CCW system 2-56 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  Auxiliary Component Cooling Water System (1217) 2.3.3.6.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.6 describes the ACCW system, which removes heat from the heat
 
exchangers and components that handle radioactive fluids necessary for normal plant
 
startup, normal power operation, normal shutdown and cooldown, and refueling. Not
 
essential for safe plant shutdown under accident conditions, the ACCW system is
 
composed of two 100-percent capacity ACCW heat exchangers, two 100-percent capacity
 
ACCW pumps, one ACCW surge tank, piping, and valves. The ACCW system
 
accomplishes cooling through an intermediate closed-loop design cooled in turn by water
 
directly from the NSCW system.
 
Because it may be contaminated by radioactive materials, the ACCW system is designed
 
for lower pressures than those for the NSCW system, which is open to the atmosphere
 
through the ultimate heat sink cooling towers, so the cooling systems do not release
 
radioactive materials to the environment.
The system cools the normal charging pump motor coolers, seal water heat exchanger, catalytic hydrogen recombiners, waste gas
 
compressors, pressurizer sample coolers, reactor coolant sample cooler, reactor coolant
 
drain tank heat exchanger, reactor coolant pump (RCP) motor coolers, thermal barriers, bearing lube oil coolers, letdown heat exchanger, excess letdown heat exchanger, and
 
ACCW pump and motor coolers.
 
The ACCW system contains safety-related components relied upon to remain functional
 
during and following DBEs. The failure of nonsafety-related SCs in the ACCW system
 
potentially could prevent the satisfactory acco mplishment of a safety-related function. In addition, the ACCW system performs functions that support fire protection and EQ.
 
LRA Table 2.3.3.6 identifies ACCW system component types within the scope of license
 
renewal and subject to an AMR: 
 
closure bolting  flow orifice/elements  heat exchangers - ACCW HXs (channel heads)  heat exchangers - ACCW HXs (shells)  heat exchangers - ACCW HXs (tubes)  heat exchangers - ACCW HXs (tubesheets)  motor coolers - ACCW pumps (channel heads)  motor coolers - ACCW pumps (shells)  motor coolers - ACCW pumps (tubes)  motor coolers - ACCW pumps (tubesheets)  piping components  piping components - pipe spools for startup strainers  pump casings - ACCW pumps  tanks - ACCW chemical addition feeder tanks  tanks - ACCW surge tanks  valve bodies 
 
2-57  The intended functions of the ACCW system component types within the scope of license
 
renewal include:
 
restriction of process flow pressure-retaining boundary 2.3.3.6.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.6 and UFSAR Section 9.2.8 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
The staff's review of LRA Section 2.3.3.6 identified areas in which additional information
 
was necessary to complete the review of the applicant's scoping and screening results. The
 
staff identified RAIs 2.3.3.6-1 and 2.3.3.6-2 involving instances of drawing errors where
 
continuation notation for the piping from one drawing to another drawing was incorrect.
 
These are described in Section 2.3.3.
 
2.3.3.6.3 Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether
 
the applicant failed to identify any components within the scope of license renewal. The
 
staff finds no such omissions. In addition, the staff's 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 the applicant has adequately
 
identified the ACCW auxiliary component coo ling 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).
 
2.3.3.7  Turbine Plant Cooling Water System 2.3.3.7.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.7 describes the turbine plant cooling water (TPCW) system, which
 
supplies cooling water to remove heat from nonsafety-related heat exchangers: turbine
 
plant closed-loop cooling water heat exchangers, main turbine lube oil coolers, normal
 
cooling water system chillers, steam generat or blowdown trim heat exchangers, CVCS chillers, generator hydrogen coolers, isophase bus coolers, vacuum pump seal water
 
coolers, and generator stator coolers.
 
The failure of nonsafety-related SCs in the TPCW system could potentially prevent the satisfactory accomplishment of a safety-related function. 
 
2-58 LRA Table 2.3.3.7 identifies TPCW system component types within the scope of license renewal and subject to an AMR: 
 
closure bolting  flow orifice/elements  piping components  strainer housings  valve bodies The intended function of the TPCW system component types within the scope of license
 
renewal is to provide a pressure-retaining boundary.
2.3.3.7.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.7 and UFSAR Section 9.2.11 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.3.7.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 the applicant has adequately identified the TPCW 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).
 
2.3.3.8  River Intake Structure System 2.3.3.8.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.8 describes the river intake structure system, which provides makeup
 
water to the circulating water system hyperbolic cooling towers and an alternate source of
 
makeup to the NSCW cooling towers and dilutes the discharge of plant effluent as required
 
to meet 10 CFR Part 20 limits. 
 
The failure of nonsafety-related SCs in the river intake structure system could potentially
 
prevent the satisfactory accomplishment of a safety-related function. 
 
LRA Table 2.3.3.8 identifies river intake structure system component types within the scope
 
of license renewal and subject to an AMR: 
 
closure bolting 2-59  piping components  valve bodies The intended function of the river intake structure system component types within the scope
 
of license renewal is to provide a pressure-retaining boundary.
 
2.3.3.8.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.8 and UFSAR Sections 10.4.5.2.2C and 10.4.5.2.3
 
using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-
 
LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.3.8.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 the applicant has adequately identified the river intake
 
structure 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).
 
2.3.3.9  Compressed Air System 2.3.3.9.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.9 describes the compressed air system, which continuously supplies
 
filtered, dry, oil-free compressed air for pneumatic instrument operation and control of
 
pneumatic actuators. The system also supplies compressed, normally filtered, dry, and oil-
 
free service air to outlets throughout the plant for operation of pneumatic tools and for other
 
service air requirements. There are one reciprocating compressor and two rotary
 
compressor trains located in each unit. The outlets from the air receivers of these three
 
trains for each unit connect to a common compressed air supply line. Piping for the third
 
reciprocating compressor train located in Unit 1 can be aligned to either the Unit 1 or Unit 2
 
compressed air supply line.
 
The compressed air supply line in each unit branches to supply both the service air system
 
and the instrument air system. The service air sy stem consists of a prefilter, a dryer, and an after-filter from which the air flows to the various service air loops. The instrument air
 
system consists of two dryers in parallel, each with a pre-filter and after-filter. The air from
 
the system flows to the various instrument air loops in the unit. 
 
The compressed air system contains safety-related components relied upon to remain
 
functional during and following DBEs. The failure of nonsafety-related SCs in the 2-60 compressed air system potentially could prev ent the satisfactory accomplishment of a safety-related function. In addition, the compressed air system performs functions that
 
support EQ.
 
LRA Table 2.3.3.9 identifies compressed air system component types within the scope of
 
license renewal and subject to an AMR: 
 
closure bolting  flow orifice/elements  piping components  valve bodies The intended functions of the compressed air system component types within the scope of
 
license renewal include:
 
restriction of process flow pressure-retaining boundary 2.3.3.9.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.9 and UFSAR Section 9.3.1 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.3.9.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 the applicant has adequately identified the compressed air
 
system components within the scope of licens e 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  Chemical and Volume Control and Boron Recycle Systems 2.3.3.10.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.10 describes the CVCS and the boron recycle system. The CVCS
 
maintains the required RCS inventory by regulating the programmed pressurizer water level
 
through continuous charging and letdown of reactor coolant water for the control of water
 
chemistry conditions, activity level, and sol uble chemical neutron absorber concentration.
The CVCS also injects seal water into the RCPs. Portions of the system contain borated
 
water at a concentration higher than that of the RCS to maintain reactor shutdown margin.
2-61  The CVCS consists of one normal charging and two standby centrifugal charging pumps.
 
The centrifugal charging pumps provide safety injection flow as described in LRA Section
 
2.3.2.2. In addition, the system has a letdown heat exchanger, an excess letdown heat exchanger, a regenerative heat exchanger, a volume control tank, piping, valves, and
 
filters. The CVCS has demineralizer vessels and chemical tanks to control RCS water
 
chemistry and the system recycles reactor grade water. Portions of the CVCS functioning
 
as parts of the ECCS inject flow to the RCS during post-accident injection and recirculation.
 
LRA Section 2.3.2.2 describes ECCS functions. 
 
The CVCS boron recycle system portion processes reactor coolant effluent fit for reuse as
 
makeup and decontaminates the effluent by demineralization. The CVCS thermal
 
regeneration system portion is usable during reactor coolant boration and dilution
 
operations, when RCS letdown flow may be directed to the thermal regeneration
 
demineralizers to adjust reactor coolant boric acid concentration. 
 
The CVCS and boron recycle systems contai n safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SCs in the
 
CVCS and boron recycle systems potentially coul d prevent the satisfactory accomplishment of a safety-related function. In addition, the CVCS and boron recycle systems perform functions that support fire protection, SBO, and EQ.
 
LRA Table 2.3.3.10 identifies CVCS and boron re cycle systems component types within the scope of license renewal and subject to an AMR: 
 
closure bolting  demineralizer vessels  filter housings  flow orifice/elements  heat exchangers - excess letdown HXs (channel heads)  heat exchangers - excess letdown HXs (shells)  heat exchangers - excess letdown HXs (tubes and tubesheets)  heat exchangers - letdown chillers (channel heads)  heat exchangers - letdown chillers (shells)  heat exchangers - letdown chillers (tubes)  heat exchangers - letdown HXs (channel heads)  heat exchangers - letdown HXs (shells)  heat exchangers - letdown HXs (tubes and tubesheets)  heat exchangers - letdown reheat HXs (channel heads)  heat exchangers - letdown reheat HXs (shells)  heat exchangers - letdown reheat HXs (tubes and tubesheets)  heat exchangers - moderating HXs (channel heads)  heat exchangers - moderating HXs (shells)  heat exchangers - moderating HXs (tubes and tubesheets)  heat exchangers - regenerative HXs (channel heads)  heat exchangers - regenerative HXs (shells)  heat exchangers - regenerative HXs (tubes and tubesheets)  letdown orifices  motor coolers - normal charging pumps (channel heads) 2-62  motor coolers - normal charging pumps (shells)  motor coolers - normal charging pumps (tubes)  motor coolers - normal charging pumps (tubesheets  piping components  piping components - pipe spools for startup  strainers  pump casings - boric acid transfer pumps  pump casings - CVCS recycle feed pumps  pump casings - normal charging pumps  pump casings - zinc addition injection pumps  tank diaphragms - boric acid storage tanks  tanks - boric acid batching tanks  tanks - boric acid storage tanks  tanks - boron meter tanks  tanks - chemical mixing tanks  tanks - recycle holdup tanks  tanks - volume control tanks  valve bodies The intended functions of the CVCS and boron re cycle systems component types within the scope of license renewal include:
 
restriction of process flow physical integrity maintenance to pr event generation of debris or loose parts which could interfere with a safety-related function  pressure-retaining boundary 2.3.3.10.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.10 and UFSAR Sections 9.3.4.1 and 9.3.4.2 using
 
the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR
 
Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.3.10.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 2-63 review, the staff concludes that the applicant has adequately identified the CVCS and boron recycle system components within the sc ope 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  Ventilation Systems - Control Building 2.3.3.11.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.11 describes the control building ventilation systems, which include the
 
following:
 
control room area HVAC system  control building safety feature elec trical equipment room HVAC system  control building wing area, levels A, B, 1, and 2 normal HVAC system  control building lab hood and laboratory area ventilation system  control building locker and toilet exhaust system  control building cable spreading rooms HVAC system  electrical penetration filter exhaust system  onsite technical support center HVAC system The control room area HVAC system operates in either normal or emergency mode. In the normal mode the system supplies conditioned air to the control room area during normal
 
plant operating conditions for personnel comfort and a suitable operating environment for
 
equipment.
 
If gaseous fission product levels exceed limits in the outside air intake, the control room
 
HVAC system would be re-aligned from norma l to emergency mode where a small amount of outside air filtered by high-efficiency filtration units maintains control room envelope
 
pressurization. The system also switches to the emergency mode upon a safety injection signal or manual actuation. The four safety-related filtration units have train-related cooling
 
coils which take cooling water from the essential chilled water system. Both Units 1 and 2
 
share the control room emergency HVAC system , the air ducts serving the control room forming a common system connected to the safety-related air handling units. 
 
The control building safety feature electrical equipment room HVAC system provides a proper environment and temperature for electrical equipment and maintenance personnel
 
during normal and postulated accident conditions. During normal operations, cooling is by
 
coils containing cooling water from the normal chilled water system. Under design-basis
 
accident conditions, two cooling trains are by cooling coils with cooling water from the
 
essential chilled water system. Power for each train of the system is from a separate and independent Class 1E power system. Continuous exhaust minimizes the accumulation of
 
hydrogen gas within the battery rooms.
 
The control building wing area levels A, B, 1, and 2 normal HVAC systems provide
 
ventilation, cooling, heating, and smoke removal for operating personnel during normal
 
conditions. Cooling coils contain cooling water from the normal chilled water system. 
 
The control building laboratory hood and laboratory area ventilation system provides
 
exhaust and auxiliary makeup airflow necessary for the proper operation of the laboratory
 
hoods. The system also purges the laboratory area of airborne radioactive contamination.
2-64 Air in the hoods and laboratory area pass through carbon filters before discharging to the atmosphere. Safety-related system com ponents are limited to the tornado dampers and their ductwork.
 
The control building locker and toilet exhaust system purges the locker, shower, storage, toilet, and control building level 2 battery areas by exhausting to the atmosphere the air
 
supplied to these areas during normal operating conditions. 
 
The control building cable spreading rooms HVAC system cools, heats, and ventilates the cable spreading, auxiliary relay, normal air-conditioning, electric equipment, and computer
 
rooms during normal conditions. 
 
The system provision of emergency cooling to the auxiliary relay, normal air-conditioning, and electric equipment rooms is a safety-related function. These emergency cooling coils
 
contain cooling water from the essential chilled water system. The other safety-related
 
portions of this system are the tornado dampers and their ductwork. 
 
The electrical penetration filter exhaust system fans and filtration units for Unit 1 were
 
abandoned in place and never installed on Unit 2. Ductwork and dampers for this system
 
are in use for normal ventilation. 
 
The onsite technical support center HVAC sy stem provides environmental control for habitability, supports computer operational requirements, and filters potentially radioactive
 
particulates and iodine gas during normal and emergency plant operations. This system is
 
not safety-related but has certain fire dampers within the scope of license renewal.
 
The control building ventilation systems cont ain safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SCs in the
 
control building ventilation systems potent ially could prevent the satisfactory accomplishment of a safety-related function. In addition, the control building ventilation
 
systems perform functions that support fire protection and SBO.
 
LRA Table 2.3.3.11 identifies control building ventilation systems component types within the scope of license renewal and subject to an AMR: 
 
AC units (ESF) housings  closure bolting  control room filter and fan unit housings  control room filter and fan unit moisture eliminators  cooling coils (essential chilled water)  cooling coils (normal chilled water)  damper housings  duct silencer housings  ductwork and fittings  fan housings  flexible connectors  heater housings  piping components  sealants
 
2-65 The intended functions of the control building ventilation systems component types within the scope of license renewal include:
 
heat exchange between fluid media missile barrier moisture elimination or reduction pressure-retaining boundary
 
2.3.3.11.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.11 and UFSAR Sections 6.4, and 9.4.1 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR
 
Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.3.11.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 the applicant has adequately identified the control building
 
ventilation 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).
2.3.3.12  Ventilation Systems - Auxiliary Building 2.3.3.12.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.12 describes the auxiliary bu ilding ventilation systems, which include the following:
 
auxiliary building outside air supply and normal HVAC  auxiliary building radwaste area filt er exhaust and continuous exhaust system  auxiliary building ESF room coolers  piping penetration filter exhaust system The auxiliary building outside air supply and norma l HVAC system provides the outside air required to maintain acceptable auxiliary build ing activity. The system also heats and cools the building to maintain acceptable temperatures during normal operation. This system
 
works in conjunction with the auxiliary buildi ng radwaste area filter exhaust system, which filters and exhausts the air supply to maintain negative pressurization in the auxiliary
 
building for radioactivity control. A containment isolation signal isolates the auxiliary building 2-66 outside air supply and normal HVAC system from the building's penetration filter exhaust system.
 
The auxiliary building radwaste area filt er exhaust and continuous exhaust system maintains negative pressure in the auxiliary bu ilding by exhausting from the building more air than is supplied so no unfiltered potentially contaminated air leaks to the environment.
 
This system also exhausts air from the radw aste transfer building and radwaste transfer tunnel, filtering all exhaust air to collect any fission products before discharging it through
 
the equipment building stack. A containment isolation signal isolates the auxiliary building
 
radwaste area filter exhaust and continuous exhaust system from the auxiliary building penetration filter exhaust system.
 
The auxiliary building ESF room coolers provide cooling to safety-related switchgear, motor control centers, and pump rooms during normal, post-accident, and loss-of-offsite-power
 
conditions. Individual fan-coil units use train-related essential chilled water during such
 
emergency conditions.
 
The safety-related piping penetration filter exhaust system minimizes the release to the
 
outside atmosphere of airborne radioactivity from containment leakage into the piping
 
penetration areas during accident conditions by exhausting air to maintain negative
 
pressure in those areas and filtering the exhaust air to remove fission products before
 
releasing it through the vent stack. A portion of the exhaust air passes through cooling coils
 
and recirculates back to the piping penetration areas. A containment ventilation isolation
 
signal isolates the piping penetration filter ex haust system from the normal auxiliary building supply and exhaust systems, energizing the piping penetration exhaust fan and filter.
 
Cooling coils contain cooling water from the NSCW system.
 
The auxiliary building ventilation systems cont ain safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SCs in the
 
auxiliary building ventilation systems potent ially could prevent the satisfactory accomplishment of a safety-related function.
In addition, the auxiliary building ventilation systems perform functions that support fire protection and EQ.
 
LRA Table 2.3.3.12 identifies auxiliary building ventilation systems component types within the scope of license renewal and subject to an AMR: 
 
closure bolting  cooling coils (essential chilled water)  cooling coils (normal chilled water)  cooling coils (NSCW)  damper housings  ductwork and fittings  fan housings  flexible connectors  piping components  piping penetration area cooler housings  piping penetration filter and fan unit housings  piping penetration filter and fan unit moisture eliminators  room cooler housings
 
2-67 The intended functions of the auxiliary building ventilation systems component types within the scope of license renewal include:
 
heat exchange between fluid media missile barrier moisture elimination or reduction pressure-retaining boundary
 
2.3.3.12.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.12 and UFSAR Section 9.4.3 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
In reviewing LRA Section 2.3.3.12, the staff identified areas in which additional information was necessary to complete the review of the results of the applicant
=s scoping and screening. Therefore, by letter dated January 28, 2008, the staff issued a request for additional information concerning the specific issues to determine whether the applicant has properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff
=s RAI and the applicant
=s related response.
In RAI 2.3.3.12-1, dated January 28, 2008, the staff identified several non-safety-related fans, not identified on the drawings as in-scope, but identified as being subject to an AMR.
 
The Scope Determination Summary states that non-safety-related fan housings in this
 
system are relied upon as missile barriers (for the fan element). Therefore, the staff
 
requested the applicant to clarify whether these components are subject to aging
 
management review.
 
Applicant's Response and Staff's Evaluation
 
In a letter dated February 27, 2008, the applicant stated: 
 
The fans are an airfoil design. The fan manufacturer asserts that the airfoil
 
fan blade design used for these fans does not fail catastrophically in such a
 
manner that a missile could be ejected. Therefore, the associated fan
 
housings are not considered in scope under 10 CFR Part 54.4(a)(2) criterion
 
as missile barriers.
 
The applicant also stated that the Scoping Determination Summary (Page 2.3-70) in the
 
LRA will be revised to clarify that only certain fan housings perform a missile barrier
 
function. Based on its review, the staff finds the applicant's response to RAI 2.3.3.12-1
 
acceptable.
 
2-68 2.3.3.12.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI response, and drawings to determine whether the
 
applicant failed to identify any SCs within the scope of license renewal. The staff finds no
 
such omissions. In addition, the staff's 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 the applicant has adequately identified the
 
auxiliary building ventilation sy stem 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).
2.3.3.13  Ventilation Systems - Containment Building 2.3.3.13.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.13 describes the containment building (CTB) ventilation systems, which include the following:
 
containment building air cooling system  containment building lower level air circulating system  containment building preaccess filter system  containment building minipurge supply and normal preaccess purge supply systems  containment building minipurge exhaust and normal preaccess purge exhaust systems  containment building post-LOCA purge exhaust system  containment building cavity cooling system  containment building reactor support cooling system  containment building auxiliary air cooling system  containment building post-LOCA cavity purge system The safety-related containment building air cooling system reduces the containment temperature and pressure following a LOCA or main streamline break accident inside
 
containment by removing thermal energy. The syst em consists of eight air coolers per unit and their ductwork and dampers. The containment coolers are divided into two trains with
 
four fan coolers each. Every cooler receiv es a start signal automatically upon a safety injection signal. The containment building air cooling system also detects reactor coolant
 
leakage during normal operation. If air cooler condensate collected and measured in a
 
standpipe rises above a preset level in the standpipe, a high condensate flow alarm
 
annunciates in the control room.
 
2-69 The containment building lower level air circulating system mixes containment lower level air to prevent local hot spots. The system fans provide horizontal circulation in the area
 
below the operating deck during normal operations.
 
The containment building preaccess filter syst em, with the normal purge system, controls airborne radioactivity inside containment. 
 
This system circulates and filters containment air without makeup to reduce radioactivity in
 
the containment atmosphere below the level required for personnel access for inspection, maintenance, and refueling operations. 
 
The containment building minipurge supply and normal preaccess purge supply systems
 
filter outside air to the containment atmosphere for adequate ventilation and personnel
 
comfort while the plant is shut down and for reduction of airborne contaminants and control
 
of pressure buildup inside containment during normal operations. 
 
The containment building minipurge exhaust and normal preaccess purge exhaust systems support the containment building minipurge supply and normal preaccess purge supply
 
systems with the necessary containment vent ilation air exhaust and filtration. Air exhaust is through the plant vent. 
 
The containment building post-LOCA purge exhaus t system allows containment purging as a backup to the hydrogen recombiner system to maintain post-accident hydrogen
 
concentration below the combustible level. Use of the system post-LOCA may be in
 
conjunction with a portable air compressor through the seismic Category I portion of the
 
service air piping to provide the purge motive force. The air removed through ducting in the
 
containment dome area passes through the seismic Category I containment penetrations
 
and the filter units where it exhausts through the vent stack. 
 
The containment building cavity cooling system cools the reactor cavity. The containment building cavity cooling units operate with NSCW system cooling water in conjunction with
 
the containment building air cooling system to cool the primary shield concrete and nuclear
 
instrumentation. The system operates during normal and loss-of-offsite-power conditions.
 
Upon loss of offsite power loading of the cooling fans is automatic on a bus energized by
 
the diesel generator but the fans must be loaded manually following a LOCA. Safety-related
 
portions of the system include the cooling coils and cavity pressure relief dampers. This
 
system is also within the scope of license renewal under 10 CFR 54.4(a)(2) due to the
 
missile barrier function of its fan housings.
 
The containment building reactor support cooling system operates in conjunction with the
 
reactor cavity cooling system to cool the reactor supports. The containment building reactor
 
support cooling fans exhaust air from the reactor vessel supports to keep the concrete
 
within its operating temperature limit during normal and loss-of-offsite-power conditions. 
 
The containment building auxiliary air cooling system removes excess thermal energy from the containment atmosphere due to heat losses from operating equipment during normal
 
power generation and refueling outages. The system augments the containment cooling
 
system cooling capacity by an amount equivalent to the heat lost from the CRDM unit fans.
The system detects reactor coolant leakage during normal operation by collecting and
 
measuring air cooler condensate in a standpipe. 
 
2-70 The containment building post-LOCA cavity purge system prevents hydrogen pocketing in the reactor cavity after a LOCA by supplying air to the reactor cavity to maintain hydrogen
 
concentration below the combustible level, a safety-related function. The system has a
 
Class 1E power supply, each redundant train connected to separate safety buses. 
 
The system meets seismic Category I criter ia and starts automatically upon a safety injection signal.
 
The containment building ventilation system s contain safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SCs
 
in the containment building ventilation system s potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the containment building
 
ventilation systems perform functions that support EQ.
 
LRA Table 2.3.3.13 identifies containment bu ilding ventilation systems component types within the scope of license renewal and subject to an AMR: 
 
closure bolting  cooling coils (NSCW)  CTB aux cooling unit housings  CTB cooling unit housings  damper housings  ductwork and fittings  fan housings  flexible connectors  flow orifice/elements  piping components  valve bodies The intended functions of the CTB ventilation sy stems component types within the scope of license renewal include:
 
heat exchange between fluid media restriction of process flow missile barrier pressure-retaining boundary
 
2.3.3.13.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.13 and UFSAR Sections 6.2.1, 6.2.2, 6.5.1, and 9.4.6
 
using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-
 
LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2-71 In reviewing LRA Section 2.3.3.13, the staff identified areas in which additional information was necessary to complete the review of the results of the applicant
=s scoping and screening. Therefore, by letter dated January 28, 2008, the staff issued a request for additional information concerning the specific issues to determine whether the applicant has properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1).
The following paragraphs describe the staff
=s RAI and the applicant
=s related response.
In RAI 2.3.3.13-1, dated January 28, 2008, the staff identified that the CRDM unit fans were not identified on the drawings as in-scope and being subject to an AMR when the applicant
 
had indicated in other areas that the housings for some fans in the containment building are
 
considered in scope under 10 CFR Part 54.4(a)(2) criterion as missile barriers. Therefore, 
 
the staff requested the applicant to clarify whether these components are subject to AMR, or justify their exclusion.
 
Applicant's Response and Staff's Evaluation
 
In a letter dated February 27, 2008, the applicant stated: 
 
The housings for the CRDM unit fans, 1(2)1509B7001 000 through 1(2)
 
1509B7004000, perform a missile barrier function in accordance with 10
 
CFR 54.4(a)(2) and should have been shown as in scope on boundary drawings 1X4LD214-1 and 2X4LD214-1. Therefore, Containment Building
 
CRDM Cooling System will be removed from LRA Table 2.2-2, "Systems and Structures Not Within the Scope of License Renewal," and added to Table
 
2.2-1. A description of the system w ill also be added to the Auxiliary System Description in LRA Section 2.3.3.13. This system description will describe
 
the basis for the Containment Building CRDM Cooling System meeting 10
 
CFR 54.4(a)(2) criterion.
 
The commodity type fan housings (ID No. 7d and 7e) in LRA Table 3.3.2-13 provide the
 
AMR for these fan housings.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.13-1 acceptable, because it is the staff's understanding, based on the applicant's response to the staff's RAI, that the CRDM unit fan housings are within the scope of license renewal in accordance with
 
10 CFR 54.4(a), and are subject to an AMR in accordance with 10 CFR 54.21(a) (1).
 
2.3.3.13.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI response, and drawings to determine whether the
 
applicant failed to identify any SCs within the scope of license renewal. The staff finds no
 
such omissions. In addition, the staff's 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 the applicant has adequately identified the
 
containment building ventilation system com ponents 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).
 
2-72 2.3.3.14  Ventilation Systems - Fuel Handling Building 2.3.3.14.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.14 describes the fuel-handling building ventilation systems, which
 
include the fuel-handling building normal HVAC and fuel-handling building post-accident
 
exhaust systems. The fuel-handling building norma l HVAC system heats, cools, ventilates, and filters fuel-handling building (shared by Units 1 and 2) air to maintain an atmosphere
 
suitable for personnel and equipment during normal operation. Redundant radiation
 
monitors in the fuel-handling building normal exhaust ductwork detect high radiation levels.
 
If radiation levels exceed setpoints, a signal isolates the fuel-handling building normal
 
exhaust system and initiates the fuel-hand ling building post-accident exhaust system.
 
The fuel-handling building post-accident ex haust system prevents ex-filtration of contaminated air from the fuel-handling build ing by filtering and exhausting air from the area after its isolation from the normal fuel-handling building ventilation subsystem. The
 
fuel-handling building post-accident exhaust system maintains a negative pressure within
 
the area following a fuel-handling accident. The system consists of two 100-percent
 
capacity exhaust filtration units, piping, ductwork, and dampers and shares the exhaust
 
ductwork from the isolation dampers to the post-accident exhaust filtration units with the
 
fuel-handling building normal HVAC system. If a fuel-handling accident releases
 
radioactivity, radiation monitors in the normal fuel-handling building exhaust duct sense
 
high radioactivity and transmit a high-radiation signal to the balance of plant safety
 
actuation system, which in turn generates a fuel-handling building isolation signal which
 
causes the isolation dampers to close, isolating the fuel-handling building from the normal
 
supply and exhaust. The exhaust filtration units start automatically upon the isolation signal
 
and duct the exhaust from the filtration units to the plant vent. The fuel-handling building
 
post-accident exhaust system also can be ac tuated manually from the control room.
 
The fuel-handling building ventilation system s contain safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SCs
 
in the fuel-handling building ventilation system s potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the fuel-handling building
 
ventilation systems perform functions that support fire protection and EQ.
 
LRA Table 2.3.3.14 identifies fuel-handling bu ilding ventilation systems component types within the scope of license renewal and subject to an AMR: 
 
closure bolting  cooling coils (normal chilled water)  damper housings  ductwork and fittings  fan housings  fuel-handling building post-accident filter and fan unit housings  fuel-handling building post-accident filter and fan unit moisture eliminators  flexible connectors  piping components  valve bodies
 
2-73 The intended functions of the fuel handling-bu ilding ventilation systems component types within the scope of license renewal include:
 
missile barrier moisture elimination or reduction pressure-retaining boundary
 
2.3.3.14.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.14 and UFSAR Section 9.4.2 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
In reviewing LRA Section 2.3.3.13, the staff identified areas in which additional information was necessary to complete the review of the results of the applicant
=s scoping and screening. Therefore, by letter dated January 28, 2008, the staff issued a request for additional information concerning the specific issues to determine whether the applicant has properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff
=s RAIs and the applicant
=s related responses.
In RAI 2.3.3.14-1, dated January 28, 2008, the staff identified that the fuel handling building normal AC unit fans and fuel pool area recirculating air handling unit fans were not
 
identified on the drawings as in-scope, but were identified as being subject to an AMR. The
 
Scope Determination Summary states that non-safety-related fan housings associated with
 
this system are relied upon as missile barriers (for the fan element). Therefore, the staff
 
requested the applicant to clarify whether these components are subject to AMR.
 
Applicant's Response and Staff's Evaluation
 
In a letter dated February 27, 2008, the applicant stated: 
 
The fans are an airfoil design. The fan manufacturer asserts that the airfoil
 
fan blade design used for these fans does not fail catastrophically in such a
 
manner that a missile could be ejected. Therefore, the associated fan
 
housings are not considered in scope under 10 CFR Part 54.4(a)(2) criterion
 
as missile barriers.
 
The applicant also stated that the Scoping Determination Summary (Page 2.3-70) in the
 
LRA will be revised to qualify that only certain fan housings perform a missile barrier
 
function.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-1 acceptable.
 
2-74 In RAI 2.3.3.14-2, dated January 28, 2008, the staff concludes fuel pool area recirculating air handling system ductwork was not identified on the drawings as in-scope or being
 
subject to an AMR. The Scope Determination Summary states that certain ductwork and
 
dampers associated with the Fuel Handling Building Normal HVAC System interface with
 
the Fuel Handling Building Post-Accident Exhaust System and must maintain integrity in
 
order to maintain negative pressure in the Fuel Handling Building post-accident. 
 
Therefore, the staff requested the applicant to clarify whether these components are in
 
scope and subject to AMR.
 
Applicant's Response and Staff's Evaluation
 
In a letter dated February 27, 2008, the applicant stated: 
 
The ductwork from PASS 1-2702-P5-SAP does not perform an in-scope
 
function. NEI95-10 Appendix F section 5.2.2.1 provides the basis for air and
 
gas systems not being a hazard to other plant equipment. The failure of the
 
non-safety related portion of ductwork is not a credible event which could
 
impact the portion of duct that is in-scope for 10 CFR Part 54.4(a)(1).
 
Therefore, the ductwork from PASS 1-2702-P5-SAP is not considered in
 
scope under 10 CFR Part 54.4(a)(2) criterion.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-2 acceptable, because it is the staff's understanding, based on the applicant's response to the staff's RAI, that the ductwork does not perform an in scope function and therefore is not within the
 
scope of license renewal in accordance with 10 CFR 54.4(a).
 
In RAI 2.3.3.14-3, dated January 28, 2008, the staff identified fuel pool area recirculating air
 
handling system ductwork and booster that were not identified on the drawings as in-scope
 
or being subject to an AMR. The Scope Determination Summary states that certain
 
ductwork and dampers associated with the Fuel Handling Building Normal HVAC System interface with the Fuel Handling Building Post-Accident Exhaust System and must maintain
 
integrity in order to maintain negative pressure in the Fuel Handling Building post-accident.
 
Therefore, the staff requested the applicant to clarify whether these components are in
 
scope and are subject to AMR.
 
Applicant's Response and Staff's Evaluation
 
In a letter dated February 27, 2008, the applicant stated: 
 
The ductwork from PASS 2-2702-P5-SAP and Booster Fan 2-1541-B7-
 
001-000 does not perform an in-scope function. NEI 95-10 Appendix F
 
section 5.2.2.1 states that industry operating experience has shown no
 
failures due to aging that have adversely impacted the accomplishment of
 
a safety function. Failure of these non-safety related portions of ductwork
 
is not a credible event which could impact the portion of duct that is in-
 
scope for 10 CFR Part 54.4(a)(1). Therefore, the ductwork from PASS 2-
 
2702-P5-SAP and Booster Fan 2-1541-B7-001-000 is not considered in
 
scope under 10 CFR Part 54.4(a)(2) criterion.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-3 acceptable, 2-75 because it is the staff's understanding, based on the applicant's response to the staff's RAI, that the ductwork and booster fan do not perform an in scope function and therefore are not
 
within the scope of license renewal in accordance with 10 CFR 54.4(a).
 
2.3.3.14.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether
 
the applicant failed to identify any SCs within the scope of license renewal. The staff finds
 
no such omissions. In addition, the staff's 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 the applicant has adequately identified the fuel
 
handling building ventilation 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).
 
2.3.3.15  Ventilation Systems - Diesel Generator Building 2.3.3.15.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.15 describes the diesel generator building ventilation system, which
 
ventilates and removes heat from the building during diesel generator operation and
 
supplies sufficient heat for easy starting of the diesel generators and for personnel
 
occupancy. The system is divided into two subsystems, ESF and non-ESF. During normal
 
plant operation, the non-ESF heating system maintains a minimum temperature when the
 
diesel generators are not running. Non-ESF building ventilation is also utilized as required
 
for maintenance and personnel access.
 
The ESF ventilation system maintains the maximum temperature of the building below
 
analyzed limits with the diesel generator operating. Building ventilation is by 100-percent
 
outside air at summer design temperatures and by recirculation and outside air as the
 
temperature drops in winter. Power for the ESF ventilation equipment is by the Class 1E
 
bus of the same train as the diesel generator set ventilated.
 
The diesel generator building ventilation system contains safety-related components relied upon to remain functional during and following DBEs. In addition, the diesel generator
 
building ventilation system performs functions that support fire protection.
 
LRA Table 2.3.3.15 identifies diesel generator building ventilation system component types within the scope of license renewal and subject to an AMR: 
 
closure bolting  damper housings  ductwork and fittings  fan housings  filter housings - EDG control panel supply ventilation  flexible connectors The intended function of the diesel generator building ventilation system component types within the scope of license renewal is to provide a pressure-retaining boundary.
 
2-76 2.3.3.15.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.15 and UFSAR Section 9.4.7 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
In reviewing LRA Section 2.3.3.15, the staff identified areas in which additional information was necessary to complete the review of the results of the applicant
=s scoping and screening. Therefore, by letter dated January 28, 2008, the staff issued an RAI concerning the specific issues to determine whether the applicant has properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff
=s RAI and the applicant
=s related response.
In RAI 2.3.3.15-1, dated January 28, 2008, the staff identified that the diesel generator building ventilation system unit heater fans were not identified on the drawings as in-scope
 
or being subject to an AMR. The Scope Determination Summary states that non-safety-
 
related fan housings associated with this system are relied upon as missile barriers (for the
 
fan element). Therefore, the staff requested the applicant to clarify whether these
 
components are in scope and subject to an AMR.
 
In a letter dated February 27, 2008, the applicant stated: 
 
The Non-ESF Exhaust fan housings, perform a missile barrier function per
 
10 CFR 54.4(a)(2), and should have been shown as in scope on boundary drawings 1X4LD217 and 2X4LD217. Unit heaters, 1(2)-1566-U7001-000
 
through 1(2)-1566-U7-020-000, also perform a missile barrier function per 10
 
CFR 54.4(a)(2). 
 
The applicant will add commodity type Fan Housings (ID No.4) in LRA Table 3.3.2.15. They
 
will also provide the AMR for the Fan H ousings, and a new commodity type Heater Housings to Tables 2.3.3-15 and 3.3.2-15, the latter of which will provide the AMR for the
 
Heater Housings. The scoping determination (LRA Page 2.3-89) is also revised to reflect
 
the addition in accordance with 10 CFR 54.4(a)(2).
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.15-1 acceptable, because it is the staff's understanding, based on the applicant's response to the staff's RAI, that the fan housings are within the scope of license renewal in accordance with 10 CFR
 
54.4(a), and are subject to an AMR in accordance with 10 CFR 54.21(a) (1).
 
2.3.3.15.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI response, and drawings to determine whether the
 
applicant failed to identify any SCs within the scope of license renewal. The staff finds no
 
such omissions. In addition, the staff's review determined whether the applicant failed to
 
identify any components subject to an AMR. The staff finds no such omissions. On the 2-77 basis of its review, the staff concludes that the applicant has adequately identified the diesel generator building ventilation 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).
2.3.3.16  Ventilation Systems - Auxiliary Feedwater Pump House 2.3.3.16.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.16 describes the auxilia ry feedwater pumphouse ventilation system, which provides heating, cooling and ventilation for an environment suitable for equipment
 
and maintenance personnel. The system operat es whenever the pumps operate during normal, accident, or loss-of-offsite-power conditions. This system utilizes both ESF and
 
non-ESF outside air supply units. The ESF fans maintain the temperature in the pump
 
rooms within analyzed limits. Pneumatica lly-operated dampers open automatically for natural ventilation of the turbine-driven auxiliary feedwater pump room during SBO.
 
The auxiliary feedwater pumphouse ventilation sy stem contains safety-related components relied upon to remain functional during and following DBEs. In addition, the auxiliary
 
feedwater pumphouse ventilation sy stem performs functions that support fire protection and SBO.
 
LRA Table 2.3.3.16 identifies auxiliary feedw ater pumphouse ventilation system component types within the scope of license renewal and subject to an AMR: 
 
closure bolting  damper housings  ductwork and fittings  fan housings The intended function of the auxiliary feedwat er pumphouse ventilation system component types within the scope of license renewal is to provide a pressure-retaining boundary.
 
2.3.3.16.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.16 and UFSAR Section 9.4.8 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
In reviewing LRA Section 2.3.3.16, the staff identified areas in which additional information was necessary to complete the review of the results of the applicant
=s scoping and screening. Therefore, by letter dated January 28, 2008, the staff issued an RAI concerning the specific issues to determine whether the applicant has properly applied the scoping 2-78 criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff
=s RAI and the applicant
=s related response.
In RAI 2.3.3.16-1, dated January 28, 2008, the staff identified that the auxiliary feedwater
 
pump house ventilation system unit heater fans were not identified on the drawings as in-
 
scope or being subject to an AMR. The Scope Determination Summary states that non-
 
safety-related fan housings associated with the system are relied upon as missile barriers (for the fan element). Therefore, the staff requested the applicant to clarify whether these
 
components are in scope and subject to an AMR.
 
In a letter dated February 27, 2008, the applicant stated: 
 
The Housings for unit heaters, 1(2)-1593-U7-001-000 through 1(2)-1593-
 
U7-007-000, perform a missile barrier function per 10 CFR 54.4(a)(2),
and should have been shown as in scope on boundary drawings 1X4LD227 and 2X4LD227. 
 
As a result, the applicant LRA Tables 2.3.3.16 (Item 4) and 3.3.2.16 (Items 4a and 4b), will
 
be revised to include the missile barrier function. The scoping determination (LRA Page
 
2.3-91) is also revised to reflect the addition in accordance with 10 CFR54.4(a)(2).
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.16-1 acceptable, because it is the staff's understanding, based on the applicant's response to the staff's RAI, that the fan housings are within the scope of license renewal in accordance with 10 CFR
 
54.4(a), and are subject to an AMR in accordance with 10 CFR 54.21(a) (1).
 
2.3.3.16.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI response, and drawings to determine whether the
 
applicant failed to identify any SCs within the scope of license renewal. The staff finds no
 
such omissions. In addition, the staff's 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 the applicant has adequately identified the
 
auxiliary feedwater pump house ventilation 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).
 
2.3.3.17  Ventilation Systems - Miscellaneous LRA Section 2.3.3.17 describes the miscellaneous ventilation systems, which include the
 
following:
 
electrical tunnel ventilation system  piping penetration ventilation system  fire protection facilities ventilation system The electric tunnel ventilation system ventila tes the tunnels carrying safety-related train-oriented cables, normal cables, or both to prevent excessive heat during normal operation, shutdown, refueling, and accident conditions.
Essential system components ventilate the two diesel power cable tunnels (train A and train B), the two NSCW tower cable tunnels (train A and train B), and the turbine building and auxiliary building train A tunnel. Normal 2-79 system components ventilate the turbine building chase to control building tunnel. Each tunnel has its own subsystem.
 
The piping penetration ventilation system provides cooling air to the main steam and
 
feedwater pipe restraints in the main steam area and steam tunnel to keep concrete
 
temperatures below limits. The system functi ons during normal plant operation, startup, cold shutdown, cooldown and hot standby, and refueling operations and remains functional
 
during loss of offsite power. Power is fr om the non-Class 1E standby power system.
 
The fire protection facilities ventilation system uses fans and louvers to ventilate the fire protection pumphouses and fire protection valve houses and maintain the air temperature
 
within these structures at or below design temperature during fire pump operation. Two
 
diesel-driven fire pumps are located in one of the pumphouses and an electric motor-driven
 
fire pump in the other. The pump room ventilation components are within the scope of
 
license renewal for fire protection. 
 
The miscellaneous ventilation systems contai n safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SCs in the
 
miscellaneous ventilation systems potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the miscellaneous ventilation
 
systems perform functions that support fire protection and EQ.
 
LRA Table 2.3.3.17 identifies miscellaneous v entilation systems component types within the scope of license renewal and subject to an AMR: 
 
closure bolting  damper housings  ductwork and fittings  fan housings  filter housings - tunnel supply air  flexible connectors The intended functions of the miscellaneous ventilation systems component types within
 
the scope of license renewal include:
 
missile barrier pressure-retaining boundary
 
2.3.3.17A  Ventilation Systems - Electric Tunnel Ventilation
 
2.3.3.17A.1  Summary of Technical Information in the Application 
 
The electric tunnel ventilation system ventila tes the tunnels carrying safety-related train-oriented cables, normal cables, or both to prevent excessive heat during normal operation, shutdown, refueling, and accident conditions.
Essential system components ventilate the two diesel power cable tunnels (train A and train B), the two NSCW tower cable tunnels (train A and train B), and the turbine building and auxiliary building train A tunnel. Normal
 
system components ventilate the turbine building chase to control building tunnel. Each
 
tunnel has its own subsystem.
 
2-80 2.3.3.17A.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.17 and UFSAR Section 9.4.9.2 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
In reviewing LRA Section 2.3.3.17, the staff identified areas in which additional information was necessary to complete the review of the results of the applicant
=s scoping and screening. Therefore, by letter dated January 28, 2008, the staff issued an RAI concerning the specific issues to determine whether the applicant has properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff
=s RAI and the applicant
=s related response.
In RAI 2.3.3.17A-1, dated January 28, 2008, the staff identified that electrical tunnel ventilation system drawing shows that t he exhaust duct and fan are in scope, but the makeup air duct for this space were not identified on the drawings as in-scope or being subject to an AMR. The Scope Determination Summary states that non-safety-related fan housings associated with the system are relied upon as missile barriers (for the fan element). Therefore, the staff requested the applicant to clarify whether these components are in scope and subject to an AMR.
In a letter dated February 27, 2008, the applicant stated that the makeup air passageway
 
and associated components perform a pressure boundary function for makeup air to the
 
tunnels and should have been shown as in scope for 10 CFR 54.4(a)(2) on boundary drawings 1X4LD238 and 2X4LD238. The pressure boundary intended function will be
 
added to the concrete components (Component Type IDs 1-4) in License Renewal Application tables 2.4.5 and 3.5.2-5 to account for the concrete portion of the passageways
 
which serves a pressure boundary function for the makeup air.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.17A-1 acceptable, because it is the staff's understanding, based on the applicant's response to the staff's RAI, that the makeup air passageway and associated components are within the scope of
 
license renewal in accordance with 10 CFR 54.4(a), and are subject to an AMR in
 
accordance with 10 CFR 54.21(a) (1).
 
In RAI 2.3.3.17A-2, dated January 28, 2008, the staff identified that the electric tunnel
 
ventilation system fan for the North-South Turbine Building Chase to Control Building tunnel
 
ventilation and associated ductwork were not identified on the drawings as in-scope as
 
being subject to an AMR therefore, the staff requested the applicant to clarify whether these
 
components are in scope and subject to an AMR.
 
In a letter dated February 27, 2008, the applicant stated:
 
the North-South Turbine Building Chase to Control Building Tunnel
 
Ventilation Fan 1(2)-1540-B7-007-000 and associated ductwork are not 2-81 credited in the design calculations for exhausting the Turbine Building and Auxiliary Building Train A Tunnel. The purpose of these fans is to
 
recirculate and, thereby, prevent a stagnant air condition in the adjoining
 
Turbine Building Chase to Control Building Tunnel during normal plant
 
conditions. Therefore, the North-South Turbine Building Chase to Control
 
Building Tunnel Ventilation Fan 1(2)-1540-B7-007-000 and associated
 
ductwork are not in scope for license renewal.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.17A-2 acceptable, because it is the staff's understanding, based on the applicant's response to the staff's RAI, that the North-South Turbine Building Chase to Control Building. Tunnel Ventilation Fan
 
(1(2)-1540-B7-007-000) and associated duct are not in scope of license renewal in
 
accordance with 10 CFR 54.4(a), and are not subject to an AMR in accordance with
 
10 CFR 54.21(a)(1).
 
2.3.3.17A.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether
 
the applicant failed to identify any SCs within the scope of license renewal. The staff finds
 
no such omissions. In addition, the staff's 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 the applicant has adequately identified the
 
electric tunnel ventilation system component s 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).
 
2.3.3.17B  Ventilation Systems - Piping Penetration Ventilation
 
2.3.3.17B.1  Summary of Technical Information in the Application 
 
The piping penetration ventilation system provides cooling air to the main steam and
 
feedwater pipe restraints in the main steam area and steam tunnel to keep concrete
 
temperatures below limits. The system functi ons during normal plant operation, startup, cold shutdown, cooldown and hot standby, and refueling operations and remains functional
 
during loss of offsite power. Power is fr om the non-Class 1E standby power system.
 
2.3.3.17B.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.17 and UFSAR Section 9.4.9.3 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.3.17B.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant 2-82 failed to identify any SCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's 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 the applicant has adequately identified the piping
 
penetration ventilation 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).
 
2.3.3.17C  Ventilation Systems - Fire Protection Facilities HVAC
 
2.3.3.17C.1  Summary of Technical Information in the Application 
 
The fire protection facilities ventilation system uses fans and louvers to ventilate the fire protection pumphouses and fire protection valve houses and maintain the air temperature
 
within these structures at or below design temperature during fire pump operation. Two
 
diesel-driven fire pumps are located in one of the pumphouses and an electric motor-driven
 
fire pump in the other. The pump room ventilation components are within the scope of
 
license renewal for fire protection. 
 
2.3.3.17C.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.17 and UFSAR Section 9.5.1 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.3.17C.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 the applicant has adequately identified the fire protection
 
facilities HVAC system components within t he 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).
 
2.3.3.18  Ventilation Systems - Radwaste Buildings HVAC 2.3.3.18.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.18 describes the radwaste building ventilation systems, which include
 
the ventilation systems for the radwaste transfer building, radwaste transfer tunnel, and dry
 
active waste (DAW) Facilities.
 
The functions of the radwaste transfer building, radwaste transfer tunnel, and DAW facilities HVAC systems are to:
 
2-83  heat, cool, and ventilate the DAW facility for proper operation of equipment and personal comfort of maintenance or operations personnel  distribute and exhaust air suitably to reduce possible concentrations of radioactive and chemical impurities in the process areas  draw effluent exhaust air from the radwaste transfer building through the auxiliary building filtration system  ventilate the tunnel as required for periodic inspection The radwaste transfer building and radwaste transfer tunnel HVAC systems are abandoned
 
except for the auxiliary building filtration system exhaust ductwor k from the auxiliary building radwaste area filter exhaust and c ontinuous exhaust system; however, a fire damper in the west fire-rated wall to prevent smoke and fire from translating to the auxiliary building via the radwaste transfer tunnel is in the fire protection program, which is credited
 
for 10 CFR 50.48 compliance and is within the scope of license renewal for fire protection.
 
The radwaste building ventilation systems perform functions that support fire protection.
 
LRA Table 2.3.3.18 identifies radwaste buildi ng ventilation systems component types within the scope of license renewal and subject to an AMR: 
 
damper housings  ductwork and fittings The intended function of the radwaste building ventilation systems component types within the scope of license renewal is to provide a pressure-retaining boundary.
 
2.3.3.18.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.18 and UFSAR Section 9.4.3.3 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.3.18.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 the applicant has adequately identified the radwaste
 
building HVAC system components within t he 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).
 
2-84 2.3.3.19  Fire Protection Systems 2.3.3.19.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.19 describes the fire protection systems, which include the following:
 
fire protection water system  fire protection seismic Category 1 water system  fire protection halon systems The fire protection water system minimizes both the probability and the consequences of
 
postulated fires by adequate means for prompt fire detection, suppression, and control. The
 
primary goals of the fire protection water system are to ensure performance of design
 
functions required for safe plant shutdown and to minimize the probability of radioactive
 
releases to the environment in a fire. To prev ent or limit fire damage to safety-related SCs so at least one redundant train of equipment is available for safe shutdown, the system
 
relies on fire prevention, fire suppression, fire detection and annunciation, suppression
 
system automatic supervision, fire separati on and confinement, fire extinguishment, fire brigade implements, and plant design features to minimize fires and their consequences.
 
Fire water suppression systems include fire tanks and pumps, automatic and manual spray
 
and sprinkler systems, hose stations, fire hydrants and hose houses, and fire mains or yard
 
loop headers to supply water to extinguish fires. Consumables and short-lived components
 
(e.g., fire extinguishers, self-contained breathing apparatus air bottles, fire brigade accouterments like boots, gloves, and helmets, and fire hoses) are included in this system.
 
Screening of the fire detection and actuation portion of this system is as part of the
 
electrical and instrumentation and controls sy stems (see LRA Section 2.5), of fire dampers as parts of the assigned HVAC system, of other passive fire barriers as parts of the
 
structural systems (see LRA Section 2.4), and of the RCP oil collection system as part of the RCS and connected lines (LRA Section 2.3.1.3).
 
The fire protection - seismic Category 1 water system supplies fire-extinguishing water for
 
manual hose stations in areas with equipment required for safe shutdown after a safe
 
shutdown earthquake that might disable the nor mal fire protection system. This system fights fires following a safe shutdown earthquake if no other source of fire-fighting water is
 
available. The system is completely manual with hose stations and stand pipes in the
 
containment, diesel generator, auxiliary, and c ontrol buildings. The NSCW system supplies water by manual valves normally locked closed.
 
The fire protection halon system, which protects by halon fire-extinguishing gas electrical
 
equipment which supports safe plant shutdown, is composed of halon cylinders, discharge
 
piping, local halon control panels, and instruments. Shutdown panels in the control building
 
shutdown panel rooms and ventilation equipment in the control building records storage
 
room supporting safe plant shutdown are protected from fire by packaged halon flooding
 
systems. Other plant spaces and electrical equipment not supporting safe plant shutdown
 
but fire-protected by packaged halon systems include the plant operating computer; the
 
service building communications room; the service building plant documentation storage rooms; and the technical support center communication, computer, cathode ray tube (CRT)
 
display, and electrical equipment rooms.
 
The fire protection systems contain safety-related components relied upon to remain 2-85 functional during and following DBEs. In addition, the fire protection system performs functions that support fire protection and EQ.
 
LRA Table 2.3.3.19 identifies fire protection systems component types within the scope of
 
license renewal and subject to an AMR: 
 
closure bolting  fire hydrants  flame arrester elements  flame arrester housings  flexible connectors  flow orifice/elements  fusible links and sprinkler head bulbs  hose station nozzles and hose connections  hose stations  piping components  pump casings - fire pumps (diesel-driver, motor-driven, and jockey pumps)  sight glasses  silencers  spray shields  sprinkler heads and spray nozzles  strainer elements  strainer housings  tanks - fuel oil storage tanks (fire pump diesel)  tanks - fire protection water storage tanks  valve bodies The intended functions of the fire protection systems component types within the scope of
 
license renewal include:
 
protection from debris  prevention of flame propagation from i gnition of vent pipe vapors back to the source  spray shield or curbs for flow direction  flow pattern or distribution provision  restriction of process flow  pressure-retaining boundary 2.3.3.19.2  Staff Evaluation The staff reviewed the VEGP LRA
, Section 2.3.3.19, (UFSAR), Section 9.5.1; NUREG-1137, "Safety Evaluation Report Related to the Operation of Vogtle Electric Generating
 
Plant, Units 1 and 2," through Supplement 5; and NUREG-1137, "Safety Evaluation Report 2-86 Related to the Operation of Vogtle Electric Generating Plant, Units 1 and 2," through Supplement 9; approving the VEGP Fire Protection Program listed in the VEGP Units 1 and
 
2 Operating License Condition 2.G, using the evaluation methodology described in SER, Section 2.3, and the guidance in SRP-LR
, Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
The staff also reviewed VEGP Units 1 and 2 commitments to Title 10 CFR 50.48, "Fire
 
protection" (i.e., approved fire protection program), using their commitment documents to
 
the Branch Technical Position (BTP) Chemical and Mechanical Engineering Branch (CMEB) 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants," Revision 2, July
 
1981, documented in the fire protection CLB. 
 
The staff's review of LRA, Section 2.3.3.19, identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAIs as discussed below.
 
In RAI 2.3.3.19-1, dated January 28, 2008, the staff stated that the following LRA drawings
 
show fire protection system components as out of scope (i.e., not colored in red):
 
LRA drawing CX4LD173-2:
 
Fire Hydrants  Fire Protection Piping to Turbine Building, Steam Tunnel, and Radwaste Solidification Building  Intake Structure LRA drawing CX4LD173-4, in the following locations:
Dry Active Waste Processing Facility  Dry Active Waste Storage Building 
 
LRA drawing 1X4LD174-1, Halon 1301 fire protection system in the following locations:
Computer Room Level A  Computer CRT Display and Communication Rooms Level 1  Radwaste Solidification Building Contamination Oil Room Level 1  Radwaste Solidification Building Elevation 192'-0" LRA drawing 2X4LD174-1, Halon 1301 fire protection system's in the following location:
Computer Room Level A
 
2-87 The staff requested that the applicant veri fy whether the above systems and components are in the scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an
 
AMR in accordance with 10 CFR 54.21(a)(1). 
 
If these components are excluded from the scope of license renewal and not subject to an
 
AMR, the staff requests that the applicant provide justification for the exclusion. By letter
 
dated February 27, 2008, the applicant stated that:
 
The fire protection SCs that are relied upon in the event of a fire to
 
maintain the ability to perform reactor plant safe shutdown functions at
 
VEGP (including plant SCs that are relied upon to perform safe shutdown
 
in the event of a fire), or to minimize radioactive releases to the
 
environment in the event of a fire, are in-scope for license renewal - see
 
VEGP-LR-TE-007, "Technical Evaluation VEGP Fire Protection Scoping." 
 
For the fire protection system, certain SCs are in scope for license
 
renewal and certain SCs are not in scope, depending on whether they are
 
relied upon for 10 CFR 50.48 and Branch Technical Position (BTP)
 
CMEB 9.5-1 compliance or not (hereafter referred to as "regulatory
 
compliance"). The following is a breakdown of fire protection SCs and a
 
discussion of in-scope applicability:
Drawing CX4LD173-2: The fire hydrants listed in UFSAR Table 9.5.1-10D
 
are required for regulatory compliance and are in scope and highlighted
 
as such on the drawing. Those fire hydrants not in UFSAR Table 9.5.1-
 
10D are not required for regulatory compliance and are not in scope and
 
thus not highlighted on the drawing. The fire protection piping to the
 
Turbine Building (including steam tunnels) is not in scope because the fire
 
protection system in the Turbine Building is not relied upon for regulatory
 
compliance (FSAR Appendix 9B, paragraph C.7.h). Refer to the answer
 
to RAI 2.1-2 for discussion regarding non-safety related components in
 
the Turbine Building. 
 
The fire protection system in the Radwaste Solidification Building is not in
 
scope because the building has been abandoned in place and there is no
 
radioactive material stored there (UFSAR Section 11.4.2.4). 
 
Since the Intake Structure is not in the scope of license renewal, the fire protection system in this structure is not in scope. See License Renewal Civil Boundary Drawing AX1D45L01.
 
In evaluating this response, the staff finds that it was incomplete and that review of LRA, Section 2.3.3.19, could not be completed. Several yard fire hydrants are excluded from the
 
scope of license renewal and from subject to an AMR. 
 
During a conference call, the staff questioned, in RAI 2.3.3.19-1, the applicant's
 
methodology, which excluded certain fire hydr ants from the scope of the license renewal and subject to an AMR. In its response dated June 23, 2008, the applicant stated that:
 
Fire protection SCs that are relied upon in the event of a fire to maintain
 
the ability to perform reactor plant safe-shutdown functions at VEGP (including plant SCs that are relied upon to perform safe-shutdown in the
 
event of a fire), or to minimize radioactive releases to the environment in
 
the event of a fire are in-scope for license renewal. For the fire protection 2-88 system, certain SCs are in scope for license renewal and certain SCs are not in scope, depending on whether they are relied upon for 10 CFR
 
50.48 and BTP CMEB 9.5-1 compliance or not (hereafter referred to as
 
"regulatory compliance").
 
The CLB for VEGP's fire protection system is as follows:
 
The fire protection systems described in the VEGP UFSAR conform to General Design
 
Criterion 3 as stated in UFSAR Section 3.0 (10 CFR 50, Appendix A, "General Design
 
Criteria for Nuclear Power Plants," Criterion 3, "Fire Protection"). The scoping criteria in 10
 
CFR 54.4(a)(3) states that plant SCs within the scope of this part are "-relied on in safety
 
analyses or plant evaluations to perform a function that demonstrates compliance with the
 
NRCs regulation for fire protection (10 CFR 50.48)..." In addition to compliance with
 
General Design Criterion 3 and 10 CFR 50.48, VEGP also utilizes the detailed guidance of
 
BTP CMEB 9.5.1, "Guidelines for Fire Protection for Nuclear Power Plants."
 
10 CFR 50.48 dictates that each applicant must have a fire protection plan that satisfies
 
Criterion 3 of Appendix A to 10 CFR 50. Criterion 3, "Fire Protection," stipulates:
 
"Structures, systems, and components important to safety shall be designed and located to minimize, consistent with other safety requirements, the probability and effect of fires and
 
explosions. Noncombustible and heat resistant materials shall be used wherever practical
 
throughout the unit, particularly in locations such as the containment and control room. Fire
 
detection and fighting systems of appropriate capacity and capability shall be provided and
 
designed to minimize the adverse effects of fires on structures, systems, and components important to safety. Firefighting systems shall be designed to assure that their rupture or inadvertent operation does not significantly impair the safety capability of these structures, systems, and components." 10 CFR 50.48 requires that the plan describe specific features
 
necessary to implement the program such as automatic and manually operated fire detection and suppression systems, and the means to limit fire damage to SCs important to safety so that the capability to shut down the plant safely is ensured.
 
The VEGP fire protection program is described in detail in the UFSAR and was approved
 
as described in the UFSAR and other licensing documents by the NRC in the operating
 
license:
Southern Nuclear shall implement and maintain in effect all provisions of
 
the approved fire protection program as described in the Final Safety
 
Analysis Report for the facility, and submittals dated July 2, August 4 and
 
13, October 10 and 24, November 5, and December 19, 1986, and
 
January 2, 1987, as approved in the SER (NUREG-1137) through
 
Supplement 5 subject to the following provision:
Southern Nuclear may make changes to the approved fire protection
 
program without prior approval of the Commission, only if those changes
 
would not adversely affect the ability to achieve and maintain safe-
 
shutdown in the event of a fire.
 
The SER (NUREG-1137) was reviewed through Supplement 9 to help make scoping
 
determinations. 
 
NUREG-1800 section 2.1.3.1.3, "Regulated Events," is a source of additional guidance on 2-89 applying the scoping criteria of 10 CFR 54.4(a)(3). It states that "...all SCs that are relied upon in the plant's CLB (as defined in 10 CFR 54.3), plant-specific experience, industry-
 
wide experience (as appropriate), and safety analyses or plant evaluations to perform a
 
function that demonstrates compliance with NRC regulations identified under 10 CFR
 
54.4(a)(3), are required to be included within the scope of the rule."  In addition, it limits the
 
extent of the review with the statement that "an applicant need not consider hypothetical
 
failures or second-, third-, or fourth-level s upport systems in determining the SCs within the scope of the rule for 10 CFR 54.4(a)(3)." This guidance is not intended to exclude any
 
support system...that is specifically relied upon for compliance with the applicable NRC
 
regulation. The guidance also recognizes that "mere mention of an SC in the analysis or
 
evaluation does not necessarily constitute support of an intended function as required by
 
the regulation." Thus, the mention of a system, structure, or component in an analysis or
 
evaluation (e.g., UFSAR, etc.) does not in and of itself constitute reliance on the SC for
 
regulatory compliance. Fire protection components also exist solely to satisfy insurance
 
requirements and are likewise not relied upon for regulatory compliance and are not in the
 
CLB.
 
In general, every fire protection system, structure, and component was reviewed against
 
the current licensing basis and scoping determinations were made based on whether the
 
SC is part of the CLB or not. 
 
For the fire protection water system, portions of the system that are in scope for 10 CFR
 
54.4 a(3) are separated from portions of t he system that are not in scope by manual isolation valves that are normally open. These valves remain normally open so that in the
 
event of a fire in a not-in-scope portion of the system, water may be immediately available
 
for fire suppression following automatic initiation of the detection/suppression system(s) in
 
the not-in-scope portion. This also applies to not-in-scope yard fire hydrants that may be
 
used to manually suppress fires. Should an age related pressure boundary failure occur in
 
the not-in-scope portion of the system such that a significant system pressure drop results, an alarm would notify plant personnel and the fire water pump(s) would start automatically.
 
Following the alarm and pump start, plant personnel would investigate the cause and
 
manually close the isolation valve(s) separating the failed not-in-scope portion of the
 
system from the in-scope portion, as warranted, considering the need to preserve fire water
 
inventory for 10 CFR 50.48 compliance. The design of the system provides multiple pumps
 
and a large volume of stored water which can be used to maintain system pressure while
 
the location of a leak is identified and isolated. Ample time is available to isolate a leak in a
 
not-in-scope location before operability of the 50.48 protection features can be affected.
 
Therefore, terminating the license renewal boundary at an open manual isolation valve is
 
acceptable.
 
Based on its review, the staff finds the applicant's response to the first portion of
 
RAI 2.3.3.19-1 acceptable. The fire hydrants included in scope of license renewal
 
encompass the fire hydrants included in Table 9.5.1-10D, UFSAR Amendment 28, November 14, 1985, and reviewed and approved by the staff in Supplement 4 to NUREG-
 
1137, December 1985, as a part of the original CLB of VEGP. This report is referenced
 
directly in the VEGP fire protection CLB and summarizes the fire protection program and
 
commitments to 10 CFR 50.48 using BTP CMEB 9.5-1. Supplement 4 to NUREG-1137
 
reviewed the VEGP UFSAR Amendments 24, 25, and 28, in which the applicant made
 
substantial changes to its fire hazards analysis for compliance with the guidelines set forth
 
in BTP CMEB 9.5-1. Originally VEGP UFSAR Amendment 28, Table 9.5.1-10D, consisted 2-90 of four hydrants for Unit 1. After Unit 2 commercial operation, seven hydrants were added in Table 9.5.1-10D based on the Unit 2 fire hazard analysis. 
 
The staff finds the hydrants in question are not credited to meet the requirements of
 
Appendix R for achieving safe-shutdown in the event of a fire and were correctly excluded
 
from the scope of license renewal and not subject to an AMR. Therefore, the staff's concern
 
described in the first portion of RAI 2.3.3.19-1 is resolved.
 
In its response, by letter dated February 27, 2008, the applicant stated that, in Drawing CX4LD173-4:
 
The fire protection systems in the Dry Active Waste Processing Facility and
 
Dry Active Waste Storage Building are in the scope of license renewal.
 
Although these buildings are in the scope of license renewal, they are
 
categorized as structures and are not highlighted on mechanical boundary drawing CX4LD173-4 because this drawing is strictly a mechanical boundary
 
drawing as stated in the drawing title block. Structures are sometimes shown
 
on mechanical boundary drawings for clarity in describing the mechanical
 
system, but the structure itself is not highlighted on the mechanical boundary
 
drawings. For the highlighted in-scope structures, see License Renewal Civil Boundary Drawing AX1D45L01. 
 
Based on its review, the staff finds the applicant's response to the second portion of RAI
 
2.3.3.19-1 acceptable because the applicant explained that the fire suppression systems
 
and components in the Dry Active Waste Processing Facility and Dry Active Waste Storage
 
Building are in scope of license renewal and subject to an AMR. The applicant identified
 
that, although the Dry Active Waste Processing Facility and Dry Active Waste Storage
 
Building are in scope of license renewal and categorized as structures, they are not highlighted on mechanical boundary drawing CX4LD173-4. However, these structures are highlighted on the civil boundary drawing AX1D45L01. Therefore, the staff is adequately
 
assured that the above fire suppression systems and components for fire suppression in
 
the Dry Active Waste Processing Facility and Dry Active Waste Storage Building will be
 
considered appropriately during the aging management activities. Therefore, the staff's
 
concern described in the second portion of RAI 2.3.3.19-1 is resolved. 
 
In its response, by letter dated February 27, 2008, the applicant stated that in, Drawing 1X4LD174-1:
 
The Halon systems in the Computer R oom Level A, Computer CRT Display and Communication Rooms Level 1, Radwaste Solidification Building
 
Contamination Oil Room Level 1, and the Radwaste Solidification Building Elevation 192'-0" are shown not highlighted on drawing 1X4LD174-1.
 
UFSAR Table 9.5.1-10, paragraph 4.1, lists the fixed Halon systems required
 
for regulatory compliance and these systems are highlighted on drawing 1X4LD174-1. The above listed Halon systems are not in this table because
 
they are not required for regulatory compliance and are thus not in the scope
 
of license renewal. The fire protection system in the Radwaste Solidification
 
Building is not in scope because it has been abandoned in place and there is
 
no radioactive material stored there (FSAR Section 11.4.2.4). 
 
2-91 In its response, by letter dated February 27, 2008, the applicant stated that in, Drawing 2X4LD174-1:
 
The Halon system in the Computer R oom Level A is shown not highlighted on drawing 2X4LD174-1. UFSAR Table 9.5.1-10, paragraph 4.1, lists the
 
fixed Halon systems required for regulatory compliance and these systems are highlighted on drawing 2X4LD174-1. The above listed Halon system is
 
not in this table because it is not required for regulatory compliance and is
 
thus not in the scope of license renewal. 
 
The staff finds that the applicant's two responses shown above, acceptable. The total
 
flooding Halon 1301 systems in Computer R oom Level A, Computer CRT Display and Communication Rooms Level 1, Radwaste Solid ification Building Contamination Oil Room Level 1, and the Radwaste Solidification Building Elevation 192'-0, 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. Although the total flooding Halon 1301
 
fire suppression system for the above areas are addressed in the NUREG-1137, these
 
systems in question are not credited to meet the requirements of Appendix R for achieving safe-shutdown in the event of a fire. The staff has confirmed that the applicant correctly
 
excluded the above total flooding Halon 1301 fi re suppression systems from scope of license renewal and subject to an AMR. Therefore, the staff's concerns described in the
 
third and fourth portions of RAI 2.3.3.19-1 are resolved.
 
In RAI 2.3.3.19-2, dated January 28, 2008, the staff stated that LRA, Section 2.3.3.19, discusses requirements for the fire water supply system but does not mention trash racks
 
and traveling screens for the fire pump suction water supply. Trash racks and traveling
 
screens are located upstream of the fire pump suctions to remove any major debris from
 
the fresh or raw water. Trash racks and traveling screens are necessary to remove debris
 
from and prevent clogging of the fire protection water supply system. Trash racks and
 
traveling screens are typically considered to be passive, long-lived components. Both trash racks and traveling screens are located in a fresh or raw water/air environment and are
 
typically constructed of carbon steel. Carbon steel in a fresh or raw water environment or
 
water/air environment is subject to loss of material, pitting, crevice formation, and
 
microbiologically influenced corrosion, and fouling. The staff requested that the applicant
 
explain the apparent exclusion of the trash racks and traveling screens that are located
 
upstream of the fire pump suctions from 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).
 
By letter dated February 27, 2008, the applicant provided the following response:
 
VEGP's fire pumps take suction from fire water storage tanks and as
 
such, do not have trash racks and traveling screens. See LRA drawing CX4LD173-1. 
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.19-2 acceptable
 
because it adequately described that the intended function supporting the fire pump suction
 
supply is accomplished from the water storage tanks for Units 1 and 2. The fire pumps at
 
VEGP do not take suction from a natural source or bay; therefore, trash racks and traveling
 
screens are not required. Additionally, water tanks are in license renewal scope and are
 
subject to an AMR. Therefore, the staff's concern described in RAI 2.3.3.19-2 is resolved.
 
2-92 In RAI 2.3.3.19-3, dated January 28, 2008, the staff stated that LRA, Table 2.3.3-19, excludes several types of fire protection components that appear in NUREG-1137 and its
 
supplements and/or the UFSAR, and which also appear in the LRA drawings colored in red.
 
These components are listed below: 
 
Hose racks  Yard hose houses  Interior fire hose stations  Pipe fittings  Pipe supports and hangers  Couplings  Threaded connections  Restricting orifices  Interface flanges  Dikes for oil spill confinement  Floor drains and curbs for fire-fighting water  Filter housing  Heater housing  Chamber housing  Actuator housing  Halon storage tanks/bottles  Buried outside diesel fuel storage tanks  Buried fire protection piping and underground fire main loop  Heat exchanger (bonnet)  Heat exchanger (shell)  Heat exchanger (tube)  Post-indicator sectional control valves  Turbocharger  Tank heater  Thermowells  Expansion joints  Gear box housing  Lubricating oil collecting system components (reactor coolant pump)  Engine intake and exhaust silencers/muffler (diesel driven fire pump)  Backflow prevention devices  Flame retardant coating for cables  Fire retardant coating for structural steel supporting walls and ceilings  Fire barrier penetration seals  Fire barrier walls, ceilings, floor, and slabs  Fire doors  Fire rated enclosures
 
The staff requested that the applicant verify whether the components listed above should
 
be included in LRA, Table 2.3.3.19. If they are excluded from the scope of license renewal
 
and not subject to an AMR, the staff requests that the applicant provide justification for the
 
exclusion. 
 
By letter dated February 27, 2008, the applicant stated that:
 
2-93 For the most part, the above listed fire protection components are in the scope of license renewal. In some cases, the item is not specifically listed in
 
Table 2.3.3.19 but is included as one of the component types listed in the
 
table. For example, "pipe fittings" and several other components listed above
 
are included as "piping components" in Table 2.3.3.19. This is consistent
 
with the guidance provided in NEI 95-10, Revision 6, and Appendix B. The
 
following is a breakdown of how each component is treated in license
 
renewal: 
: 1) Hose racks are in scope and form part of a hose station, and as such, are included as "hose stations" in Table 2.3.3.19. 2) Yard hose houses are not in the scope of license renewal because they are not required for regulatory compliance and are a second level support
 
system for yard fire hydrants and fire hydrant fire hoses. These structures
 
are small sheds associated with yard fire hydrants and serve as a
 
convenient location for storing tools and the accompanying fire hydrant fire
 
hoses. These structures also afford limited protection from the weather for
 
the fire hydrants and fire hoses. However, convenience of fire hydrant
 
accessory storage and limited protection from the weather for the fire
 
hydrants and fire hoses are not credited in license renewal and not
 
required for regulatory compliance. Hypothetical failure of a hose house, which is a second level support system, need not be considered in
 
determining the SCs within the scope of the rule under 10 CFR 54.4(a)(3) -
 
see NUREG-1800, Revision 1, Section 2.1.3.1.3. The cast iron fire
 
hydrants are in scope and age managed in the outdoor environment (fire
 
hydrants in Table 2.3.3.19) and the fire hoses are in scope but are short-
 
lived, being subject to periodic replacement and as such, do not require an
 
AMR. 3) Interior fire hose stations are in scope and included in hose station nozzles and hose connections and hose stations in Table 2.3.3.19. 4) Pipe fittings are in scope and included in "piping components" in Table 2.3.3.19. 5) Pipe supports and hangers are in scope and considered structural components and covered in Table 2.4.12. 6) Couplings are in scope and included in "piping components" in Table 2.3.3.19. 7) Threaded connections are in scope and included in "piping components" in Table 2.3.3.19. 8) Restricting orifices are in scope and included in "flow orifice/element" in Table 2.3.3.19. 9) Interface flanges are in scope and included in "piping components" in Table 2.3.3.19. 10) Dikes for oil spill confinement are considered to be part of the in-scope structure in which they are located and are included in structural concrete
 
commodities in LRA section 2.4. 11a) Curbs for containment of spilled water, including fire fighting water, are considered to be part of the in-scope structure in which they are located
 
and are also included in structural concrete commodities in LRA Section
 
2.4. 11b) Floor drains for processing spilled water, including fire fighting water, are included in the "Drains Systems" and are found in Table 2.3.3.23. The 2-94 structures for which the drain systems are in scope include the containment building, the auxiliary building, and the control building, and
 
the fuel handling building. The NSCW structure has a leak detection
 
system with associated level switches and alarms. The drain or leak
 
detection features for these structures are in scope primarily for mitigation
 
of flooding due to a line break. However, release of fire protection system
 
water in these structures would also be processed by these in-scope
 
drains. The drain systems for the other structures that contain in-scope fire
 
protection systems are not credited in the CLB for mitigation of flooding
 
and are therefore not in the scope of license renewal. Flooding analyses
 
have determined that flooding in these structures will not impact any
 
safety-related equipment.
 
==References:==
VEGP-LR-TE-010, "Scoping
 
Methodology for Nonsafety Related Equipment that Could Affect Safety
 
Related Equipment," Section 5.3.2; UFSAR Sections 3F.2.4, 3.4.1, and
 
9.3.3. 12) Filter housings are in scope and included as "strainer housings" in Table 2.3.3.19. 13) Heater housings are associated with the fire water pump diesel engines' on-skid heat exchangers. The fire pump diesel engines and the on-skid
 
equipment are in scope but are complex active assemblies, not subject to
 
an AMR. 14) Chamber housings include retard c hambers in fire suppression systems.
Chambers are in scope and included as "piping components" in Table
 
2.3.3.19. 15) Actuator housings include dry pilot actuator housings in fire suppression systems. Actuator housings are in scope and included as "valve bodies" in
 
Table 2.3.3.19. 16) Halon storage bottles are in scope and are short-lived, being subject to periodic replacement and as such, do not require an AMR. 17) The fire pump diesel fuel oil storage tanks are in scope but are not buried, being located outside, above ground level. They are included in Table
 
2.3.3.19 as "tanks -F. O. storage tanks (fire pump diesel)."  18) The buried fire protection piping and underground fire main loop are in scope and included in Table 2.3.3.19 as follows: piping components; fire
 
hydrants; valve bodies; closure bolting. 19) Heat exchanger bonnets are associated with the fire water pump diesel engines' on-skid heat exchangers. The fire pump diesel engines and the
 
on-skid equipment are in scope but are complex active assemblies, not
 
subject to an AMR. 20) Heat exchanger shells are associated with the fire water pump diesel engines' on-skid heat exchangers. The fire pump diesel engines and the
 
on-skid equipment are in scope but are complex active assemblies, not
 
subject to an AMR. 21) Heat exchanger tubes are associated with the fire water pump diesel engines' on-skid heat exchangers. The fire pump diesel engines and the
 
on-skid equipment are in scope but are complex active assemblies, not
 
subject to an AMR. 22) The post-indicator sectional control valves are in scope and included as "valve bodies" in Table 2.3.3.19. 23) The turbochargers are associated with the fire water pump diesel engines and are mounted on the engines. The fire pump diesel engines, their 2-95 appurtenances, and the on-skid equipment are in scope but are complex active assemblies, not subject to an AMR. 24) There are no tank heaters associated with the fire protection system tanks -fire water storage tanks or fire pump diesel fuel oil storage tanks. 25) Thermowells are in scope and included as "piping components" in Table 2.3.3.19. 26) Expansion joints are in scope and included as "flexible connectors" in Table 2.3.3.19. 27) Gear box housings for such components as electric motor driven equipment are in scope but are part of the complex active assembly and
 
not subject to an AMR. 28) The lubricating oil collecting system components (reactor coolant pump) are in scope and included in the RCS in Table 2.3.1.3 as follows: RCP lube
 
oil drain tank; RCP lube oil drain tank flame arrestor element; RCP lube oil
 
drain tank flame arrestor housing; RCP lube oil drip pans and enclosure;
 
piping components. 29) The engine intake and exhaust silencers/mufflers (diesel driven fire pump) are in scope. The mufflers are mounted on the fire pump house roof and
 
are included in Table 2.3.3.19 as "silencers." The intake silencers are
 
mounted on the engine skids and are part of the complex active engine
 
assembly and as such, do not require an AMR. 30) The backflow prevention devices include check valves and are included in Table 2.3.3.19 as "valve bodies". 31) Flame retardant coatings are not used at VEGP for cables. 
: 32) Fire retardant coatings for structural steel supporting walls and ceilings are in scope and included in LRA Section 2.4.12 and Table 2.4.12, Item 13. 33) Fire barrier penetration seals are in scope and included in LRA Section 2.4.12 and Table 2.4.12, Item 18. 34) Fire barrier walls, ceilings, floors, and slabs are in scope and included in LRA Section 2.4.12 and Table 2.4.12, Items 14 and 15. 35) Fire doors are in scope and included in LRA Section 2.4.12 and Table 2.4.12, Item16. 36) Fire rated enclosures are in scope and included in LRA Section 2.4.12 and Table 2.4.12, Items 12 and 17.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.19-3 acceptable.
 
Although the applicant states that they consider some components to be included in other
 
line items, the descriptions of the line items in the LRA do not actually list all these
 
components specifically. Further the applicant has committed to interpret some
 
components, for example, dikes for oil spill confinement and curbs for fire-fighting, as being
 
included in structural concrete commodities in LRA, Section 2.4. Floor drains for processing
 
spilled water, including fire-fighting water are included in "Auxiliary Syst em Drains Systems" in LRA Table 2.3.3.23. The applicant has included the following items in the scope of
 
license renewal and subject to an AMR because of their intended functions as part of the
 
pressure boundary: (1) hose racks are included in hose stations commodity; (2) interior fire
 
hose stations are included in hose station nozzles and hose connection commodity; (3)
 
pipe fittings, couplings, threaded connections, interface flanges, chamber housing, and
 
thermowells are included in piping components commodity; (4) pipe supports, fire retardant
 
coatings for structural steel, fire barrier penetration seals, fire barrier wall, ceiling, floor, and
 
slabs, fire doors, and fire rated enclosures are included in Section 2.4.12 and Table 2.4.12;
 
(5) buried fire protection piping and underground fire main loop are included in Table 2-96 2.3.3.19 as piping components, fire hydrants, valve bodies and closure bolting; (6) restricting orifices are included in flow orifice/element commodity (7) actuator housings, backflow prevention devices, and post-indicator sectional control valves are included in
 
valve bodies commodity;(8)  expansion join ts are included in flexible connectors commodity; (9) lubricating oil collection syst em components are included in Table 2.3.1.3. 
 
The applicant considered the Halon 1301 storage bottles to be in the scope of license
 
renewal but excluded from the AMR. The applicant stated that Halon storage bottles are
 
replaced periodically and, therefore, not subject to an AMR. The applicant excluded Halon
 
storage bottles from an AMR under 10 CFR 54.21(a)(1)(ii) on a plant-specific basis. The
 
applicant routinely monitors Halon storage bottles based on performance or condition
 
criteria ensuring that storage bottles will maintain their intended function. Because the
 
applicant has interpreted the Halon storage bottles as part of an active component (condition monitoring to determine whether the Halon storage bottles are at the end of their
 
qualified lives), the staff concludes that the component was correctly excluded from the scope of license renewal and is not subject to an AMR.
 
For each of the following components, the staff finds that they were not included in the line
 
item descriptions in the LRA for an AMR: heat exchanger bonnets, shells, and tubes; fire
 
pump turbocharger; gear box housings; diesel dr iven fire pump intake silencers; and heater housings. The staff recognizes that the applicant's interpretation of these components as
 
active will result in more vigorous oversight of their condition and performance.
 
Because the applicant has interpreted heat exchanger bonnets, shells, and tubes; fire
 
pump turbocharger; gear box housings; diesel dr iven fire pump intake silencers; and heater housings as active, the staff concludes thei r exclusion from scope of license renewal is correct and that they are not subject to an AMR.
 
The staff finds that the yard hoses were not included in the line item descriptions in the LRA
 
table. The applicant stated that yard fire hydrants are housed in small sheds; fire hoses are
 
in scope but are short-lived, being subject to periodic replacement. Therefore, they do not
 
require an AMR. The staff recognizes the applicant's interpretation of these components as
 
passive (short-lived component), which will result in more vigorous oversight of the
 
condition and performance of the components. The staff concludes that the above
 
components were excluded correctly from the scope of license renewal and are not subject
 
to an AMR. Therefore, the staff's concern described in RAI 2.3.3.19-3 is resolved.
 
In RAI 2.3.3.19-4, dated January 28, 2008, the staff informed the applicant that NUREG-
 
1137 and its supplements listed various types of fire suppression systems provided in the plant areas for fire suppression activities. The fire suppression systems in various areas
 
are:
Total flooding Halon 1301 systems for two shutdown panel rooms, computer room, and five non-safety-related areas in the control
 
building.
Dry standpipe for the control building, containment building, and auxiliary building  Deluge systems for charcoal filter assemblies 2-97  Dry pre-action sprinkler systems below the reactor coolant pumps and in areas of high cable tray concentrations  Cable spreading room automatic pre-action sprinkler system  Wet standpipe and hose system throughout the plant The staff requested that the applicant verify whether the above fire suppression systems installed in various areas of the plant are in the scope of license renewal in accordance with
 
10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). 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. 
 
By letter dated February 27, 2008, the applicant stated that:
 
The above listed fire protection systems are in the scope of license renewal as follows: 
: 1) The total flooding Halon 1301 systems required for regulatory compliance are in scope. See response to 2.3.3.19-1 for details. 2) The dry standpipe systems for the control building, containment building, and auxiliary building are in scope. See License Renewal Boundary Drawings 1X4LD174-6 and 2X4LD174-6. 3) The deluge systems for charcoal filter assemblies are in scope. See License Renewal Boundary Drawings 1X4LD205-1, 1X4LD208-1, 1X4LD209, 1X4LD213-1, 1X4LD213-2, AX4LD204-1, AX4LD206-1, AX4LD206-3, AX4LD215, AX4LD235, 2X4LD205-1, 2X4LD208-1, 2X4LD213-1, and 2X4LD213-2. It is
 
noted that two charcoal filters (1-1562-N7-001 & 002) on boundary drawing 1X4LD209 in the control building on Unit 1 have been
 
abandoned in place and the charcoal removed from the filter units.
 
The manual fire protection spray systems for these two filters are
 
not required and are not in-scope. The fire protection in-scope
 
boundary terminates at the first isolation valve in each filter unit's
 
fire water supply header. The high temperature fire alarm that was
 
in each filter's charcoal bed has been disabled. 4) The dry pre-action sprinkler systems below the reactor coolant pumps and in areas of high cable tray concentrations in the
 
containment building were never installed. See NUREG-1137, Supplement No.2, Section 9.5.1.6. 5) The cable spreading room automatic pre-action sprinkler systems are in scope. See License Renewal Boundary Drawings 1X4LD174-3, rooms R-A44 and R-225 at coordinates D-2 and G-3 respectively; 2X4LD174-3, rooms R-A23 and R-224 at coordinates
 
D-2 and G-3, respectively. 6) The wet standpipe and hose system throughout the plant is in scope. See License Renewal Boundary Drawings 1X4LD174-2, 1X4LD174-3, 1X4LD174-4, 2X4LD174-2, 2X4LD174-3, and 2X4LD174-4. 
 
2-98 Based on its review, the staff finds the applicant's response to RAI 2.3.3.19-4 acceptable. 
 
The applicant stated that all above mentioned fire suppression systems in various area of
 
the plant are in scope; except for the Unit 1 control building charcoal filter deluge system
 
because the two charcoal filters for this system have been abandoned in place. Further, the
 
applicant informed the staff that the dry-action sprinkler systems, which were to be located
 
below the reactor coolant pumps and in areas of high cable tray concentrations in the
 
containment building, were never installed.
 
The total flooding Halon 1301 systems in Computer Room Level A, Computer CRT Display, and Communication Rooms Level 1, 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. Although the total flooding Halon 1301 fire suppression system for the
 
above areas are addressed in the NUREG-1137, these systems in question are not
 
credited to meet the requirements of Appendix R for achieving safe-shutdown in the event
 
of a fire. The staff has confirmed that the applicant correctly excluded the above total
 
flooding Halon 1301 fire suppression systems from scope of license renewal and subject to
 
an AMR. Therefore, the staff's concern described in RAI 2.3.3.19-4 is resolved.
 
2.3.3.19.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether
 
the applicant failed to identify any SCs within the scope of license renewal. The staff finds
 
no such omissions. On the basis of its review, the staff concludes that the applicant has
 
adequately identified the fire protection system components that are 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).
2.3.3.20  Emergency Diesel Generator System 2.3.3.20.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.20 describes the emergency diesel generator (EDG) system, which
 
consists of one diesel generator per safety-related load group complete with its accessories
 
and fuel storage and transfer systems and which generates onsite electric power to feed
 
the standby power system. The st andby power system provides alternating current power for safe shutdown of the plant in loss of offsite power. There are two EDGs per unit, each
 
connected exclusively to a single 4.16kV safety feature bus of a load group. Each unit has
 
two 4.16kV Class 1E trains, and the safety-related equipment on both trains is similar. The
 
trains are redundant and for each unit one train is adequate to satisfy minimum ESF
 
demand caused by a LOCA and a simultaneous loss of preferred power supply. The fuel oil
 
storage for each unit is sized for seven days of operation to meet the ESF load plus an
 
additional amount for periodic testing of the diesel generator. The EDG support systems
 
provide stored energy to start the EDGs along with cooling, lubrication, and combustion air
 
intake and exhaust to allow the EDGs to perform their function. The NSCW system supplies
 
cooling water to the EDG jacket water coolers.
 
The EDG system contains safety-related components relied upon to remain functional
 
during and following DBEs. The failure of nonsafety-related SCs in the EDG system
 
potentially could prevent the satisfactory acco mplishment of a safety-related function. In addition, the EDG system performs functions that support fire protection and SBO.
2-99  LRA Table 2.3.3.20 identifies EDG system component types within the scope of license
 
renewal and subject to an AMR: 
 
air receivers  closure bolting  collection troughs (EDG lube oil leakage)  eductors - EDG fuel oil ejector assembly  electric heater housings  filter housings  flame arrester elements  flame arrester housings  flexible connectors  flow orifice/elements  heat exchangers - EDG jacket water HXs (channel heads)  heat exchangers - EDG jacket water HXs (shells)  heat exchangers - EDG jacket water HXs (tubes)  heat exchangers - EDG jacket water HXs (tubesheets)  heat exchangers - EDG lube oil HXs (channel heads)  heat exchangers - EDG lube oil HXs (shells)  heat exchangers - EDG lube oil HXs (tubes)  heat exchangers - EDG lube oil HXs (tubesheets)  oil reservoirs - EDG lube oil sumps  piping components  pump casings - EDG fuel oil engine-driven pumps  pump casings - EDG fuel oil storage tank pumps  pump casings - EDG jacket water chemical addition pumps  pump casings - EDG jacket water keep-warm pumps  pump casings - EDG jacket water pumps  pump casings - EDG lube oil keep-warm pumps  pump casings - EDG lube oil pumps  silencers  strainer elements  strainer housings  tanks - EDG fuel oil day tanks  tanks - EDG fuel oil line leakage tanks  tanks - EDG fuel oil storage tanks  tanks - EDG jacket water chemical addition tanks  valve bodies  vent screens - tank vents The intended functions of the EDG system component types within the scope of license
 
renewal include:
protection from debris heat exchange between fluid media prevention of flame propagation from i gnition of vent pipe vapors back to the source 2-100  restriction of process flow pressure-retaining boundary 2.3.3.20.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.20 and UFSAR Sections 8.3.1.1.3, 9.5.4 through
 
9.5.8 using the evaluation methodology described in SER Section 2.3 and the guidance in
 
SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
The staff's review of LRA Section 2.3.3.20 identified areas in which additional information
 
was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAIs as discussed below.
 
In RAI 2.3.3.20-1, dated January 28, 2008, the staff noted that drawings 1X4LD170-1, 1X4LD170-2, 2X4LD170-1, and 2X4LD170-2 (G-7) indicate jacket water standpipes that
 
are within the scope of license renewal based on criterion 10 CFR 54.4(a)(1). The applicant
 
was requested to provide additional information explaining why the standpipes are not
 
listed in LRA Table 2.3.3.20 as a component type subject to an AMR.
 
In its response, dated February 27, 2008, the applicant stated:
 
The Emergency Diesel Generator System jacket water system standpipe is not listed in LRA Table 2.3.3.20 as a separate component type subject to an
 
AMR. However, the standpipes are included in the component type, "Piping
 
Components" as shown in Table 2.3.3.20 Item No. 20 and Table 3.3.2-20
 
Items 20c, 20d and 20k. The standpipes are vertical, cylindrical piping
 
components constructed of carbon steel; therefore, they have been
 
classified in the LRA as piping components.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-1 acceptable
 
because the applicant provided clarification that the standpipes are included as Item No. 20
 
"Piping Components" in the AMR tables. Therefore, the staff's concern described in RAI
 
2.3.3.20-1 is resolved.
 
In RAI 2.3.3.20-2, dated January 28, 2008, the staff noted that drawings 1X4LD170-1, 1X4LD170-2, 2X4LD170-1, and 2X4LD170-2 (E-6) and as described in the UFSAR Section
 
9.5.8.2.3 indicate that the housings for the turbocharger and aftercooler form a pressure
 
boundary for intake air going to the engine intake manifolds and should be in scope for
 
license renewal based on criterion 10 CFR 54.4(a)(1). The applicant was requested to
 
provide additional information explaining why the turbocharger/aftercooler housings with
 
their pressure boundary and heat exchange functions are not listed in LRA Table 2.3.3.20
 
for components subject to an AMR.
 
2-101 In its response, dated February 27, 2008, the applicant stated:
The turbocharger and after-cooler are skid mounted equipment of the
 
Emergency Diesel Generators assembly and thus considered part of this
 
complex assembly - emergency diesel generator engine. Therefore, no AMR
 
of the housing for these components is required due to the complex active
 
assembly classification of this assembly, i.e., this component/assembly does
 
not meet the AMR criteria for an integrated plant assessment per
 
10 CFR 54.21(a)(1)(i). Consequently, the turbocharger/aftercooler housings
 
with their pressure boundary and heat exchange functions are not listed in
 
LRA Table 2.3.3.20 for components subject to an AMR.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-2 acceptable
 
because the applicant stated that the turbocharger/aftercooler housings are skid mounted
 
equipment of the complex assembly - emergency diesel generator, and do not meet the
 
AMR criteria for an integrated plant assessment per 10 CFR 54.21(a)(1)(i). Therefore the
 
staff's concern described in RAI 2.3.3.20-2 is resolved.
 
In RAI 2.3.3.20-3, dated January 28, 2008, the staff noted that drawings 1X4LD170-1, 1X4LD170-2, 2X4LD170-1, and 2X4LD170-2 (E-3) and (B-3) indicate that manhole covers
 
which provide a pressure boundary for the diesel fuel oil day and storage tanks are within
 
the scope of license renewal based on criterion 10 CFR 54.4(a)(1). The applicant was
 
requested to provide additional information explaining why the manhole covers are not
 
listed in LRA Table 2.3.3.20 for components subject to an AMR.
 
In its response, dated February 27, 2008, the applicant stated:
 
Tank manways were not identified as a separate component type for tanks in
 
mechanical systems. The manways for t he diesel fuel oil day and fuel oil storage tanks were included as part of the tank. In the LRA Table 2.3.3.20, the manway covers for the diesel fuel oil day and storage tanks are covered
 
under Item 31 and 33 respectively. 
 
In the LRA Table 3.3.2-20, the AMR of the diesel fuel oil day tank manways
 
are covered by Items 31a and 31c.
 
The AMR of the diesel fuel oil storage tank manways and covers are
 
covered by Items 33a and 33c of this table as well. 
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-3 acceptable, because the applicant provided clarification that the manway covers for the diesel fuel oil
 
day and storage tanks are considered an integral part of the tank components listed in the
 
AMR tables. Therefore, the staff's concern described in RAI 2.3.3.20-3 is resolved.
 
In RAI 2.3.3.20-4, dated January 28, 2008, the staff noted that drawings 1X4LD170-1, 1X4LD170-2, 2X4LD170-1, and 2X4LD170-2 locations (H-7), (C-8), (D-2), (C-2), and (E-3)
 
indicate tank vents that are within the scope of license renewal. LRA Table 2.3.3.20 lists
 
tank vent screens as components that provide debris protection for a vent, but none of the
 
vents show a debris screen. The applicant was requested to provide additional information
 
explaining which tank vents on the drawi ngs do or do not have the tank vent screen component that is listed as Item 36 in LRA Table 2.3.3.20.
2-102  In its response, dated February 27, 2008, the applicant stated:
 
Vent screens that cover tank vents for debris/ bird protection on the
 
various EDG System atmospheric vents to outdoors have been put in
 
scope. Since no equipment tag numbers apply and no material
 
documentation could be found, the vent screens are assumed to be
 
carbon steel based on the piping material. Piping and instrument
 
diagrams used to develop the referenced LRA boundaries did not show
 
screens for tank vents; although, area physical drawings do identify
 
screen covers for the diesel fuel oil storage tank vents; no screen covers
 
were identified for the diesel fuel oil day tank vents. Since the vents for
 
both tanks provide the same function, it was assumed that screen covers
 
were installed on the diesel fuel day tank vents as well.
 
By telecom dated April 17, 2008, the applicant was advised that the staff will proceed based
 
on having the screens in place. The applicant acknowledged staff's position and stated that
 
they are planning to inspect the plant in the near future to verify screen installation and
 
screen materials.
 
In a letter dated February 16, 2009, the applicant provided a revision to the LRA concerning
 
diesel generator day tank vent line inspections. The new commitment, number 42, provides for an inspection to verify screen installation prior to the period of extended
 
operation.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-4 acceptable, because the applicant stated the screens are in scope and committed to verify screen
 
materials and vents with screens. Therefore, the staff's concern described in RAI 2.3.3.20-4
 
is resolved.
 
In RAI 2.3.3.20-5, dated January 28, 2008, the staff noted that drawings 1X4LD170-1, 1X4LD170-2, and 2X4LD170-1 (D-4) indicate that the concrete vault roof has a vent that is
 
within the scope of license renewal based on criterion 10 CFR 54.4(a)(1). Those drawings
 
cover the diesel generator trains A and B for plant Unit #1 and train A for plant Unit #2.
However, drawing 2X4LD170-2 for train B of plant Unit #2 does not show a vent for the
 
concrete vault roof. The applicant was requested to provide additional information explaining why the concrete vault roof vent is missing on drawing 2X4LD170-2 for diesel
 
generator plant Unit #2 Train B.
 
In its response, dated February 27, 2008, the applicant stated:
 
It has been determined from review of domestic supporting drawings that the concrete vault roof vent missing on drawing 2X4LD170-2 is an error and the vent should be shown as on 2X4LD170-1. 
 
The diesel fuel oil storage tank pump house forming plans sections and
 
details show the roof vents for both trains of both units.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-5 acceptable, because the applicant provided clarification that the concrete vault roof vent was missing from drawing 2X4LD170-2 in error and should be shown and in scope for license renewal.
2-103 Therefore, the staff's concern described in RAI 2.3.3.20-5 is resolved.
 
In RAI 2.3.3.20-6, dated January 28, 2008, the staff noted that drawing 2X4LD170-2 (F/G-
: 6) indicates the 343-3/4" pipeline and associated drain are within the scope of license renewal based on criterion 10 CFR 54.4(a)(1). However, drawings 1X4LD170-1, 1X4LD170-2, and 2X4LD170-1 for the same location indicates that the similar 343-3/4" and
 
339-3/4" pipelines are within the scope of license renewal based on criterion
 
10 CFR 54.4(a)(2), rather than 10 CFR 54.4(a)(1), and the drain is not within the scope of
 
license renewal. The applicant was requested to provide additional information to define the
 
correct criterion to use for all four of these drawings for the 343-3/4" and 339-3/4" drain
 
pipelines and their respective drains.
 
In its response, dated February 27, 2008, the applicant stated:
 
License renewal drawing 2X4LD170-2 (F/G-6) inadvertently shows the
 
343-3/4" pipeline and associated drain within the scope of license
 
renewal based on criterion 10 CFR 54.4(a)(1). This pipeline 343-3/4" is
 
within the scope of license renewal based on criterion 10 CFR 54.4(a)(2),
rather than 10 CFR 54.4(a)(1) which is the same in scope bases as pipeline 339-3/4" shown on 2X4LD170-2 (F/G-6). These lines function as
 
drain piping from the diesel generator spill collection trough and are
 
classified as non-safety related.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-6 acceptable
 
because the applicant provided clarification that the 343-3/4" pipeline on drawing 2X4LD170-2 (F/G-6) should have been shown in scope for criterion 10 CFR 54.4(a)(2),
rather than criterion 10 CFR 54.4(a)(1). Therefore, the staff's concern described in RAI
 
2.3.3.20-6 is resolved.
 
In RAI 2.3.3.20-7, dated January 28, 2008, the staff noted that drawing 2X4LD170-1 (C/D-
 
8), indicates a lube oil press fill pipeline located outside the engine piping boundary and
 
connected to a three-inch pipeline within the engine piping boundary that is entirely within
 
the scope of license renewal based on criterion 10 CFR 54.4(a)(1). However, drawings 1X4LD170-1, 1X4LD170-2, and 2X4LD170-2, for the same general location and pipeline
 
characteristics, indicate the lube oil press fill piping is not within the scope of license
 
renewal. The applicant was requested to provide additional information to define the correct
 
criterion to be applied to the lube oil press fill pipeline outside the engine piping boundary
 
on all four drawings referenced above.
 
In its response, dated February 27, 2008, the applicant stated:
 
Per review of the License Renewal drawing 2X4LD170-1 at (C/D-8)
 
regarding scoping of the lube oil press fill pipeline, the boundary line for
 
this pipeline should have been shown as red not gray for drawings 1X4LD170 -1 & 2 and 2X4LD170-2. The lube oil press fill piping is within
 
the scope of license renewal based on criterion 10 CFR 54.4(a)(1).
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-7 acceptable
 
because the applicant provided clarification that the lube oil press fill pipelines on drawings 1X4LD170 -1 &2 and 2X4LD170-2 are in scope for criterion 10 CFR 54.4(a)(1). Therefore, the staff's concern described in RAI 2.3.3.20-7 is resolved.
2-104  In RAI 2.3.3.20-8, dated January 28, 2008, the staff noted that drawing 2X4LD170-1 (E-8)
 
shows sections of 037-10" and 035-10" piping within the scope of license renewal based on criterion 10 CFR 54.4(a)(2) with a continuation to drawing 2X4LD135-1 (G-6). The continuation location G-6 on drawing 2X4LD135-1 indicates the 037-10" and 035-10" piping
 
are within the scope of license renewal based on criterion 10 CFR 54.4(a)(1). It appears that the sections of 037-10" and 035-10" piping shown on drawing 2X4LD170-1 between the engine piping boundary and the continuation marker to drawing 2X4LD135-1 should
 
also be in-scope based on criterion 10 CFR 54.4(a)(1) as are the other emergency diesel generators shown in LR drawings 2X4LD170-2, 1X4LD170-1, and 1X4LD170-2. The
 
applicant was requested to provide additional information clarifying why the subject piping on drawing 2X4LD170-1 (E-8) meets the requirements of criterion 10 CFR 54.4(a)(2), rather
 
than 10 CFR 54.4(a)(1).
 
In its response, dated February 27, 2008, the applicant stated:
 
From a review of the  drawings 2X4LD170-1 and 2X4LD135-1 and a re-
 
visit of the 10 CFR 54.4(a)(1) criterion against the function of the
 
pipelines, 037-10" and 035-10", it is concluded that the sections of piping shown on drawing 2X4LD170-1 between the engine piping boundary and the continuation marker to drawing 2X4LD135-1 are in-scope based on
 
criterion 10 CFR 54.4(a)(1), and should have been indicated as the other pipelines are for this function shown on LR drawings 2X4LD170-2, 1X4LD170-1, and 1X4LD170-2.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-8 acceptable because the applicant provided clarification that on drawing 2X4LD170-1 the sections of
 
037-10" and 035-10" pipelines between the engine piping boundary and the continuation marker to drawing 2X4LD135-1 should have been in scope for criterion 10 CFR 54.4(a)(1).
 
Therefore, the staff's concern described in RAI 2.3.3.20-8 is resolved.
 
2.3.3.20.3  Conclusion The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether
 
the applicant failed to identify any components within the scope of license renewal. The
 
staff finds no such omissions. In addition, the staff's 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 the applicant has adequately
 
identified the emergency diesel generator 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).
 
2.3.3.21  Demineralized Water System 2.3.3.21.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.21 describes the demineralized water (DW) system, which stores and
 
delivers deionized water to various plant systems. Demineralized water is not required for
 
any safety-related function. 
 
2-105 The DW system contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SCs in the DW system potentially
 
could prevent the satisfactory accomplishment of a safety-related function. 
 
LRA Table 2.3.3.21 identifies DW system component types within the scope of license
 
renewal and subject to an AMR: 
 
closure bolting  flow orifice/elements  piping components  piping components - pipe spools for startup strainers  pump casings - demineralized water transfer booster pumps  valve bodies The intended function of the DW system component types within the scope of license
 
renewal is to provide a pressure-retaining boundary.
 
2.3.3.21.2 Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.21 and UFSAR Section 9.2.3 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
The staff's review of LRA Section 2.3.3.21 identified an area in which additional information
 
was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.3.3.21-1, dated January 28, 2008, the staff noted drawing AX4LD190-2 (E-3) shows pipe section 172-1" in-scope for 10 CFR 54.4(a)(2). The continuation to AX4LD123-
 
2 (A-6) is not shown as in-scope for license renewal. The applicant was asked to provide
 
additional information detailing the license renewal boundary for pipe section 172-1" on drawing AX4LD123-2 (A-6).
 
In its response, dated February 27, 2008, the applicant stated:
 
The segment of line A-1210-172-1" which appears on mechanical boundary drawing AX4LD123-2 was inadvertently not shown as being in
 
scope for 10 CFR 54.4(a)(2). This line segment is in scope for
 
10 CFR 54.4(a)(2).
Based on its review, the staff finds the applicant's response to RAI 2.3.3.21-1 acceptable
 
because the applicant explained that the piping in question is within the scope of license
 
renewal. Therefore, the staff's concern described in RAI 2.3.3.21-1 is resolved.
 
2-106 2.3.3.21.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether
 
the applicant failed to identify any components within the scope of license renewal. The
 
staff finds no such omissions. In addition, the staff's 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 the applicant has adequately
 
identified the DW 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).
 
2.3.3.22  Hydrogen Recombiner and Monitoring System 2.3.3.22.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.22 describes the hydrogen recombiner and monitoring system, which
 
was installed to monitor and control post-accident containment hydrogen. The applicant
 
intends to downgrade the recombiners to nonsafety-related and to abandon them in place.
 
The hydrogen monitors also will be downgraded to nonsafety-related; however, piping for these monitors penetrating containment has a containment integrity safety function. Until
 
these CLB changes are processed, these components are within the scope of license
 
renewal as safety-related.
 
The hydrogen recombiner and monitoring syst em contains safety-related components relied upon to remain functional during and following DBEs. In addition, the hydrogen
 
recombiner and monitoring system performs functions that support EQ.
 
LRA Table 2.3.3.22 identifies hydrogen reco mbiner and monitoring system component types within the scope of license renewal and subject to an AMR: 
 
closure bolting  hydrogen recombiner (containment) housings  piping components  valve bodies The intended functions of the hydr ogen recombiner and monitoring system component types within the scope of license renewal include:
spray shield or curbs for flow direction pressure-retaining boundary
 
2.3.3.22.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.22 and UFSAR Section 6.2.5 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant has identified as within the scope of license 2-107 renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.3.22.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 the applicant has adequately identified the hydrogen
 
recombiner and monitoring 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).
 
2.3.3.23  Drain Systems 2.3.3.23.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.23 describes the drain systems, which consist of collection piping, valves, equipment drains, floor drains, vents, seals, cleanouts, oil and sediment
 
interceptors, acid neutralization tanks, collection sumps, sump pumps, and collection tanks
 
with discharge pumps, piping, and valves. 
 
The drains within the scope of license renewal include the following systems:
 
containment and auxiliary building drain system - radioactive  auxiliary building drain system - nonradioactive  auxiliary building flood-retaining rooms, alarms, and drains  control building drain system  fuel-handling building drains  sanitary waste and vent  turbine building drain system The containment and auxiliary building drain system - radioactive is designed to drain water in the containment building and tritiated water in the other buildings. Water drained into the
 
system enters the plant liquid waste proce ssing system for recycling or disposal.
The auxiliary building drain system - nonradi oactive drains normally nonradioactive equipment and floor liquid waste from open areas of the auxiliary building to the floor drain
 
tank via the auxiliary building sump or the penetration room sump. This system also
 
includes miscellaneous drains that convey fluids to other sumps and empty or drain the sumps.
 
The auxiliary building flood-retaining rooms, al arms, and drain system prevents drain or flood water from backing up into selected impor tant auxiliary building rooms. The system retains post-LOCA radioactive liquid leakage within the water-tight flood-retaining rooms up
 
to the maximum expected flood level by water-tight doors evaluated as parts of component
 
supports and bulk commodities (LRA Section 2.4.12). 
 
The control building drain system collects water from fire protection sprinklers in the control
 
building, equipment building, technical support center, and connected electrical tunnels as 2-108 well as from incidental leaks. The system routes water to a sump below the control building.
Sump pumps transfer the water to the turbine building oil separator. The system also
 
provides an alternate route to the waste monitor tank in the auxiliary building for processing
 
radioactive liquid.
 
The fuel-handling building drainage system collects water in the fuel-handling building drain
 
sump from drains within the building. Fuel-handling building drain sump pumps transfer
 
water from the building's drain sump to the waste monitor tank for processing or disposal. 
 
The sanitary waste and vent system provides plumbing drains and vents for toilets, locker rooms, showers, and janitor rooms in the control and turbine buildings.
 
The turbine building drain system removes all liquid wastes from the turbine building for
 
disposal to the waste water effluent system.
This system also monitors and, if necessary, removes radioactive contaminants from these wastes if radioactive material appears in the
 
drains from a tube leak in one of the steam generators. Filters and demineralizers that
 
remove radioactive contaminants from wastes pr ocessed by this system are located in the auxiliary building.
 
The drain systems contain safety-related components relied upon to remain functional
 
during and following DBEs. The failure of nonsafety-related SCs in the drain systems
 
potentially could prevent the satisfactory acco mplishment of a safety-related function. In addition, the drain systems perform functions that support EQ.
 
LRA Table 2.3.3.23 identifies drain systems component types within the scope of license renewal and subject to an AMR: 
 
closure bolting  drain bodies  floor drain plugs  piping components  pump casings - CCW drain tank pumps  tanks - acid neutralizing sumps  valve bodies The intended function of the drain systems component types within the scope of license
 
renewal is to provide a pressure-retaining boundary.
 
2.3.3.23.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.23 and UFSAR Sections 9.3.3 and 11.2 using the
 
evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR
 
Section 2.3.
 
During its review of the sanitary waste and vent and the turbine building drain systems, 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 component types with intended functions delineated under 10 CFR 54.4(a).
 
2-109 During its review of the remaining drain syst ems, 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 delineated under
 
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 in accordance with the requirements
 
of 10 CFR 54.21(a)(1).
 
The staff's review of LRA Section 2.3.3.23 identified areas in which additional information
 
was necessary to complete the review of the applicant's scoping and screening results. In
 
addition to the RAI 2.3.3.23-1 related to drawing continuation errors discussed in Section
 
2.3.3, the applicant responded to the staff's RAIs as discussed below.
In RAI 2.3.3.23-2, dated January 28, 2008, the staff noted that drawings 1X4LD145-6 and 2X4LD145-6 (B-2) show pipe 256-4" as not within the scope of license renewal. Drawings 1X4LD145-5 and 2X4LD145-5 (D-4) show pipe 256-4" within the scope of license renewal
 
based on criterion 10 CFR 54.4(a)(2). The applicant was requested to provide additional information clarifying why pipe 256-4" on drawings 1X4LD145-6 and 2X4LD145-6 (B-2) is
 
not within the scope of license renewal.
 
In its response, dated February 27, 2008, the applicant stated:
 
Line 1215-256-4" as shown on drawings 1X4LD145-6 and 2X4LD145-6 is in scope for 10 CFR 54.4(a)(2). Drawings 1X4LD145-6 and 2X4LD145-6 should have shown this line highlighted as in scope for
 
10 CFR 54.4(a)(2).
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.23-2 acceptable because the applicant provided clarification that line 1215-256-4" on drawings 1X4LD145-6 and 2X4LD145-6 should have been shown highlighted as in scope for 10 CFR 54.4(a)(2).
 
Therefore, the staff's concern described in RAI 2.3.3.23-2 is resolved.
 
In RAI 2.3.3.23-3, dated January 28, 2008, the staff noted that drawings 1X4LD179-2 and 2X4LD179-2 (D-7) show pipeline 097-2" within the scope of license renewal based on criterion 10 CFR 54.4(a)(2) continuing to drawings 1X4LD124-2 (F-4) and 2X4LD124-2 (G-4). Drawings 1X4LD124-2 and 2X4LD124-2 could not be located in the boundary drawing
 
package. The applicant was requested to provide additional information to verify that the continuation from drawings 1X4LD179-2 and 2X4LD179-2 has been made to the correct
 
drawings and locations and provide the drawings.
 
In its response, dated February 27, 2008, the applicant stated:
 
Line 1407-097-2" on drawings 1X4LD179-2 and 2X4LD179-2 continues to P&ID AX4DB124-2. P&ID AX4DB124-2 shows the point where this
 
line exits the Auxiliary Building into the Radwaste Transfer Tunnel. There
 
are no safety related components in the Radwaste Transfer Tunnel, so
 
potential spatial interactions are not a concern and the in-scope portion
 
of the line ends at the Auxiliary Building to Radwaste Transfer Tunnel boundary. However, P&ID AX4DB124-2 was not redrawn into a license
 
renewal mechanical boundary drawing. To resolve this discrepancy, mechanical boundary drawings 1X4LD179-2 and 2X4LD179-2 should 2-110 have been revised to include the Auxiliary Building to Radwaste Transfer Tunnel boundary for clarity.
 
By telecom dated April 17, 2008, the applicant verified that there were no new component
 
types within the boundary for which the drawings were not provided.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.23-3 acceptable
 
because the applicant provided clarification that the license renewal boundary ends at the
 
Auxiliary Building to Radwaste Transfer Tunnel boundary and stated that there were no
 
new component types within the boundary for which drawings were not provided.
 
Therefore, the staff's concern described in RAI 2.3.3.23-3 is resolved.
 
2.3.3.23.3  Conclusion
 
For the sanitary waste and vent and the turbine building drain systems, the staff reviewed
 
the LRA and the UFSAR to determine whether the applicant failed to identify any
 
component types that are typically found within the scope of license renewal and finds no
 
such omissions. On the basis of its review, the staff concludes that the applicant has
 
adequately identified the sanitary waste and vent and the turbine building drain systems
 
component types within the scope of license renewal, as required by 10 CFR 54.4(a).
 
For the remaining drain systems, the staff reviewed the LRA, UFSAR, RAI responses, and
 
drawings to determine whether the applicant failed to identify any components within the
 
scope of license renewal. The staff finds no such omissions. In addition, the staff's 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 the applicant
 
has adequately identified the 
 
containment and auxiliary building drain system - radioactive,  auxiliary building drain system - nonradioactive,  auxiliary building flood-retaining rooms, alarms, and drains,  control building drain system, and  fuel-handling building drains as 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).
2.3.3.24  Potable and Utility Water Systems 2.3.3.24.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.24 describes the potable and utility water systems. The potable water
 
system chemically treats, stores, and distributes well water for drinking to the units. The
 
utility water system provides water for general washdown purposes at utility stations
 
throughout the plant (nonradioactive process areas). Utility water also serves for sump
 
pump bearing lubrication and miscellaneous cooling purposes (e.g., cooling of the steam generator blowdown samples). The failure of nonsafety-related SCs in the potable and
 
utility water systems could potentially prevent t he satisfactory accomplishment of a safety-related function. 
 
2-111 LRA Table 2.3.3.24 identifies potable and utility water systems component types within the scope of license renewal and subject to an AMR: 
 
arresters (water hammer)  closure bolting  piping components  pump casings - hot water recirculation pumps  strainer housings  valve bodies  water heater housings and jackets The intended functions of the potable and utility water systems component types within the
 
scope of license renewal include:
 
spray shield or curbs for flow direction pressure-retaining boundary
 
2.3.3.24.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.24 and UFSAR Section 9.2.4 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
component types with intended functions delineated under 10 CFR 54.4(a). 
 
2.3.3.24.3  Conclusion The staff reviewed the LRA and the UFSAR to determine whether the applicant failed to identify any component types that are typica lly found within the scope of license renewal and finds no such omissions. On the basis of its review, the staff concludes that the
 
applicant has adequately identified the potable and utility water systems component types
 
within the scope of license renewal, as required by 10 CFR 54.4(a).
2.3.3.25 Radiation Monitoring System (1609) 2.3.3.25.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.25 describes the radiation monitoring system, which monitors radiation levels in the process flow streams of plant fl uid systems, measures direct gamma radiation, and provides corresponding indications, recordings, alarms, and controls. For normally
 
radioactive fluid systems with direct or diluted discharge paths to the surrounding
 
environment, the radiation monitoring system ac tuation functions limit further discharge if activity concentrations exceed preset levels. The system also provides information for detecting and monitoring RCS leakage.
 
2-112 Radiation monitors fall into five functional classifications:
process monitors, which determine concentrations of radioactive material in plant fluid systems. The primary-to-secondary leak detection monitors (N16
 
and noble gas leak rate detectors) are included in this category. effluent monitors, which measure radioactivity discharged to the environs  airborne monitors, which provide operator information on airborne concentrations of radioactive gases and particulate radioactivity at various
 
points in the ventilation ducts  area monitors, which provide operator information on external gamma radiation levels at fixed points throughout the plant  post-accident (or high-range) monitors designed to assess and follow potential pathways for release of radioactive materials during accident
 
conditions The radiation monitors themselves are in strumentation components and therefore are addressed in the scoping and screening for the electrical and instrumentation and controls
 
systems (LRA Section 2.5). Mechanical aspects (e.g.; process line components) are addressed in the mechanical scoping and screening.
 
The radiation monitoring system contains safety-related components relied upon to remain
 
functional during and following DBEs. The failure of nonsafety-related SCs in the radiation
 
monitoring system potentially could prevent t he satisfactory accomplishment of a safety-related function. In addition, the radiation monitoring system performs functions that support
 
EQ.
 
LRA Table 2.3.3.25 identifies radiation moni toring system component types within the scope of license renewal and subject to an AMR:
 
closure bolting  piping components  valve bodies The intended function of the radiation monitori ng system component types within the scope of license renewal is to provide a pressure-retaining boundary.
 
2.3.3.25.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.25 and UFSAR Sections 11.5 and 12.3.4 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR
 
Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant has identified as within the scope of license 2-113 renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
 
The staff's review of LRA Section 2.3.3.25 identified an area in which additional information
 
was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.3.3.25-1, dated January 28, 2008, the staff noted that drawings 1X4LD133-1, 1X4LD133-2, 2X4LD133-1, and 2X4LD133-2 (H-3), and drawings 1X4LD136 and 2X4LD136 (A-3) and (E-3) show radiation monitors that are identified as in scope for
 
license renewal based on criterion 10 CFR 54.4(a)(2). Each radiation monitor is connected
 
to 1 inch sensing lines identified as within the scope of license renewal based on criterion 10 CFR 54.4(a)(1). Also, the staff noted that for similar equipment on drawings 1X4LD213-2 and 2X4LD213-2 (D-1) radiation monitors are within the scope of license renewal based on
 
criterion 10 CFR 54.4(a)(2) but have equivalent anchors on each end. The applicant was
 
requested  to provide additional information explaining why the radiation monitors on drawings 1X4LD133-1, 1X4LD133-2, 1X4LD136, 2X4LD133-1, 2X4LD136, and 2X4LD133-
 
2 are not within the scope of license renewal based on criterion 10 CFR 54.4(a)(1) as are
 
the connecting pipe sections.
 
In its response, dated February 27, 2008, the applicant stated:
 
The radiation monitors on mechanical boundary drawings 1X4LD133-1, 1X4LD133-2, 1X4LD136, 2X4LD133-1, 2X4LD136, 2X4LD133-2, 1X4LD213-2 and 2X4LD213-2 are not in scope for 10 CFR 54.4(a)(1)
 
scoping criteria because they do not ensure the integrity of the reactor
 
coolant pressure boundary; ensure the capability to shut down the
 
reactor and maintain it in a safe shutdown condition; or ensure the
 
capability to prevent or mitigate the consequences of accidents that
 
could result in potential offsite exposure comparable to the guidelines in
 
10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11, as
 
applicable.
 
The safety classifications of both the radiation monitors and the
 
connecting pipe sections are established in the current licensing basis in
 
accordance with regulatory guidance. Refer to LRA section 2.1, Scoping
 
and Screening Methodology, for additional discussion.
 
Also note that the radiation monitors on mechanical boundary drawings 1X4LD213-2 and 2X4LD213-2 do not have equivalent anchors on each
 
end. Boundary endpoint clarification note #4 indicates that the radiation
 
monitors are the equivalent anchors. However, given that there are no
 
piping endpoints at the radiation monitors, it would be more appropriate
 
to describe these radiation monitor packages as non-safety related
 
piping that is connected at both ends to safety related piping. Boundary
 
endpoint clarification note # 4 on mechanical boundary drawings 1X4LD213-2 and 2X4LD213-2 is unnecessary and should not have been
 
included.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.25-1 acceptable
 
because the in scope classification of the radiation monitor and sensing lines are consistent 2-114 with the plant licensing bases. Therefore, the staff's concern described in RAI 2.3.3.25-1 is resolved.
2.3.3.25.3 Conclusion
 
The staff reviewed the LRA, UFSAR, RAI response, and drawings to determine whether the
 
applicant failed to identify any components within the scope of license renewal. The staff
 
finds no such omissions. In addition, the staff's 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 the applicant has adequately identified the
 
radiation monitoring 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).
2.3.3.26  Reactor Makeup Water Storage System 2.3.3.26.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.26 describes the reactor makeup water storage system (RMW), which
 
supplies recycled and deaerated demineralized water to safety-related surge tanks. This
 
system also supplies water to the boric acid mixing tee for daily use as an RCS diluent and
 
to various gas strippers, pumps, tanks, and pipelines for cleaning and flushing operations. It
 
is an assured seismic Category I make-up source to the spent fuel pool and an assured
 
backup seismic Category I makeup source to the CCW and ACCW surge tanks. The
 
reactor makeup water storage tank degasifier recirculates and degasifies the demineralized
 
water to reduce the oxygen content to primary plant usage specifications.
 
The reactor makeup water storage tanks are constructed of concrete with a stainless steel
 
liner. The tank liner is evaluated in this section as a mechanical component. The concrete
 
shell, roof, and base slab are evaluated in the structural scoping for the concrete tank and
 
valve house structures (LRA Section 2.4.7). The reactor makeup water storage tanks have
 
floating diaphragms which minimize oxygen absorption.
 
The reactor makeup water storage system contains safety-related components relied upon
 
to remain functional during and following DBEs. The failure of nonsafety-related SCs in the
 
reactor makeup water storage system potent ially could prevent the satisfactory accomplishment of a safety-related function. 
 
LRA Table 2.3.3.26 identifies reactor makeup water storage system component types
 
within the scope of license renewal and subject to an AMR. The intended functions of the
 
reactor makeup water storage system component types within the scope of license renewal
 
include:
restriction of process flow  physical integrity maintenance to prevent generation of debris or loose parts which could interfere with a safety-related function  pressure-retaining boundary
 
2.3.3.26.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.26 and UFSAR Section 9.2.7 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
2-115  During 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 delineated under 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
The staff's review of LRA Section 2.3.3.26 identified areas in which additional information
 
was necessary to complete the review of the applicant's scoping and screening results. In
 
addition to RAI 2.3.3.26-1 related to drawing continuation errors described in Section 2.3.3, the applicant responded to the staff's RAIs as discussed below.
 
In RAI 2.3.3.26-2, dated January 28, 2008, the staff noted drawing 1X4LD184 (C-8) shows
 
a drawing continuation of 163-1" piping, within the scope of license renewal based on criterion 10 CFR 54.4(a)(2), to drawing 1X4LD129 (G-6). Part of the 163-1" piping on 1X4LD129 (G-6) to In-Scope Boundary Endpoint Clarification Symbol A11 is shown as not
 
in scope for license renewal. The applicant was asked to provide additional information
 
justifying the boundary locations.
 
In its response, dated February 27, 2008, the applicant stated:
 
Mechanical boundary drawing 1X4LD129 shows that the in scope portion of
 
line 1228-163-1" ends at an anchor, and refers to endpoint clarification
 
Note #11. Note #11 indicates that the pipe is in scope for attached pipe
 
considerations up to the identified anchor. Note #11 also states that the
 
spatial interaction boundary extends beyond the identified anchor. No
 
endpoint should have been shown at this location. Where spatial interaction
 
concerns bound the attached anchor endpoint, the line should have been
 
shown as in scope all the way to the spatial interaction endpoint.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.26-2 acceptable
 
because the applicant explained that the entire piping between the anchor A11 and the
 
spatial interaction endpoint is in scope for license renewal. 
 
Therefore, the staff's concern described in RAI 2.3.3.26-2 is resolved.
 
In RAI 2.3.3.26-3, dated January 28, 2008, the staff noted drawing 1X4LD129 (H-2) shows
 
pipe section 172-1" splits and connects to a 172-3/4" line and a 172-1" line. The drawing
 
also shows that part of the 172-1" line before the split, as well as the 172-3/4" line, as
 
nonsafety-related and within the scope of license renewal for spatial effects. Yet no portion
 
of the continuing 172-1" line that is connected to the catalytic hydrogen re-combiner is
 
within the scope of license renewal. The applicant was asked to provide additional
 
information to clarify why this line is not included in the scope of license renewal as per
 
requirements of 10 CFR 54.4(a)(2).
 
In its response, dated February 27, 2008, the applicant stated:
 
On mechanical boundary drawing 1X4LD129 the Reactor Makeup Water (RMW) System piping was put in scope up to the boundaries of that
 
system. After additional review of this drawing, the RMW System 2-116 boundaries do not clearly coincide with 10 CFR 54.4(a)(2) endpoints as defined in NEI 95-10, Appendix F. The mechanical boundary drawings 1X4LD129 and 2X4LD129 should have shown the RMW System piping
 
to the catalytic hydrogen recombiners as in scope for 10 CFR 54.4(a)(2)
 
up to the connections to the recombiners. The catalytic hydrogen
 
recombiners are already in scope for 10 CFR 54.4(a)(2) as equivalent
 
anchors.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.26-3 acceptable because the applicant explained that the mechanical boundary drawings 1X4LD129 and 2X4LD129 should have shown the RMW Syst em piping to the catalytic hydrogen recombiners as in scope for 10 CFR 54.4(a)(2) up to the connections to the recombiners.
 
Therefore, the staff's concern described in RAI 2.3.3.26-3 is resolved.
 
2.3.3.26.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether
 
the applicant failed to identify any components within the scope of license renewal. The
 
staff finds no such omissions. In addition, the staff's 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 the applicant has adequately
 
identified the reactor makeup water storage 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).
2.3.3.27  Sampling Systems 2.3.3.27.1  Summary of Technical Information in the LRA 
 
LRA Section 2.3.3.27 describes the sampling systems, which consists of the following:
 
nuclear sampling system - liquids  nuclear sampling system - gaseous  turbine plant sampling system  post-accident sampling system The nuclear sampling system - liquids supplies representative process liquid samples to
 
the for laboratory analysis to guide operation of the RCS, the RHR system, safety injection
 
system, waste processing system, and CVCS. The nuclear sampling system - liquids is for manual operation and has no emergency function; however, certain valves in the system have a containment isolation function, and lines which penetrate containment are relied
 
upon for containment integrity.
 
The nuclear sampling system - gaseous supp lies representative process stream gas samples for laboratory analysis from the CVCS and gaseous waste and boron recycle
 
systems as required to support plant operati on. The nuclear sampling system - gaseous is for manual operation only during periods of normal plant operation.
 
The turbine plant sampling system collects, cools, analyzes, controls, alarms, and records
 
water quality from various sampling points in the secondary plant systems. The system
 
monitors water samples from the steam gener ator blowdown lines, the turbine cycle, and 2-117 the circulating water system to control water chemistry and permit appropriate corrective action.
 
The post-accident sampling system takes and returns post-accident containment
 
atmosphere samples via system piping and skid-mounted equipment. The original system design included the capability, now eliminated, to obtain fluid samples from the RCS and
 
the containment sumps. Post-accident fluid samples from the RCS and the containment
 
sumps can be obtained by the nuclear sampling system - liquids. Certain system lines and valves are relied upon for containment isolation and integrity.
 
The sampling systems contain safety-related components relied upon to remain functional
 
during and following DBEs. The failure of nonsafety-related SCs in the sampling systems
 
potentially could prevent the satisfactory acco mplishment of a safety-related function. In addition, the sampling systems perform functions that support SBO and EQ.
 
LRA Table 2.3.3.27 identifies sampling systems component types within the scope of
 
license renewal and subject to an AMR: 
 
closure bolting  corrosion product monitors (shells and heads)  filter housings  flow orifice/elements  piping components  pump casings - SGBD sample pumps  rotameter housings  sample baths - steam generator blowdown bath (shells)  sample coolers - primary and secondary-side samples (shells and end plates)  strainer housings  valve bodies The intended functions of the sampling systems component types within the scope of
 
license renewal include:
 
restriction of process flow pressure-retaining boundary
 
2-118 2.3.3.27.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.27 and UFSAR Section 9.3.2 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
The staff's review of LRA Section 2.3.3.27 identified areas in which additional information
 
was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAIs as discussed below.
 
In RAI 2.3.3.27-1, dated January 28, 2008, the staff noted that drawing 2X4LD171-8 (E-5),
turbine plant sampling system, pipe section 139-11/2" downstream of valve 094 is shown as
 
not within the scope of license renewal for criterion 10 CFR 54.4(a)(2). While drawing 1X4LD171-8 (E-5), Turbine Plant Sampling System, shows this piping within the scope of
 
license renewal. The applicant was asked to provide additional information to justify the omission of the 2X4LD171-8 pipe section 139-11/2" from the applicable requirements of
 
10 CFR 54.4(a)(2) and provide the license renewal boundary for 139-11/2".
 
In its response, dated February 27, 2008, the applicant stated:
 
Line 1305-139-11/2" downstream of valve 094 on mechanical boundary drawing 2X4LD171-8 was inadvertently omitted from scope. This drawing should have shown all of line 1305-139-11/2" in scope for 10 CFR 54.4(a)(2).
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.27-1 acceptable
 
because the applicant explained that the piping in question is within the scope of license
 
renewal. Therefore, the staff's concern described in RAI 2.3.3.27-1 is resolved.
 
In RAI 2.3.3.27-2, dated January 28, 2008, the staff noted that drawings 1X4LD171-8 and 2X4LD171-8 have 16 within the scope of license renewal to not within the scope of license
 
renewal transitions identified for 3/8" piping downstream of the steam generator main steam
 
sample coolers that meets the 10 CFR 54.4(a)(2) criterion. There is not enough information
 
provided to identify the transition location. The applicant was asked to provide additional
 
information to identify these LR boundaries and to justify the boundary locations with
 
respect to the applicable requirements of 10 CFR 54.4(a)(2) for the following locations on
 
both drawings:
 
Location D-3, downstream of valve 008.
 
Location E-3, downstream of valve 007.
 
Location F-3, downstream of valve 006.
 
Location G-3, downstream of valve 005.
 
Location D-6, downstream of valve 010.
 
Location E-6, downstream of valve 011.
 
Location F-7, downstream of valve 012.
 
Location G-8, downstream of valve 009.
2-119  In its response, dated February 27, 2008, the applicant stated:
 
The sample lines described above are shown as in scope for
 
10 CFR 54.4(a)(2) criteria up to the point where they exit from the
 
Auxiliary Building into Main Steam and Feedwater Tunnel 1T1 (2T1 on
 
Unit 2). The sample lines downstream of the sample coolers are only in
 
scope for potential spatial interaction effects. There are no safety related
 
systems or components in Tunnels 1T1 or 2T1, therefore the
 
10 CFR 54.4(a)(2) spatial interaction criteria do not apply once the
 
sample lines have exited the Auxiliary Building. Refer to the answer to
 
RAI 2.1-2 for non-safety related components in the Turbine Building.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.27-2 acceptable
 
because the applicant explained why these sample lines are not in scope. Therefore, the
 
staff's concern described in RAI 2.3.3.27-2 is resolved.
 
In RAI 2.3.3.27-3, dated January 28, 2008, the staff noted that drawings 1X4LD110 and 2X4LD110 (F-8), Post Accident Sampling System, show the piping associated with
 
penetration 86C as not within the scope of license renewal based on criterion
 
10 CFR 54.4(a). The applicant was asked to provide additional information to justify the
 
omission of this piping from the applicable requirements of 10 CFR 54.4(a).
 
In its response, dated February 27, 2008, the applicant stated:
 
Line 2702-008-1" which is associated with penetration 86C on mechanical boundary drawings 1X4LD110 and 2X4LD110 is in scope.
 
These drawings should have shown line 2702-008-1" in scope for
 
10 CFR 54.4(a)(1).
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.27-3 acceptable
 
because the applicant explained that the piping in question is within the scope of license
 
renewal. Therefore, the staff's concern described in RAI 2.3.3.27-3 is resolved.
 
2.3.3.27.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether
 
the applicant failed to identify any components within the scope of license renewal. The
 
staff finds no such omissions. In addition, the staff's 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 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).
 
2.3.3.28  Auxiliary Gas Systems 2.3.3.28.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.28 describes the auxiliary gas systems, which include the auxiliary gas system - nitrogen and the auxilia ry gas system - hydrogen.
 
2-120 The auxiliary gas system-nitrogen supplies nitrogen for pressurizing, blanketing, and purging of various plant components. 
 
The auxiliary gas system-hydrogen supplies hydr ogen to the generator for cooling, to the CVCS for oxygen scavenging, and to the waste gas decay tanks and the reactor coolant
 
drain tanks.
 
The auxiliary gas systems contain safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SCs in the auxiliary
 
gas systems potentially could prevent the sati sfactory accomplishment of a safety-related function. In addition, the auxiliary gas sy stems perform functions that support EQ.
 
LRA Table 2.3.3.28 identifies auxiliary gas sy stems component types within the scope of license renewal and subject to an AMR: 
 
closure bolting  piping components  valve bodies The intended function of the auxiliary gas syst ems component types within the scope of license renewal is to provide a pressure-retaining boundary.
 
2.3.3.28.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.28 and UFSAR Section 9.3.5 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review of the auxiliary gas system - nitrogen, 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 delineated under
 
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 in accordance with the requirements
 
of 10 CFR 54.21(a)(1).
 
During its review of the auxiliary gas system
- hydrogen, the staff evaluated the system functions described in the LRA and the UFSAR to verify that the applicant has not omitted
 
from the scope of license renewal any component types with intended functions delineated
 
under 10 CFR 54.4(a).
 
2.3.3.28.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any components within the scope of license renewal. The staff finds no
 
such omissions. In addition, the staff's 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 the applicant has adequately identified the auxiliary
 
gas system - nitrogen 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 The staff reviewed the LRA and UFSAR associated with the auxiliary gas system -
hydrogen to determine whether the applicant failed to identify component types that are
 
typically found within the scope of license renewal and finds no such omissions. On the
 
basis of its review, the staff concludes that the applicant has adequately identified the
 
auxiliary gas system - hydrogen component types within the scope of license renewal, as required by 10 CFR 545.4(a).
 
2.3.3.29  Chilled Water Systems 2.3.3.29.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.29 describes the chilled water systems, which consist of the following:
 
normal chilled water system  essential chilled water system  special chilled water system The normal chilled water system supplies chilled water throughout the plant to all air-
 
conditioning and air cooling units required during normal plant operation. Each unit's
 
system also can be connected to supply chilled water for use in one containment building
 
auxiliary air cooling unit and one reactor cavity cooling unit during refueling outages.
 
The essential chilled water system supplies chilled water to the cooling coils of the various
 
ESF rooms or areas, including battery rooms, switchgear rooms, control rooms, ESF pump rooms, penetration areas, and the spent fuel pool heat exchanger and pump rooms. Both
 
trains of essential chilled water actuate automatically upon either a safety injection signal or
 
control room isolation signal; however, in a loss of offsite power system actuation is manual. Power for each essential chilled water train is by the emergency bus for the
 
equipment it cools.
 
The special chilled water system supplies the necessary cooling water to air-cooling
 
systems for the onsite technical support center and the standby central alarm station. 
 
The chilled water systems contain safety-related components relied upon to remain
 
functional during and following DBEs. The failure of nonsafety-related SCs in the chilled
 
water systems potentially could prevent the sati sfactory accomplishment of a safety-related function. In addition, the chilled water systems perform functions that support fire
 
protection.
 
LRA Table 2.3.3.29 identifies chilled water systems component types within the scope of
 
license renewal and subject to an AMR: 
 
air separator  closure bolting  electric heater housings  essential chillers - condenser (channel heads)  essential chillers - condenser (shells)  essential chillers - condenser (tubes)  essential chillers - condenser (tubesheets)  essential chillers - evaporator (channel heads) 2-122  essential chillers - evaporator (shells)  essential chillers - evaporator (tubes)  essential chillers - evaporator (tubesheets)  flow orifice/elements  oil reservoirs - chiller compressors  piping components  piping components - pipe spools for startup strainers  pump casings - chilled water pumps  pump casings - chiller motor driven oil pumps  sight glasses  strainer elements  strainer housings  tanks - chilled water chemical feed pots  tanks - chilled water expansion tanks  tanks - chiller economizers  valve bodies The intended functions of the chilled water systems component types within the scope of
 
license renewal include:
 
protection from debris heat exchange between fluid media restriction of process flow pressure-retaining boundary
 
2.3.3.29.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.29, and UFSAR Section 9.2.9, and UFSAR Table
 
3.2.2-1 using the evaluation methodology described in SER Section 2.3 and the guidance
 
in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
The staff's review of LRA Section 2.3.3.29 identified areas in which additional information
 
was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAIs as discussed below.
 
In RAI 2.3.3.29-1, dated January 28, 2008, the staff noted that drawings 1X4LD233, 2X4LD233, 1X4LD234, and 2X4LD234 show numerous essential chilled water cooling coils
 
that are within the scope of license renewal based on criterion 10 CFR 54.4(a)(1). Also, drawings AX4LD231 and AX4LD232 show numerous normal chilled water cooling coils that
 
are within the scope of license renewal based on criterion 10 CFR 54.4(a)(2). The applicant
 
was requested to provide additional information explaining why the cooling coil component
 
type was omitted from LRA Table 2.3.3.29 for components subject to an AMR.
 
2-123 In its response, dated February 27, 2008, the applicant stated:
The cooling coil component type(s) are included within the LRA ventilation
 
system which corresponds to their associated component tag number. For
 
instance, essential and normal chilled water cooling coil component types
 
are included in the control and auxiliary building ventilation component type tables, 2.3.3.11 and 2.3.3.12, respectively. Therefore, the component types
 
were not duplicated in the chilled water system Table 2.3.3.29.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.29-1 acceptable
 
because the applicant explained that the essential and normal chilled water cooling coil
 
component types are included in the contro l and auxiliary building ventilation component tables, 2.3.3.11 and 2.3.3.12 respectively. Therefore, the staff's concern described in RAI
 
2.3.3.29-1 is resolved.
 
In RAI 2.3.3.29-2, dated January 28, 2008, the staff noted that the license renewal AMR
 
Table 2.3.3.29 did not include some of the typical components that are listed in AMR tables
 
of other plant LRAs, including the housings for the chiller compressor/motor, compressor oil
 
cooler, oil filter, oil pump, and the refrigerant dryer filter. The applicant was requested to
 
provide additional information to explain why these components are not included in LRA
 
Table 2.3.3.29 as components subject to an AMR.
 
In its response, dated February 27, 2008, the applicant stated:
 
The chiller compressor oil is cooled as the lube oil piping passes through
 
the refrigerant filled motor, therefore the chiller compressor does not
 
have a separate sub-component which functions as an oil cooler.
 
The oil pump is listed in LRA Table 2.3.3.29, Item No. 17, as "Pump
 
Casings - Chiller Motor Driven Oil Pumps."
 
The chiller compressor housings, chiller compressor lube oil filters, and
 
refrigerant filter dryers were omitted from the application and will be
 
added to LRA Table 2.3.3.29. In addition, the chiller compressor purge
 
tanks were omitted from the application and will be added to LRA Table
 
2.3.3.29.
 
LRA Table 3.3.2-29 will be revised to include AMR results for the chiller
 
compressor housings, chiller compressor lube oil filters, refrigerant filter
 
dryers, and chiller compressor purge tanks. In addition, LRA Table 3.3.2-29
 
will be revised to include AMR results for the following components in the
 
chiller compressor lube oil and refrigerant sub-systems that were not
 
included in the initial AMR results:
 
Closure Bolting (copper alloy)  Flow Orifice / Elements  Piping Components  Sight Glasses  Strainer Elements  Strainer Housings  Valve Bodies 2-124 Based on its review, the staff finds the applicant's response to RAI 2.3.3.29-2 acceptable because the applicant explained that LRA AMR Tables 2.3.3.29 and 3.3.2-29 would be
 
updated to include missing components that were not included in the initial AMR results.
 
Therefore, the staff's concern described in RAI 2.3.3.29-2 is resolved.
 
2.3.3.29.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether
 
the applicant failed to identify any components within the scope of license renewal. The
 
staff finds no such omissions. In addition, the staff's 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 the applicant has adequately
 
identified the chilled 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).
2.3.3.30  Waste Management Systems 2.3.3.30.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.30 describes the waste management systems, which include the
 
following:
 
backflushable filter system  condensate cleanup system  waste processing system, liquid  waste processing system, gas The backflushable filter system consists of two major subsystems which filter and transport
 
radioactive crud: 
 
backflushable filters subsystem for filtering crud during normal operation in the CVCS, boron recycle system, liquid waste processing system, spent fuel cooling and purification system, and steam generator blowdown system  crud collection subsystem consisting of a backflushable filter crud tank (equipped with a sprayball) and two crud tank pumps which collect and
 
transport the crud solution to the radwaste solidification system or alternate
 
radwaste building for disposal.
The backflushable filter system is nonsafety-re lated, intermittent during infrequent filter backflushing operations, and isolated most of the time.
The condensate cleanup system maintains the required purity of feedwater for the steam
 
generators by filtration to remove corrosion products, ion exchange to remove condenser
 
leakage impurities, or both filtration and ion exchange. 
 
The condensate cleanup system consists of the condensate filter demineralizer, the
 
backwash recovery, the spent resin disposal, and the spent resin dewatering systems, all of
 
which are retired in place.
2-125  The condensate polishing system is included in the condensate cleanup system. The
 
condensate polishing system (full-flow condensat e filter/demineralizers) filters suspended corrosion products from the condensate and removes ionic contaminants to minimize
 
localized corrosion in the steam generator, turbine, and feedwater systems.
 
The waste processing system, liquid controls, collects, processes, handles, stores, and
 
disposes of liquid radioactive waste generated by normal operation, including anticipated
 
operational occurrences. This system has three subsystems that perform the following
 
activities:
 
the recycle subsystem processes reactor grade water entering the system via equipment leaks and drains, valve leakoffs, pump seal leakoffs, tank
 
overflows, and other tritiated water sources and makes it available for reuse
 
in the plant  the liquid waste subsystem collects and processes nonreactor-grade liquid wastes, including wastes from floor drains, equipment drains for nonreactor
 
grade sources, laundry and hot shower drains, spent and excess radioactive
 
samples, and other nonreactor grade sources  the spent resin collection subsystem transports spent resin to the spent resin storage tank The waste processing system, gas, removes fission product gases from the RCS in the volume control tank, the boron recycle system, the reactor coolant drain tank, and the liquid
 
waste processing system. The waste proce ssing system, gas, has a long-term storage capacity for fission product gases, eliminating any need for scheduled discharges of
 
radioactive gases.
 
The waste processing system, gas, performs no function for safe shutdown of the plant;
 
however, the system distributes the stored activi ty inventory so that, in a waste gas decay tank failure, the dose will be a fraction of the 10 CFR Part 100 permissible limit with the
 
curie content of each waste gas decay tank individually limited in accordance with the
 
technical requirements manual; hence, the waste gas decay tanks are safety-related. The
 
tanks and the piping and valves out to the first isolation valve are safety-related,
 
and the safety-related portion includes the common piping header for the discharge of the
 
pressure relief valves for the tanks.
 
A safety-related interface allows the CLB to consider a waste processing system, gas
 
release and a recycle hold-up tank gaseous release separately. Without the safety-related
 
interface, consideration of the two releases would have to be concurrent; therefore, the
 
interface components mitigate accident consequences and are within the scope of license
 
renewal.
 
The waste management systems contain safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SCs in the waste
 
management systems potentially coul d prevent the satisfactory accomplishment of a safety-related function. In addition, the waste management systems perform functions that support
 
EQ.
2-126  LRA Table 2.3.3.30 identifies waste management systems component types within the scope of license renewal and subject to an AMR: 
 
accumulators  closure bolting  equipment frames - catalytic H 2 recombiner skid  equipment frames - waste gas compressor skid  filter housings  flow orifice/elements  gas traps  piping components  piping components - pipe spools for startup strainers  pump casings - gas decay drain pumps  tanks - backflushable filter crud tanks  tanks - waste gas decay shutdown tanks  tanks - waste gas decay tanks  valve bodies The intended function of the waste m anagement systems component types within the scope of license renewal is to provide a pressure-retaining boundary.
2.3.3.30.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.30 and UFSAR Sections 11.4.2.3.2, 10.4.6, 11.2, and
 
11.3 using the evaluation methodology described in SER Section 2.3 and the guidance in
 
SRP-LR Section 2.3.
 
During its review of the backflushable filter system and the condensate cleanup system, the
 
staff evaluated the system functions described in the LRA and the UFSAR to verify that the
 
applicant has not omitted from the scope of license renewal any component types with intended functions delineated under 10 CFR 54.4(a).
 
During its review of the waste processing system, liquid and waste processing system, gas, 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 delineated under 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 in accordance with the requirements of
 
10 CFR 54.21(a)(1).
 
The staff's review of LRA Section 2.3.3.30 identified areas in which additional information
 
was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAIs as discussed below.
 
In RAI 2.3.3.30-1, dated January 28, 2008, the staff noted drawing 1X4LD111 (H-7) shows
 
pipe section 314-2" as within the scope of license renewal based on criterion 2-127 10 CFR 54.4(a)(2) with the license renewal boundary identified by note A2 and the continuation portion not within the scope of license renewal. However, the continuation of pipe 314-2" on 1X4LD127 (A-8) is also identified as within the scope of license renewal.
 
The applicant was asked to provide additional information detailing the license renewal boundary for pipe section 314-2" on drawings 1X4LD111 (H-8) and 1X4LD127 (A-8).
 
In its response, dated February 27, 2008, the applicant stated:
 
A detail review of the piping isometrics that identify the equivalent anchors for the pipe section 314-2" shown on License Renewal drawing 1X4LD111 (H-7) which continues to drawing 1X4LD127 (A-8) confirms that this line
 
should have been shown in scope per criterion 10CFR 54.4(a)(2). This
 
discrepancy represents a duplication in identifying equivalent anchors for
 
this section of pipe. It has been determined that the in-scope pipe section (314-2") per criterion (a)(2) should continue to drawing 1X4LD127 (A-8) and
 
terminate at note 8 downstream.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.30-1 acceptable
 
because the applicant explained that the in scope pipe section (314-2") should continue to drawing 1X4LD127 (A-8) and terminate at note A8. Therefore, the staff's concern described
 
in RAI 2.3.3.30-1 is resolved.
 
In RAI 2.3.3.30-2, dated January 28, 2008, the staff noted drawings 1X4LD111 (H-3) and 1X4LD127 (F-7) show pipe sections 376-1/2" not within the scope of license renewal. This line connects to 255-3/4" inside the 10 CFR 54.4(a)(2) boundary identified on 1X4LD127.
Additionally, 376-1/2" connects to 048-3" valve 025 on drawing 1X4LD111 which is
 
identified within the scope of license renewal based on criterion 10 CFR 54.4(a)(1). The
 
applicant was asked to provide additional information detailing the license renewal boundary for pipe sections 376-1/2" on drawings 1X4LD111 (H-3) and 1X4LD127 (F-7).
 
In its response, dated February 27, 2008, the applicant stated:
 
Mechanical boundary drawing 1X4LD127 should have taken credit for
 
existing pipe supports so that the end point of the in-scope portion of line
 
1901-199-3/8" terminated before the connection to line 1901-001-3." This
 
removes part of line 1901-199-3/8," all of line 1901-001-3," and all of line
 
1901-255-3/4" from scope. Refer to the answer to RAI 2.3.3.30-4 for
 
additional discussion of line 1901-376-1/2".
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.30-2 acceptable
 
because the applicant stated that:
 
Connecting line to 255-3/4" as well as 376-1/2" are not included in scope.
 
These lines are non-safety related and are not in scope for
 
10 CFR 54.4(a)(1). Also these lines are not in scope for 10 CFR 54.4(a)(2)
 
connected pipe criteria because the CLB considers that the non-safety
 
related small bore line can not affect the large bore safety related line and
 
spatial interaction criteria because all safety related SCs inside containment
 
are assumed to be qualified for spray effects or submergence. 
 
2-128 Therefore, the staff's concern described in RAI 2.3.3.30-2 is resolved.
 
In RAI 2.3.3.30-3, dated January 28, 2008, the staff noted drawing 1X4LD114 (G-3) shows
 
pipe section 369-1/2" within the scope of license renewal based on criterion for
 
10 CFR 54.4(a)(2). However, the continuation of pipe section 369-1/2" on drawing 1X4LD127 (G-7) shows it is not within the scope of license renewal. The applicant was
 
asked to provide additional information detailing the license renewal boundary for pipe sections 369-1/2" on drawings 1X4LD114 (G-3) and 1X4LD127 (G-7).
 
In its response, dated February 27, 2008, the applicant stated:
 
Mechanical boundary drawing 1X4LD114 inadvertently showed lines
 
1901-382-1/2" and 1901-369-1/2" as being in scope for
 
10 CFR 54.4(a)(2). However, these lines are not in scope. Mechanical boundary drawing 1X4LD127 correctly shows line 1901-369-1/2" as not
 
in scope. Refer to the answer to RAI 2.3.3.30-4 for additional discussion.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.30-3 acceptable
 
because the applicant explained that 1901-382-1/2" and 1901-369-1/2" are non-safety
 
related and are not in scope for 10 CFR 54.4(a)(1). Also, these lines are not in scope for
 
10 CFR 54.4(a)(2) connected pipe criteria because the CLB considers that the non-safety
 
related small bore line can not affect the large bore safety related line and spatial
 
interaction criteria because all safety related SCs inside containment are assumed to be
 
qualified for spray effects or submergence. Therefore, the staff's concern described in RAI
 
2.3.3.30-3 is resolved.
In RAI 2.3.3.30-4, dated January 28, 2008, the staff noted drawing 1X4LD114, (G-3) and (F-3), shows pipe sections 369-1/2" within the scope of license renewal based on criterion
 
10 CFR 54.4(a)(2) and 428-1/2" within the scope of license renewal based on criterion
 
10 CFR 54.4(a)(1). The following pipe sections which also continue to the reactor coolant
 
drain tanks are not within the scope of license renewal:
 
1X4LD114 and 2X4LD114 (F-5) 364-1/2" 1X4LD114 and 2X4LD114 (G-5) 363-1/2" 1X4LD114 and 2X4LD114 (G-5) 365-1/2" 1X4LD114 and 2X4LD114 (F-5) 366-1/2" 1X4LD114 and 2X4LD114 (G-6) 362-1/2" 1X4LD114 and 2X4LD114 (G-7) 370-1/2" 1X4LD114 and 2X4LD114 (G-7) 375-1/2" 1X4LD114 (G-8) 370-1/2" 1X4LD114 and 2X4LD114 (E-3) 371-1/2" 2X4LD114 (F-4) 428-1/2", Note 428-1/2" is in scope for 10 CFR 54.4(a)(1) on 1X4LD114 (F-4).
2X4LD114 (G-3) 369-1/2", Note 369-1/2" is in scope for 10 CFR 54.4(a)(2) on 1X4LD114 (G-3).
2X4LD114 (G-4) 382-1/2", Note 382-1/2" is in scope for 10 CFR 54.4(a)(2) on 1X4LD114 (G-4).
 
The applicant was asked to provide additional information detailing the license renewal
 
boundaries for the above pipe sections and explain the apparent difference in scoping
 
methodologies.
2-129  In its response, dated February 27, 2008, the applicant stated:
 
Mechanical boundary drawing 1X4LD114 inadvertently showed lines
 
1901-382-1/2" and 1901-369-1/2" as being in scope for
 
10 CFR 54.4(a)(2). Refer to the answer to RAI 2.3.3.30-3. These lines
 
are not in scope. See below for 10 CFR 54.4(a)(2) criteria discussion.
 
Mechanical boundary drawing 1X4LD114 inadvertently showed line
 
1901-428-1/2" as being in scope for 10 CFR 54.4(a)(1). Line 1901-428-
 
1/2" is Project Classification 427, which is non-safety related and
 
therefore not in scope for 10 CFR 54.4(a)(1). See below for
 
10 CFR 54.4(a)(2) criteria discussion.
 
Lines 1901-362-1/2," 1901-363-1/2," 1901-364-1/2," 1901-365-1/2,"
1901-366-1/2," 1901-369-1/2," 1901-370-1/2," 1901-371-1/2," 1901-375-
 
1/2," 1901-382-1/2," and 1901-428-1/2" on each unit are non-safety
 
related valve packing leakoff lines. Because they are non-safety related
 
they are not in scope for 10 CFR 54.4(a)(1).
 
These lines are not in scope for 10 CFR 54.4(a)(2) connected pipe
 
criteria because the CLB considers that the non-safety related small bore
 
line can not affect the large bore safety related line. In general the stress
 
calculations consider the loads imposed on a large bore line by 1/2" or 3/4"
 
tubing to be insignificant and those loads are neglected. The small bore
 
line is considered to be decoupled. Therefore the 10 CFR 54.4(a)(2)
 
connected pipe criteria does not apply.
 
These lines are not in scope for 10 CFR 54.4(a)(2) spatial interaction
 
criteria because all safety related SCs inside containment are assumed
 
to be qualified for spray effects or submergence, where required, to
 
address a high energy line break or LOCA. Furthermore, the pipe
 
supports for these lines are in scope so seismic 2/1 is not a concern and
 
the lines operate at low pressure so pipe whip is not a concern.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.30-4 acceptable
 
because the applicant explained that the subject lines are non-safety related and are not in
 
scope for 10 CFR 54.4(a)(1). Also these lines are not in scope for 10 CFR 54.4(a)(2)
 
connected pipe criteria because the CLB considers that the non-safety related small bore
 
line can not affect the large bore safety related line and spatial interaction criteria because
 
all safety related SCs inside containment are qualified for spray effects or submergence.
 
Therefore, the staff's concern described in RAI 2.3.3.30-4 is resolved.
 
In RAI 2.3.3.30-5, dated January 28, 2008, the staff noted drawing 2X4LD124 (A-5) shows
 
the license renewal boundary for pipe section 045-2" from the Boron Recycle System (BRS) recycle evaporator as within the scope of license renewal based on criterion 10 CFR 54.4(a)(2). This in-scope line is continued from drawing AX4LD123-1. However, the
 
same section of pipe on Unit 1 is identified as not within the scope of license renewal in drawing 1X4LD124 (A-5). The applicant was asked to provide additional information
 
explaining the apparent difference in scoping methodologies for pipe section 045-2" on drawings 1X4LD124 (A-5) and 2X4LD124 (A-5).
2-130 In its response, dated February 27, 2008, the applicant stated:
The scoping methodologies for Unit 1 and Unit 2 piping line number 045-2" are the same. A section of Unit 2 piping line number 2-1901-045-2" is
 
located on Level B of the auxiliary building in the vicinity of safety related
 
components that are within the scope of license renewal based on criterion
 
10 CFR 54.4(a)(1). The corresponding section of Unit 1 piping (line number
 
1-1901-045-2") is located in a separate area of the auxiliary building such
 
that there is no potential for spatial interaction with safety related
 
components. Therefore, only the Unit 2 piping section is within the scope of
 
license renewal based on criterion 10 CFR 54.4(a)(2). 
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.30-5 acceptable
 
because the applicant explained that a section of Unit 2 piping line number 2-1901-045-2" is located on Level B of the auxiliary building in the vicinity of safety related components that are within the scope of license renewal based on criterion 10 CFR 54.4(a)(1). The
 
corresponding section of Unit 1 piping is located in a separate area of the auxiliary building
 
such that there is no potential for spatial interaction with safety related components.
 
Therefore, the staff's concern described in RAI 2.3.3.30-5 is resolved.
 
2.3.3.30.3  Conclusion
 
The staff reviewed the LRA and UFSAR associated with the backflushable filter system and
 
the condensate cleanup system to determine whether the applicant failed to identify
 
component types that are typically found within the scope of license renewal and finds no
 
such omissions. On the basis of its review, the staff concludes that the applicant has
 
adequately identified the backflushable filter system and the condensate cleanup system
 
component types within the scope of license renewal, as required by 10 CFR 54.4(a).
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether
 
the applicant failed to identify any components within the scope of license renewal for the
 
waste processing system, liquid, and the waste processing system, gas. The staff finds no
 
such omissions. In addition, the staff's 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 the applicant has adequately identified the waste
 
processing system, liquid, and the waste pr ocessing system, gas, 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).
 
2.3.3.31  Thermal Insulation 2.3.3.31.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.31 describes the thermal insulation, which minimizes heat loss from
 
components and protects personnel from high-te mperature components. Insulation in areas with safety-related equipment retains structural integrity during and after a seismic
 
Category I event. The insulation support structures for the reactor vessel and nozzles limit
 
the amount of insulation displaced by blow down during a LOCA condition below the amount assumed for the reactor cavity pressurization analysis. Inside the containment, the
 
containment cooling system design credits insulation on components with high operating
 
temperatures.
2-131  Thermal insulation outside containment has no safety design basis; however, insulation in
 
areas with safety-related equipment is designed to retain structural integrity during and after seismic events.
 
Insulation on piping at containment penetrations must keep local concrete temperatures
 
below 200 °F. For certain HVAC systems, heat load calculations, that assure performance
 
of safety-related functions credit insulation. The EDG building heat-up calculation credits
 
EDG exhaust pipe insulation (including the silencers).
 
Outside area insulation with heat tracing protects small-bore piping and instrument lines for
 
in-scope systems from freezing. Insulation supports heat tracing and shields certain lines in
 
the battery rooms from spray.
 
The failure of nonsafety-related SCs in the thermal insulation could prevent the satisfactory
 
accomplishment of a safety-related function. The thermal insulation also performs functions
 
that support SBO.
 
LRA Table 2.3.3.31 identifies thermal insulation component types within the scope of
 
license renewal and subject to an AMR: 
 
insulation - jacketing and supports  thermal insulation The intended functions of the thermal insulation component types within the scope of
 
license renewal include:
 
environmental control of plant areas within equipment limitations physical integrity maintenance to prevent generation of debris or loose parts which could interfere with a safety-related function shelter/protection for safety-related/nonsafety-related components structural/functional support for safety-related/nonsafety-related components with maintenance of physical integrity and flow path considerations
 
2.3.3.31.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.31 and UFSAR Sections 5.2.3.2.3 and 6.2.1.2.1.2
 
using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-
 
LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2-132 2.3.3.31.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 the applicant has adequately identified the thermal
 
insulation 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).
 
2.3.3.32  Miscellaneous Leak Detection System 2.3.3.32.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.32 describes the miscellaneous leak detection system, which detects
 
leaks in the containment bottom and side liners and in liners of the spent fuel pool, fuel
 
transfer canal, and fuel cask loading pit. This system also has containment penetrations
 
necessary to perform the periodically necessa ry containment integrated leak rate test.
 
The miscellaneous leak detection system contains safety-related components relied upon
 
to remain functional during and following DBEs. The failure of nonsafety-related SCs in the
 
miscellaneous leak detection system potentia lly could prevent the satisfactory accomplishment of a safety-related function. 
 
LRA Table 2.3.3.32 identifies miscellaneous leak detection system component types within
 
the scope of license renewal and subject to an AMR: 
 
closure bolting  piping components  valve bodies The intended function of the miscellaneous leak detection system component types within
 
the scope of license renewal is to provide a pressure-retaining boundary.
 
2.3.3.32.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.32 and the UFSAR using the evaluation methodology
 
described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.3.32.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's review determined whether the applicant failed to identify 2-133 any components subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the miscellaneous
 
leak detection system components within t he 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  Steam and Power Conversion Systems LRA Section 2.3.4 identifies the steam and pow er conversion systems SCs subject to an AMR for license renewal.
 
The applicant described the supporting SCs of t he steam and power conversion systems in the following LRA sections:
 
2.3.4.1  main steam system 2.3.4.2  condensate and feedwater 2.3.4.2  condensate chemical injection 2.3.4.2  feedwater heater and MSR drain 2.3.4.3  steam generator blowdown system 2.3.4.4  auxiliary feedwater systems 2.3.4.5  auxiliary steam system 2.3.4.6  electrohydraulic control system All of these systems are Balance of Plant systems.
 
The staff identified the following BOP systems for Tier 1 reviews:
 
LRA Section System 2.3.4.2 feedwater heater and moisture separator/reheater drain system 2.3.4.5 auxiliary steam system 2.3.4.1  Main Steam System 2.3.4.1.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.4.1 describes the main steam system (MSS), which is integral to the
 
nuclear steam supply system heat removal systems and steam generator overpressure protection features. The main steam system conducts the steam generated in the four
 
steam generators through the containment to the turbine-generator, moisture separator
 
reheaters, steam jet air ejectors, turbine shaft gland seals, steam generator feedwater
 
pump turbines, turbine-driven auxiliary feedwat er pump, and the turbine bypass system. 
 
Safety-related portions of the main steam system include heat removal, overpressure
 
protection, and isolation features. Steam conducted from the steam generators to the
 
atmospheric relief and main steam safety valves, which protect the steam generator and
 
the main steam piping from over-pressurization, removes heat from the RCS. The outlet
 
nozzle of each steam generator has a flow restrictor designed to limit flow rate and thrust
 
loads in a main steam line rupture. The main steam system also supplies steam to the auxiliary feedwater pump turbine supplying feedw ater to the steam generators for reactor heat removal during accident or transient conditions when normal feedwater is unavailable.
 
Each of the four main steam lines has two main steam isolation valves and two main steam 2-134 bypass valves to isolate the secondary side of the steam generators in the event of leakage or malfunction to prevent uncontrolled blowdown of the steam generators and to isolate
 
nonsafety-related portions of the system.
 
The main steam system contains safety-related components relied upon to remain
 
functional during and following DBEs. The failure of nonsafety-related SCs in the MSS
 
potentially could prevent the satisfactory acco mplishment of a safety-related function. In addition, the main steam system performs functions that support fire protection, ATWS, SBO, and EQ.
 
LRA Table 2.3.4.1 identifies main steam sy stem component types within the scope of license renewal and subject to an AMR: 
 
closure bolting  filter housings - ARV local (manual) actuators  flexible connectors  flow orifice/elements  flow restrictors - ARV discharge paths  oil reservoirs - ARV local (manual) actuators  oil reservoirs filler/breather caps - ARV local (manual) actuators  piping components  piping components - forged sections for 5-way pipe restraints  pump casings - ARV manual hand pumps  pump casings - wet layup recirculation pumps  valve bodies The intended functions of the main steam system component types within the scope of
 
license renewal include:
 
protection from debris spray shield or curbs for flow direction restriction of process flow pressure-retaining boundary 2.3.4.1.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.4.1 and UFSAR Section 10.3 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.4.1.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such 2-135 omissions. In addition, the staff's 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 the applicant has adequately identified the main steam
 
system components within the scope of licens e 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  Feedwater System 2.3.4.2.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.4.2 describes the feedwater system, which includes the following:
 
condensate and feedwater system  condensate chemical injection system  feedwater heater and moisture separator/reheater drain system The condensate and feedwater system condenses high-pressure and low-pressure turbine
 
extraction and exhaust steam and main feedwat er pump turbine exhaust steam, collects the condensate in the condenser hotwell, and maintains steam generator water levels by
 
supplying preheated feedwater through all power operation modes of the plant. The system
 
also isolates feedwater as required to lim it mass and energy in the containment in any feedwater break and prevents RCS over-cooli ng and steam generator overfilling with water in the steam lines. Feedwater flow to each steam generator is via a 16-inch main feedwater
 
line to the steam generator main feedwater nozzle or the 6-inch feedwater bypass line to
 
the auxiliary feedwater nozzle. The system s hares the feedwater bypass line portion from upstream of the feedwater bypass isolati on valves to the steam generator bypass feedwater/auxiliary feedwater nozzle with t he safety-related auxiliary feedwater (AFW) system. 
 
The primary function of the condensate chemical in jection system is to supply chemicals to the condensate and feedwater system for corrosion control. The condensate chemical
 
injection system includes the piping and storage/transfer equipment conveying the chemicals and extending to the piping for the condensate and feedwater system, AFW
 
system, and steam generators. System safety functions are containment isolation and integrity.
 
The feedwater heater and moisture separator/reheater drain system drains the liquid (condensed steam) from the feedwater heaters and moisture separator/reheaters and
 
routes it to the condensate and feedwater syst em. This system performs no safety function but is within the 10 CFR 54.4(a)(2) scope of license renewal.
 
The feedwater system contains safety-related components relied upon to remain functional
 
during and following DBEs. The failure of nonsafety-related SCs in the feedwater system
 
potentially could prevent the satisfactory acco mplishment of a safety-related function. In addition, the feedwater system performs functions that support ATWS and EQ.
 
LRA Table 2.3.4.2 identifies feedwater system component types within the scope of license renewal and subject to an AMR: 
 
closure bolting  flow orifice/elements 2-136  piping components  piping components - forged sections for 5-way pipe restraints  piping components - guard pipe  valve bodies The intended functions of the feedwater system component types within the scope of
 
license renewal include:
 
restriction of process flow pressure-retaining boundary
 
2.3.4.2.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.2 and UFSAR Sections 10.3.5 and 10.4.7 using the
 
evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR
 
Section 2.3.
 
During its review of the condensate and feedwater system and the condensate chemical
 
injection system, the staff evaluated the syst em 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 delineated under 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
During its review of the feedwater heater and moisture separator/reheater drain system, the
 
staff evaluated the system functions described in the LRA and the UFSAR to verify that the
 
applicant has not omitted from the scope of license renewal any component types with intended functions delineated under 10 CFR 54.4(a).
 
2.3.4.2.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, and drawings associated with the condensate and
 
feedwater system and the condensate chemical injection system to determine whether the applicant failed to identify any SCs within the scope of license renewal. The staff finds no
 
such omissions. In addition, the staff's 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 the applicant has adequately identified the
 
condensate and feedwater system and the c ondensate chemical injection 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 staff reviewed the LRA and UFSAR associated with the feedwater heater and moisture
 
separator/reheater drain system to determine whether the applicant failed to identify
 
component types that are typically found within the scope of license renewal and finds no
 
such omissions. On the basis of its review, the staff concludes that the applicant has
 
adequately identified the feedwater heater and moisture separator/reheater drain system
 
component types within the scope of license renewal, as required by 10 CFR 54.4(a).
 
2-137 2.3.4.3  Steam Generator Blowdown System 2.3.4.3.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.4.3 describes the steam generator blowdown system, which accepts secondary water from each steam generator blowdown line, processes the water as
 
required, and delivers the processed water to either the condensate system or the waste
 
water retention basin. Process steps include cooling with heat recovery, pressure reduction, filtration, and ion exchange. The purpose of t he steam generator blowdown system is to maintain optimum secondary side water chemistry during normal operation and during
 
anticipated operational occurrences by removing impurities from primary coolant or
 
circulating water in-leakage concentrated in the steam generator by evaporation. 
 
Safety-related instrumentation in the steam generator blowdown system helps detect and isolate high-energy lines in the auxiliary bu ilding. Interfaces between steam generator blowdown system nonsafety-related portions and other plant systems can affect safety-related portions of the plant adversely following a postulated pipe rupture in the nonsafety-
 
related high-energy portion of the system outside of containment.
 
The steam generator blowdown system contai ns safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SCs in the
 
steam generator blowdown system potentia lly could prevent the satisfactory accomplishment of a safety-related function. In addition, the steam generator blowdown
 
system performs functions that support EQ.
 
LRA Table 2.3.4.3 identifies steam generator bl owdown system component types within the scope of license renewal and subject to an AMR: 
 
closure bolting  filter housings  flow orifice/elements  heat exchangers - SGBD HXs (channel heads)  heat exchangers - SGBD HXs (shells)  heat exchangers - SGBD trim HXs (channel heads)  heat exchangers - SGBD trim HXs (shells)  piping components  piping components - pipe spools for startup strainers  pump casings - steam generator drain pumps  pump casings - steam generator blowdown spent resin sluice pumps  strainer housings  valve bodies The intended functions of the steam generator blowdown system component types within the scope of license renewal include:
 
restriction of process flow pressure-retaining boundary
 
2-138 2.3.4.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.3 and UFSAR Section 10.4.8 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.4.3.3  Conclusion
 
The staff reviewed the LRA, UFSAR and drawings to determine whether the applicant failed
 
to identify any SCs within the scope of license renewal. The staff finds no such omissions.
 
In addition, the staff's 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 the applicant has adequately identified the steam generator
 
blowdown system components within the sc ope 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  Auxiliary Feedwater System (1302) 2.3.4.4.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.4.4 describes the AFW system, which supplies feedwater to the steam
 
generators during startup, cooldown, and emergency conditions resulting in a loss of main
 
feedwater. The two motor-driven and one turbi ne-driven AFW pumps are available to ensure the required feedwater flow to the steam generators. During normal operations, the
 
system is in a standby mode with cont rols selected for automatic operation.
 
System capacity is sufficient to remove decay heat and to supply adequate feedwater for
 
RCS cooldown within specified limits. The AFW system is relied upon for feedwater supply
 
to the steam generators to maintain a secondary heat sink for DBE mitigation; therefore, this system is safety-related.
 
The AFW feedwater source for both normal conditions and DBE mitigation is the
 
condensate storage tank. Such tanks are constructed of concrete lined with stainless steel.
 
This section evaluated the tank liner as a mechanical component. LRA Section 2.4.7, "Concrete Tank and Valve House Structures," evaluated the concrete shell, roof, and base
 
slab. The condensate storage tanks have floating diaphragms to minimize oxygen
 
absorption.
 
The AFW system contains safety-related components relied upon to remain functional
 
during and following DBEs. The failure of nonsafety-related SCs in the AFW system
 
potentially could prevent the satisfactory acco mplishment of a safety-related function. In addition, the AFW system performs functions that support fire protection, ATWS, SBO, and
 
EQ.
 
2-139 LRA Table 2.3.4.4 identifies AFW system component types within the scope of license renewal and subject to an AMR: 
 
closure bolting  filter housings  flow orifice/elements  oil coolers - TDAFWP turbine (channel heads)  oil coolers - TDAFWP turbine (shells)  oil coolers - TDAFWP turbine (tubes)  oil coolers - TDAFWP turbine (tubesheets)  oil reservoirs - TDAFWP turbine lube oil  piping components  piping components - pipe spools for startup strainers  pump casings - AFW pumps  pump casings - CST vacuum degasifier pumps  pump casings - TDAFWP lube oil pumps  spargers - TDAFWP steam exhaust condensate  tank - CST degasifier tank  tank diaphragms - CSTs  tank liners (and internals) - CST liners  turbine casings (AFW pump drive turbine)  valve bodies The intended functions of the AFW system component types within the scope of license
 
renewal include:
 
heat exchange between fluid media flow pattern or distribution provision restriction of process flow physical integrity maintenance to prevent generation of debris or loose parts which could interfere with a safety-related function pressure-retaining boundary
 
2.3.4.4.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.4 and UFSAR Section 10.4.9 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
The staff's review of LRA Section 2.3.4.4 identified an area in which additional information
 
was necessary to complete the review of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
 
2-140  In RAI 2.3.4.4-1, dated January 28, 2008, the staff noted drawings 1X4LD161-1 and 2X4LD161-1 (E-7) downstream of valve HV5089 is shown as within the scope of license
 
renewal based on criterion 10 CFR 54.4(a)(2), up to an equivalent anchor A1/A4, whereas, there is no annotation if there is an equivalent anchor for the 153-10" line at HV5103. The
 
applicant was asked to provide additional information justifying the boundary locations with
 
respect to the applicable requirements of 10 CFR 54.4(a).
In its response, dated February 27, 2008, the applicant stated:
Downstream of HV5103 on 1X4LD161-1 and 2X4LD161-1 is a spool
 
piece identified as line 1302-104-10." This spool piece is shown as not in
 
scope (colored gray) and in phantom on these boundary drawings
 
because it is a removable spool piece that is only installed for hydrostatic
 
testing of the main condenser. The lines on either side of the spool piece
 
(1302-153-10" and 1302-010-10"") terminate at the blind flanges. The
 
end point of line 1302-153-10" is therefore defined in accordance with
 
the guidance provided in NEI 95-10, Appendix F, as the free end of the
 
non-safety related piping. An equivalent anchor is not required.
 
By telecom dated April 17, 2008, the applicant corrected an error in line reference numbers
 
from 1302-153-10" and 1302-010-10" to 1305-153-10" and 1305-010-10", respectively. 
 
Based on its review, the staff finds the applicant's response to RAI 2.3.4.4-1 acceptable, because the applicant explained that the lines on either side of the spool piece (1305-153-
 
10" and 1305-010-10") terminate at the blind flanges. The end point of line 1305-153-10" is
 
therefore defined in accordance with the guidance provided in NEI 95-10, Appendix F, as
 
the free end of the non-safety related piping. Therefore, the staff's concern described in RAI
 
2.3.4.4-1 is resolved. 
 
2.3.4.4.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI response, and drawings to determine whether the
 
applicant failed to identify any components within the scope of license renewal. In addition, the staff's review determined whether the applicant failed to identify any components
 
subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff
 
concludes the applicant has adequately identified the auxiliary feedwater 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).
 
2.3.4.5  Auxiliary Steam System 2.3.4.5.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.4.5 describes the auxiliary steam system, which c onveys auxiliary steam to the balance-of-plant systems during startup, shutdown, and normal operation. The
 
supply of steam for this system is the main steam system. By a cross-connect an operating unit can supply steam to a unit shut down.
The auxiliary steam sy stem performs the following functions:
 
2-141  heating of the condensate during condensate and feedwater system preoperational cleanup  assisting in attaining and holding the required vacuum in the main condensers  sealing the glands of the main turbine and feedwater pump drive turbines prior to the availability of main steam  preoperational testing of the AFW pump turbine and steam generator feedwater pump turbines  heating the cleaning solutions for preoperational piping and equipment cleaning  steam blanketing of moisture separator reheaters during plant shutdown  assisting in deaeration of the main condensate during cold cleanup operations  as an alternative, main steam line and main turbine shell preheating following extended main steam isolation and prior to entry of steam from
 
steam generators The failure of nonsafety-related SCs in the aux iliary steam system c ould potentially prevent the satisfactory accomplishment of a safety-related function. 
 
LRA Table 2.3.4.5 identifies auxiliary steam sy stem component types within the scope of license renewal and subject to an AMR: 
 
closure bolting  flow orifice/elements  piping components  steam/fluid trap bodies  valve bodies The intended functions of the auxiliary steam sy stem component types within the scope of license renewal include:
 
restriction of process flow pressure-retaining boundary
 
2.3.4.5.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.5 and UFSAR Section 9.5.9 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
component types with intended functions delineated under 10 CFR 54.4(a).
2-142  2.3.4.5.3  Conclusion
 
The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify
 
any component types that are typically found within the scope of license renewal and finds no such omissions. The staff finds no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the auxiliary steam system
 
component types within the scope of license renewal, as required by 10 CFR 54.4(a).
2.3.4.6  Electrohydraulic Control System 2.3.4.6.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.4.6 describes the electrohy draulic control system. The steam turbine converts the thermal energy of the steam fr om the main steam system into mechanical energy to drive the main generator and produce the plant electrical output. Integral to
 
operation of the turbine is the turbine control system, which includes the digital
 
electrohydraulic control system. 
 
The turbine control system positions the steam valves controlling steam flow to the high-pressure and low-pressure turbines (i.e., high-pressure control valves and stop valves and low-pressure intermediate stop valves and intercept valves). The electrohydraulic control 
 
system meets the fluid pressure demands for positioning of these steam valves. The turbine lube oil system supplies pressurized oil to the auto-stop oil header and lubricates
 
the turbine. Loss of the auto-stop oil header pressure or the electrohydraulic control fluid
 
pressure to the actuators will close the steam valves (tripping the turbine).
 
Electrohydraulic control system nonsafety-relat ed components required to trip the turbine in response to ATWS are within the 10 CFR 54.4(a)(3) regulated event scoping criteria for
 
license renewal. The applicant conservatively includes nonsafety-related components
 
which trip the turbine in response to overspeed within the scope of license renewal under
 
10 CFR 54.4(a)(2).
 
The failure of nonsafety-related SCs in the elec trohydraulic control system could potentially prevent the satisfactory accomplishment of a safety-related function. The electrohydraulic control system also performs functions that support ATWS.
 
There are no electrohydraulic control system mechanical components subject to an AMR.
The screening process concluded that active components accomplish system mechanical
 
component functions and that any component pressure boundary failure would not prevent
 
performance of system intended functions, a conclusion consistent with the SRP-LR
 
Table 2.1-5 as to turbine controls for actuator and overspeed trip. The screening concluded
 
that the electrohydraulic control system components perform no intended functions for license renewal; therefore, none of the electr ohydraulic control  system components are subject to an AMR. 
 
2.3.4.6.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.6 and UFSAR Sections 7.7.1.11, 10.1, 10.2, and
 
10.2.2.3.1.5 using the evaluation methodology described in SER Section 2.3 and the
 
guidance in SRP-LR Section 2.3.
2-143  During 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 delineated under 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.3.4.6.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's 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 the applicant has adequately identified the electrohydraulic
 
control 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).
 
2.4  Scoping and Screening Results - Structures This section documents the staff's review of the applicant's scoping and screening results for structures. Specifically, this section discusses:
 
containment structures auxiliary, control, fuel handling, and equipment buildings EDG structures turbine building tunnels and duct banks nuclear service cooling water structures concrete tank and valve house structures switchyard structures fire protection structures  radwaste structures  auxiliary feedwater pumphouse structures  component supports and bulk commodities In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must identify and list passive, long-lived SCs within the scope of license renewal and subject to an AMR. To
 
verify that the applicant properly implemented its methodology, the staff's review focused on the implementation results. This approach allowed the staff to confirm that there were no
 
omissions of structures and components that meet the scoping criteria and are subject to
 
an AMR.
 
The staff's evaluation of the information in the LRA was performed in the same manner 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 those structures
 
that appear to meet the license renewal scoping criteria. Similarly, the staff evaluated the
 
applicant's screening results to verify that all passive, long-lived SCs were subject to an
 
AMR in accordance with 10 CFR 54.21(a)(1).
 
2-144 In its scoping evaluation, the staff reviewed the applicable LRA sections, focusing on components that have not been identified as within the scope of license renewal. The staff
 
reviewed the UFSAR, for each structure to determine whether the applicant has omitted
 
from the scope of license renewal components with intended functions delineated under
 
10 CFR 54.4(a). The staff also reviewed the UFSAR to determine whether the LRA
 
specified all intended functions delineated under 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 applicant's 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
 
described in 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). By letter dated, January 28, 2008, the staff requested additional
 
information to resolve any omissions or discrepancies identified.
 
2.4.1  Containment Structures 2.4.1.1  Summary of Technical Information in the Application In LRA Section 2.4.1, the applicant described the containment structures, including
 
containment buildings and containment internal structures. The containment building is a
 
seismic Category I structure that completely encloses the reactor, the Reactor Coolant
 
System (RCS), the steam generators, and por tions of the auxiliary and engineered safety features systems. The containment building also houses components required for reactor refueling, including the polar crane, refueling cavity, and portions of the fuel handling
 
system. The containment structure protects these features from external events (e.g., tornado, flooding, et cetera) and functions as a fission product barrier following an accident.
 
The containment structure also provides biological shielding during normal operation and
 
following a LOCA.
 
The major elements of the containment building structure are the main structure and
 
foundation, the steel containment liner, and the containment penetrations.
 
The containment internal structures are comprised of concrete and steel components. The
 
major concrete internal components are the reactor cavity and primary shield wall, secondary shield wall, refueling cavity (and transfer canal), and floor slabs. Major steel
 
internal components are the refueling canal liner and structural steel framing.
 
Miscellaneous items unique to the containment internal structures include the emergency
 
sump screens and the trisodium phosphate baskets on the containment base slab.
 
Common structural commodities include supports for piping, cable trays, conduits, ventilation ducting, and other components, whip restraints, cable trays and conduits, platforms, racks and frames, and grating.
 
The containment structures contain safety-related components relied upon to remain
 
functional during and following DBEs. The failure of nonsafety-related SCs in the
 
containment structure potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the containment structures perform functions that support fire
 
protection, ATWS, and SBO.
 
2-145 LRA Table 2.4.1 identifies containment structures component types within the scope of license renewal and subject to an AMR.
2.4.1.2  Staff Evaluation The staff reviewed LRA Section 2.4.1 using the evaluation methodology described in SER
 
Section 2.4 and the guidance in SRP-LR Section 2.4, "Scoping and Screening Results:
 
Structures."
 
During its review of the LRA Section 2.4.1, the staff identified areas in which additional
 
information was necessary to complete the evaluation of the applicant's scoping and
 
screening results for containment structures. Therefore, the staff issued requests for
 
additional information (RAIs) by letter dated January 28, 2008 to determine whether the
 
applicant properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria
 
of 10 CFR 54.21(a)(1). The following discussion describes the staff's RAIs related to the
 
LRA Section 2.4.1, the corresponding applicant responses, and the staff evaluation.
 
In Section 2.4.1 of the LRA the applicant stated that a tendon access gallery is located
 
beneath the perimeter of the base slab for the installation and inspection of the U-shaped
 
tendons. In RAI 2.4.1-1, dated January 28, 2008, the staff asked whether the applicant
 
considered the tendon access gallery and its associated vertical access shafts in the scope
 
of license renewal and subject to an AMR.
 
By letter dated February 27, 2008, the applicant provided the response to RAI 2.4.1-1 and
 
confirmed that the tendon access gallery and its associated vertical access shafts are
 
included in the scope of license renewal for VEGP and subject to an AMR. Therefore, the
 
staff finds the applicant's scoping of the tendon access gallery acceptable.
 
From review of LRA Table 2.4.1, the staff could not determine if the following components
 
of the Containment Structures have been screened-in as components subject to an AMR.
 
(i) Control rod drive missile shield (ii) Polar crane support brackets (iii) Reactor cavity manipulator crane
 
In RAI 2.4.1-2, dated January 28, 2008, the staff asked the applicant to clarify the inclusion
 
of these components in the scope of license renewal.
 
By letter dated February 27, 2008, the applicant provided the following response to
 
RAI 2.4.1-2.
 
(i) Control rod drive missile shield has been screened-in as a component subject to an AMR. This item is included in Table 2.4.1 ID 13 'Steel
 
Components: Integrated Reactor Head Steel Assemblies.' (ii) Polar crane support brackets have been screened-in as a component subject to an AMR. This item is included in Table 2.4.1 ID 11 'Steel
 
Components: All Structural Steel.' (iii) Reactor cavity manipulator crane is part of 'Refueling Machine' at VEGP and 2-146 it has been screened-in as a component subject to an AMR. This item is included in Section 2.3.3.3 under 'Fuel Handling and RV Servicing
 
Equipment.'
In its response, the applicant provided clarification that the control rod drive missile shield, polar crane support brackets and reactor cavity manipulator crane are included in the scope
 
of license renewal for VEGP and subject to an AMR. Therefore, the staff finds the
 
applicant's response to RAI 2.4.1-2 acceptable.
 
Under the title "Steel Containment Liner" in Section 2.4.1, the LRA states that "The floor
 
liner plate is installed on top of the foundation slab and is then covered with concrete." The
 
staff issued RAI 2.4.1-3 on January 28, 2008, to request the applicant to confirm that the
 
inaccessible floor liner plate of the base mat, including the leak chase system and the
 
concrete fill slab above this liner are included in the components listed in Table 2.4.1 and
 
are subject to an AMR.
 
By letter dated February 27, 2008, the applicant provided the response to RAI 2.4.1-3 and
 
confirmed that the inaccessible floor liner plate (including the leak chase system) on the top
 
of the base mat is included in Table 2.4.1 ID 14 'Steel Components: Liner (Containment);
 
Liner Anchors; Integral Attachments' and the concrete fill slab above this liner is included in
 
Table 2.4.1 ID 4 'Concrete: Internal Structures.' Considering that these items are included
 
in the scope of license renewal for VEGP and subject to an AMR, the staff finds the
 
applicant's response to RAI 2.4.1-3 acceptable.
 
By letter dated January 28, 2008, the staff issued RAI 2.4.1-4 to request the applicant to
 
clarify that the component identified as "Steel Components: All Structural Steel" in various
 
tables in Section 2.4 of the LRA includes the connection components (gusset plates, welds, bolts, etc.) of structural steel.
 
By letter dated February 27, 2008, the applicant confirmed that the connection components (gusset plates, welds, bolts, etc.) are included in the scope of license renewal for VEGP
 
and subject to an AMR. Therefore, the staff finds the applicant's response to RAI 2.4.1-4
 
acceptable.
 
By letter dated January 28, 2008, the staff issued RAI 2.4.1-5 to request clarification on the
 
intended function of containment internal structure relative to radiation shielding as
 
described in Section 3.8.3 of the VEGP UFSAR.
 
By letter dated February 27, 2008, the applicant confirmed that radiation shielding is an
 
intended function of concrete internal structures and was inadvertently omitted from Table
 
2.4.1. By letter dated March 20, 2008, the applicant amended the LRA to add radiation
 
shielding to Table 2.4.1 and Table 3.5.2-1. Therefore, the staff finds the applicant's
 
response related to the intended function of the internal structures acceptable.
 
LRA Table 2.4.1 lists the Equipment Hatch and Personnel Airlocks as Containment
 
components subject to an AMR. By letter dated January 28, 2008, the staff issued RAI
 
2.4.1-6 to request the applicant to confirm that the hatch locks, hinges and closure
 
mechanisms, that help prevent loss of sealing/leak-tightness for these listed hatches, are
 
included in the scope of license renewal and subject to an AMR.
 
2-147 By letter dated February 27, 2008, the applicant responded to RAI 2.4.1-6, stating that the locks, hinges and closure mechanisms for the containment hatches and locks are active
 
components and are not subject to an AMR. In a subsequent telephone conference, as
 
summarized in a letter from D. J. Ashley (NRC) to Southern Nuclear Operating Company
 
dated March 26, 2008, the applicant agreed to update the LRA Table 3.5.1 to delete "active
 
component" discussion of Item 3.5.1-17. By letter dated March 20, 2008, the applicant
 
amended the LRA stating that the locks, hinges and closure mechanisms are subject to an
 
AMR under VEGP 10 CFR 50 Appendix J program along with the host components.
 
Considering the above, the staff finds the applicant's response to RAI 2.4.1-6 acceptable.
 
By letter dated January 28, 2008, the staff issued RAI 2.4.1-7 to request the applicant to
 
confirm that the channel/angle shrouds that have been used at the liner welded joints (including those at penetrations) are considered in-scope components and subject to an
 
AMR.
 
By letter dated February 27, 2008, the applicant confirmed that all items welded to the
 
concrete side of the liner or welded to the interior face of the liner are included in the scope
 
of license renewal for VEGP and subject to an AMR. Therefore, the staff finds the
 
applicant's response to RAI 2.4.1-7 acceptable.
 
Section 3.8.2.1.4 of the VEGP UFSAR discusses the isolation valve encapsulation vessel
 
assemblies. These vessels and their respective supports/anchorages were not specifically
 
listed in Table 2.4.1 as in-scope components and subject to an AMR. By letter dated
 
January 28, 2008, the staff issued RAI 2.4.1-8 to request the applicant to confirm that the
 
isolation valve encapsulation vessel assemblies and their supports/anchorages are
 
screened-in and subject to an AMR.
 
By letter dated February 27, 2008, the applicant provided clarification and confirmed that
 
the isolation valve encapsulation vessel assemblies are in scope and are included in Table
 
2.3.2.1 and their supports/anchorages are also in scope and are included in Table 2.4.2.
 
Considering that the encapsulation vessel assemblies and their supports are considered in
 
the scope of license renewal for VEGP and subject to an AMR, the staff finds the
 
applicant's response to RAI 2.4.1-8 acceptable.
 
The insulation and cooling system provided to lim it the inside face temperature of primary shield wall and reactor cavity to 150 F are described in Section 3.8.3.4.4 of the VEGP UFSAR. By letter dated January 28, 2008, the staff issued RAI 2.4.1-9 to request the
 
applicant to confirm that the insulation and cooling system described in Section 3.8.3.4.4 of
 
the VEGP UFSAR have been considered in the scope of license renewal and subject to an
 
AMR.
 
By letter dated February 27, 2008, the applicant provided clarification and confirmed that
 
the insulation installed on the reactor vessel, reactor coolant system piping, and other
 
components inside the containment building with high operating temperatures is credited
 
for reducing the thermal loading inside the containment building, including thermal loading
 
of the primary shield wall and reactor cavity. The applicant also stated that the cooling
 
systems provided to limit the inside face tem perature of primary shield wall and reactor cavity consist of the Containment Building Cavity Cooling System and the Containment Building Reactor Support Cooling System.
 
By letter dated March 20, 2008, the applicant amended the LRA to update Sections 2-148 2.3.3.13 and 2.3.3.31 of the LRA to include clarification relative to the criterion 10 CFR 54.4(a)(2) in-scope function of insulation and cooling system provided to limit the inside face temperature of the primary shield wall and reactor cavity to 150 F.
Considering the applicant's clarifications and the LRA updates, the staff finds the
 
applicant's response to RAI 2.4.1-9 acceptable.
By letter dated January 28, 2008, the staff issued RAI 2.4.1-10 to determine whether the
 
equipment hatch concrete external shield door is considered in the scope of license
 
renewal and subject to an AMR.
 
By letter dated February 27, 2008, the applicant provided the response to RAI 2.4.1-10 and
 
stated that the equipment hatch concrete external shield door is in-scope and subject to an
 
AMR. By letter dated March 20, 2008, the applicant amended the LRA to update Table
 
2.4.1 and Table 3.5.2-1 to add the equipment hatch concrete external shield door as a
 
component subject to an AMR. Therefore, the staff finds the applicant's response to RAI
 
2.4.1-10 acceptable.
 
According to VEGP UFSAR Section 2.4.12.1.3.1, ground water is the primary source of
 
supply for reactor cooling water makeup, normal makeup to the nuclear service cooling
 
towers, and fire protection. By letter dated January 28, 2008, the staff issued RAI 2.4.1-11
 
to request the applicant to provide justification for the exclusion of makeup water wells from
 
the scope of license renewal.
 
By letter dated February 27, 2008, the applicant provided its response to RAI 2.4.1-11 and
 
stated that the Plant Makeup Well Water System is a non-safety related system that does
 
not perform any safety related functions, nor c an failure of this system prevent any safety related system from performing its functions. In addition, the applicant stated that the non-
 
safety related Plant Makeup Well Water System is not in scope for supporting the Fire
 
Protection System because the 10 CFR 54.4(a)(2) criteria do not apply to non-safety
 
related systems or components which suppor t other non-safety related systems or components. Based on the above, the applicant concluded that the Plant Makeup Well
 
Water System does not perform any functions that meet the criteria of 10 CFR 54.4(a)(1),
10 CFR 54.4(a)(2) or 10 CFR 54.4(a)(3) and is not in the scope of license renewal.
 
In a subsequent telephone conference, as summarized in a letter from D. J. Ashley (NRC)
 
to Southern Nuclear Operating Company, Inc., dated March 26, 2008, further discussion
 
with the applicant provided clarification that although the VEGP UFSAR Section
 
2.4.12.1.3.1 states that the Plant Makeup Well Water System is the primary source of
 
supply for fire protection, the fire water storage tanks are credited as the sources of water
 
for the fire protection system. As discussed in NUREG 1800, Table 2.1-2, for
 
10 CFR 54.4(a)(3), a second level support system (i.e., Plant Makeup Well Water System)
 
need not be considered in the scope of license renewal. Considering the above, the staff
 
finds the applicant's response to RAI 2.4.1-11 acceptable.
 
Section 2.4.1 of the LRA discusses Jib cranes inside the containment structures. By letter
 
dated January 28, 2008, the staff issued RAI 2.4.1-12 to request the applicant to confirm 
 
that the support anchorages and mechanical components of Jib cranes are in-scope and
 
subject to an AMR.
 
By letter dated February 27, 2008, the applicant responded to RAI 2.4.1-12 and confirmed 2-149 that the Jib cranes and associated passive components are included in Table 2.4.12 ID 21
'Miscellaneous Cranes including Monorails' and support anchorages are included in Table
 
2.4.12 ID 35 'Supports for EDGs, HVAC Components, and Misc. Mechanical Equipment:
 
Support Members, Welds, Bolted Connections, Support Anchorages to Building Structure.' 
 
Considering that the Jib cranes, support anchorages and other passive components of Jib
 
cranes inside the containment structures are included in the scope of the LRA and subject
 
to an AMR, the staff finds the applicant's response to RAI 2.4.1-12 acceptable.
 
2.4.1.3  Conclusion The staff reviewed the LRA, UFSAR, and RAI responses to determine whether the
 
applicant failed to identify any SCs within the scope of license renewal. The staff finds no
 
such omissions. In addition, the staff's review determined whether the applicant failed to
 
identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its
 
review, the staff concludes that the applicant has adequately identified the containment
 
structures SCs 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  Auxiliary, Control, Fuel Handling, and Equipment Buildings 2.4.2.1  Summary of Technical Information in the Application LRA Section 2.4.2 describes the auxiliary, control, fuel-handling, and equipment buildings, which include the following structures:
 
auxiliary building  control building  fuel-handling building  equipment buildings
 
These adjacent structures form a common complex that adjoins the containment buildings.
 
The auxiliary building is a seven-story reinforced concrete seismic Category I structure
 
common to both plant units located south of the fuel-handling building and containment
 
structures. Three stories are above grade, four subterranean. There are two penetration
 
areas, one, on the south side of each containment. All auxiliary building columns, slabs, and structural walls are of reinforced concrete. The roof is a reinforced concrete slab with a
 
minimum thickness of two feet. The auxiliary building structure is founded on a mat
 
continuous over the plan of the building. The auxiliary building houses major safety-related
 
and nonsafety-related plant facilities (e.g
., CVCS, ECCS, RHR system, HVAC facilities) and other equipment.
 
A number of access openings are sealed with removable concrete block wall units of short
 
height for radiation shielding and maintenance purposes held in place by structural
 
elements (e.g
., steel angle or steel beams).
 
The control building is a six-story, deeply-embedded, reinforced concrete structure common
 
to both plant units situated north of and adjacent to the fuel-handling and the two
 
containment buildings. It is supported on a mat foundation 40 feet below grade. The boxlike
 
center section has three upper levels extending to 60 feet above grade. A partial fourth 2-150 level extends an additional 20 feet. Penetration areas east and west of the center section for access to the two containment buildings are the primary areas for routing of electrical
 
and control system cables into the containmen
: t. Directly north of each containment building is a main steam isolation valve room whic h extends 40 feet above grade. The control room and technical support center principally occupy the level at grade. The levels, immediately
 
above and below grade, house the cable spreading rooms. The lowest level houses the
 
switchgear and HVAC equipment. The third and fourth floors mainly contain HVAC
 
equipment, while the fourth floor is primar ily occupied by nonsafety-related components.
 
The fuel-handling building is a five-story, boxlike, reinforced concrete structure, common to
 
both plant units, completely surrounded by other Category I buildings and located between
 
the two containment structures. The fuel storage facility part of the fuel-handling building
 
consists of the new fuel storage area, spent fuel pool (including the structure, liner, and fuel
 
storage racks), fuel transfer canal, cask storage area, cask washdown area, and rooms for
 
supporting equipment.
 
Each nuclear unit has a separate but connected spent fuel pool approximately 41 feet
 
deep, constructed of reinforced concrete, and lined with a stainless steel plate. The spent
 
fuel pool is for underwater storage of spent fuel assemblies after their removal from the
 
reactor. New fuel may be moved from the new fuel racks to the spent fuel racks in
 
preparation for a refueling outage.
 
The fuel transfer canal is an intermediate handling area, connected to the refueling canal
 
inside containment by the fuel transfer tube, which is evaluated as part of the containment
 
structures. The fuel transfer canal may be drained for fuel handling equipment service or
 
flooded for fuel handling. The cask storage area is a location for shipping casks to be
 
loaded. The isolated cask wash area is for cleaning and decontamination of shipping casks.
 
Adjacent rooms house the spent fuel cooling and cleanup system equipment that cools and
 
purifies the spent fuel pool water. The fuel-handling building's overhead and refueling load
 
handling cranes are evaluated in Section 2.3.3.3.
 
The equipment building is not a distinct structure but composed of portions of the control
 
and fuel-handling buildings. The equipment building partially surrounding (approximately
 
three quadrants) the containment building is a seismic Category II structure, designed, however, to seismic Category I requirements to preclude any safety impact on the safety-related equipment in the control and fuel-handling buildings. The primary function of the
 
equipment building is to support nonsafety-related HVAC equipment.
 
The auxiliary, control, fuel-handling, and equipment buildings contain safety-related
 
components relied upon to remain functional during and following DBEs. The failure of
 
nonsafety-related SCs in the auxiliary, control, fuel-handling, and equipment buildings
 
potentially could prevent the satisfactory acco mplishment of a safety-related function. In addition, the auxiliary, control, fuel-handling, and equipment buildings perform functions
 
that support fire protection, ATWS, and SBO.
 
LRA Table 2.4.2 identifies auxiliary, control, fuel-handling, and equipment buildings
 
component types within the scope of license renewal and subject to an AMR.
 
2-151 2.4.2.2  Staff Evaluation The staff reviewed LRA Section 2.4.2 using the evaluation methodology described in SER
 
Section 2.4 and the guidance in SRP-LR Section 2.4.
 
During its review of the LRA Section 2.4.2, the staff identified areas in which additional
 
information was necessary to complete the evaluation of the applicant's scoping and
 
screening results for auxiliary, control, fuel-handling and equipment buildings. Therefore, the staff issued an RAI by letter dated January 28, 2008, to determine whether the
 
applicant properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria
 
of 10 CFR 54.21(a)(1). The following discussion describes the staff's RAI related to the
 
LRA Section 2.4.2 and the corresponding applicant response.
 
By letter dated January 28, 2008, the staff issued RAI 2.4.2-1 to confirm that the leak chase
 
system for the spent fuel pool liner is in-scope and subject to an AMR.
 
By letter dated February 27, 2008, the applicant provided its response to RAI 2.4.2-1 and
 
confirmed that the leak chase system for the spent fuel pool liner is in the scope of license
 
renewal for VEGP and subject to an AMR. Therefore, the staff finds the applicant's
 
response to RAI 2.4.2-1 acceptable.
 
2.4.2.3  Conclusion The staff reviewed the LRA, UFSAR and RAI response to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's review determined whether the applicant failed to identify
 
any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the auxiliary, control, fuel
 
handling, and equipment buildings SCs 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  Emergency Diesel Generator Structures 2.4.3.1  Summary of Technical Information in the Application LRA Section 2.4.3 describes the EDG structures, which include the diesel generator
 
buildings and diesel fuel storage tank pump houses. Each diesel generator building and its
 
proximate diesel fuel storage tank pump houses support EDG operation.
 
The diesel generator buildings (one for each unit) are rectangular, reinforced concrete, seismic Category I structures designed to withstand various combinations of loads defined
 
in the UFSAR. Each bay houses a diesel generator and air-handling, exhaust, and silencing
 
equipment. The building's primary function is to house the diesel generators needed to
 
supply emergency onsite power in a loss of offsite power.
 
The diesel fuel storage tank pump houses (two for each unit) are seismic Category I
 
structures that shelter the pumps and valves for the buried diesel fuel oil storage tanks
 
supplying the EDGs and house the nozzles, gages, drains, and pump mount systems. The
 
reinforced concrete pump houses straddle the tanks and extend three feet above grade
 
except for a common entry between each pai r of pump houses extending 14 feet above 2-152 grade. Each pump house foundation consists of wall strip footings. The pump houses are boxlike with work space levels above the top of the tanks.
 
The EDG structures contain safety-related components relied upon to remain functional
 
during and following DBEs. The failure of nonsafety-related SCs in the EDG structures
 
potentially could prevent the satisfactory acco mplishment of a safety-related function. In addition, the EDG structures perform functions that support fire protection and SBO.
 
LRA Table 2.4.3 identifies EDG structures component types within the scope of license
 
renewal and subject to an AMR.
 
2.4.3.2  Staff Evaluation The staff reviewed LRA Section 2.4.3 using the evaluation methodology described in SER
 
Section 2.4 and the guidance in SRP-LR Section 2.4.
 
During its review, 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 SCs with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those SCs 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 SCs subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.4.3.3  Conclusion The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify
 
any SCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an
 
AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that
 
the applicant has adequately identified the EDG structures SCs 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  Turbine Building 2.4.4.1  Summary of Technical Information in the Application LRA Section 2.4.4 describes the turbine building, a nonsafety-related, seismic Category II
 
structure that houses all main turbine-generator equipment including the main condenser
 
and other power-generation and auxiliary equipment.
 
Steel-framed and enclosed with a reinforced concrete roof and metal siding, the turbine
 
building is a trussed rigid-frame structure above the turbine deck level; below, the frames
 
are braced to reduce side sway. The building has three floors of reinforced concrete or
 
steel grating and a basement. The building mat foundation also supports the turbine
 
pedestal.
 
The turbine-generator pedestal supports the turbine-generator unit. The pedestal, designed
 
to withstand operating and emergency loading forces including seismic disturbances and
 
machine imbalance, consists of a reinforced concrete deck on columns attached to a 2-153 basemat. Also part of the turbine building is the elevated electrical bridge structure between the main structure and the control building.
 
The turbine building and the electrical bridge structure are in close proximity to safety-
 
related structures. In addition, the failure of nonsafety-related SCs in the turbine building
 
could potentially prevent the satisfactory a ccomplishment of a safety-related function. The turbine building also performs functions that support ATWS and SBO.
 
LRA Table 2.4.4 identifies the turbine building component types within the scope of license
 
renewal and subject to an AMR.
 
2.4.4.2  Staff Evaluation The staff reviewed LRA Section 2.4.4 using the evaluation methodology described in SER
 
Section 2.4 and the guidance in SRP-LR Section 2.4.
 
During its review of LRA Section 2.4.4, the staff identified areas in which additional
 
information was necessary to complete the evaluation of the applicant's scoping and
 
screening results for the turbine building. Therefore, the staff issued its RAIs by letter dated
 
January 28, 2008, to determine whether the applicant properly applied the scoping criteria
 
of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following
 
discussion describes the staff's RAIs related to the LRA Section 2.4.4 and the
 
corresponding applicant responses.
 
By letter dated January 28, 2008, the staff issued RAI 2.4.4-1 to request the applicant to
 
provide justification for excluding the turbine pedestal from the scope of license renewal. In
 
addition, considering the plant's current licensing basis, the applicant was requested to
 
discuss the ATWS and SBO systems/components identified in Section 2.4.4 and their
 
spatial interaction with the turbine pedestal.
 
By letter dated February 27, 2008, the applicant provided the following response to
 
RAI 2.4.4-1.
 
An integral foundation system is provided for both turbine building and the turbine pedestal.
 
The turbine generator pedestal is isolated from the turbine building structure above the foundation. The turbine building is in scope because of its proximity to Class I structures.
 
Cascading effects of the turbine pedestal on the main turbine building is not required to be
 
considered. Therefore, the turbine pedestal is not in the scope of license renewal. However
, the turbine pedestal is in scope under maintenance rule and inspected under the Structural
 
Monitoring Program.
 
Some of the raceways and supports for the turbine impulse input signal to the AMSAC
 
system and the output signal to the turbine trip solenoids that are mounted to the turbine
 
pedestal are within the scope of license renewal. As per NUREG-1800 for
 
10 CFR 54.4(a)(3), an applicant need not consider second level support systems. This
 
condition does not need the turbine pedestal to be included in scope of license renewal
 
because as per NUREG-1800 for 10 CFR 54.4(a)(3), an applicant need not consider
 
second level support systems.
 
Considering that, under the current VEGP licensing basis, the interaction between the
 
turbine pedestal and turbine building is not required to be evaluated. The turbine pedestal is 2-154 currently inspected under the Structural Monitoring Program, and as discussed in NUREG-1800, Table 2.1-2, for 10 CFR 54.4(a)(3); a second level support system (i.e., turbine
 
pedestal) need not be considered in the scope of license renewal, and as such, the staff
 
finds the applicant's response to RAI 2.4.4-1 acceptable.
 
In RAI 2.4.4-2, dated January 28, 2008, the staff requested the applicant to provide
 
justification for excluding the turbine building bridge crane from the scope of license
 
renewal.
 
By letter dated February 27, 2008, the applicant provided the response to RAI 2.4.4-2 and
 
stated that the turbine building bridge crane is in a seismic Category II structure and does
 
not have a license renewal intended function. The applicant also referred to the response to
 
RAI 2.1-2. In RAI 2.1-2, the staff requested that the applicant provide the rational and basis
 
for not including nonsafety-related SCs in the vicinity of safety-related SCs in the turbine
 
building within the scope of license renewal. In response to RAI 2.1-2, the applicant
 
provided justification that while VEGP conservatively classified a number of components in
 
the turbine building as safety-related, these components are either strictly anticipatory, perform no safety function, or are not credited in the accident analysis. As such, the
 
provisions of 10 CFR 54.4(a)(2) do not apply and no other components in the turbine
 
building are considered in the scope of license renewal.
 
Since the components in the turbine building are either anticipatory, perform no safety
 
function and are not credited in the accident analysis, the staff finds the exclusion of the
 
turbine building bridge crane from the scope of license renewal acceptable.
 
2.4.4.3  Conclusion The staff reviewed the LRA, UFSAR, and RAI responses to determine whether the
 
applicant failed to identify any SCs within the scope of license renewal. The staff finds no
 
such omissions. In addition, the staff's review determined whether the applicant failed to
 
identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its
 
review, the staff concludes that the applicant has adequately identified the turbine building
 
SCs 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  Tunnels and Duct Banks 2.4.5.1  Summary of Technical Information in the Application LRA Section 2.4.5 describes the tunnels and duct banks, which include mechanical piping
 
tunnels, electrical cable tunnels, duct banks, and valve and pull boxes. The radwaste
 
transfer tunnel is not evaluated in this structures grouping but as part of the radwaste
 
structures grouping in Section 2.4.10 of the LRA.
 
The Category I tunnels within the scope of license renewal consist of main steam, NSCW, diesel generator piping, diesel generator electric, AFW, turbine electric, and electric steam
 
boiler tunnels. The main steam and electric steam boiler tunnels are designed to seismic
 
Category I criteria and for pipe break loads due to their proximity to, and required interface
 
with other seismic Category I structures; however, the design did not have to consider the
 
effects of tornado missiles.
 
2-155 The Category I box-like, reinforced concrete tunnels are buried either completely or with roofs exposed at or near grade level and house piping and electrical trays. The main steam
 
tunnel roof is mainly grating instead of concrete for venting in the event of postulated pipe
 
breaks. The auxiliary feedwater tunnels are covered with removable concrete slabs that are
 
bolted down to prevent them from becoming missiles in a postulated AFW line break. The
 
underground electrical duct banks for safety-related electrical cables to and from safety-
 
related buildings and equipment are rectangular reinforced concrete structures poured in
 
place around PVC conduit. Also included are nonsafety-related duct runs for SBO (e.g
., for the high-voltage switchyard).
 
Rectangular reinforced concrete valve boxes and pull boxes with steel or aluminum covers
 
for safety-related boxes and aluminum covers for nonsafety-related boxes are located strategically for above-ground access to isolation valves and to cables in buried piping and
 
cable runs routed through the pull boxes to appropriate duct banks.
 
The tunnels and duct banks contain safety-related components relied upon to remain
 
functional during and following DBEs. The failure of nonsafety-related SCs in the tunnels
 
and duct banks potentially could prevent the sa tisfactory accomplishment of a safety-related function. In addition, the tunnels and duct banks perform functions that support fire
 
protection, ATWS, and SBO.
 
LRA Table 2.4.5 identifies tunnels and duct banks component types within the scope of
 
license renewal and subject to an AMR.
 
2.4.5.2  Staff Evaluation The staff reviewed LRA Section 2.4.5 using the evaluation methodology described in SER
 
Section 2.4 and the guidance in SRP-LR Section 2.4.
 
During its review, 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 SCs with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those SCs, 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 SCs subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.4.5.3  Conclusion The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify
 
any SCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an
 
AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that
 
the applicant has adequately identified the tunnels and duct banks SCs 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  Nuclear Service Cooling Water Structures 2.4.6.1  Summary of Technical Information in the Application LRA Section 2.4.6 describes the NSCW structures, which include the NSCW cooling towers 2-156 and NSCW valve houses and consist of four NSCW cooling towers (two per reactor unit) and their valve houses. The NSCW structures are seismic Category I safety-related
 
structures designed to withstand the load combinations defined in the UFSAR. The NSCW
 
towers and valve houses support and protect the appropriate NSCW system components
 
during normal plant operation and shutdown conditions as well as during earthquakes, extreme wind, tornadoes, and other abnormal conditions of postulated accidents. The
 
NSCW towers are relied upon as the ultimate heat sink to support normal operation, safe
 
shutdown, and post-accident heat loads.
 
Each NSCW cooling tower, comprised of a cooling tower superstructure and a below-grade
 
storage basin, is a reinforced concrete cylindrical shell with a concrete basemat, flat roof
 
deck and supported on a 9-foot thick circular mat foundation.
 
The NSCW valve house next to each NSCW tower is a transition structure which protects
 
the piping, valves, and electrical supply running from the NSCW tunnels into the tower. The
 
valve houses are irregularly-shaped reinforced concrete structures with roofs approximately
 
14 feet above and basemat tops approximately 14 feet below grade to match the NSCW
 
tunnels. The NSCW valve house is supported on a 6-foot thick mat foundation.
 
The NSCW structures contain safety-related components relied upon to remain functional
 
during and following DBEs. The failure of nonsafety-related SCs in the NSCW structures
 
could potentially prevent the satisfactory acco mplishment of a safety-related function. In addition, the NSCW structures perform functions that support fire protection.
 
LRA Table 2.4.6 identifies NSCW structures component types within the scope of license
 
renewal and subject to an AMR.
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.
 
During its review, 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 SCs with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those SCs, 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 SCs subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.4.6.3  Conclusion The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify
 
any SCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an
 
AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that
 
the applicant has adequately identified the NSCW structures SCs 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).
 
2-157 2.4.7  Concrete Tank And Valve House Structures 2.4.7.1  Summary of Technical Information in the Application LRA Section 2.4.7 describes the concrete tank and valve house structures, which include
 
the condensate storage tanks and valve houses, reactor makeup water storage tanks, and
 
RWST. Each unit has two dedicated condensate storage tanks, one reactor makeup water
 
storage tank, and one RWST.
 
The condensate storage tank is a seismic Category I, safety-related, 480,000-gallon
 
capacity, cylindrical, reinforced concrete shell. Each pair of condensate water storage tanks
 
has a common reinforced concrete valve house protecting piping and equipment from
 
missiles and supported by a combined foundation mat. Perimeter dikes for retention of
 
spilled water are constructed of reinforced concrete integral to the basemat. The
 
condensate storage tank supplies condensate water for the AFW system and for normal
 
make-up and supply to the condenser hot well.
 
The reactor make-up water storage tank is a seismic Category I, safety-related, 165,000-
 
gallon capacity, cylindrical, reinforced concrete shell supported by a basemat foundation at
 
grade. Tank perimeter dikes for retention of spilled water are constructed of reinforced
 
concrete integral to the basemat. The reactor make-up water storage tank supplies the
 
RCS makeup water.
 
The RWST is a seismic Category I, safety-related, 715,500-gallon capacity, cylindrical, reinforced concrete shell supported by a basemat foundation at grade. Perimeter dikes for
 
the retention of spilled water, constructed of reinforced concrete, are integral portions of the
 
basemat. 
 
The RWST is designed to hold enough dilute boric acid solution to fill the refueling canal
 
prior to refueling operations and to provide injection water to support emergency core
 
cooling and containment spray functions.
 
The concrete tank and valve house structures contain safety-related components relied
 
upon to remain functional during and following DBEs. The failure of nonsafety-related SCs
 
in the concrete tank and valve house structures could potentially prevent the satisfactory
 
accomplishment of a safety-related function. In addition, the concrete tank and valve house
 
structures perform functions that support fire protection, ATWS, and SBO.
 
LRA Table 2.4.7 identifies concrete tanks and valve house structures component types
 
within the scope of license renewal and subject to an AMR.
 
2.4.7.2  Staff Evaluation The staff reviewed LRA Section 2.4.7 using the evaluation methodology described in SER
 
Section 2.4 and the guidance in SRP-LR Section 2.4.
 
During its review, 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 SCs with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those SCs, that the applicant has identified as within the scope of license 2-158 renewal, to verify that the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.4.7.3  Conclusion The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify
 
any SCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an
 
AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that
 
the applicant has adequately identified the concrete tank and valve house structures SCs
 
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).
2.4.8  Switchyard Structures 2.4.8.1  Summary of Technical Information in the Application LRA Section 2.4.8 describes the switchyard structures, which include the high-voltage and
 
the low-voltage switchyards. The high-voltage switchyard is the connection point for the off-
 
site transmission and generator output lines and for the feeds to the unit startup
 
transformers. The high-voltage switchyard electrical installation connects two preferred
 
power sources from the offsite transmission lines to the transformer yards as required per
 
10 CFR Part 50 Appendix A General Design Criterion 17. The high-voltage switchyard
 
structures include a switch house with the primary functions of relieving space congestion
 
in the main control room and locating the switchyard relay panels close to their equipment.
 
The switch house also stores other switchyard equipment.
 
The low-voltage switchyard adjacent to the turbine building is where the main power, unit
 
startup, and unit auxiliary transformers are located. The low-voltage switchyard electrical
 
installation connects the high-voltage switchyard to the plant. The high- and low-voltage
 
switchyards are connected by both overhead and underground cables.
 
The switchyard structures perform functions that support SBO.
 
LRA Table 2.4.8 identifies switchyard structures component types within the scope of
 
license renewal and subject to an AMR.
 
2.4.8.2  Staff Evaluation The staff reviewed LRA Section 2.4.8 using the evaluation methodology described in SER
 
Section 2.4 and the guidance in SRP-LR Section 2.4.
 
During its review, 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 SCs with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those SCs 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 SCs subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2-159 2.4.8.3  Conclusion The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify
 
any SCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an
 
AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that
 
the applicant has adequately identified the switchyard structures SCs 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).
 
2.4.9  Fire Protection Structures 2.4.9.1  Summary of Technical Information in the Application LRA Section 2.4.9 describes the fire protection structures, which include the fire water
 
pumphouse and the structural support feature of the fire water storage tanks.
 
The primary function of the fire pumphouse is to house conventional fire protection water
 
pumps for extinguishing fires. The fire water pumphouse provide structural support, fire
 
barrier separation, and environmental protection for the fire pumps and their auxiliary
 
components. Only the fire protection features, including fire-rated block walls, equipment
 
pedestals, and the concrete building foundation are within the scope of license renewal.
 
There are two fire water pumphouses, No. 1 with one electric motor-driven fire pump and
 
one electric motor-driven jockey pump and No. 2 with two diesel-driven fire pumps and one
 
electric motor-driven jockey pump. The floor slab, perimeter footing, and equipment block
 
pads consist of a reinforced concrete mat sl ab. The one-story concrete masonry buildings have steel-framed concrete roofs supported by steel decking.
 
The fire water storage tank foundations support two separate fire water storage tanks. The
 
boundary includes a reinforced concrete ring beam and a mat of oiled sand inside the ring
 
beam and underneath the bottom of the tanks. Two 300,000-gallon fire water storage tanks
 
are adjacent to the fire water pumphouses. The fire protection tanks are vertically
 
cylindrical, flat-bottom tanks made of steel plate.
 
The failure of nonsafety-related SCs in the fire protection structures could potentially
 
prevent the satisfactory accomplishment of a safety-related function. The fire protection
 
structures also perform functions that support fire protection.
 
LRA Table 2.4.9 identifies fire protection structures component types within the scope of
 
license renewal and subject to an AMR.
 
2.4.9.2  Staff Evaluation The staff reviewed LRA Section 2.4.9 using the evaluation methodology described in SER
 
Section 2.4 and the guidance in SRP-LR Section 2.4.
 
During its review of the LRA Section 2.4.9, the staff identified areas in which additional
 
information was necessary to complete the evaluation of the applicant's scoping and
 
screening results for the fire protection structures. Therefore, the staff issued its RAI by 2-160 letter dated January 28, 2008 to determine whether the applicant properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). 
 
The following discussion describes the staff's RAI related to the LRA Section 2.4.9 and the
 
corresponding applicant response.
 
By letter dated January 28, 2008 the staff issued RAI 2.4.9-1 to request the applicant to
 
provide information relative to proximity (spatial interaction) of the demineralized water
 
storage tank and the electrical fire pump house No. 1 considering the current VEGP
 
licensing basis.
By letter dated February 27, 2008, the applicant provided its response to RAI 2.4.9-1 and
 
stated that the Fire Protection System components contained in electrical fire pump house
 
No. 1, including the pump house structure, are non-safety related components that are in
 
scope for license renewal for 10 CFR 54.4(a)(3) criteria. The non-safety related
 
Demineralized Water Storage Tank is not in scope for 10 CFR 54.4(a)(2) spatial interaction
 
criteria relative to electrical fire pump house No. 1 because those criteria do not apply to
 
non-safety related systems or components wh ich could affect other nonsafety-related systems or components.
 
In its response, the applicant provided clarification and confirmed that within the current
 
VEGP licensing basis the spatial interaction between nonsafety-related SCs which could
 
affect other nonsafety-related SCs need not be considered. Therefore, the staff finds the
 
applicant's response to RAI 2.4.9-1 acceptable.
2.4.9.3  Conclusion The staff reviewed the LRA, UFSAR, and RAI response to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's review determined whether the applicant failed to identify
 
any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the fire protection structures
 
SCs 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).
 
2.4.10  Radwaste Structures 2.4.10.1  Summary of Technical Information in the Application LRA Section 2.4.10 describes the radwaste structures, which house equipment and provide
 
space for processing, packaging, and storage of radioactive wastes generated in normal
 
plant operation. The radwaste structures in the scope of license renewal include the
 
following:
 
radwaste transfer tunnel  radwaste transfer building  dry active waste warehouse  dry active waste processing facility  radwaste processing facility  alternate radwaste building 2-161  The DAW buildings consist of processing and storage buildings located in the southwest
 
portion of the owner-controlled area. These metal-siding buildings, supported on base
 
slabs, have precast concrete panels and concrete masonry walls for shielding. The roofs
 
are metal panels supported by steel beams. The processing building houses equipment for
 
processing dry waste and the storage building stores it for offsite shipment. The grade
 
elevation is above that required for natural flood protection. Curbs and ramps in radioactive
 
areas are provided to contain water from fire sprinkler actuation.
 
The radwaste processing facility, located between the solidification and the field support
 
buildings, is a concrete building supported on a slab to house process equipment for
 
handling radioactive liquids, resins, and filters. The facility has a subterranean
 
demineralizer vault, subterranean high-integrity container storage vaults, a rollup door for a
 
truck bay, and a 40-ton bridge crane to service equipment. The slab and shield walls inside
 
the building are designed to retain radioactive liquids.
 
The alternate radwaste building and its systems and equipment were designed to process
 
liquid and solid waste without utilizing the solidification systems and evaporators of the
 
original plant design. This metal-siding building, which formerly housed the liquid radwaste
 
systems, is supported on a base slab. The building basemat has curbing to retain
 
radioactive liquid. It contains a demineralizer vault, high-integrity container system storage
 
vault, laydown area, and a truck-trailer loadi ng bay. Allotted areas are for staging process shields and process skids.
 
The radwaste transfer building has two-stories with the basemat located at grade. This
 
building and the radwaste transfer tunnel are no longer in service and abandoned in place;
 
however, the radwaste transfer building has a fire damper on the fire-rated west wall
 
credited with preventing smoke and fire from entering the auxiliary building through the radwaste transfer tunnel, and other fire protection equipment with its supports is also in this
 
building.
 
The reinforced-concrete radwaste transfer tunnel connects the auxiliary, radwaste transfer, and radwaste solidification buildings and houses pipes for transferring liquid and slurry
 
wastes to the radwaste solidification building (which is abandoned in place), pipes for
 
related services, and a walkway for access. Though the radwaste transfer tunnel is
 
abandoned in place, a portion of it is within the scope of license renewal because of the fire
 
protection and electrical components for fire protection that pass through it. Conservatively, the tunnel from the auxiliary building to the entrance of the radwaste transfer building (concrete structure and fire protection supports) and south end of the tunnel (support for in-
 
scope electrical commodities only) are within the scope of license renewal. 
 
The radwaste structures perform functions that support fire protection.
 
LRA Table 2.4.10 identifies radwaste structures component types within the scope of
 
license renewal and subject to an AMR.
 
2.4.10.2  Staff Evaluation The staff reviewed LRA Section 2.4.10 using the evaluation methodology described in SER
 
Section 2.4 and the guidance in SRP-LR Section 2.4.
 
2-162 During its review, 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 SCs with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those SCs 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 SCs subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
 
2.4.10.3  Conclusion The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify
 
any SCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an
 
AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that
 
the applicant has adequately identified the radwaste structures SCs 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).
2.4.11  Auxiliary Feedwater Pumphouse Structures 2.4.11.1  Summary of Technical Information in the Application LRA Section 2.4.11 describes the AFW pumphouse structures, including the AFW pumps
 
and auxiliary support systems. The AFW pumphouse is a seismic Category I, safety-related structure.
 
The one-story, rectangular, reinforced concrete AFW pumphouses (one for each unit)
 
extend 22 feet above grade and are supported on basemat foundations four feet below
 
grade. Four interior walls separate the steam- and electric-driven pumps. Roof hatches
 
allow pump access. Separation walls between pumps and tanks guard against fire, flooding, and heat.
 
The AFW pumphouse structures contain safety-related components that are relied upon to
 
remain functional during and following DBEs. The failure of nonsafety-related SCs in the
 
AFW pumphouse structures could potentially prev ent the satisfactory accomplishment of a safety-related function. In addition, the AFW pumphouse structures perform functions that
 
support fire protection, ATWS, and SBO.
 
LRA Table 2.4.11 identifies AFW pumphouse structures component types within the scope
 
of license renewal and subject to an AMR.
 
2.4.11.2  Staff Evaluation The staff reviewed LRA Section 2.4.11 using the evaluation methodology described in SER
 
Section 2.4 and the guidance in SRP-LR Section 2.4.
 
During its review, 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 SCs with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those SCs, 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 SCs subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2-163  2.4.11.3  Conclusion The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify
 
any SCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an
 
AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that
 
the applicant has adequately identified the auxiliary feedwater pumphouse structures SCs
 
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).
2.4.12  Component Supports and Bulk Commodities 2.4.12.1  Summary of Technical Information in the Application LRA Section 2.4.12 describes the component supports and bulk commodities, which
 
include the following:
 
electrical raceway supports  HVAC duct supports  pipe supports  pipe whip restraints  raceway system  miscellaneous cranes and hoists
 
There are physical interfaces with the struct ure, system, or component supported and with the building structural element anchoring the support. A primary function of a support is to
 
provide anchorage for DBEs so the supported element can perform its intended function.
 
Items within the scope of license renewal include support members, welds, bolted
 
connections, anchorage (including base plate and grout) to the building structure, spring
 
hangers, guides, and building concrete at bolt/anchorage locations.
 
The major RCS component group includes the supports and support anchorage for ASME
 
Code class piping and components like pumps and heat exchangers. Components
 
evaluated in this group include support structural members (e.g., welds, bolting) that
 
comprise the interface between the structure and the mechanical component. The reactor
 
pressure vessel is supported by four seats under two hot leg and two cold leg nozzles
 
spaced approximately 90 º apart in the primary shield wall. The support seats carry the
 
vertical loads to the embedded steel welds under each support, while the embedded steel
 
welds in the primary shield wall carry the radial and tangential loads.
 
Four steel columns vertically support the steam generator. Bearing blocks and a steel beam
 
spanning the inside of the walls supply a lower lateral component support. The upper lateral
 
component support consists of a bearing ring located near the steam generator center of
 
gravity.
 
Each reactor coolant pump support consists of three structural steel columns and lateral tie
 
rods. A steel ring bearing plate bolted to the flange of the pressurizer support skirt supports
 
the pressurizer. This ring rests in turn on a structural steel frame attached to steel embeds 2-164 in the pressurizer compartment walls. Four stops projecting from embeds within the pressurizer compartment walls also support the pressurizer laterally at an upper level.
 
For supports and support anchorage for cable trays, conduits, HVAC ducts, tube track, and
 
instrument tubing components evaluated incl ude cable trays, conduits, HVAC ducts, and their structural support members, welds, bolting, etc., comprising the interface between the
 
structure and the mechanical, electrical, or instrument component.
 
For supports and support anchorage for enclosures of various types that contain and
 
support electrical equipment components evaluated include support structural members, welds, bolting, etc., comprising the interface between the structure and the electrical or
 
instrument component.
 
For supports and support anchorage for equipment not addressed in previous groups (e.g
., diesel generators, HVAC fans), components ev aluated include support structural members, welds, bolting, etc., comprising the interface between the structure and the component.
 
For structure and anchorage for miscellaneous support structures (e.g
., platforms, pipe whip restraints, and high energy line break barriers) not included in the other support
 
categories, component types include support structural members, welds, bolting, etc.,
comprising the support structure and its anchorage.
 
The component supports and bulk commodities contain safety-related components that are
 
relied upon to remain functional during and following DBEs. The failure of nonsafety-related
 
SCs in the component supports and bulk commodities could potentially prevent the
 
satisfactory accomplishment of a safety-related function. In addition, the component
 
supports and bulk commodities perform functions that support fire protection, SBO, and
 
EQ.
 
LRA Table 2.4.12 identifies component supports and bulk commodities within the scope of
 
license renewal and subject to an AMR.
 
2.4.12.2  Staff Evaluation The staff reviewed LRA Section 2.4.12 using the evaluation methodology described in SER
 
Section 2.4 and the guidance in SRP-LR Section 2.4.
 
During its review of the Section 2.4.12, the staff identified areas in which additional
 
information was necessary to complete the evaluation of the applicant's scoping and
 
screening results for component supports and bulk commodities. Therefore, the staff issued
 
its RAI by letter dated January 28, 2008, to determine whether the applicant properly
 
applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of
 
10 CFR 54.21(a)(1). The following discussion describes the staff's RAI related to LRA
 
Section 2.4.12 and the corresponding applicant response.
 
By letter dated January 28, 2008, RAI 2.4.12-1 was issued to request the applicant to
 
confirm whether the following items are considered in the scope of license renewal:
 
Grout pads for building structural column base plates 2-165  Vibration isolators  Floor and wall embedded plates/anchorages for RCS primary equipment  Fluid containment curbs/walls/dikes  Waterproofing membrane in general  Any other hoists or lifting devices (e.g. Reactor Vessel Head Lifting Device, Reactor Internals Lifting Device)  Relevant subcomponents of crane (bridge, trolley, rails/hardware, girders)  All cranes within in-scope structures By letter dated February 27, 2008, the applicant responded to RAI 2.4.12-1 and stated that
 
grout pads for building structural column base plates, floor and wall embedded
 
plates/anchorages for RCS primary equipment, fluid containment curbs/walls/dikes, waterproofing membrane, relevant crane sub-components (including bridge and trolley, crane rail, fasteners and rail hardware, girders, etc.), and all the cranes within in-scope
 
structures, unless otherwise stated as not in scope (e.g., Turbine Building Overhead crane)
 
are included in the scope of license renewal. The applicant also stated that lifting devices
 
are considered as tools and rigging components and are not in the scope of license
 
renewal. Furthermore, the applicant stated that vibration isolators are not applicable to
 
VEGP and in a subsequent telephone conference, as summarized in a letter from D. J.
 
Ashley (NRC) to Southern Nuclear Operating Company, Inc. dated March 26, 2008, the
 
applicant agreed to update LRA Section 2.4.12 to remove "vibration isolators" and to clarify
 
that VEGP does not utilize vibration isolators. The applicant, in the same telephone
 
conference, also agreed to update the LRA Table 2.4.12 and Table 3.5.2-12 to change
 
"roof membrane" to "waterproofing membrane." By letter dated March 20, 2008, the
 
applicant amended the LRA to include the above changes.
 
Considering the above, the staff finds the applicant's response to RAI 2.4.12-1 acceptable.
2.4.12.3  Conclusion The staff reviewed the LRA, UFSAR, and RAI response to determine whether the applicant
 
failed to identify any SCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the staff's review determined whether the applicant failed to identify
 
any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the component supports and
 
bulk commodities SCs 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 Controls Systems This section documents the staff's review of the applicant's scoping and screening results
 
for electrical and instrumentation and controls (I&C) systems. Specifically, this section discusses:
2-166    scoping - plant-wide electrical In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, long-lived SCs within the scope of license renewal and subject to an AMR. To verify that
 
the applicant properly implemented its methodology, the staff's review focused on the
 
implementation results. This focus allowed the staff to confirm that there were no omissions
 
of electrical and I&C system components that meet the scoping criteria and are subject to an AMR.
 
The staff's evaluation of the information in the LRA was the same for all electrical and I&C
 
systems. The objective was to determine whether the applicant has identified, in
 
accordance with 10 CFR 54.4, components and supporting structures for electrical and I&C
 
systems that appear to meet the license renew al scoping criteria. Similarly, the staff evaluated the applicant's screening results to verify that all passive, long-lived components
 
were subject to an AMR in accordance with 10 CFR 54.21(a)(1).
 
In its scoping evaluation, the staff reviewed the applicable LRA sections, focusing on
 
components that have not been identified as within the scope of license renewal. The staff
 
reviewed relevant licensing basis documents, including the UFSAR, for each electrical and
 
I&C system to determine whether the applicant has omitted from the scope of license
 
renewal components with intended functions delineated under 10 CFR 54.4(a). The staff
 
also reviewed the licensing basis documents to determine whether the LRA specified all
 
intended functions delineated under 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 applicant's 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
 
described in 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.
 
2.5.1  Summary of Technical Information in the Application LRA Section 2.5 describes the scoping - plant-wide electrical, the LRA designation
 
grouping electrical components into one system for scoping, screening, and AMR. This
 
designation is not a VEGP system, not found in the UFSAR, and strictly for convenience in presenting the results of electrical AMRs. LRA Section 2.1.3.3 describes the methodology
 
for identifying electrical and I&C components requiring an AMR. Identification of component
 
types of electrical and I&C systems, mechanica l systems, and civil structures within the scope of license renewal was generic. In limited cases (e.g., restoration of offsite power following SBO) component type identification and evaluation was not generic but limited to
 
only the system portion within the scope of license renewal. LRA Section 2.1.2.3.5
 
describes the evaluation boundaries of the offsite power system for SBO. 
 
During the scoping phase, the applicant determined that the following component types do
 
not meet 10 CFR 54.4(a) criteria:
 
2-167 Metal Enclosed Bus: A metal enclosed bus evaluation determined that VEGP has no metal enclosed bus that supports any license renewal intended function.
 
Uninsulated Ground Conductors: Nonsafety-related uninsulated ground conductors bond
 
metal raceways, building structural steel, and plant equipment to earth ground through an
 
installed grounding grid and protect personnel and equipment. In the event of a fault in an
 
electrical circuit or component, the ground conductors provide a direct path to ground for
 
fault currents to minimize equipment damage. They do not prevent faults and are not
 
required for equipment operation. Failure of a ground conductor cannot affect any safety
 
functions; therefore, uninsulated ground conductors perform no intended function that
 
meets 10 CFR 54.4(a) criteria and are not within the scope of license renewal.
 
The in-scope electrical and I&C component types associated with the in-scope electrical
 
and I&C systems contain safety-related components relied upon to remain functional during
 
and following DBEs. The failure of nonsafety-related SCs in the scoping - plant-wide
 
electrical potentially could prevent the sati sfactory accomplishment of a safety-related function. In addition, the electrical component types perform functions that support fire
 
protection, ATWS, SBO, and EQ.
 
LRA Table 2.5.1 identifies electrical component types within the scope of license renewal
 
and subject to an AMR: 
 
cable connections (metallic parts) not subject to 10 CFR 50.49 EQ requirements  conductor insulation for electrical cables and connections not subject to 10 CFR 50.49 EQ requirements  conductor insulation for inaccessible medium-voltage cables not subject to 10 CFR 50.49 EQ requirements  connector contacts for electrical connectors exposed to borated water leakage not subject to 10 CFR 50.49 EQ requirements  fuse holders (not parts of any larger assembly): insulation not subject to 10 CFR 50.49 EQ requirements  fuse holders (not parts of any larger assembly): metallic clamps  high-voltage insulators  switchyard bus and connections  transmission conductors and connections The intended functions of the electrical component types within the scope of license
 
renewal include:  insulation resistance to preclude shorts/grounds and unacceptable current leakage 2-168  electrical conductor insulation from ground and support from the mounting structure  electrical connections for delivery of voltage, current, or signals to specific electric circuit sections 2.5.2  Staff Evaluation The staff reviewed LRA Section 2.5 using the evaluation methodology described in the
 
guidance in SRP-LR Section 2.5, "Scoping and Screening Results: Electrical and
 
Instrumentation and Controls Systems."
 
During its review, the staff evaluated the system functions described in the LRA and
 
UFSAR to verify that the applicant has not omitted from the scope of license renewal any
 
components with intended functions delineated under 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant 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 in accordance with the requirements of 10 CFR 54.21(a)(1).
 
Interim Staff Guidance (ISG)-2, dated April 1, 2002, "Staff Guidance on Scoping of
 
Equipment Relied on to Meet the Requirements of the Station Blackout Rule
 
(10 CFR 50.63) for License Renewal (10 CFR 54.4(a)(3))," and later incorporated in SRP-
 
LR Section 2.5.2.1.1 states: 
 
"For purposes of the license renewal rule, the staff has determined that the plant system
 
portion of the offsite power system that is used to connect the plant to the offsite power
 
source should be included within the scope of the rule. This path typically includes
 
switchyard circuit breakers that connect to t he offsite system power transformers (startup transformers), the transformers themse lves, the intervening overhead or underground circuits between circuit breaker and transformer and transformer and onsite electrical
 
system, and the associated control circuits and structures. Ensuring that the appropriate
 
offsite power system long-lived passive stru ctures and components that are part of this circuit path are subject to an AMR will assure that the bases underlying the SBO
 
requirements are maintained over the period of extended license."
 
Section 2.1.2.3.5 of the LRA indicates that the preferred path of offsite power when
 
recovering from a Station Blackout is thr ough the Reserve Auxiliary Transformers (RATs) from the power grid via the 230 kV switchyard, and the 230 kV power circuit breakers
 
represent the scoping boundary. Figure 2.1.2.3.5-1, "Plant Vogtle License Renewal Offsite
 
Power for SBO," shows that 230 kV circuit breakers 161860 and 161960 for Offsite Power
 
Source 1 and 230 kV circuit breakers 161820 and 161920 for Offsite Power Source 2
 
represent the scoping boundary. Hence, the scoping boundary is in accordance with SRP-
 
LR Section 2.5.2.1.1, and the staff finds this acceptable. 
 
2.5.3  Conclusion The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify
 
any SCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's 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 2-169 concludes that the applicant has adequately identified the electrical component types within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
2.6  Conclusion for Scoping and Screening The staff reviewed the information in LRA Section 2, "Structures and Components Subject
 
to AMR." The staff concludes that the applicant's scoping and screening methodology is
 
consistent with 10 CFR 54.21(a)(1) requirements and the staff's position on the treatment of
 
safety-related and nonsafety-related SCs within the scope of license renewal and that the
 
SCs requiring an AMR is consistent with the requirements of 10 CFR 54.4 and
 
10 CFR 54.21(a)(1).
 
On the basis of its review, the staff concludes that the applicant has adequately identified
 
systems and components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
The staff concludes that the activities authorized by the renewed license will continue to be
 
conducted in accordance with the CLB, and any changes made to the CLB, in order to
 
comply with 10 CFR 54.29(a), with the Atomic Energy Act of 1954, as amended, and with
 
NRC regulations.
2-170 
 
THIS PAGE INTENTIONALLY LEFT BLANK.
 
3-1 SECTION 3 AGING MANAGEMENT REVIEW RESULTS
 
This section of the safety evaluation r eport (SER) evaluated aging management programs (AMPs) and aging management reviews (AMRs) for Vogtle Electric Generating Plant (VEGP) Units 1 and 2, by the staff of the United States (U.S.) Nuclear Regulatory
 
Commission (NRC) (the staff). In Appendix B of its license renewal application (LRA),
Southern Nuclear Operating Company, Inc. (SNC or the applicant) described the 38 AMPs
 
that it relies on to manage or monitor the aging of passive, long-lived structures and
 
components (SCs).
 
In LRA Section 3, the applicant provided the results of the AMRs for those SCs identified in
 
LRA Section 2 as within the scope of license renewal and subject to an AMR.
 
3.0  Applicant's Use of the Generic Aging Lessons Learned Report In preparing its LRA, the applicant credited NUREG-1801, Revision 1, "Generic Aging
 
Lessons Learned (GALL) Report," dated September 2005. The GALL Report contains the
 
staff's generic evaluation of the existing pl ant 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 Repor t 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 effici ency 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 has determined will adequately manage or
 
monitor aging during the period of extended operation.
 
The GALL Report identifies: (1) systems, structures, and components (SSCs), (2) SC
 
materials, (3) 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 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, Revision 1, "Standard Review Plan for Review of License Renewal 3-2 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 Part 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 audit of selected AMRs and
 
associated AMPs, during the weeks of October 15 - 19, 2007 and December 10 - 14, 2007.
 
The audits and reviews are designed for maximum efficiency of the staff's LRA review. The
 
applicant can respond to questions, the staff can readily evaluate the applicant's
 
responses, the need for formal correspondence between the staff and the applicant is
 
reduced, and the result is an improvement in review efficiency.
 
3.0.1  Format of the License Renewal Application The applicant submitted an application that follows the standard LRA format agreed to by
 
the staff and the Nuclear Energy Institute (NEI) by letter dated April 7, 2003 (Agencywide
 
Documents Access and Management System (A DAMS) No. 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 VEGP application is essentially the same. The
 
intent of the revised format of the VEGP LRA was to modify the tables in LRA Section 3 to
 
provide additional information that would assist in the staff's 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.
 
3.0.1.1  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:
3-3  further evaluation recommended - information or reference to where that information is located  The name of a plant-specific program  exceptions to GALL Report assumptions  discussion of how the line is consistent with the corresponding line item in the GALL Report when the consistency may not be obvious  discussion of how the item is different from the corresponding line item in the GALL Report (e.g., when an exception is taken to a GALL Report AMP)
The format of each Table 1 allows the staff to align a specific row in the table with the
 
corresponding GALL Report table row 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 system, engineered safety features, auxiliary systems, etc.). For example, the engineered safety features group has tables specific to the containment sp ray system, containment isolation system, and emergency core cooling system. Each Table 2 consists of nine columns:
 
Component Type - The first column lists LRA Section 2 component types subject to an AMR in alphabetical order. Intended Function - The second column identifies the license renewal intended functions for the listed component types. Definitions of intended
 
functions are in LRA Table 2.1.3. Material - The third column lists the particular construction material(s) for the component type. 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. Aging Effect Requiring Management - The fifth column lists aging effects requiring management (AERMs). As part of the AMR process, the applicant
 
determined any AERMs for each combination of material and environment. Aging Management Programs - The sixth column lists the AMPs that the applicant uses to manage the identified aging effects. GALL Report Vol. 2 Item - The seventh column lists the GALL Report 3-4 item(s) identified in the LRA as similar to the AMR results. The applicant compared each combination of component type, material, environment, AERM, and AMP in LRA Table 2  with the GALL Report items. If there are no
 
corresponding items in the GALL Report, the applicant leaves the column
 
blank in order to identify the AMR results in the LRA tables corresponding to
 
the items in the GALL Report tables. 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 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. 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
 
consistency.    (2) For items that the applicant stated were consistent with the GALL Report with exceptions, enhancements, or both, the staff conducted either an audit
 
or a technical review of the item to determine consistency. In addition, the
 
staff conducted either an audit or a technical review of the applicant's
 
technical justifications for the exceptions or 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.
3-5  Staff audits and technical reviews of the applicant's AMPs and AMRs determine whether
 
the aging effects on SCs can be adequately managed to maintain their intended function(s)
 
consistent with the plant's current licensing basis (CLB) for the period of extended
 
operation, as required by 10 CFR Part 54.
 
3.0.2.1  Review of 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 under all CLB design
 
conditions during the period of extended operation.    (7) Corrective Actions - Corrective actions, including root cause determination and prevention of recurrence, should be timely.    (8) Confirmation Process - Confirmation process should ensure that preventive actions are adequate and that appropriate corrective actions have been
 
completed and are effective.    (9) Administrative Controls - Administrative controls should provide for a formal review and approval process.
3-6    (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.
Details of the staff's 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," "confir mation 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.
 
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 number s in column seven of the LRA, "NUREG-1801 Vol. 2 Item," correlate to an AMR combination as identified in the GALL Report. The
 
staff also conducted 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 applicant's programs and
 
activities for managing aging effects for the period of extended operation, as required by
 
10 CFR 54.21(d).
 
3.0.2.4  Documentation and Documents Reviewed In its review, the staff used the LRA, LRA supplements, the SRP-LR, and the GALL Report.
 
During the audit, the staff also examined the applicant's justifications to verify that the
 
applicant's activities and programs will adequately manage the effects of aging on SCs.
 
The staff also conducted detailed discussions and interviews with the applicant's license
 
renewal project personnel and others with technical expertise relevant to aging
 
management.
 
3.0.3  Aging Management Programs SER Table 3.0.3-1 presents the AMPs credited by the applicant and described in LRA 3-7 Appendix B. The table also indicates the SSCs that credit the AMPs and the GALL AMP with which the applicant claimed consistency and shows the section of this SER in which
 
the staff's evaluation of the program is documented.
 
Table 3.0.3-1  VEGP Aging Management Programs AMP (LRA Section)
New or Existing AMP GALL Report Comparison GALL Report AMPs LRA Systems or Structures That Credit the AMP Staff's SER Section ACCW System Carbon Steel
 
Components
 
Program (B.3.1) New Plant-specific  reactor vessel, reactor vessel internals, and reactor coolant system / auxiliary systems  3.0.3.3.1 Bolting Integrity Program (B.3.2) New Plant-specific  reactor vessel, reactor vessel internals, and reactor coolant system / engineered safety features systems /
auxiliary systems / steam and power conversion systems  3.0.3.3.2 Boric Acid Corrosion Control Program (B.3.3) Existing Consistent with enhancements XI.M10  reactor vessel, reactor vessel internals, and reactor coolant system / engineered safety features systems /
auxiliary systems / steam and power conversion systems / containments, structures, and component
 
supports / electrical and
 
instrumentation and controls
 
components 3.0.3.2.1 Buried Piping and Tanks Inspection
 
Program (B.3.4) New Consistent with exceptions XI.M34  auxiliary systems / steam and power conversion systems  3.0.3.2.2 CASS RCS Fitting Evaluation Program (B.3.5) New Consistent with exception XI.M12  reactor vessel, reactor vessel internals, and reactor coolant system 3.0.3.2.3 Closed Cooling Water Program (B.3.6) Existing Consistent with exceptions and
 
enhancements XI.M21  reactor vessel, reactor vessel internals, and reactor coolant system / engineered safety features systems /
auxiliary systems 3.0.3.2.4 Diesel Fuel Oil Program (B.3.7) Existing Plant-specific  auxiliary systems  3.0.3.3.3 3-8  AMP (LRA Section)
New or Existing AMP GALL Report Comparison GALL Report AMPs LRA Systems or Structures That Credit the AMP Staff's SER Section External Surfaces Monitoring Program (B.3.8) New Consistent with exceptions XI.M36  reactor vessel, reactor vessel internals, and reactor coolant system / engineered safety features systems /
auxiliary systems / steam and power conversion systems  3.0.3.2.5 Fire Protection Program (B.3.9) Existing Consistent with exceptions and
 
enhancements XI.M26 XI.M27 auxiliary systems /
containments, structures, and component supports 3.0.3.2.6 Flow-Accelerated Corrosion Program (B.3.10) Existing Consistent with exceptions XI.M17  reactor vessel, reactor vessel internals, and reactor coolant system / auxiliary systems  3.0.3.2.7 Flux Thimble Tube Inspection Program (B.3.11) Existing Consistent with enhancement XI.M37  reactor vessel, reactor vessel internals, and reactor coolant system 3.0.3.2.8 Generic Letter 89-13 Program (B.3.12) Existing Consistent with exception and
 
enhancements XI.M20  engineered safety features systems / auxiliary systems 3.0.3.2.9 Inservice Inspection Program (B.3.13) Existing Plant-specific  reactor vessel, reactor vessel internals, and reactor coolant system / auxiliary systems / containments, structures, and component
 
supports 3.0.3.3.4 Nickel Alloy Management
 
Program for Non-
 
Reactor Vessel
 
Closure Head
 
Penetration Locations (B.3.14) New Plant-specific  reactor vessel, reactor vessel internals, and reactor coolant system 3.0.3.3.5 Nickel Alloy Management
 
Program for Reactor
 
Vessel Closure Head
 
Penetrations (B.3.15) Existing Consistent XI.M11A reactor vessel, reactor vessel internals, and reactor coolant system 3.0.3.1.1 Oil Analysis Program (B.3.16) Existing Consistent with exception and
 
enhancements XI.M39  reactor vessel, reactor vessel internals, and reactor coolant system / engineered safety features systems /
auxiliary systems / steam and power conversion systems  3.0.3.2.10 3-9  AMP (LRA Section)
New or Existing AMP GALL Report Comparison GALL Report AMPs LRA Systems or Structures That Credit the AMP Staff's SER Section One-Time Inspection Program (B.3.17) New Consistent XI.M32 reactor vessel, reactor vessel internals, and reactor coolant system / engineered safety features systems /
auxiliary systems / steam and power conversion systems  3.0.3.1.2 One-Time Inspection Program for ASME
 
Class 1 Small Bore
 
Piping (B.3.18) New Consistent with exceptions XI.M35  reactor vessel, reactor vessel internals, and reactor coolant system 3.0.3.2.11 One-Time Inspection Program for Selective
 
Leaching (B.3.19) New Consistent with exception XI.M33  engineered safety features systems / auxiliary systems 3.0.3.2.12 Overhead and Refueling Crane
 
Inspection Program (B.3.20) Existing Consistent XI.M23 auxiliary systems  3.0.3.1.3 Periodic Surveillance and Preventive
 
Maintenance
 
Activities (B.3.21) Existing Plant-specific  auxiliary systems / steam and power conversion systems / containments, structures, and component
 
supports 3.0.3.3.6 Piping and Duct Internal Inspection
 
Program (B.3.22) New Consistent with exceptions XI.M38  engineered safety features systems / auxiliary systems
/ steam and power conversion systems 3.0.3.2.13 Reactor Vessel Closure Head Stud
 
Program (B.3.23) Existing Consistent with exceptions XI.M3  reactor vessel, reactor vessel internals, and reactor coolant system 3.0.3.2.14 Reactor Vessel Internals Program (B.3.24) New Plant-specific  reactor vessel, reactor vessel internals, and reactor coolant system 3.0.3.3.7 Reactor Vessel Surveillance Program (B.3.25) Existing Consistent with exceptions and
 
enhancements XI.M31  reactor vessel, reactor vessel internals, and reactor coolant system 3.0.3.2.15 Steam Generator Tubing Integrity
 
Program (B.3.26) Existing Consistent with exception XI.M19  reactor vessel, reactor vessel internals, and reactor coolant system 3.0.3.2.16 Steam Generator Program for Upper
 
Internals (B.3.27) Existing Plant-specific  reactor vessel, reactor vessel internals, and reactor coolant system 3.0.3.3.8 3-10  AMP (LRA Section)
New or Existing AMP GALL Report Comparison GALL Report AMPs LRA Systems or Structures That Credit the AMP Staff's SER Section Water Chemistry Control Program (B.3.28) Existing Consistent XI.M2 reactor vessel, reactor vessel internals, and reactor coolant system / engineered safety features systems /
auxiliary systems / steam and power conversion systems / containments, structures, and component
 
supports 3.0.3.1.4 10 CFR 50 Appendix J Program (B.3.29) Existing Consistent XI.S4 containments, structures, and component supports 3.0.3.1.5 Inservice Inspection Program - IWE (B.3.30) Existing Plant-specific  c ontainments, structures, and component supports 3.0.3.3.9 Inservice Inspection Program - IWL (B.3.31) Existing Plant-specific  c ontainments, structures, and component supports 3.0.3.3.10 Structural Monitoring Program (B.3.32) Existing Consistent with enhancements XI.S6  containments, structures, and component supports 3.0.3.2.17 Structural Monitoring Program - Masonry
 
Walls (B.3.33) Existing Consistent with enhancement XI.S5  containments, structures, and component supports 3.0.3.2.18 Non-EQ Cables and Connections Program (B.3.34) New Consistent XI.E1 electrical and instrumentation and controls
 
components 3.0.3.1.6 Non-EQ Inaccessible Medium-Voltage
 
Cables Program (B.3.35) New Consistent XI.E3 electrical and instrumentation and controls
 
components 3.0.3.1.7 Non-EQ Cable Connections One-Time Inspection
 
Program (B.3.36) New Plant-specific  electrical and instrumentation and controls
 
components 3.0.3.3.11 Environmental Qualification Program (B.3.37) Existing Consistent X.E1 electrical and instrumentation and controls
 
components 3.0.3.1.8 Fatigue Monitoring Program (B.3.38) Existing Consistent with enhancements X.M1  reactor vessel, reactor vessel internals, and reactor coolant system 3.0.3.2.19
 
3-11 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:
Nickel Alloy Management Program for Reactor Vessel Closure Head Penetrations  One-Time Inspection Program  Overhead and Refueling Crane Inspection Program  Water Chemistry Control Program  10 CFR 50 Appendix J Program  Non-EQ Cables and Connections Program  Non-EQ Inaccessible Medium-Voltage Cables Program  Environmental Qualification Program 3.0.3.1.1  Nickel Alloy Management Program for Reactor Vessel Closure Head Penetrations 
 
Summary of Technical Information in the Application LRA Section B.3.15 describes the existing Nickel Alloy Management Program for Reactor Vessel Closure Head Penetrations as consistent with GALL AMP XI.M11A, "Nickel-Alloy Penetration Nozzles Welded to the
 
Upper Reactor Vessel Closure Heads of Pressurized Water Reactors." 
 
The applicant stated that development of the existing Nickel Alloy Management Program for Reactor Vessel Closure Head Penetrations program addressed industry concerns about
 
potential primary water stress corrosion cracking (PWSCC) in nickel alloy components
 
exposed to reactor coolant. The program is based upon NRC First Revised Order EA 009, which established requirements for susceptibility ranking and inspections.
 
Susceptibility ranking based on calculated effective degradation years and the results of
 
previous inspection findings determines inspection frequencies.
 
The applicant also stated that detection of cracking is by a combination of bare metal visual
 
examinations of 100 percent of each reactor vessel head surface, including 360 º around
 
each reactor vessel head penetration nozzle, and nonvisual techniques requiring either 
 
(1) ultrasonic testing of each reactor vessel head penetration nozzle (i.e., nozzle base metal) from two inches above the J-groove weld to the bottom of the nozzle and a
 
assessment for leakage into the interference fit zone or (2) eddy-current or dye-penetrant
 
testing of the wetted surface of each J-groove weld and reactor vessel head penetration
 
base metal to at least two inches above the J-groove weld. Additionally, general visual
 
inspection at each refueling outage detects potential borated water leaks from pressure-
 
retaining components above the reactor vessel head.
 
3-12 The applicant further stated that the current program includes one relaxation and one alternative from First Revised Order EA-03-009 inspection requirements. These deviations
 
from the requirements are not exceptions to the GALL Report Revision 1, Section XI.M11A program because they were approved by the staff (consistent with Section IV.F of the
 
order).
: 1) Order EA-03-009, Section IV.C(5)(a), specifies for bare metal visual examination coverage of the reactor vessel head surface. Full examination
 
coverage is not possible without removal of reflective metal insulation. A
 
minimum additional dose of 10 rem is necessary for examination of the less
 
than one percent of the vessel head surface obscured by the insulation in an
 
area where leakage is not likely to initiate. The applicant requested from the
 
staff relaxation of inspection for the small surface of the reactor vessel head
 
obscured by insulation. A September 2005 Safety Evaluation granted
 
relaxation.
: 2) Order EA-03-009, Section IV.C(5)(b), specifies examination volume for reactor vessel head penetration nozzle base material. Full examination
 
volume coverage by ultrasonic testing is not possible due to geometry.
 
Specifically, the bottom ends of the nozzles are threaded, internally tapered, or both, making ultrasonic inspection in accordance with First Revised Order
 
EA-03-009 a hardship due to the need for an increased radiation dose to
 
implement surface examination options. The applicant proposed to the staff
 
ultrasonic testing of nozzle ends to the maximum extent possible. The staff
 
in an August 2006 Safety Evaluation approved this alternate approach.
 
The program will implement commitments for reactor vessel closure head penetrations of
 
nickel alloys from (1) NRC orders, bulletins, and generic letters and (2) staff-accepted
 
industry guidelines.
 
Staff Evaluation During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report.
 
The staff's recommended program for reactor vessel closure head (RVCH) and its penetration nozzles is GALL AMP XI.M11-A, Nickel-Alloy Penetration Nozzles Welded to
 
the Upper Reactor Vessel Closure Head of Pressurized Water Reactor Program. The
 
program elements of this GALL program are based on compliance with the staff's
 
augmented inspection requirements for pressurized water reactors (PWR) reactor vessel
 
closure heads (RVCH) and their penetration nozzles. These augmented inspection
 
requirements were originally defined in NRC Order EA-03-009 and amended in the First
 
Revised Order EA-03-009 (henceforth these Orders will be referred to collectively as the
 
Order). 
 
The Order requires U.S. holders of operating licenses for PWRs to perform an integrated
 
plant susceptibility model calculation of their upper RVCHs and their penetration nozzles
 
and to establish the ranking in terms of an effective degradation year (EDY) parameter, as follows:
3-13  High susceptibility
: either plants with an EDY greater than 12 EDY or plants with a RVCH that has experience cracking in a penetration nozzle or J-
 
groove weld due to PWSCC  Moderate susceptibility
: plants with a calculated value of EDY less than or equal to 12 and greater than or equal to 8 AND no previous inspection
 
findings requiring classification as High  Low susceptibility
: plants with a calculated value of EDY less than 8 AND no previous inspection findings requiring classification as High  Replaced Category
: plants with a replaced RPV head AND with a calculated value of EDY less than 8 AND no previous inspection findings requiring
 
classification as High The Order requires that licensees to perform a combination of bare metal visual (BMV)
 
examinations on their upper RVCHs and non-visual examinations (i.e., either penetrant test
 
[PT] or magnetic particle test [MT] surface exam ination techniques or ultrasonic test [UT] or eddy current test [ET] volumetric examination techniques) on their upper RVCH penetration
 
nozzles. Based on the susceptibility calculation result, the Order requires these licensees
 
perform the augmented inspections based on the following frequency requirements:
 
High susceptibility
: the BMV examination of the upper RVCH and the non-visual examinations of the upper RVCH penetration nozzles are required to
 
be performed once every refueling outage. Moderate susceptibility
: either a BMV examination of the upper RVCH or the non-visual examinations of the upper RVCH penetration nozzles is required
 
to be performed once every refueling outage, with added requirement that
 
the BMV examination of the upper RVCH and the non-visual examinations of
 
the RVCH penetration nozzles are required to be performed at least once of
 
the course of every 2 refueling outages. Low susceptibility
: the BMV examination of the upper RVCH is to be performed once every 3 rd refueling outage or every five years, which ever comes first. The non-visual examinations of the upper RVCH penetration
 
nozzles are to be performed once every 4 th refueling outage or every seven years, whichever comes first. Replaced Category
: the inspection frequency requirements are similar to those for low susceptibility heads with the exception of minor variations.
The Order also requires a licensee to re-rank the susceptibility of its RVCH (including the
 
penetration nozzle base metal and partial penetration J-groove weld materials) into the
 
High susceptibility category if any of the augmented inspections result in the detection of
 
degradation of the RVCH or its penetration nozzles and to follow the implementation
 
schedule for High susceptibility RVCHs.
The staff reviewed the applicant's license renewal basis evaluation document for the
 
applicant's Nickel Alloy Management Program for Reactor Vessel Closure Head 3-14 Penetrations, as well as the applicant's responses to the Order and applicable SNC-corporate and VEGP-specific procedures that are relevant to the applicant's augmented
 
inspection program for the RVCH and its penetration nozzles. The staff concludes that the
 
applicant's Nickel Alloy Management Program for Reactor Vessel Closure Head
 
Penetrations is an augmented condition monitoring program that is designed to comply with
 
the augmented inspection requirements in the NRC's First Revised Order EA-03-009 for
 
RVCH and its penetration nozzles and to conform with the recommended program elements in GALL AMP XI.M11-A. 
 
The staff concludes that the scope of the Nickel Alloy Management Program for Reactor
 
Vessel Closure Head Penetrations includes the upper RVCHs and their penetration
 
nozzles. The staff concludes that these nozzles include both the control rod drive
 
mechanism (CRDM) penetration nozzles (78 in total), RVCH instrumentation nozzles, and
 
the upper RVCH vent nozzle. This is consistent with "scope of program" program element in GALL AMP XI.M11-A, and is acceptable.
 
The staff also determined that the scope of the applicant's program includes the applicant's
 
response to Order EA-03-009 dated March 3, 2003, as amended in the applicant's letter of
 
March 8, 2004. These documents provide the applicant consent to comply with the
 
requirements of the Order and to establish an augmented inspection program for the upper
 
RVCHs and their penetration nozzles. 
 
The staff concludes that the program includes both BMV examinations of the RVCH
 
surfaces to look for signs of reactor coolant leakage and boric acid-induced wastage of the
 
RVCHs and for indications of cracking in the penetration nozzles or their partial penetration
 
J-groove welds, which is usually initiated as result of PWSCC. This is in compliance with
 
the Order and is consistent with the "paramet ers monitored" program element in GALL AMP XI.M11-A and is acceptable. 
 
The staff concludes that the applicant's response letter of March 8, 2004, indicates that the
 
applicant will perform BMV examinations of the outside surface of the RVCH and UT of the
 
RVCH penetrations nozzles extending from 2 inches above the J-groove penetration down to the majority of the length below to J-groove weld. The staff concludes that the applicant
 
requested minor relaxations of the 100 percent coverage requirements for the BMV
 
examinations in the response letter of March 8, 2004, and for the UT examinations
 
requirements in a letter dated May 18, 2006. The NRC granted the relaxation on the BMV
 
requirements in a safety evaluation dated September 13, 2005 and the relaxation on the UT
 
requirements in a safety evaluation dated August 30, 2006. These relaxations are in
 
accordance with the relaxation request provisions of Order EA-03-009 and are consistent with the guidance in GALL AMP XI.M11-A.
 
The staff concludes that the applicant cu rrently implements its augmented BMV and UT examinations in accordance with the inspection frequency for Low susceptibility RVCHs, as
 
based on the EDY information submitted in the SNC letters of June 6, 2005 for Unit 1 and
 
June 28, 2005 for Unit 2, and on the relaxed augmented inspection criteria that were
 
approved in the NRC's safety evaluations of September 13, 2005, and August 30, 2006. 
 
This is in compliance with the requirements of the Order and is consistent with the
 
"detection of aging effects" and "monitoring and trending" program elements of GALL AMP XI.M11-A, and is acceptable.
 
3-15 The staff concludes that the applicant's uses the acceptance criteria in the NRC letter of April 11, 2003 as the basis for evaluating any indications of degradation that may result
 
from its augmented examinations. This is consis tent with the "acceptance criteria" program element in GALL AMP XI.M11-A and is acceptable.
 
Based on this assessment, the staff concludes that AMP B.3.15, Nickel Alloy Management
 
Program for Reactor Vessel Closure Head Penetrations, is consistent with the program elements in GALL AMP XI.M11-A without exception and is acceptable.
 
Operating Experience LRA Section B.3.15 states that to date the VEGP Units 1 and 2 reactor vessel heads remain in the "Low" susceptibility category requiring bare metal visual
 
examination every third refueling outage or ev ery five years (whichever comes first) and nonvisual examination every fourth refueli ng outage or every seven years (whichever comes first). 
 
The LRA Section B.3.15 provides the following additional information relative to this
 
operating experience:
 
In the most recent inspection of the Unit 1 reactor vessel head in the fall of 2006
 
nonvisual examination found no degradation in any of 78 control rod drive mechanism penetrations or the reactor vessel head vent penetration. General
 
visual inspection at the same time detected boron residue on one of four conoseal
 
assemblies. Cleaning and reinspection of the areas below the conoseals found no
 
degradation. In the most recent inspection of the Unit 2 reactor vessel head in the
 
spring of 2007 nonvisual examination found no degradation in any of 78 control
 
rod drive mechanism penetrations or in the reactor vessel head vent penetration.
 
General visual inspection at the same time detected no indications of leakage.
 
Implementation and maintenance of the Nickel Alloy Management Program are in
 
accordance with general requirements for engineering programs. Periodic program
 
reviews ensure compliance with regulatory, process, and procedural requirements. 
 
The applicant's license renewal basis evaluation document of relevant industry operating
 
experience indicates that the generic operating experience on PWSCC of upper RVCH
 
penetration nozzles, as discussed in NRC Bulletins 2001-01 and 2002-01 and in the Order, and on loss of material of upper RVCHs induced by reactor coolant leakage and boric acid
 
induced corrosion, as discussed in the Order, is applicable to the RVCHs at VEGP and
 
their penetration nozzles. The applicant indicated that the Nickel Alloy Management
 
Program for Reactor Vessel Closure Head Penetrations is implemented to monitor for the
 
potential to occur in the RVCHs at VEGP or their penetration nozzles (including the partial
 
penetration J-groove welds).
 
The staff noted that the SNC submittals of June 6, 2005 for Unit 1 and June 28, 2005 for
 
Unit 2 indicate that applicant has been implementing the required augmented inspection for
 
Low susceptibility RVCHs based on an EDY of 3.01 for the Unit 1 RVCH and an EDY of
 
2.67 for Unit 2 RVCH. The staff also noted that the submittals of June 6, 2005 for Unit 1
 
and June 28, 2005 also document the results of the applicant's augmented inspections that
 
were performed during the Spring 2005 refueling outage (RFO #1R12) for Unit 1 and during
 
the Spring 2004 refueling outage (RFO #2R10) for Unit 2 and indicate the inspections
 
performed during these outages did not reveal the presence of any indications in the upper
 
RVCHs or their penetration nozzles. Based on this assessment, the staff concludes that the 3-16 applicant has factored the relevant operating experience for the RVCHs of U.S. PWRs into the Nickel Alloy Management Program for Reactor Vessel Closure Head Penetrations and
 
has been implementing this augmented inspection program in accordance with the
 
requirements of the Order.
 
Based on this review, the staff confirmed that the "operating experience" program element
 
satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable.
 
UFSAR Supplement In LRA Section A.2.15, the applicant provided the UFSAR supplement for the Nickel Alloy Management Program for Reactor Vessel Closure Head Penetrations.
 
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). The staff verified that the LRA includes Commitment No. 13 to implement
 
the Nickel Alloy Management Program for Reactor Vessel Closure Head Penetrations in
 
accordance with the program elements for AMP B.3.15 and the UFSAR supplement criteria
 
for this AMP, as defined in LRA Section A.2.1.15. This commitment was submitted in the
 
applicant's letter dated June 27, 2007 and requires the applicant to implement this program
 
in accordance of the following bases: (1) applicable NRC Orders, Bulletins, and Generic
 
Letters, and (2) NRC-approved industry guidance. 
 
The Order, as discussed in the evaluation section for this AMP, provides the current
 
licensing basis (CLB) for augmented examinations of PWR upper RVCHs and their
 
penetration nozzles. The NRC staff incorporated these requirements into the program elements for GALL AMP XI.M11-A when it issued the AMP as part of GALL, Revision 1 (September 2005). Therefore, the provisions of Commitment No. 13 are consistent with the
 
applicant's basis to perform its augmented inspection of the RVCHs and their penetration
 
nozzles in accordance with the requirements of the Order and with the guidelines of GALL AMP XI.M11-A. Based on this assessment, the staff concludes that implementation of
 
Commitment No. 13 will provide continued assurance that the applicant will implement the
 
requirements of the Order during the period of extended operation, or until that time when
 
new augmented requirements for RVCHs and their penetration nozzles can be developed and incorporated into a version of the ASME Code Section XI that is endorsed by reference
 
in the requirements of 10 CFR 50.55a, "Codes and Standards."
 
Conclusion On the basis of its audit and review of the applicant's Nickel Alloy Management Program for Reactor Vessel Closure Head Penetrations, 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 determined that it provides an adequate summary description of the program, as
 
required by 10 CFR 54.21(d).
 
3.0.3.1.2  One-Time Inspection Program 
 
Summary of Technical Information in the Application LRA Section B.3.17 describes the new One-Time Inspection Program as consistent with GALL AMP XI.M32, "One-Time
 
Inspection." 
 
The applicant stated that the One-Time Inspection Program proves objectively that an 3-17 aging effect has not occurred or occurs so slowly as not to affect the component or structure intended function during the period of extended operation and therefore requires
 
no additional aging management. The new One-Time Inspection Program will verify the effectiveness of AMPs or confirm the insignificance of potential aging effects by one-time
 
inspections of plant piping and components where (a) an aging effect probably will not
 
occur but there is insufficient data to rule it out with reasonable confidence, (b) an aging
 
effect probably will progress very slowly in a specified environment but conditions may be more adverse than those specified, or (c) the aging effect has a long incubation period
 
relative to the operating life of the plant. 
 
The inspections will be within the ten years preceding the period of extended operation.
 
The applicant further stated that the One-Time Inspection Program will include (a)
 
determination of sample size based on assessment of materials of fabrication, environment, plausible aging effects, and operating experience, (b) selection of system or component
 
inspection locations based on the aging effect, (c) determination of examination techniques, including acceptance criteria, effective in detecting and quantifying the aging effect, and (d)
 
evaluation of the need for further examinat ions to monitor aging progression, expand sample size, or take other corrective actions as appropriate if age-related degradation could
 
affect an intended function before the end of the period of extended operation. The One-
 
Time Inspection Program for Selective Leaching addresses inspections of components
 
potentially susceptible to such degradation. The One-Time Inspection Program for ASME
 
Class 1 Small Bore Piping addresses inspections of American Society of Mechanical
 
Engineers (ASME) Code Class 1 piping less than or equal to nominal pipe size (NPS) 4.
 
Staff Evaluation During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report.
 
The staff interviewed the applicant's technical personnel and reviewed the One-Time
 
Inspection Program basis documents. Specifica lly, the staff reviewed the program elements and corresponding basis documents for consistency with GALL AMP XI.M32. The staff
 
concludes that the program element descriptions in the One-Time Inspection Program
 
conformed to the corresponding program elements in GALL AMP XI.M32, "One-Time Inspection." The staff finds the applicant's One-Time Inspection Program consistent with the recommended GALL AMP XI.M32 and acceptable.
 
In Enclosure 2 of the letter dated, August 11, 2008 the applicant provided Commitment No.
 
15 to implement the One-Time Inspection Program as described in LRA Section B.3.17 and
 
to perform the inspections under this program within a ten year window prior to the period
 
of extended operation. The staff finds this commitment acceptable, because the resulting
 
program will address the recommendations of the GALL Report and be consistent with GALL AMP XI.M32.
 
On January 8, 2009 the staff had a teleconference with the licensee regarding the neutron-
 
absorbing material reduction in neutron-absorbing capacity (Section 3.3.2.2.6). This
 
resulted in an amendment to the LRA, dated January 20, 2009 which includes a change in
 
Commitment 37 to include a One-Time Inspection Program on Boral and the addition of the
 
One-Time Inspection Program on Boral to the One-Time Inspection Program Section. This
 
Commitment and addition to the One-Time Inspection Program states that "The inspections
 
will include baseline and follow-up inspections of the effectiveness of the BoralŽ neutron-
 
absorbing panels credited in the criticality analysis for the Unit 1 spent fuel storage racks to 3-18 provide reasonable assurance that the panels will continue to perform their reactivity control function during the period of extended operation. The baseline inspection will be performed
 
within a window of ten years immediately preceding the period of extended operation. The
 
follow-up inspection will be performed at a date to be determined based on the results of
 
the baseline inspection and relevant industry guidance, not to exceed ten years after the
 
baseline inspection." The staff has reviewed this new Commitment to a One-Time
 
Inspection Program on the Boral and the amendment to the One-Time Inspection Program
 
in LRA B.3.17. LRA B.3.17 states that, "The One-Time Inspection Program will include: (a)
 
determination of sample size based on an assessment of the 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 identifying and quantifying the aging effect for which the component is
 
examined, and (d) evaluation of the need for follow-up examinations to monitor the progression of aging, expansion of the sample size, or other corrective actions as
 
appropriate if age-related degradation is found that could jeopardize an intended function
 
before the end of the period of extended operation."  The staff has reviewed the
 
amendment and has found the Commitment to a One-Time Inspection Program on Boral to
 
be acceptable, since the One-Time Inspection Program would require the inspection plan to
 
include the sample size and location of the samples, the examination technique, detection
 
of aging effects, acceptance criteria, evaluation of the need for follow-up examinations and
 
corrective actions. This inspection program provides reasonable assurance that during the
 
period of extended operation that the licensee will be able to adequately manage the
 
reduction of neutron-absorbing capacity.
 
Operating Experience LRA Section B.3.17 states that there is no programmatic operating experience specifically applicable to the new one-time inspections but that selection of the
 
initial component sample sets will consider plant-specific and industry operating
 
experience.
 
During the on-site audit, the staff confirmed that VEGP has ongoing programs to monitor
 
industry and site operating experience. These programs include mechanisms to update or
 
modify plant procedures or practices to incorporate lessons learned.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section A.2.17, the applicant provided the UFSAR supplement for the One-Time Inspection Program. The staff reviewed the applicant's license renewal
 
commitment letter (NL-07-1261, dated June 27, 2007) and confirmed that this program is
 
identified as Commitment No. 15 to be implemented prior to the period of extended
 
operation. The staff reviewed LRA Section A.2.17 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 One-Time Inspection Program, the staff finds that, upon the implementation of Commitment No. 15, all program
 
elements are consistent with the GALL Report. The staff concludes that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB for the period of extended operation, 3-19 as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and determined that it provides an adequate summary description of the program, as
 
required by 10 CFR 54.21(d).
 
3.0.3.1.3  Overhead and Refueling Crane Inspection Program 
 
Summary of Technical Information in the Application LRA Section B.3.20 describes the existing Overhead and Refueling Crane Inspection Program as consistent with GALL AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling)
 
Handling Systems." 
 
The applicant stated that the Overhead and Refueling Crane Inspection Program manages
 
the effects of general corrosion and wear of crane bridge and trolley structural girders and
 
beams and crane rails and support girders within the scope of license renewal. The
 
Overhead and Refueling Crane Inspection Program monitors conditions in the following
 
nuclear safety
-related and quality-related material handling systems: refueling machine, fuel handling machine bridge crane, spent fuel cask bridge crane, and containment building (reactor) polar crane. The Overhead and Refueling Crane Inspection Program is based on
 
American National Standards Institute (ANSI) B30.2 guidance for overhead cranes.
 
NUREG-0612 provides the basis for inspection of the cranes.
 
Staff Evaluation During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report.
 
During the audit and review, the staff noted that LRA Section B.3.20, Overhead and
 
Refueling Crane Inspection Program, states that the program is an existing program that is consistent with GALL AMP XI.M23. The applicant also states in the VEGP basis document for AMP B.3.20 that the program is consistent with GALL AMP XI.M23. The program basis
 
document, under the program element "detection of aging effects", states that for the
 
cranes within the scope of license renewal, crane rails and crane structural components are
 
routinely visually inspected for excessive wear, corrosion, or misalignment. However, a
 
review of the existing program implementati on (inspection) procedures for the polar cranes, refueling machines (bridge and trolley system) and fuel handling machine bridge cranes
 
shows that the polar cranes are not inspected for corrosion and crane rail wear, the
 
refueling machines are not inspected for corrosion and the fuel handling bridge cranes
 
structural components are not shown as being inspected. The staff asked the applicant to
 
explain how the existing VEGP AMP B.3.20, Overhead and Refueling Crane Inspection Program is consistent with GALL AMP XI.M 23 when the existing program does not address the above inspections.
 
In its response, the applicant stated the cranes within the scope of the Overhead and
 
Refueling Crane Inspection Program are routinely inspected, however the existing
 
procedures do not explicitly identify inspection of structural components for excessive wear, corrosion, and misalignment in all cases.
 
As a result, the applicant will enhance applicable plant procedures to explicitly identify
 
inspection of crane rails and crane structural components for loss of material due to
 
corrosion and wear, and for indication of rail misalignment.
 
In its letter dated, August 11, 2008, the applicant revised the LRA to enhance the program
 
element "detection of aging effects" by revi sing the program implementing procedures for 3-20 the cranes within the scope of license renewal to require that visual inspections for excessive wear, corrosion, or misalignment of crane rails and crane structural components
 
be routinely performed. In the same letter, the applicant provided Commitment No. 34 to
 
enhance the Overhead and Refueling Crane Inspection Program prior to the period of
 
extended operation.
 
The staff finds the applicant's response acceptable because it explains that currently the
 
existing VEGP program implementation (inspecti on) procedures for the refueling machines, fuel handling machine bridge cranes, spent fuel cask bridge crane, and polar cranes do not
 
all routinely visually inspect for excessive wear, corrosion, or misalignment of crane rails
 
and crane structural components. 
 
The staff reviewed those portions of the Overhead and Refueling Crane Inspection Program for which the applicant claims consistency with GALL AMP XI.M23 and found that
 
they are consistent with the GALL Report AMP. Furthermore, the staff concludes that the
 
applicant's Overhead and Refueling Crane Ins pection Program will properly manage the aging of the crane bridge and trolley structural girders, beams, crane rails and support
 
girders for the period of extended operation. 
 
The staff finds the applicant's Overhead and Refueling Crane Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M23, "Inspection of
 
Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems," with the
 
enhancement as described below.
 
The enhancement evaluation that follows is based on the applicant's license renewal
 
amendment to enhance the Overhead and Refueling Crane Inspection Program.
 
Enhancement The applicant's license renewal amendment states an enhancement to the following GALL Report program element:
 
Element: 4: detection of aging effects
 
Enhancement: Revise plant procedures for the refueling machines, fuel handling machine bridge cranes, spent fuel cask bridge
 
crane, and polar cranes to routinely visually inspect for
 
excessive wear, corrosion, or misalignment of crane rails
 
and crane structural components. 
 
The staff finds this enhancement acceptable, since the enhanced program implementing
 
procedures will address the recommendations of the GALL Report and be consistent with
 
the "detection of aging effects" program element.
On this basis, the staff finds the applicant's Overhead and Refueling Crane Inspection
 
Program acceptable since when the enhancement is implemented; the program will be consistent with GALL AMP XI.M23 and will provide assurance that the effects of aging will
 
be adequately managed.
 
Operating Experience LRA Section B.3.20 states that the operating history of the overhead and refueling cranes shows no significant degradation of the crane bridge and trolley
 
structural girders and beams or of the crane rails and support girders and that the program
 
has managed aging effects for the overhead and refueling cranes effectively.
3-21  The applicant stated that the inspections from 2001 to 2006 detected minor degradation like
 
misalignment of crane rails, loose crane rail hold-down bolts, wire rope reeving problems, reductions in wire rope diameter, wear on a fuel-handling crane roller assembly, and minor
 
flaw indications. The Corrective Actions Program evaluated the reported conditions and
 
resolved them. 
 
During the audit and review, the staff reviewed operating experience discussed in the LRA
 
and in the basis document for the Overhead and Refueling Crane Inspection Program. A
 
condition report was reviewed by the staff in which inservice inspection (ISI) found a linear
 
indication on each side of the web section weld for the beam of the pendant take up drum
 
for the spent fuel cask crane. The indications were removed by grinding. The AISC Manual
 
of Steel Construction was reviewed by the staff to determine the permissible variations and
 
standard mill practices for rolled steel sections. Based on the manual, it was concluded by
 
the staff, that the indications found along the beam web section weld were not structurally
 
significant.
 
Another condition report reviewed by the staff identified the rails of the spent fuel cask
 
crane as being out of alignment with numerous loose hold down bolts. The rails were re-
 
aligned and the hold down bolts tightened with a requirement added to check their tightness
 
every five years.
 
An additional condition report reviewed by the staff identified flaw indications in two studs in
 
a crane rail plate clamp for the Unit 2 polar crane. The disposition was to use the studs as
 
is since there was adequate rail clamps structurally on both sides of the flawed studs
 
clamp.
 
The staff finds that the review of the operating experience documented in the LRA and
 
basis document for the Overhead and Refueling Crane Inspection Program did not reveal
 
any unusual or significant findings.
 
On the basis of its review of the above plant-specific operating experience and discussions
 
with the applicant's technical staff, the staff concludes that the applicant's Overhead and
 
Refueling Crane Inspection Program will adequately manage the aging effects for which the
 
AMP is credited.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section A.2.20, the applicant provided the UFSAR supplement for the Overhead and Refueling Crane Inspection Program. The staff reviewed the
 
applicant's license renewal commitment list dated August 11, 2008, and confirmed that this
 
program (enhancement to this program) is identified as Commitment No. 34 to be implemented prior to the period of extended operation. The staff concludes 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 Overhead and Refueling Crane Inspection Program, the staff concludes that those program elements for which the
 
applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed 3-22 the enhancement and confirmed that its implem entation prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it
 
was compared. The staff concludes that the applicant has demonstrated that the effects of
 
aging will be adequately managed so that the intended function(s) will be maintained
 
consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
determined that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
 
3.0.3.1.4  Water Chemistry Control Program 
 
Summary of Technical Information in the Application LRA Section B.3.28 describes the existing Water Chemistry Control Program as consistent with GALL AMP XI.M2, "Water Chemistry." The applicant stated that the Water Chemistry Control Program mitigates loss
 
of material, cracking, and heat transfer reduction in system components and structures
 
through the control of water chemistry. The program controls detrimental chemical species
 
and adds chemical agents. The program is based on the Electric Power Research Institute (EPRI) water chemistry guidelines for prim ary and secondary water chemistry control:
* Pressurized Water Reactor Primary Water Chemistry Guidelines: Volumes 1 and 2, Revision 5 , EPRI, Palo Alto, CA, 2003. 1002884 and
* Pressurized Water Reactor Secondary Water Chemistry Guidelines, Revision 6 , EPRI, Palo Alto, CA, 2004. 1008224.
Water Chemistry Control Program updates follow releases of EPRI guideline revisions. The
 
One-Time Inspection Program includes inspec tions to verify Water Chemistry Control Program effectiveness.
 
Staff Evaluation During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report.
 
The staff reviewed the information in LRA AMP B.3.28, Water Chemistry Control Program, the license renewal (LR) basis evaluation document, and applicant SNC-specific and
 
VEGP-specific procedures that pertain to the design, details, and implementation of this
 
AMP. In LRA AMP B.3.28, the applicant identifies that the Water Chemistry Control
 
Program is an existing plant-specific AMP that is consistent, without exception, with the NRC recommended guidelines and program elements in GALL AMP XI.M2, "Water
 
Chemistry." 
 
The staff noted that the "scope of program" program element for the Water Chemistry
 
Control Program states that the program calls for periodic monitoring and control of
 
detrimental contaminants, such as chlorides, fluorides, dissolved oxygen, and sulfates. The
 
staff concludes that this is consistent with the criteria for programmatic monitoring and
 
water chemistry control recommended in the "
scope of program" program element of GALL AMP XI.M2, "Water Chemistry. 
 
The staff also noted that the "scope of program" program element for the applicant's Water
 
Chemistry Control Program states that the program applies the EPRI Primary Water
 
Chemistry Guidelines in EPRI Report No. 1002884 and the EPRI Secondary Water 3-23 Chemistry Guidelines in EPRI Report No. 1008224 as the basis for implementing the primary and secondary water chemistry control pr ocess activities for the applicant's primary coolant (i.e, the reactor coolant) and secondary coolants. The staff reviewed the "scope of
 
program" program element criterion in GALL AMP XI.M2, "Water Chemistry," and determined that the GALL criterion recommends that the primary water chemistry
 
guidelines in EPRI Report No. TR-105714 and the secondary water chemistry guidelines in
 
EPRI Report No.TR-102134 as the bases for PWR primary and secondary water chemistry
 
control. However, the staff also noted the "scope of program" program element in GALL AMP XI.M2 permits license renewal applicants to apply more recent versions of the EPRI
 
primary and secondary water chemistry guidelines as the basis for the water chemistry monitoring and controls at their facilities. The staff noted that the water chemistry guidelines
 
credited by the applicant for license renewal are the most recent editions of the primary and
 
secondary PWR water chemistry guidelines that have been developed and issued by EPRI, and these guidelines are updates to the versions of the report mentioned in the GALL AMP XI.M2. Based on this assessment, the staff concludes that the applicant's use and crediting
 
of EPRI Primary Water Chemistry Guidelines in EPRI Report No. 1002884 and the EPRI
 
Secondary Water Chemistry Guidelines in EPRI Report No. 1008224 for aging
 
management is acceptable because it  meets the alternative provision in GALL AMP XI.M2 that license renewal applicant's may apply and us e more recent versions of EPRI primary and secondary water chemistry guidelines as the basis for controlling the chemistry of their facilities' primary and secondary coolants. 
 
The staff noted from its review of the LR basis evaluation document that the remaining
 
program elements for the applicant's Water Chemistry Control Program were consistent
 
with the program element criteria recommended in GALL AMP XI.M2, "Water Chemistry,"
with the exception of the following aspects of the program that need additional clarification.
 
With regard to the applicant's "scope of program" program element, the staff asked the
 
applicant to provide its basis why pH is only used as a diagnostic parameter, given that low
 
pH can lead to stress corrosion-induced cracking and high pH can lead to caustic cracking
 
of stainless steel and Inconel materials.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant provided clarification that the reference for pH control
 
pertains solely to sampling requirements and water chemistry testing of secondary-side
 
coolant in the steam generator blowdown processing system, and that for sampling and
 
testing of steam generator blowdown coolant, the PWR secondary water chemistry
 
guidelines in EPRI Report No. 1008224 use a pH diagnostic parameter, not a water
 
chemistry control parameter. In its response, the applicant further stated that the applicant
 
continuously monitors for steam generator bl owdown coolant online and samples the steam generator blowdown coolant weekly and tests the coolant samples for pH. The applicant
 
further stated that if an adverse trend in pH is identified, corrective actions are taken to
 
identify and correct the factors causing the trend. The staff finds the applicant's response
 
acceptable because it clarifies the EPRI secondary water chemistry guidelines used by the
 
applicant do not recommend that pH be used as a water chemistry control parameter and
 
because the response clarifies that the applicant does take appropriate corrective actions if
 
adverse trends in steam generator blowdown coolant pH are noted. 
 
Based on this review the staff concludes that the applicant does not need to establish limits
 
on steam generator blowdown coolant pH because pH is not used as a control parameter
 
for steam generator blowdown coolant and the applicant does take appropriate corrective 3-24 actions if adverse trends in steam generator blowdown coolant pH are noted. This question is resolved.
 
With regard to the applicant's "parameters moni tored/inspected" program element, the staff asked the applicant to clarify whether the EPRI secondary water chemistry guidelines
 
included appropriate monitoring and control guidelines for chemical control and additive
 
species in the boric acid storage, refueling water storage, spent fuel pool, letdown
 
purification system, and chemical and volume control tanks, and if so, to clarify what the
 
parameters are and to identify by reference or by direct response what the limits or
 
specifications are for the parameters and what the sampling frequencies are for monitoring
 
for these parameters. 
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant provided clarification that Appendix B of the EPRI
 
primary water chemistry guidelines for PWR (as described in EPRI Report No. 1002884)
 
addresses chemistry control practices for systems that interface with the reactor coolant
 
system, and it also provides suggestions for parameters to be monitored and the frequencies of sampling and monitoring testing. The applicant further stated that these
 
EPRI guidelines do not establish any chemistry control parameter limitations or action
 
levels for systems that interface with the reactor coolant system. The applicant stated that, in general, monitoring of water chemistry in the boric acid storage, refueling water storage, spent fuel pool, letdown purification system, and chemical and volume control tanks is done
 
for the purpose of minimizing the potential ingress of detrimental chemical species into the
 
reactor coolant system. The staff finds the applicant's response to be acceptable because it
 
clarifies the EPRI primary water chemistry guidelines (as described in EPRI Report No.
 
1002884) used by the applicant do not establish water chemistry limits or action levels for
 
the water chemistry parameters that are monitored for in the boric acid storage tank, refueling water storage tank, spent fuel pool, letdown purification system, and chemical and
 
volume control tank coolant inventories. Based on this review the staff concludes that the
 
applicant does not need to establish chemistry parameter limits or action levels for these
 
coolants because the EPRI primary water chemistry guidelines for PWRs do not establish
 
chemistry parameter limits for these system s and because the applicant is using a version of the EPRI primary water chemistry guidelines that have been endorsed for use in GALL AMP XI.M2, Water Chemistry." This question is resolved. 
 
Based on this review, the staff concludes that the applicant's program elements for the
 
Water Chemistry Control Program are consis tent with the corresponding program element criteria that are recommended in GALL AMP XI.M2, Water Chemistry," and that the Water
 
Chemistry Program will be capable of controlling the water chemistry of the VEGP primary
 
and secondary coolants and of mitigating the corrosive-induced aging effects in the system
 
and components for which the program is credited. 
 
Based on this assessment, the staff concludes that the applicant's Water Chemistry Control
 
Program is acceptable because the program elements for the AMP are consistent with the corresponding program element criteria recommend in GALL AMP, XI.M2, "Water
 
Chemistry."
 
Operating Experience LRA Section B.3.28 states that the Water Chemistry Control Program is based upon EPRI water chemistry guidelines developed from plant experience, research
 
data, and expert opinion. Industry by consens us periodically updates and improves these guidelines.
3-25 LRA Section B.3.28 provides that following additional information relative to the water chemistry experience at VEGP:
 
On the primary side, VEGP has experienced increased silica concentrations in the
 
spent fuel pool due to the leaching from the Boraflex spent fuel racks. Silica
 
cannot be removed by ion exchange. VEGP monitors silica concentrations in the
 
spent fuel pool and uses reverse osmosis as needed to remove lower silica
 
concentrations. Silica has no significant impact on the structural integrity of
 
passive components and is only as a diagnostic parameter in the EPRI Pressurized Water Reactor Primary Water Chemistry Guidelines. Additional spent fuel racks added to the Unit 1 pool in 1998 contain no Boraflex but instead use
 
Boral. Aluminum concentrations in the spent fuel pool water have increased since
 
the introduction of these racks but have not resulted in any significant problems.
 
Ion exchange controls aluminum effectively.
 
On the secondary side, VEGP has experienced in-leakage (e.g., condenser tube leaks, etc.) from the cooling water side resulting in plant operation at sodium
 
concentrations higher than desirable. In 2002, an inadvertent addition of sodium
 
hexametaphosphate to the condensate chemical feed tanks on both units
 
exceeded the action level 3 limits for sodium in the steam generators (SGs). Both
 
units immediately shut down to reduce the high sodium and phosphate
 
concentrations. Fill and drain processes effectively removed the sodium but
 
significant phosphate residuals remained trapped in the SG by interaction with its
 
internal surfaces and sludge. Small but significant phosphate levels return during
 
start-ups. As a result, the Water Chemistry Control Program modifications included
 
phosphate action levels and terminated molar ratio control. During the last
 
refueling outage for each VEGP unit, chemical cleaning of the secondary side of
 
the SGs removed approximately 7000 pounds of scale deposit from Unit 1 and
 
5000 from Unit 2. Since the removal of scale deposit and its adsorbed phosphate, the applicant has monitored plant chemistry parameters to determine the best time
 
to re-initiate molar ratio control.
 
Recent chemistry control improvements replaced the primary and secondary water
 
treatment plants in 2003 with modern treatment components including ultra-
 
filtration, reverse osmosis, catalytic oxygen removal, and final polishing through
 
virgin resin.
 
The staff focused its review of the "operating experience" program element for this program on the water chemistry operating experience discussed above because this represents that
 
operating experience with potential to impact the integrity of the safety related systems at VEGP. 
 
With regard to the operating experience pertaining to the detection of high sodium and
 
phosphate levels and scale deposits in the secondary sides of the VEGP steam generators, the staff asked the applicant to: (1) clarify whether a root cause analysis of the scale
 
products (corrosion products) was ever performed to identify those chemical elements or
 
compounds that make up the scale, and (2) to identify the parameter and process controls
 
that are established to ensure that the concentrations of these adverse elements or
 
compounds are controlled to prevent recurrence of the scale in the SGs.
 
The applicant provided its response to the staff's question in a letter dated February 8, 3-26 2008. In its response, the applicant stated that the primary source of scale in the steam generators was from metallic oxides, with the predominant species being iron oxide. The
 
applicant stated that the amount of scale is well within the normal range of scale and sludge
 
expected to occur in Westinghouse recirculating steam generators. The applicant also
 
stated that its optimized secondary side water chemistry program is expected to keep the
 
amount of scale in the VEGP steam generators minimized. The applicant supported this basis by confirming that the normal range for iron cation concentrations in the secondary
 
side coolant is low (i.e, 0.7 - 0.8 ppb). The staff finds this response to be acceptable
 
because the applicant has taken corrective actions to remove the scale from the VEGP
 
steam generators and because the applicant has supported its basis that its optimized
 
secondary side water chemistry program is achieving its purpose of minimizing metallic
 
cations in the secondary side coolant. This question is resolved.
 
The staff noted that the applicant's Boral panels in spent fuel pool are composite materials
 
that are made of an aluminum-boron composite material which is housed inside of an
 
encasing aluminum metal sheath. These Boral panels are used for neutron absorbing
 
capability for fuel rods that are contained in the applicant's spent fuel pools. Upon review of
 
this operating experience, the staff was initially concerned that the indications of aluminum in the spent fuel pool could be representative of degradation in either the aluminum sheaths
 
or composite materials in the Boral panels. With regard to this operating experience on
 
detection of aluminum in the borated spent fuel pool coolant, the staff asked the applicant
 
to justify why aluminum levels in the spent fuel pool would not require the applicant to
 
implement a monitoring program for its spent fuel pool Boral panels.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant acknowledged that the source of the aluminum cation
 
concentrations in the VEGP Unit 1 spent fuel pool coolant was from the Boral panels. The
 
applicant identified that the VEGP Unit 2 spent fuel pool does not include Boral panels
 
because criticality control for the VEGP Unit 2 spent fuel pool does not rely on the presence
 
of boron neutron absorbing composite materials (such as Boral or boraflex).
 
In the applicant's response, the applicant stated that the Boral panels are constructed from
 
aluminum plates which are bonded to aluminum
- boron carbide composite material matrix core. The applicant stated that, while it is expected that the aluminum oxide protective layer
 
on the aluminum plates will provide reasonable corrosion resistance, minor release of
 
aluminum into the spent fuel pool coolant over time is an expected phenomenon. The
 
applicant also stated that the aluminum plates (aluminum cladding) in the Boral panels are
 
not credited to prevent loss of aluminum or boron from the aluminum - boron carbide composite material matrix core; the applicant stated that, instead, the aluminum cladding
 
serves the following objectives: (1) acts as a lubricant in the hot rolling process used in
 
fabrication of the Boral panels, and (2) to facilitate handling of the long and narrow panels
 
during handling. The applicant stated that, once the Boral panels are set into place in the
 
fuel pool storage racks, the integrity of the aluminum cladding is not longer of major
 
significance and the aluminum - boron carbide composite material matrix core is
 
considered to be suitable for exposure to the borated water coolant in the spent fuel pool.
 
The applicant further stated that it continues to use its operating experience and corrective
 
actions program to monitor the industry operating experience databases for any Boral
 
degradation issues and that, if relevant Boral degradation operating experience is identified, the operating experience is assessed for applicability to VEGP and any appropriate
 
corrective action measures are implemented.
 
3-27 In LRA Commitment No. 37, dated March 20, 2008, the applicant provided the following commitment relative to Boral panels that are present in the VEGP Unit 1 spent fuel pool in
 
order to ensure that possible degradation of the Boral panels will be is addressed during
 
the period of extended operation:
 
To ensure the Boral spent fuel racks will continue to perform their intended
 
function during the period of extended operation, VEGP commits (Appendix A, Commitment Number 37) to monitor spent fuel pool aluminum concentrations and
 
to implement corrective actions if adverse trends are identified. Additionally, SNC will monitor industry experience related to Boral and will take appropriate actions if
 
significant degradation of Boral is identified.
 
Based on this response, the staff considers that the applicant has addressed that the loss
 
of material of the aluminum cladding of the Boral panels due to general corrosion during the
 
period of extended operations because: (1) the applicant has provided a valid basis to
 
support its basis that the aluminum cladding in the panels do not serve a structural integrity
 
function, and (2) the applicant has committed to continued monitoring of the aluminum
 
cation concentrations in the spent fuel pool and to taking appropriate corrective actions if
 
adverse trends in the aluminum cation concentrations are indicated, and (3) the applicant
 
has committed to continued monitoring of the industry operating experience databases for
 
experience related to Boral degradation and to take appropriated corrective actions if
 
significant degradation of Boral is indicated. While the Water Chemistry Program addresses
 
the management of Boral's loss of material, the staff still had questions about the
 
management of Boral's loss of neutron-absorbing capacity. Subsequently, the staff sent the
 
licensee RAIs and had a phone call with them to address this issue. More information on
 
the management of Boral's loss of material and neutron-absorbing capacity are further
 
evaluated in Section 3.3.2.2.6.
 
Based on this review, the staff concludes that the applicant has adequately addressed the
 
relevant water chemistry operating experience for the VEGP spent fuel pools and steam
 
generator components and has taken steps to ensure that either the relevant conditions do
 
not impose a threat to the intended function of these components or that the applicant has
 
taken applicable steps to address and resolve the adverse conditions created by the
 
operating experience such that the intended functions of the impacted components will be
 
maintained during the period of extended operation. Based on this assessment, the staff
 
confirmed that the "operating experience" progr am element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program element
 
acceptable.
 
UFSAR Supplement In LRA Section A.2.28, the applicant provided the UFSAR supplement for the Water Chemistry Control 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 Water Chemistry Control 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 determined that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3-28  3.0.3.1.5  10 CFR 50 Appendix J Program 
 
Summary of Technical Information in the Application LRA Section B.3.29 describes the existing 10 CFR 50 Appendix J Program as consistent with GALL AMP XI.S4, "10 CFR 50, Appendix J." 
 
The applicant stated that its 10 CFR 50 Appendix J Program monitors leakage rates
 
through the containment pressure boundary, including penetrations and access openings.
 
Containment leak rate tests assure that leakage through the primary containment and
 
systems and components penetrating primary c ontainment does not exceed allowable limits of VEGP Technical Specifications. The program takes corrective actions if leakage
 
rates exceed established administrative limits fo r individual penetrations or for the overall containment pressure boundary. The program also monitors seals, gaskets, and bolted
 
connections.
 
The applicant also stated that its 10 CFR 50 Appendix J Program utilizes the performance-
 
based approach of 10 CFR Part 50 Appendix J, "Primary Reactor Containment Leakage
 
Testing for Water-Cooled Power Reactors," Option B with appropriate guidance from
 
Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," NEI 94-
 
01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50
 
Appendix J," and ANSI/American Nuclear Society (ANS) 56.8, "Containment System
 
Leakage Testing Requirements."
 
Type A tests measure the containment overall integrated leakage rate. Procedures require
 
a general visual inspection of the accessible interior and exterior surfaces of the primary
 
containment and components prior to each integrated leak rate test pressurization and
 
visual examinations of containment, as described in Regulatory Guide 1.163, in the
 
intervals between Type A tests. The next Type A test is scheduled in the year of 2017 for Unit 1 and 2010 for Unit 2 (at a 15-year interval from the previous test).
 
Type B local leak rate tests on containment pressure boundary access penetrations are at
 
frequencies that comply with the requirements of 10 CFR Part 50 Appendix J Option B. The
 
Type B Test detects or measures leakage across pressure-retaining or leakage-limiting
 
boundaries other than valves. 
 
Type C local leak rate tests on containment isolation valves are at frequencies that comply
 
with the requirements of 10 CFR Part 50 Appendix J Option B.
 
Staff Evaluation During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report AMP XI.S4. 
 
The staff interviewed the applicant's technical staff and reviewed 10 CFR 50 Appendix J
 
Program bases documents. Specifically, t he staff reviewed the program elements and associated bases documents to determine consistency with GALL AMP XI.S4. The staff
 
noted that for the integrated leak rate testing, the VEGP program utilizes Option B and the
 
guidance in NRC Regulatory Guide (RG) 1.163 and NEI 94-01,  "Industry Guideline for
 
Implementing Performance Based Option of 10 CFR Part 50, Appendix J." For local leak
 
rate testing, the Type B and Type C tests are performed at frequencies that comply with the
 
requirements of 10 CFR 50 , Appendix J, Option B. On the basis of its review, the staff
 
concludes that the applicant's Containment Leak Rate Program provided assurance that 3-29 the containment leak rate will be adequately managed for the period of extended operations (PEO). 
 
The staff finds the applicant's Containment Leak Rate Program acceptable because it conforms to the recommended GALL AMP XI.S4, "10 CFR 50, Appendix J."
 
Operating Experience LRA Section B.3.29 states that implementation and maintenance of the 10 CFR 50 Appendix J Program are in accordance with general requirements for
 
engineering programs. Periodic program reviews and assessments ensure compliance with
 
regulatory, process, and procedural requirements. 
 
The applicant stated that the last containment integrated leak rate testing was in March
 
2002 for Unit 1 (1R10) and in March 1995 for Unit 2 (2R4). Local leak rate testing found
 
some leaks to be repaired prior to the integrated leak rate testing, the results of which were
 
satisfactory and in compliance with the Technical Specifications and 10 CFR Part 50
 
Appendix J. The applicant noted that following two consecutive leakage rate findings of less
 
than 1.0 (allowable leakage rate), the integrated leak rate testing interval is 15 years, to
 
1R20 (Spring 2017) for Unit 1 and 2R14 (Spring 2010) for Unit 2, as noted in the program
 
description. In addition, applicant also stated that industry and plant-specific operating
 
experience confirms that the local leak rate tests effectively detect and initiate corrective
 
actions for leakage at containment penetrations, including the equipment hatch and air
 
locks, and confirm the effectiveness of corrective actions taken.
 
The staff reviewed the above operating experience provided in the LRA and in the
 
operating experience report, and interviewed the applicant's technical staff to confirm that
 
the plant-specific operating experience did not reveal any degradation not bounded by
 
industry experience. The staff noted that there were no instances of Appendix J test failures
 
due to causes other than valve or flange seat leakage. For these failures, all conditions
 
were evaluated and corrected. The staff did not identify any age-related related issues not
 
bounded by the industry operating experience. 
 
On the basis of its review of the above plant-specific operating experience and discussions
 
with the applicant's technical staff, the staff finds that the applicant's 10 CFR Part 50, Appendix J Program will adequately manage the aging effects for which the AMP is
 
credited
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section A.2.29, the applicant provided the UFSAR supplement for the 10 CFR 50 Appendix J 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 10 CFR 50 Appendix J Program, the staff finds all program elements consistent with the GALL Report. The staff
 
concludes that the applicant has demonstrated that the effects of aging will be adequately
 
managed so that the intended function(s) will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed 3-30 the UFSAR supplement for this AMP and determined that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.1.6  Non-EQ Cables and Connections Program 
 
Summary of Technical Information in the Application LRA Section B.3.34 describes the new Non-EQ 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-EQ Cables and Connections Program maintains the function of electrical cables
 
and connections not subject to 10 CFR 50.49 EQ requirements but exposed to adverse
 
environments of heat, radiation, or moisture significantly more severe than the service
 
condition for the insulated cable or connection.
 
The aging effect of concern is reduced insulation resistance caused by visually observable
 
(e.g., color changes or surface cracking) degradation of the insulating materials on electrical cables and connections. 
 
The program will inspect visually a representative sample of accessible insulated cables
 
and connections within the scope of license renewal for cable and connection jacket
 
surface anomalies (e.g., embrittlement, discoloration, and cracking). The applicant will provide the technical basis for the sample selections of cables and connections to be
 
inspected. The scope of this sampling program will include electrical cables and
 
connections in adverse environments. The N on-EQ Cables and Connections Program will be implemented and the first inspection will be completed 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 staff reviewed the information in LRA Section B.3.34 that describes the new Non-EQ
 
Cables and Connections Program. The staff interviewed the applicant's technical staff and
 
reviewed Non-EQ Cables and Connections Progr am bases documents. Specifically, the staff reviewed the program elements and associated bases documents to determine consistency with GALL AMP XI.E1.
 
The staff finds the Non-EQ Cables and Connections Program acceptable because it conforms to the recommended GALL AMP XI.E1, "Electrical Cables and Connections Not
 
Subject to 10 CFR50.49 Environmental Qualification Requirements."
 
Operating Experience LRA Section B.3.34 states that the new Non-EQ Cables and Connections Program has no programmatic histor
: y. Implementation of this program will consider industry and plant-specific operating experience; however, as GALL Report notes, industry operating experience shows adverse environments of heat or radiation for electrical cables and connections next to or above (within three feet of) steam generators, pressurizers, or hot process pipes like feedwater lines.
 
The program is based on the GALL Report program description, which in turn is based on
 
industry operating experience; therefore, this program when implemented assures 3-31 management of the effects of aging so applicable components will continue to perform intended functions consistent with the CLB through the period of extended operation.
 
The staff reviewed the operating experience pr ovided in the program basis document and interviewed the applicant's technical personnel to confirm this program element satisfies the
 
criterion defined in the GALL Report and in SRP-LR Section A.
The staff finds that the applicant has considered plant-specific and industry wide operating
 
experience in the development of this progr am and the applicant has confirmed that the operating experience discussed in GALL AMP XI.E1 is bounding and the operating
 
experience going forward will be captured through the VEGP Corrective Action and
 
Operating Experience Programs implement ed in accordance with VEGP procedures.
 
The staff interviewed the applicant's personnel and reviewed the applicant's Operating
 
Experience Report and a sample of plant-specific operating experience of components in
 
the program and confirmed that the plant-specific operating experience did not identify any
 
aging effects for components within the scope of this program that are not bounded by
 
industry operating experience. 
 
On the basis of its review of the operating experience and discussions with the applicant's
 
technical personnel, the staff concludes that the applicant's will adequately manage the
 
aging effects identified in the LRA for which this AMP is credited.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section A.2.34, the applicant provided the UFSAR supplement for the Non-EQ Cables and Connections Program. The staff also reviewed the applicant's
 
license renewal commitment list and confirmed that this new program is identified as
 
Commitment No. 25 to be implemented prior to the period of extended operation. 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 Non-EQ Cables and Connections 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 determined that it provides an
 
adequate summary description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.1.7  Non-EQ Inaccessible Medium-Voltage Cables Program 
 
Summary of Technical Information in the Application LRA Section B.3.35 describes the new Non-EQ Inaccessible Medium-Voltage Cabl es Program as consistent with GALL AMP XI.E3, "Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49
 
Environmental Qualification Requirements." 
 
The new Non-EQ Inaccessible Medium-Voltage Cables Program manages the aging effects for inaccessible medium-voltage cables (cables with operating voltage from 2kV to 35kV) 3-32 within the scope of license renewal exposed to significant moisture and voltage. The aging effect of concern is localized damage and breakdown of insulation. The program
 
periodically inspects and removes water accu mulation from manholes with medium-voltage cables and tests cables as needed. Inspection frequency based on actual plant experience
 
is at least every two years. 
 
In-scope medium-voltage cables exposed to significant moisture and voltage are tested at
 
least every ten years for an indication of the condition of the conductor insulation. The
 
specific test is proven for detecting deterioration of the insulation system due to wetting.
 
The Non-EQ Inaccessible Medium-Voltage C ables Program will be implemented and the first inspections completed 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 staff reviewed the information in LRA Section B3.35 that describes the new Non-EQ
 
Inaccessible Medium-Voltage Cables Program. During the audit and review , the staff
 
interviewed the applicant's technical sta ff and reviewed Non-EQ Inaccessible Medium-Voltage Cables Program basis documents. Spec ifically, the staff reviewed the program elements and associated basis documents to determine consistency with GALL AMP XI.E3. 
 
In addition, the staff reviewed the applicant's evaluations, plant drawings, and cable
 
routings, and also conducted a plant walkdown of the key electrical areas to determine
 
whether the applicant has considered all medium voltage cables within the scope of license renewal in accordance with the guidance provided in GALL AMP XI.E3. The staff verified
 
that the applicant has correctly identified and included cables in the Non-EQ Inaccessible
 
Medium-Voltage Cables Program that meets the following criteria specified in GALL AMP XI.E3: (1) they are located underground and assumed wet, and (2) they must be
 
energized at least 25 percent of the time. VEGP medium voltage cables within the scope of
 
license renewal that did not meet these criteria were screened out and are not included in
 
the Non-EQ Inaccessible Medium-Voltage Cabl es Program. Based on the review, the staff concludes that the applicant's program basis document appropriately considered the
 
medium-voltage power cables most likely to be exposed to a wetted environment in accordance with GALL AMP XI.E3 recommendations. 
 
Based on the review, the staff finds the applicant's Non-EQ Inaccessible Medium-Voltage
 
Cables Program acceptable because it is consistent with 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.3.35 states that this new program has no programmatic history; however, as the GALL Report notes, operating experience shows
 
that medium-voltage cables simultaneously exposed to significant moisture and significant
 
voltage are susceptible to water tree formation. The formation and growth of water trees
 
vary directly with operating voltage. Treeing is much less prevalent in 4kV cables than in
 
those operated at higher voltages. Minimizing exposure to moisture also minimizes the
 
potential for water tree development.
 
The applicant states in the LRA that the Non-EQ Inaccessible Medium-Voltage Cables
 
Program is a new program with no site-specific operating experience history. The staff 3-33 noted that SRP-LR, Revision 1, Appendix A, Branch Technical Position RLSB-1, states that an applicant may have to commit to providing operating experience in the future for new
 
programs to confirm their effectiveness. Therefore, the staff asked the applicant to describe
 
how operating experience will be captured to confirm the program effectiveness and the
 
process to be used to adjust the program as needed. In its response the applicant stated
 
that:
Industry and plant-specific operating experience will be considered when
 
implementing this program. VEGP has ongoing programs to monitor industry and site operating experience. These programs include mechanisms to update or modify plant procedures or practices to incorporate lessons learned.
Procedures NMP-GM-008, "Operating Experience Program," and 50026-C, "ESD -
 
Operating Experience Program," describe the program for evaluating industry and vendor-supplied operating experience. Operat ing experience information that is identified as being applicable to VEGP is disseminated to the appropriate groups for
 
further evaluation and possible modification of plant procedures or practices.
If an unacceptable condition or situation is identified in the selected sample, the
 
Corrective Action Program will be used to evaluate the condition and determine
 
appropriate correction action. This corrective action will involve a determination as
 
to whether the same condition or situation is applicable to other cables and
 
connections not in the sample population.
Section B.3.35 of the LRA will be revised to indicate that both industry and plant
 
specific OE will be reviewed for this program.
 
In a letter dated March 20, 2008, the applicant amended the LRA to add the above
 
discussion to the operating experience program element in LRA Section B.3.35.
 
The staff finds the applicant's response acceptable because the applicant revised the Non-
 
EQ Inaccessible Medium-Voltage Cables Program to state that industry and plant-specific
 
operating experience will be considered in it s development. Industry operating experience that forms the basis for the program is included in the operating experience element of the
 
GALL Report program description and the applicant will monitor to verify that plant-specific
 
operating experience is consistent with GALL AMP. In addition, the applicant 's existing
 
corrective action and operative experience pr ograms require them to update programs and procedures to incorporate lessons learned.
 
On the basis of its review of the operating experience program elements and discussions
 
with the applicant's technical personnel, the staff concludes that the applicant's Non-EQ
 
Inaccessible Medium-Voltage Cables Progr am will adequately manage the aging effects for which this AMP is credited. 
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
3-34 UFSAR Supplement In LRA Section A.2.35, the applicant provided the UFSAR supplement for the Non-EQ Inaccessible Medium-Volt age Cables Program. The staff reviewed the applicant's license renewal commitment list dated June 27, 2007, and confirmed that the
 
implementation of the Non-EQ Inaccessible M edium-Voltage Cables Program is identified as Commitment No. 26, to be implemented before the period of extended operation. 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 Non-EQ Inaccessible Medium-Voltage Cables 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
 
determined that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
 
3.0.3.1.8  Environmental Qualification Program 
 
Summary of Technical Information in the Application LRA Section B.3.37 describes the existing Environmental Qualification Program as consistent with GALL AMP X.E1, "Environmental Qualification (EQ) of Electric Components." 
 
The existing Environmental Qualification Pr ogram implements 10 CFR 50.49 requirements.
The program demonstrates that certain electric al components are qualified to perform their safety functions in harsh plant environments consistent with 10 CFR 50.49 requirements.
 
The Environmental Qualification Program manages component thermal, radiation, and
 
cyclical aging, as necessary, through the us e of aging evaluations. The program requires action be taken before individual components exceed their qualified lives. Actions taken
 
include replacement of parts or components at specified intervals and reanalysis to
 
maintain qualification.
 
As required by 10 CFR 50.49, EQ components not qualified for the current license term
 
must be refurbished or replaced or their qualification must be extended before they reach
 
the aging limits established in the evaluation. Some aging evaluations for EQ components
 
specify a qualification of at least 40 years and are time-limited aging analyses (TLAAs) for
 
license renewal. The Environmental Qualification Program ensures maintenance of these
 
EQ components within the bounds of their qualification bases. 
 
The reanalysis of an aging evaluation for component qualification under 10 CFR 50.49(e) is
 
a routine part of the Environmental Qualification Program. The reanalysis is normally
 
extends the qualification by reducing conservatisms incorporated in the evaluation. 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. The evaluation
 
may have used conservative bounding conditions that can be refined to extend the
 
qualification.
 
Important attributes of the reanalysis of an aging evaluation include analytical methods, data collection and reduction methods, the underlying assumptions, the acceptance criteria, and corrective actions (if acceptance criteria are not met). 
 
3-35 The analytical models in the reanalysis of an aging evaluation are the same as those of the prior evaluation. The Arrhenius methodology is an acceptable model for a thermal aging
 
evaluation. The analytical method for a radiation aging evaluation is to demonstrate
 
qualification for the total integrated dose (i.e., normal radiation dose for the projected installed life plus accident radiation dose). For license renewal, one acceptable method for
 
establishing the 60-year normal radiation dose is to multiply the 40-year normal radiation
 
dose by 1.5 (60 years/40 years) and add the result to the accident radiation dose to obtain
 
the total integrated dose for the component. 
 
For cyclical aging, a similar method may be used. Use of actual plant-specific operating
 
history to re-evaluate and establish the normal integrated radiation dose for the 60-year
 
period may also be used. Other models may be justified case- by-case basis.
 
Reduction of excess conservatism in the component service conditions (e.g., temperature, radiation, and cycles) used in the prior aging evaluation is frequently employed for a reanalysis. Temperature data used in an aging evaluation is to be conservative based on
 
plant design temperatures or on actual plant temperature data. Actual plant temperature
 
data can be obtained in several ways, including by monitors for compliance with Technical
 
Specifications, other installed monitors, measurements by plant operators during rounds, and temperature sensors on large motors (while not running). Evaluation of a
 
representative number of temperature measur ements is conservative to establish the temperatures in an aging evaluation. An aging evaluation may use plant temperature data
 
in different ways: (a) direct application of the plant temperature data in the evaluation or (b)
 
use of the plant temperature data to demonstrate conservatism when using plant design
 
temperatures. Justifications of any changes to material activation energy values in a
 
reanalysis are case-specific. Reduction of ex cess conservatism in the component service conditions in the prior aging evaluation may use similar methods for radiation and cyclical
 
aging.
 
EQ component aging evaluations have sufficient conservatism to account for most
 
environmental changes due to plant modifica tions and events. When unexpected adverse conditions during operational or maintenance activities affect the normal operating
 
environment of a qualified component, the pr ogram evaluated the affected EQ component and takes appropriate corrective actions which may include changes to the qualification
 
bases and conclusions.
 
Reanalysis of an aging evaluation could extend the qualification of the component. If the
 
qualification cannot be extended by reanalysis, the component is replaced, or re-qualified
 
before it exceeds the period for which the current qualification remains valid. The reanalysis must be timely (i.e., with sufficient time to refurbish, replace, or re-qualify the component if the reanalysis is unsuccessful).
 
Staff Evaluation During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report.
The staff interviewed the applicant's technical personnel and reviewed the Environmental
 
Qualification Program bases documents. Spec ifically, the staff reviewed the program elements and bases documents for consistency with GALL AMP X.E1.
 
Based on its review, the staff concludes that the applicant's Environmental Qualification
 
Program reasonably assures management of thermal, radiation, and cyclical aging effects 3-36 for electrical equipment important to safety and located in harsh environments. The staff finds the applicant's Environmental Qualification Program acceptable because it is consistent with the recommended GALL AMP X.E1 , "Environmental Qualification (EQ) of Electric Components."
 
Operating Experience LRA Section B.3.37 states that VEGP has maintained the Environmental Qualification Program since it s inception. Program documentation, including EQ packages, is maintained and updated periodically. Routine monitoring of industry
 
operating experience reports, self-assessments, QA audits, and the corrective action
 
process assure continued program improv ement and maintenance of VEGP EQ equipment in a qualified condition.
 
The applicant states in the LRA that an equipment walk-down during the last Environmental
 
Qualification Program Team self-assessm ent in June 2005 found two EQ Rosemount transmitters with rotated electronic heads indicating possible moisture seal damage or
 
degradation. The team inspected the remaining EQ Rosemount transmitters for rotated
 
heads, replaced eight, and placed warnings about electronic head rotation in the Central
 
File and plant procedure. 
 
A 10 CFR Part 21 notice was recently issued on the potential for Barton transmitters with
 
bare conductors outside their seal plugs or potting compounds. VEGP has addressed this
 
issue by adding a qualified environmental seal for the Barton transmitters. 
 
Data Loggers monitor actual temperatures for many rooms of the plant, finding hot spots resulting in reanalysis and appropriate reductions of component qualified life. The program
 
proposes additional data collection when needed to monitor for temperature changes due
 
to plant changes.
 
Experienced employees, annual training, industry involvement (Nuclear Utility Group on
 
Equipment Qualification, Nuclear Utility Obsolescence Group, and Institute of Electrical and
 
Electronics Engineers working groups), routine monitoring of OE reports, self-assessments, 
 
central file maintenance process improvements, QA audits, and condition reports assure
 
maintenance of EQ equipment in a qualified condition.
The staff interviewed the applicant's technical personnel and also reviewed the above
 
operating experience and the applicant's operating experience reports to confirm that plant-
 
specific operating experience revealed no degradation not bounded by industry experience. 
 
A sample review of the applicant' s actions to address EQ related issues related to Part 21
 
reports, INPO operating experience reports, and periodic self assessments revealed that the applicant is evaluating and addressing the EQ related operating experience issues. 
 
Based on its review of the operating experience and discussions with the applicant's
 
technical personnel, the staff concludes that the applicant's Environmental Qualification
 
Program will adequately manage the effects of aging for which the LRA credits this AMP.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section A.2.37, the applicant provided the UFSAR supplement for the Environmental Qualification Program. The staff reviewed this section and 3-37 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 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 determined 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 or Enhancements In LRA Appendix B, the applicant stated that the following AMPs are, or will be, consistent
 
with the GALL Report, with exceptions or enhancements:
 
Boric Acid Corrosion Control Program Buried Piping and Tanks Inspection Program CASS RCS Fitting Evaluation Program Closed Cooling Water Program External Surfaces Monitoring Program Fire Protection Program  Flow-Accelerated Corrosion Program Flux Thimble Tube Inspection Program Generic Letter 89-13 Program Oil Analysis Program One-Time Inspection Program for ASME Class 1 Small Bore Piping One-Time Inspection Program for Selective Leaching Piping and Duct Internal Inspection Program Reactor Vessel Closure Head Stud Program Reactor Vessel Surveillance Program Steam Generator Tubing Integrity Program Structural Monitoring Program Structural Monitoring Program - Masonry Walls Fatigue Monitoring Program 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 those
 
attributes or features of the program, for which the applicant claimed consistency with the
 
GALL Report, were indeed consistent. The staff also reviewed the exception(s) and/or
 
enhancement(s) to the GALL Report to determine whether they were acceptable and
 
adequate. The results of the staff's audits and reviews are documented in the following
 
sections.
 
3.0.3.2.1  Boric Acid Corrosion Control Program 
 
Summary of Technical Information in the Application LRA Section B.3.3 describes the existing Boric Acid Corrosion Control Program as consistent, with an enhancement, with GALL AMP XI.M10, "Boric Acid Corrosion."
3-38  The applicant stated that the Boric Acid Corrosion Control Program monitors the condition
 
of components on which borated water may leak to detect, evaluate, and remove borated
 
water leakage and boric acid residue before any loss of intended function of affected
 
components. The program detects boric acid leakage by periodic visual inspection of
 
systems containing borated water and by inspection of adjacent structures and components
 
for evidence of leakage. Development of the program responds to the recommendations of
 
Generic Letter (GL) 88-05. The program addr esses operating experience described in recent NRC generic communications, including NRC Regulatory Issue Summary 2003-013.
 
The program consists of (1) visual inspections of component surfaces potentially exposed
 
to borated water leakage, (2) detection of leak paths and removal of boric acid residue, (3)
 
assessment of the corrosion, and (4) follow-up inspection, as appropriate, for adequacy of
 
corrective actions.
 
The applicant also stated that enhancements to the Boric Acid Corrosion Control Program
 
will be implemented prior to the period of extended operation.
 
Staff Evaluation During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. 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.
 
During its audit and review, the staff reviewed the elements of the Boric Acid Corrosion
 
Program for which the applicant claims consistency with GALL AMP XI.M10, "Boric Acid Corrosion," with the enhancement described below.
 
During the audit and review, the staff reviewed LRA B.3.3, "Boric Acid Corrosion Control
 
Program," and the program elements defined and discussed in GALL AMP XI.M10, "Boric Acid Corrosion Program." The staff also reviewed the license renewal evaluation document
 
for the applicant's Boric Acid Corrosion Control Program and interviewed SNC staff
 
members involved with implementation of the Boric Corrosion Control program. 
 
In Generic Letter (GL) 88-05, "Boric Acid Corrosion of Carbon Steel Reactor Pressure
 
Boundary Components in PWR Plants," the staff informed the U.S. nuclear power industry
 
that borated water leakage is a safety issue for PWR reactor coolant pressure boundaries.
 
In GL 88-05, the NRC recommended that licensees of PWR facilities perform visual
 
examinations of their borated water system s to monitor leakage that could impact the integrity of plant systems made from ferritic steel materials (i.e., carbon steel or low alloy steel materials). The program elements in GALL AMP XI.M10, "Boric Acid Corrosion
 
Program," are based on performing these leakage examinations, as recommended in GL
 
88-05.
 
The applicant, in the program evaluation document, clarifies that the Boric Acid Corrosion
 
Control Program (BACCP) was initially developed in response to NRC Generic Letter 88-
: 05. The program was developed to include the following attributes:
 
Determination of the source of the leakage  Procedures for locating small coolant leakage  Inspections and assessments to evaluate corrosion impact  Corrective actions to prevent recurrences 3-39  Further, the applicant stated that the current program is also based on NRC Bulletins 
 
2001-01, 2002-02, 2003-02, and NRC Order EA-03-009. The applicant also explained that
 
the scope includes all systems which contain borated water (above 180ºF) and also
 
locations where borated water systems at any temperature may be above carbon steel systems which may be affected by borated water leakage. This procedure states that
 
potential leak locations in concentrated BA systems should be evaluated to determine if
 
potential leakage would impact safety-related equipment (e.g., piping, piping supports, electrical connectors, etc.).
 
The applicant added that, in conjunction with the Section XI requirements, the following
 
locations are evaluated for examination requirements:
 
Locations inside containment:
 
Reactor Vessel Head  Mechanical piping connections within the RCPB  Mechanical piping connections outside of the RCPB  Alloy 600 base material and Alloy 82/182 weld locations
 
Locations outside of containment:
 
Mechanical piping connections with borated water  Potential leak locations where potential leakage would impact safety-related equipment  Mechanical piping connections containing borated water above carbon steel piping systems.
Also, boric acid inspections are implemented through both ISI activities such as leakage
 
testing, leakage assessment, and through normal departmental plant walkdowns.
 
During the audit and review, the staff asked the applicant to clarify whether the VEGP-
 
specific responses to applicable NRC's generic communications and orders on boric acid
 
leakage or corrosion (including, Bulletin 2003-02, Bulletin 2004-01, and First Revised Order
 
EA-03-009) are within the scope of its Boric Acid Corrosion Control Program. 
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. The applicant in its response stated that the VEGP-specific responses to the
 
applicable NRC's generic communications and orders on boric acid leakage/corrosion are
 
within the scope of the VEGP Boric Acid Corrosion Control Program. This program uses the
 
VEGP reactor coolant system Alloy 600 material inspection program as the current-term
 
program vehicle for performing inspections of these nickel alloy component locations that
 
are the subject of these NRC communications. For the period of extended operation, the
 
Nickel Alloy Program for Reactor Vessel Closure Head Penetrations and the Nickel Alloy
 
Program for Non-Reactor Vessel Closure Head Penetration Locations are the program
 
vehicles for implementing details and commitments. 
 
In addition, the applicant in its response provided references to the Vogtle-specific 3-40 responses to the following NRC generic communications and orders: NRC Bulletin 2003-02, "Leakage from Reactor Pressure Vessel Lower Head Penetrations and Reactor
 
Pressure Boundary Integrity," NRC Bulletin 2004-01, "Inspection of Alloy 82/182/600
 
Materials Used in the Fabrication of Pressurizer Penetrations and Steam Space Piping
 
Connections at PWRs," and NRC First Revised Order, EA-03-009, "Issuance of First
 
Revised Order Establishing Interim Inspection Requirements for Reactor Pressure Vessel
 
Heads at Pressurized Water Reactors," February 20, 2004.
 
The staff finds the applicant's response acceptable on the basis that it clearly explained the
 
scope of VEGP Boric Acid Corrosion, which was originally developed in response to GL 88-
 
05, has been modified to include the plant specific responses to the NRC's generic
 
communications and orders.
 
During the audit and review, the staff asked the applicant to clarify whether any of the
 
commitments made in response to these generic letters and orders are within the scope of
 
the Boric Acid Corrosion Program. The applicant provided its response to the staff's
 
question in a letter dated February 8, 2008. The applicant in its response provided details
 
regarding commitments that SNC made in response to the following generic letters and
 
orders that are within the scope of the VEGP Boric Acid Corrosion Control Program:
 
Regarding NRC Bulletin 2003-02, the applicant stated that NRC Bulletin 2003-02
 
requirements included a one-time visual inspection of all the nozzles penetrating the bottom
 
head of the vessel and a general inspection of the bottom head for indication of wastage or
 
corrosion of the low alloy steel vessel. During the fall 2003 refueling outage for Unit 1 and
 
during the spring 2004 refueling outage for Unit 2, the entire circumference of the interface
 
of each nozzle with the vessel was visually examined for the presence of any deposits that
 
might indicate leakage from the annulus between the nozzle and the vessel bottom head, and no significant problems noted for either Unit.
Regarding NRC Bulletin 2004-01, the applicant stated that the Alloy 82/182 locations at
 
VEGP associated with the pressurizer are the butt welds connecting stainless steel safe
 
ends to one 4" spray nozzle, four 6" Safety/Relief nozzles, and one 14" surge nozzle for
 
each unit. To supplement the Inservice Inspection Program, inspections for the butt welded
 
pressurizer nozzle locations containing Alloy 82/182 material were performed in response
 
to EPRI MRP 2003-039, issued January 20, 2004. Full structural weld overlays mitigation
 
for Alloy 82/182 pressurizer butt welds, consisting of PWSCC-resistant welding material
 
Alloy 52/152, were applied on each of the six pressurizer nozzles on Vogtle Unit 2 during
 
the Spring 2007 refueling outage. On Unit 1, SNC requested approval from the staff (ML073610061) to extend the mitigation actions beyond the December 31, 2007 deadline.
 
SNC committed to apply full structural weld overlays during the spring 2008 refueling
 
outage on Unit 1. The required full structural weld overlays were applied in accordance with
 
SNCs commitment. An evaluation of the full structural weld overlays was provided to the
 
Commission prior to entry into Mode 4 during startup from the spring 2008 refueling outage (ML081280889).
Regarding NRC Order EA-03-009, the applicant stated that VEGP reactor vessel head
 
inspections are performed in accordance with NRC Order EA-03-009 dated February 13, 2003, and revised on February 20, 2004. Order EA-03-009 Section IV.C(5)(a) specifies
 
examination coverage for bare metal visual examination of the reactor vessel head surface.
 
The SNC requested relaxation, relief request, from the staff to not inspect the small surface
 
of the reactor vessel head obscured by insulation. This relief request was granted by the 3-41 staff in a September 2005 Safety Evaluation. Further, Order EA-03-009 Section IV.C(5)(b) specifies examination volume for reactor vessel head penetration nozzle base material. Full
 
examination volume coverage using ultrasonic testing is not possible at VEGP due to
 
geometric considerations. SNC proposed an alternate to ultrasonically test nozzle ends to
 
the maximum extent possible. This alternate approach was approved by the staff in an
 
August 2006 Safety Evaluation 
 
The staff finds the applicant's response acceptable on the basis that: 1) regarding Bulletin
 
2003-02, the entire circumference of the interface of each nozzle with the vessel was
 
visually examined for VEGP Unit 1 and Unit 2, and no significant problems were noted for
 
either unit, 2) regarding NRC Bulletin 2004-01, full structural weld overlays were applied on
 
each of the six pressurizer nozzles on Vogtle Unit 2 during the Spring 2007, and during the
 
Spring 2008 refueling outage on Unit 1, and 3) regarding NRC Order, EA-03-009, VEGP
 
reactor vessel head inspections, including one relief and one alternate, are performed in
 
accordance with NRC Order, EA-03-009 dated February 13, 2003 and revised on February
 
20, 2004.
 
Enhancement
: In the LRA, the applicant states the following enhancement to the GALL Report program elements:
 
Elements: 1. Program Scope
: 6. Acceptance Criteria
 
Enhancement: The Boric Acid Corrosion Control Program scope and acceptance criteria will be enhanced to address the effects of
 
borated water leakage on materials other than steels, including electrical components (e.g., electrical connectors)
 
that are susceptible to boric acid corrosion.
 
The applicant in Enclosure 2 to its letter dated June 27, 2006 committed (Item 3) to
 
implement the above enhancement prior to the period of the extended operation.
 
During the audit and review, the staff asked the applicant to list the components that will be
 
added to the scope of this program and materials that they are made of. Also, discuss the
 
method for detection of aging effects, frequency of inspections, and acceptance criteria for
 
evaluation of any detected borated water leakage or crystal buildup for these components. 
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. The applicant in its response stated that SNC has made a commitment (Appendix A, Commitment Number 3) to enhance the Boric Acid Corrosion Control Program to
 
specifically include materials other than steels that are potentially susceptible to boric acid
 
corrosion if exposed to boric acid leakage. Materials identified during the aging
 
management review process other than steels were cast iron, copper alloys, and aluminum
 
alloys. The applicant added that the components subject to an aging management review
 
that are constructed of these materials and have a potential to be exposed to borated water
 
leakage are predominantly fire protection components, misc. mechanical components (e.g.,
valves, drain bodies, housings, casings) and electrical connectors. 
 
The applicant in its response also stated that detection of aging effects for these components due to borated water leakage or boric acid crystal residue is primarily through
 
visual observation. If a boric acid leak is identified, the applicant will perform a screening 3-42 evaluation to determine if a corrosion assessment is necessary. If corrosion is present, the applicant's corrective action process assesses the extent of the corrosion, the acceptability
 
of continued service, and any required corrective actions. Boric acid inspections are
 
implemented through ISI activities (e.g., pressure testing), leakage assessments, and
 
personnel performing routine work activities and plant walkdowns (operations, maintenance, health physics, engineering, Boric Acid Corrosion Control Program owner
 
performing program walkdowns, etc.). The fr equency of these inspections and activities ensure the timely detection of loss of material due to boric acid leakage.
 
The staff finds the applicant's response acceptable on the basis that it 1) identified
 
additional components and materials that will be added to the scope of the Boric Acid
 
Corrosion Program and 2) provided clarification that aging effects of the components
 
exposed to boric acid is adequately managed by this program through implementing inservice inspections and other plant's activities.
 
The staff finds that this enhancement acceptable because the inclusion of mechanical and
 
electrical components made of materials other that steel makes the program consistent with GALL AMP XI.M10.
 
Operating Experience LRA Section B.3.3 states that an assessment of the Boric Acid Program revealed that it had not detected and evaluated boric acid leaks consistently.
 
Program enhancements based on these findings changed procedures to require personnel
 
to write condition reports of detected boric acid leakage. Problem markers flag leaks
 
outside of containment in the field and boric acid corrosion control training is required for all
 
VEGP site personnel. 
 
Reactor pressure vessel head inspections in accordance with NRC First Revised Order EA-
 
03-009 observed boron residue. There was no evidence of head material wastage or of
 
leaking or cracked nozzles. The boron residue was from previous cleaning and
 
decontamination of conoseals and not new, active leakage. The areas below the conoseals
 
were cleaned and re-inspection during startup observed no leakage.
 
During the audit and review, the staff requested that the applicant discuss its process for
 
reviewing all VEGP-specific and generic boric acid leakage experience and discuss how
 
this process is used to incorporate such experience into the scope of the Boric Acid
 
Corrosion Control Program and schedule the relevant system locations for boric acid
 
leakage examinations. 
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. The applicant in its response stated that operating experience (OE) is continuously
 
evaluated to determine any impact to aging effects and/or mechanisms managed by the Boric Acid Corrosion Control Program. Plant-specific items such as condition reports, SNC
 
licensee event reports (LERs), SNC OE Alerts are reviewed for potential impact to the Boric
 
Acid Corrosion Program by the program ow ner. Industry events are likewise screened by the owner for applicability to the Boric Acid Corrosion Program, including NRC generic
 
communications, vendor communications, NUREG reports, industry operating experience, EPRI and MRP reports, and LERs. Health reports are issued periodically on the Boric Acid
 
Corrosion Program, which take into consideration operating experience and trends.
 
The staff concludes that the operating experience of the Boric Acid Corrosion Program
 
includes the applicant's responses to the NRC's generic communications, applicable 3-43 NUREG reports, and industry's operating experience and reports applicable to Boric Acid Corrosion Program. On the basis of this determination, the staff finds the applicant's
 
response acceptable.
 
The staff reviewed the operating experience discussed in program basis document and
 
interviewed the applicant's technical staff and confirmed that the plant-specific operating
 
experience did not reveal any degradat ion not bounded by industry experience.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section  A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section  A.2.3, the applicant provided the UFSAR supplement for the Boric Acid Corrosion Control Program. In Enclosure 2 of its letter dated June 27, 2007, the applicant committed (Appendix A, Commitment Number 3) to enhance Boric Acid
 
Corrosion Control Program documents to address the effects of borated water leakage onto
 
materials other than steels, including electrical components that are susceptible to boric
 
acid operation corrosion. The staff reviewed this commitment and LRA Section A.2.3 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).
 
Conclusion On the basis of its audit and review of the applicant's Boric Acid Corrosion Control Program, the staff concludes that those program elements, for which the applicant
 
claimed consistency with the GALL Report, are consistent. Also, the staff reviewed the
 
enhancement and confirmed that its implement ation prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it
 
was compared. The staff concludes that the applicant has demonstrated that the effects of
 
aging will be adequately managed so that the intended function(s) will be maintained
 
consistent with the CLB for the period of extended operation, as required by 10  CFR
 
54.21(a)(3). 
 
The staff also reviewed the UFSAR supplement for this AMP and determined that it
 
provides an adequate summary description of the program, as required by
 
10 CFR  54.21(d).
 
3.0.3.2.2  Buried Piping and Tanks Inspection Program 
 
Summary of Technical Information in the Application LRA Section B.3.4 describes the new Buried Piping and Tanks Inspection Program as consistent, with exceptions, with GALL AMP XI.M34, "Buried Piping and Tanks Inspection." 
 
The applicant stated that the Buried Piping and Tanks Inspection Program manages loss of
 
material from the external surfaces of buried carbon steel, cast iron, and stainless steel
 
components by both preventive measures and vi sual inspections. Preventive measures consist of coatings and wrappings required by design in accordance with industry
 
standards. Buried components within the scope of license renewal will be inspected when
 
excavated for maintenance or exposed for any other reason. 
 
The program applies to the buried components within the scope of license renewal in the following systems:
 
3-44  Emergency diesel generator system (buried fuel oil storage tanks and fuel oil transfer piping)  Feedwater system (buried piping between the condensate storage tanks and the condenser hotwells)  Fire protection system  Nuclear service cooling water system (buried sample lines between the nuclear service cooling water (NSCW) system pumphouses and the NSCW
 
chemical control buildings)
The applicant also stated that prior to the period of extended operation; a review will
 
determine whether there has been at least one opportunistic or focused inspection of buried
 
piping and tanks within the 10 years prior to the period of extended operation. If not, there
 
will be a focused inspection prior to the period of extended operation.
 
In addition, there will be a focused inspection of buried piping and tanks within the first
 
10 years of the period of extended operation unless an engineering evaluation determined
 
that sufficient opportunistic and focused inspections during this time have demonstrated the
 
ability of the underground coatings to protect the underground piping and tanks from
 
degradation.
 
The Buried Piping and Tanks Inspection Program will be implemented prior to the period of
 
extended operation. 
 
Staff Evaluation During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. 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.
 
During the audit and review, the staff confirmed that preventive measures such as
 
protective coatings/wrappings are used in buried steel, stainless steel, and cast iron piping
 
applications, in addition to buried carbon steel tank applications. The staff verified that as
 
part of the implementation plan for the new program, the VEGP procedure for excavation
 
will be revised to include a requirement that buried piping and tanks are to be inspected
 
when they are excavated for maintenance or when exposed for any reason. In addition, as
 
part of the program implementation, the app licant stated in the program basis document that a new procedure will be issued to provide guidance for inspection of buried piping and
 
tanks which are exposed by excavation. The new procedure will provide the acceptance criteria such that any evidence beyond t he acceptance criteria of damaged wrapping or coating defects, such as coating perforation, holidays, or other damage, is an indicator of
 
possible corrosion damage to the external surface of the buried piping and tanks. When
 
inspections reveal evidence of degradation beyond the acceptance criteria, evaluation and appropriate corrective action in accordance with the plant corrective action process may be
 
required.
 
During audit and review, the staff asked the applicant to identify the methodology and
 
criteria that will be used to determine the locations for inspections based on areas with the
 
highest likelihood of corrosion problems. The applicant provided its response to the staff's 3-45 question in a letter dated February 8, 2008. The applicant stated that for focused inspections the determination of areas with the highest likelihood of corrosion problems will
 
include a review of plant condition reports for areas with a history of leaks and corrosion
 
problems or the observance of water or an unusually wet surface on the ground by site
 
personnel while performing normal site activities. The applicant also stated that a review of
 
plant operating experience indicates that this has been the primary method of identifying
 
underground leaks at VEGP. For opportunistic inspections in relatively small excavations, the entire exposed surface will be inspected. For opportunistic inspections in large
 
excavations, the inspections will be performed in the exposed areas with the highest
 
likelihood of corrosion problems, and in areas with a history of corrosion problems (such as
 
near building foundations, at tank nozzles, pipe fittings, locations where the coating system
 
may have been repaired, etc.).
 
The staff finds the applicant's approach acceptable because for focused inspections the
 
applicant will use historical records to determine areas with the highest likelihood of
 
corrosion problems. 
 
During the audit and review, the staff noted that GALL AMP XI.M34, "Buried Piping and
 
Tanks Inspection" states that gray cast iron, which is included under the definition of steel, is also subject to a loss of material due to selective leaching, which is an aging effect managed under GALL AMP XI.M33, "Selective Leaching of Materials." LRA Section B.3.19
 
describes the new One-Time Inspection Program for Selective Leaching for VEGP. During
 
the audit and review, the staff asked the applicant to clarify how the One-Time Inspection
 
Program for Selective Leaching will be coordinated with the Buried Piping and Tanks
 
Inspection Program when opportunistic inspections for buried pipe and tanks become
 
available. 
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated the One-Time Inspection Program for Selective
 
Leaching is credited for managing loss of material due to selective leaching from both the
 
internal and external surfaces of buried gr ay cast iron fire hydrant components and valve components. The buried cast iron fire protection piping components within the scope of
 
license renewal are not gray cast iron and therefore are not subject to selective leaching.
 
The VEGP Buried Piping and Tanks Inspection Program implementing procedures will
 
include guidance to notify Engineering Support to have the One-Time Inspection Program
 
for Selective Leaching Program owner review exca vations of the fire protection system to determine whether an opportunity exists to per form a selective leaching inspection on a gray cast iron component that is being expos ed or replaced. If such an opportunity is determined to exist on a component that can be credited as meeting the requirements of
 
the One-Time Inspection Program for Selective Leaching, it will be the option of the
 
responsible site personnel to perform a selective leaching inspection. Once the
 
requirements of the One-Time Inspection Program for Selective Leaching are fulfilled, no
 
further selective leaching inspections would be performed under that program.
 
The staff finds the applicant's response acceptable because it explained the details of how
 
the VEGP Buried Piping and Tanks Inspection Program and One-Time Inspection Program
 
for Selective Leaching Program will coordinate inspections during buried component
 
excavations.
 
The staff reviewed those portions of the Buried Piping and Tanks Inspection Program for 3-46 which the applicant claims consistency with GALL AMP XI.M34 and found that they are consistent with the GALL Report AMP. Furthermore, the staff concludes that the applicant's
 
Buried Piping and Tanks Inspection Program will properly manage the aging of buried
 
piping and tanks for the period of extended operation. The staff finds the applicant's Buried
 
Piping and Tanks Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M34, "Buried Piping and Tanks Inspection Program," with the exception as
 
described below.
 
The LRA states an exception to the following GALL Report program elements:
 
Elements: 1: scope of the program 3: parameters monitored or inspected 10: operating experience
 
Exception: The VEGP Buried Piping and Tanks Inspection Program contains an exception to the scope of the GALL program in
 
that the VEGP program addresses buried stainless steel
 
piping in addition to buried steel piping and tanks. 
 
During the audit and review, the staff noted that the applicant stated in the program basis
 
document that the addition of stainless steel leads to the conclusion that there is a potential
 
for galvanic corrosion of carbon steel if any dissimilar metal joints exist in the buried
 
environment.
 
The staff finds the exception acceptable because it includes the inspection of buried
 
stainless steel piping within the scope of the program and while stainless steel buried piping
 
is not likely to experience the same aging effects as buried steel piping there is a potential
 
for galvanic corrosion of the carbon steel piping if any dissimilar metal joints exist in the
 
buried environment. Since the applicant believes there is the possibility that buried stainless
 
steel pipe may be connected to steel piping at dissimilar metal joints; the staff agrees that it
 
is appropriate to include stainless steel pipe within the scope of the program, inspect a
 
sampling of stainless steel buried piping at dissimilar metal joints and review operating
 
experience for buried stainless steel pipe connected to buried steel pipe.
 
Operating Experience LRA Section B.3.4 states that this new program has no documented programmatic operating experience. There have been failures in buried galvanized pipe not
 
within the scope of license renewal. The only leaks from buried components within the
 
scope of license renewal were in buried fire protection components typically attributed to
 
design, installation, or operational and not age-related issues.
 
The program is based on the GALL Report program description which in turn is based on
 
industry operating experience. This industry experience-basis for the program assures that
 
implementation of the Buried Piping and Tanks Inspection Program will manage the effects
 
of aging adequately during the period of extended operation.
 
The staff noted in LRA Section B.3.4, Buried Piping and Tanks Inspection Program, under
 
the program element "operating experience," that the only leaks identified from buried
 
components within the scope of license renewal were in buried fire protection components.
 
These leaks were typically attributed to design, installation, or operational issues, and not
 
age related. During the audit and review, the staff asked the applicant to quantify the
 
number of leaks identified in the buried fire protection system and identify the type of 3-47 components affected and also discuss the number of leaks attributed to design, installation, or operational issues and the number of leaks attributed to age-related degradation and
 
characterize the root causes of the leaking fire protection components. In addition, the staff
 
asked the applicant to provide the basis for not crediting a periodic inspection-based
 
program to manage the effects of aging on the intended functions of the impacted buried
 
fire protection components for the period of extended operation. 
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that from 1999 through 2006, eight leaks were
 
identified in fire protection system buried piping, including:
 
two installation errors (bolt left out of a pipe flange, pipe sections misaligned)  one pipe damaged during excavation of an adjacent storm drain  one leaking gasket at pipe elbow  one pipe break due to a water hammer event  three leaks with no cause documented.
In addition, the applicant stated one leak has been identified but has not yet been
 
excavated, so neither the source of the leak or its cause has been determined. This leak
 
was noted in the applicant's response because sampling of water from the leak indicates
 
that it could be from fire protection.
 
A Root Cause and Corrective Action (RCCA) determination is documented for the condition
 
report addressing the water hammer event. That condition report describes a fire protection
 
pipe break due to a water hammer event. The apparent causes of this event were identified
 
as unusual plant conditions or configuration (fire protection surveillance in progress) and
 
equipment not designed for the operating conditions (modification created an extended
 
dead leg of buried piping susceptible to water hammer). An RCCA determination is not
 
documented for the remaining fire protection leaks.
 
The applicant did not attribute any leaks to age-related degradation. In addition, the
 
applicant stated inspections done on pipe segments replaced in 1999, 2003 and 2004 (documented in VEGP condition reports) did not identify either internal or external
 
corrosion. Therefore a periodic inspection-based program is not warranted.
The staff finds the applicant's response acceptable because the leaks identified were not attributed to age-related degradation. The VEGP specific operating experience
 
demonstrates that VEGP has not experienced age-related degradation of its buried piping
 
and tanks within the scope of license renewal and subject to aging management. While
 
there have been leaks associated with the VEGP buried piping and tanks, they have been
 
the result of design, operation and construction issues. VEGP will continue to document
 
issues with buried piping and tanks up to the period of extended operation and review the
 
information when determining if enough opportunistic buried piping and tank inspections
 
have been performed or use the information to determine where to perform focused buried
 
pipe and tank inspections within the 10 years prior to the period of extended operation.
 
During the audit and review, the staff reviewed the actual operating experience
 
documentation referenced in the basis document for the Buried Piping and Tanks
 
Inspection Program and did not find any unusual or significant findings associated with age-
 
related degradation. 
 
3-48 On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical staff, the staff concludes that the applicant's Buried Piping and
 
Tanks Inspection Program, when implemented, will adequately manage the aging effects
 
for which the AMP is credited. 
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section A.2.4, the applicant provided the UFSAR supplement for the Buried Piping and Tanks Inspection Program. The staff reviewed the applicant's
 
license renewal commitment letter (NL-07-1261, dated June 27, 2007) and confirmed that
 
this program is identified as Commitment No. 4 to be implemented before the period of
 
extended operation. The staff reviewed LRA Section A.2.4 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 Buried Piping and Tanks Inspection Program, the staff finds, with the implementation of Commitment No. 4, 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
 
determined that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
 
3.0.3.2.3  CASS RCS Fitting Evaluation Program 
 
Summary of Technical Information in the Application LRA Section B.3.5 describes the new CASS RCS Fitting Evaluation Program as consistent, with exception, with GALL AMP XI.M12, "Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)." 
 
The CASS RCS Fitting Evaluation Program manages the effects of loss of fracture 
 
toughness due to thermal aging for susceptible CASS components in the reactor coolant
 
system (RCS). This program augments Inse rvice Inspection Program requirements.
 
The applicant stated that this AMP evaluated the susceptibility of CASS components to
 
thermal aging embrittlement based on casting method, molybdenum content, and percent
 
ferrite. Screening for susceptibility to thermal aging is not required for pump casings and
 
valve bodies according to the assessment documented in the letter dated May 19, 2000, from Christopher Grimes, NRC, to Douglas Walters, NEI. ASME Code Section XI inspection
 
requirements, including the alternative r equirements of ASME Code Case N-481 for pump casings, are adequate for all pump casings and valve bodies.
 
The program manages aging through either a flaw tolerance or an enhanced volumetric
 
examination. Additional inspections or evaluations to demonstrate the adequacy of the
 
material's fracture toughness are not required for components which are not susceptible to
 
thermal aging embrittlement.
3-49  According to the applicant, based on screening consistent with the process specified in GALL Report Revision 1, Section XI.M12, VEGP components requiring additional aging
 
management under this program are the Unit 1 Loop 4 and the Unit 2 Loop 1 reactor
 
coolant pump inlet elbows. For these two castings, management of loss of fracture
 
toughness due to thermal aging will be by component-specific flaw tolerance evaluation, additional inspections, or a combination of these techniques.
 
The applicant also stated that this program will not include the CASS bottom-mounted
 
instrumentation column cruciforms, reactor vessel internals components managed by the
 
Reactor Vessel Internals Program.
 
The applicant noted that the CASS RCS Fitting Evaluation Program will be implemented
 
prior to the period of extended operation.
 
Staff Evaluation During its audit and review, the staff confirmed the applicant's claim of consistency , with an exception , 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.
 
During its audit and review, the staff reviewed the program elements of LRA B.3.5, "CASS
 
RCS Fitting Evaluation Program," for which t he applicant claims consistency with GALL AMP XI.M12, "Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS),"
 
with the exception described below.
 
During the audit and review, the staff also reviewed the license renewal evaluation
 
document for the applicant's CASS RCS Fitting Evaluation Program and interviewed SNC
 
staff members involved with implementation of the CASS RCS Fitting Evaluation Program.
 
GALL XI.M12, Scope of Program states that the program includes screening criteria to
 
determine which CASS components are potentially susceptible to thermal aging
 
embrittlement and require augmented inspection. 
 
The screening criteria are applicable to all primary pressure boundary and reactor vessel
 
internal components constructed from SA-351 Grades CF3, CF3A, CF8, CF8A, CF3M, CF3MA, CF8M, with service conditions above 250°C (482°F). 
 
The screening criteria for susceptibility to thermal aging embrittlement are not applicable to
 
niobium-containing steels; such steels require evaluation on a case-by-case basis.
 
During the audit and review, the staff noted that the applicant, in the program evaluation
 
document clarifies that none of the VEGP CASS components are niobium-containing
 
steels. As such, the staff concludes that the limitation on use of the normal screening
 
criteria for niobium containing steels is not applicable to VEGP.
 
GALL XI.M12, Scope of Program states that based on the criteria set forth in the
 
Christopher Grimes letter dated May 19, 2000, the susceptibility to thermal aging
 
embrittlement of CASS components is determi ned in terms of casting method, molybdenum content, and ferrite content. For low-molybdenum content (0.5 wt.% max.) steels, only
 
static-cast steels with >20% ferrite are potentially susceptible to thermal embrittlement.
 
Static-cast low-molybdenum steels with 20% ferrite and all centrifugal-cast low-3-50 molybdenum steels are not susceptible. For high-molybdenum content (2.0 to 3.0 wt.%)
steels, static-cast steels with >14% ferrite and centrifugal-cast steels with >20% ferrite are
 
potentially susceptible to thermal embrittl ement. Static-cast high-molybdenum steels with 14% ferrite and centrifugal-cast high-molybdenum steels with 20% ferrite are not susceptible.
 
During the audit and review, the staff requested that the applicant identify all CASS
 
components that have been screened out from AMP B.3.5 based on the above screening criteria and to provide the bases (including relevant casting method information and
 
Molybdenum and delta-ferrite content parameter value information) for excluding these
 
components from the scope of the AMP.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. The applicant in its response stated that reactor coolant loop pipe castings are
 
centrifugally cast from CF8A (low Molybdenum) material. Using the criteria contained in the May 19, 2000 letter from Christopher Grimes to Douglas Walters, none of these castings
 
are susceptible to significant thermal embrittlement, regardless of the casting Mo and delta
 
Ferrite content. The VEGP reactor coolant loop elbow fitting castings, which are statically
 
cast from CF8A (low Mo) material, have been screened out from AMP B.3.5 using casting
 
data, based on the screening criteria in the Christopher Grimes letter dated, May 19, 2000.
 
However, the VEGP Unit 1 Loop 4 RCP inlet elbow and the VEGP Unit 2 Loop 1 RCP inlet
 
elbow are considered to be potentially susceptible to thermal embrittlement aging using
 
their casting data. The applicant also noted that the Mo content values for the component
 
with static casting were assumed at the max allowed by SA351 Grade CF8A in the absence
 
of measured Mo content.
The applicant also in its response provided the results of the SNC calculations for the
 
VEGP reactor coolant loop piping, loop fittings, and accumulator injection line laterals. As a
 
result of these analyses, the applicant determined the VEGP components that require
 
additional aging management under this program are the VEGP Unit 1 Loop 4 RCP inlet
 
elbow and the VEGP Unit 2 Loop 1 reactor coolant pump (RCP) inlet elbow. 
 
During the audit and review, the staff reviewed the CASS RCS Fitting Evaluation Program
 
and the supporting documents. The staff also reviewed the ferrite content calculation
 
method used for screening. On the basis of its review, the staff has determined that the
 
applicant has applied the NRC's screening criteria (i.e. criteria in the Christopher Grimes
 
letter of May 19, 2000) to establish those RCS CASS piping components that are
 
susceptible to thermal aging because the applicant has credited either inspection methods
 
or analysis methods to manage thermal aging embrittlement and the staff concludes the
 
applicant's response to the staff's question is acceptable. Therefore, the staff finds LRA B.3.5, with the exception described below, consistent with the GALL AMP XI.M12.
 
Exception In the LRA Section B.3.5, the applicant identified an exception to the following GALL Report program elements: 
 
Elements 5: Monitoring and Trending 6: Acceptance Criteria Exception: Flaw tolerance evaluations and any inspections will be performed in accordance with the VEGP Inservice Inspection Program Code of
 
Record at the time of the evaluation.
3-51  GALL Report Section XI.M12, describes the program as conforming to the requirements of the ASME Code, Section XI, 2001 Edition including the 2002 and 2003 Addenda, for flaw
 
tolerance evaluation and inspections. The staff noted that for the current inspection interval, the VEGP Inservice Inspection Program, which is augmented to detect the effects of loss of fracture toughness due to thermal embrittlement, uses ASME Section XI, 2001 Edition
 
including the 2002 and 2003 Addenda. The staff concludes that this is not an exception to
 
the GALL Report recommendations.
 
During the audit and review, the staff asked the applicant to explain why the relevant
 
statement on the Code Edition for the LRA B.3.5 is considered to be an exception to GALL AMP XI.M12, or clarify if the LRA needs to be amended to delete this exception based on
 
the staff's determination.
The applicant provided its response to the staff's question in a letter dated February 8, 2008. The applicant in its response stated that SNC understands it is the staff's interpretation that use of later Editions of ASME Section XI than the edition specified in the
 
GALL Report, Revision 1 for future inspection intervals is not an exception to the GALL Report, provided the Edition of ASME Section XI currently used is the same Edition
 
referenced in the GALL Report, Revision 1. As a result, the applicant in its letter dated
 
March 20, 2008 amended the "Exceptions to NUREG-1801" section of B.3.5 to read "None"
 
for the exception for this program. In addition, the applicant amended the "Program
 
Description" text for section B.3.5 to add the removed "Exception" text, along with the
 
content of footnote (1) from the LRA. The staff finds the applicant's response and the revision to LRA B.3.5 program consistent with the GALL AMP XI.M12 recommendation. The staff reviewed the amendment letter and verified that the applicant made the changes.
 
Operating Experience LRA Section B.3.5 states that the new CASS RCS Fitting Evaluation Program has no operating experience. 
 
To date, there has been no plant-specific or industry operating experience with degradation
 
of austenitic stainless steel castings due to thermal aging.
 
The screening criteria in use by the GALL Report and by the VEGP RCS CASS Fitting
 
Evaluation are based upon research data in NUREG/CR-4513, Revision 1. Flaw tolerance evaluation criteria are conservative based on Section XI of the ASME Boiler & Pressure
 
Vessel Code. Because the ASME Code is a consensus document widely used over a long
 
period, it has been effective in managing aging effects in components and their
 
attachments in light-water cooled power plants.
 
The staff noted that the CASS Evaluation Program is a new program for which no
 
programmatic operating experience exists. There has been no VEGP or industry field
 
operating experience regarding degradation of austenitic stainless steel castings due to
 
thermal aging. However, laboratory data clearly demonstrates that reductions in material
 
fracture toughness occur in cast austenitic stainless steels when operated at elevated
 
temperatures; however, this effect has yet to be observed in an operating PWR.
 
During the audit and review, the staff recognized that VEGP has ongoing programs to
 
monitor industry and site operating experience. These programs include mechanisms to
 
update or modify plant procedures or practices to incorporate lessons learned. The VEGP
 
operating experience procedures describes t he program for evaluating industry and vendor-3-52 supplied operating experience and possible modification of plant procedures or practices.
On this basis, the staff finds it acceptable that the future plant specific and industry
 
operating experience relevant to the CASS Evaluation Program will be captured by the plant operating experience procedures.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10; the staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section A.2.5, the applicant provided the UFSAR supplement for the CASS RCS Fitting Evaluation Program. In Enclosure 2 of its letter dated June 27, 2007, the applicant committed (Item No. 5) to implement, the CASS RCS Fitting Evaluation
 
Program described in LRA Section B.3.5, prior to the period of extended operation. 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).
 
Conclusion On the basis of its audit and review of the applicant's CASS RCS Fitting Evaluation Program, the staff concludes that those program elements, for which the
 
applicant claimed consistency with the GALL Report are consistent. The staff concludes
 
that the applicant has demonstrated that the effects of aging will be adequately managed
 
so that the intended function(s) will be maintained consistent with the CLB for the period of
 
extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR
 
supplement for this AMP and determined that it provides an adequate summary description
 
of the program, as required by 10 CFR 54.21(d).
 
3.0.3.2.4  Closed Cooling Water Program 
 
Summary of Technical Information in the Application LRA Section B.3.6 describes the existing Closed Cooling Water Program as consistent, with exceptions and an enhancement, with GALL AMP XI.M21, "Clos ed-Cycle Cooling Water System." 
 
The applicant stated that the Closed Cooling Water Program manages loss of material, cracking, and reduction in heat transfer in closed-cycle cooling water systems and
 
components cooled by these systems.
 
The program maintains corrosion inhibitor, pH -buffering agent, and biocide concentrations, monitors concentrations of detrimental ionic species, reduces them if necessary. and
 
monitors and evaluates important diagnostic par ameters for significant trends. The program also trends iron and copper concentrations, inspects components, and monitors corrosion
 
rates. 
 
The applicant also stated that the Closed Cooling Water Program is based on the EPRI
 
closed cooling water chemistry guidelines, currently "Closed Cooling Water Chemistry Guideline: Revision 1 to TR-107396, Closed Cooling Water Chemistry Guideline , EPRI, Palo Alto, CA: 2004. 1007820." The Closed Cooling Water Program updates follow
 
releases of EPRI guideline revisions.
 
The applicant stated that Closed Cooling Water Program enhancements will be
 
implemented prior to the period of extended operation.
 
3-53 Staff Evaluation During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions and an enhancement
 
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 the information in AMP B.3.6, "Closed Cooling Water Program," the
 
license renewal (LR) basis evaluation document, and the applicant's VEGP-specific
 
procedures that pertain to the design, details, and implementation of this AMP. 
 
The staff concludes that the applicant identifies that the Closed Cooling Water Program is
 
an existing AMP that is designed to be consistent with the program elements in GALL AMP XI.M21, "Closed Cooling Water System
," with exceptions and an enhancement.
Specifically, the staff reviewed those portions of the AMP program elements for which the applicant claims consistency with GALL AMP XI.M21. 
 
The staff concludes from its review of the LR basis evaluation document that the program elements for the Closed Cooling Water Program are consistent with the program elements in GALL AMP XI.M21 with the following two exceptions taken to GALL AMP XI.M21, and
 
one enhancement of the program. The staff's evaluation on how these exceptions and the
 
enhancement provide for adequate aging management is described in the paragraphs that
 
follow: 
 
Exceptions
 
Exception 1: The LRA states an exception to the "preventive actions" program element in GALL AMP XI.M21, "Closed Cooling Water Progr am." Specifically, the exception states:
The VEGP program currently uses the 2004 version of the EPRI
 
Closed Cooling Water Chemistry Guidelines (EPRI 1007820) and will
 
be updated periodically to incorporate later closed cooling water guidance. The program described in NUREG-1801, Section XI.M21, is based on the 1997 version of the EPRI Closed Cooling Water
 
Chemistry Guidelines, TR-107396. The VEGP program currently
 
uses the 2004 version of the EPRI Closed Cooling Water Chemistry
 
Guidelines and will be updated periodically to incorporate later closed
 
cooling water guidance. This difference is considered to be an
 
exception. 
 
The staff asked the applicant to clarify how EPRI Report No.1007820 differs from EPRI
 
Report No.107396 in its recommendations for preventive actions program element, and provide the basis why the preventive actions described in EPRI 1007820 are considered
 
acceptable for managing corrosion and stress corrosion cracking in the closed-cycle
 
cooling water systems.
 
In its response, dated February 8, 2008, the applicant stated that:
EPRI 1007820, "Closed Cycle Cooling Water Chemistry Guideline," Revision 1, supersedes EPRI TR-107396, "Closed Cycle Cooling Water Chemistry Guideline,"
Revision 0. Revision 1 includes normal ranges for chemistry control parameters, extends allowable corrosion inhibitor concentrations, and establishes well defined
 
action levels.
3-54 All VEGP closed-cycle cooling water systems included within the scope of license renewal currently use nitrite / azole based corrosion control. For a nitrite based
 
program, the differences between the Revision 0 and Revision 1 are summarily
 
described as follows:
 
Revision 1 revises the Nitrite, Azole, pH, Chloride, Fluoride, dissolved oxygen 
 
control range, it also specifies monitoring frequencies for Tier 1, Tier 2, and
 
Intermittent Systems Revision 1 of the EPRI Closed Cooling Water Guidelines provides an acceptable
 
basis for managing corrosion and SCC in closed cooling water system, Revision 1
 
is a considerably more prescriptive guideline, which results in an improved
 
application of chemistry controls.
 
The staff noted that GALL.AMP XI.M21 recommends that the program include (a) preventive measures to minimize corrosion and stress corrosion cracking (SCC) and (b)
 
testing and inspection to monitor the effects of corrosion and SCC on the intended function of the component. The GALL AMP XI.M21 also relies on maintenance of system corrosion
 
inhibitor concentrations within the specified limits of Electric Power Research Institute (EPRI) TR-107396 to minimize corrosion and SCC, non-chemistry monitoring techniques
 
such as testing and inspection in accordance with guidance in EPRI TR-107396 for closed-
 
cycle cooling water (CCCW) systems provi de one acceptable method to evaluate system and component performance. These measures, recommended by GALL AMP XI.M21, will ensure that the intended functions of the CCCW system and components serviced by the
 
CCCW system are not compromised by aging. 
 
The staff reviewed the applicant's evaluation and confirmed that the applicant had
 
incorporated EPRI TR-1007820 as the technical basis guideline for the Water Chemistry
 
Control - Closed Cooling Water Program. The staff concludes that the use of EPRI TR-1007820 provides guidance consistent with the recommendations in GALL AMP XI.M21
 
and offers more detail on the various water treatment methods used at nuclear power
 
plants, as well as control and diagnostic parameters, monitoring frequencies, operating
 
ranges, and action levels. 
 
Therefore, the staff finds the use of EPRI TR-1007820 as the basis for this program
 
acceptable.
 
On this basis, the staff concludes that the use of EPRI Report No. TR-1007820 is an
 
acceptable alternative industry guideline for the Closed Cycle Cooling Water Systems and
 
will continue to provide adequate aging management guidelines of Closed Cycle Cooling Water Systems and components that are within the scope of the program.
 
Based on the above assessment and staff evaluation, the staff concludes that this
 
exception to the "preventive actions program element" in GALL AMP XI.M21 is acceptable. 
 
Exception 2:  The LRA states an exception to the "parameters monitored/inspected,"
"detection of aging effects," "monitoring and trending," and "acceptance criteria, " program elements in GALL AMP XI.M21,"Closed-Cycle Cooling Water System." 
 
3-55 Specifically, the exception states:
The VEGP program is based on EPRI 1007820, which does not include
 
performance monitoring and functional testing. The VEGP program uses
 
corrosion monitoring techniques to manage component degradation that
 
could impact a passive function. **
**This exception includes the following footnote The program described in NUREG-1801, Section XI.M21, describes
 
performance testing and functional testing as performed in accordance with
 
EPRI TR-107396. The VEGP program is based on EPRI 1007820, which
 
does not include performance monitoring and functional testing as a key
 
part of a closed cooling water program. EPRI 1007820 notes that
 
performance testing is typically part of an engineering program. In most
 
cases, functional and performance testing verify that component active
 
functions can be accomplished and as such would be included as a part of
 
Maintenance Rule (10 CFR 50.65). Therefore, performance monitoring and
 
functional testing is not included as a part of the VEGP Closed Cooling
 
Water Program. The VEGP program uses corrosion-monitoring (which
 
includes component inspections) to monitor program effectiveness at
 
managing component degradation that could impact a passive function.
 
The staff asked the applicant to identify the corrosion monitoring techniques that will be
 
applied as part of this exception and to provide its basis for concluding that corrosion
 
monitoring alone is considered to be capable of managing aging for the period of extended
 
operation without crediting any performance or functional tests, as is otherwise recommended in "GALL AMP XI.M21"Closed-Cycle Cooling Water System."
In its response, dated February 8, 2008, the applicant stated that
: Corrosion monitoring aspects of the SNC Closed Cooling Water Program implemented to-date include monitoring and trending iron and copper
 
concentrations and limited corrosion coupon measurements.
 
Measurement of accumulated corrosion products such as iron and copper
 
provides an indirect indication of syst em corrosion. Each system establishes normal concentrations of these corrosion products. Consequently, a specific
 
not to exceed value cannot be assigned. Rather, it is the overall trends
 
which provide meaningful informati on regarding system corrosion rates.
Corrosion coupons are installed in the VEGP Turbine Plant Cooling Water
 
System. Measurement of coupon weight loss is an effective means to assess corrosion rates.
As summarized in the enhancement subsection of LRA Section B.3.6, additional corrosion monitoring techniques will be implemented prior to the
 
period of extended operation. Currently, the monitoring techniques being
 
considered include electrochemical monitoring, such as linear polarization 3-56 measurement or electrochemical noise corrosion rate monitoring, and corrosion inspections.
Electrochemical monitoring techniques, corrosion inspection techniques, primarily in the form of visual inspections are important parts of the
 
inspection process. Inspection techniques will vary depending on the
 
component type being inspected (piping, valves, heat exchangers, pump
 
casings, etc.).
While NUREG-1801 Section XI.M21 endorses performance and functional
 
testing with EPRI TR-107396 as a basis, neither EPRI TR-107396, nor
 
EPRI 1007820 conclude that performance or functional testing are effective
 
for detection of passive component aging effects. However, both EPRI
 
documents also recognize that performanc e monitoring is typically part of an engineering program. In most cases, functional and performance testing
 
verifies that component active functions can be accomplished and such
 
would be governed by the maintenance rule (10 CFR 50.65). For example, corrosion cannot be detected by system performance testing.
Therefore, performance monitoring and functional testing is not included as
 
a part of the VEGP Closed Cooling Water Program. The VEGP program
 
uses corrosion-monitoring (which includes component inspections) to
 
monitor program effectiveness at managing component degradation that
 
could impact a passive function.
 
The staff noted that while GALL AMP XI.M21 endorses performance and functional testing
 
with EPRI TR-107396 as a basis, neither EPRI TR-107396 nor EPRI 1007820 determined
 
that performance or functional testing are effective for detection of passive component
 
aging effects. 
 
Also, the staff noted that VEGP program uses corrosion-monitoring, that will be
 
implemented prior to the period of extended operation and, also the functional testing is
 
done as per the maintenance rule.
 
The staff reviewed EPRI Report TR-1 007820 (Revision 1 to EPRI TR-1 07396) and
 
determined that it does not recommend that performance and functional testing be part of
 
the water chemistry control program. This engineering testing could be performed as part of
 
another program. Usually, the Maintenance Rule (10 CFR 50.65) dictates the requirements
 
of the performance and functional testing, although Technical Specification (TS) 3.7 does
 
mandate some performance/functional testing for the Vogtle component cooling water (CCW) system. The staff also noted that the applicant does sample and test corrosion
 
coupons in the Turbine Plant Cooling Water System (TPCW) to monitor the effects of
 
corrosion on the system and that the applicant indicated that it may use electrochemical
 
potential monitoring techniques as additional potential monitoring techniques for the
 
components that are within the scope of this program. The staff finds that these measures
 
will provide for an adequate means of managi ng corrosion in the CCCW systems because the applicant does inspect the components (condition monitoring) for corrosion and
 
because the applicant does actually perform some performance/functional testing to
 
manage corrosion that may potentially occur in the CCCW systems (i.e. required
 
performance/functional testing of the CCW system components). Therefore, the staff finds
 
that the activities included in this program are adequate to manage the aging effects for 3-57 which the program is credited without the need for performance and functional testing. On this basis, the staff finds this exception acceptable.
 
This exception is acceptable, because, the staff concludes that this exception to the
 
"parameters monitored/inspected," "detection of aging effects," monitoring and trending,"
 
and "acceptance criteria," program elements is adequate to manage the aging effects for
 
which it is credited. The exception, therefore, is acceptable.
 
Enhancement
: The LRA states an enhancement to the "parameters monitored/inspected program element in GALL AMP XI.M21, "Clos ed Cooling Water Program" Specifically, the enhancement states:
 
The VEGP Closed Cooling Water Program Strategic Plan will be updated to
 
indicate the components in each system that are most susceptible to
 
various corrosion mechanisms and to ensure that corrosion monitoring is
 
appropriately implemented.
 
During the audit, the staff asked the applicant to clarify how a ranking of the in-scope
 
components would be accomplished based on the susceptibility to corrosion mechanisms
 
and clarify how the susceptibility ranking will be applied to the AMP in order to pick
 
components for inspection.
 
In its response, dated February 8, 2008, the applicant stated that:
 
A reasonable assessment of system components most susceptible to
 
corrosion can be developed using a fundamental understanding of corrosion
 
principles associated with closed cooling water chemistries and review of
 
system, plant, and industry operating experience.
Components located in stagnant regions or in systems that are infrequently
 
operated and components with creviced regions are at greater risk for
 
significant corrosion since adequate transport of corrosion inhibitors, pH
 
buffering agents, and biocides to the component location may not occur and
 
adequate transport of corrosion products away from the component may not
 
occur. In these cases, inadequate corrosion film development, deposit
 
formation, and increased microbiological activity could result in increased
 
corrosion rates not consistent with observed corrosion rates for other
 
portions of the system. Additionally , creviced areas could experience differential aeration, resulting in localized attack of material within the
 
crevice. Components located in higher temperature regions could experience higher
 
corrosion rates due to the fundamental temperature dependence on
 
corrosion rates.
Review of system and plant operating experience provides a valuable tool
 
for use in estimating component locations most likely to be more susceptible
 
to degradation mechanisms.
Finally, reviews of industry-wide operating experience, including chemistry
 
history, inspection results, and repair histories, can provide valuable insights 3-58 into the corrosion processes occurring within closed cooling water systems and can be incorporated into susceptibility evaluations for these systems.
Based on this response, SNC will enhance VEGP License Renewal future
 
action commitment list Item no. 6 as follows:
Enhance Closed Cooling Water Program documents to indicate the
 
components in each system that are most susceptible to various corrosion
 
mechanisms and to ensure that corrosion monitoring is appropriately
 
accomplished. This qualitative assessment will be based on an
 
understanding of corrosion principles associated with closed cooling water
 
chemistries and on review of system, plant, and industry operating
 
experience. Parameters considered in the review will include system flow
 
parameters (focusing on identification of stagnant regions and on
 
intermittently operated systems), normal operating temperatures, and component geometries (e.g. creviced areas).
 
The applicant's CCW is a CCCW system and is within the scope of the limiting conditions
 
for operation in Technical Specification (TS) 3.7. The staff verified that TS 3.7 does require
 
the applicant to perform verification of CCW flow once every 18 months. The staff noted
 
that the applicant response indicates that corrosion monitoring (inspections) will be
 
performed on those components in each system that are considered to be most
 
susceptible, as based on plant, system and industry-wide operating experience with
 
corrosion and on the utilization of the fundamentals of corrosion principles to various
 
corrosion mechanisms. The staff considers this question to be resolved because the
 
applicant will use appropriate industry and engineering bases to select for inspection those
 
CCCW components that are considered most susceptible to corrosion and because the
 
applicant does perform some functional/performance testing on the CCW system in
 
accordance with Vogtle TS. The staff also verified that the applicant amended the LRA in a
 
letter dated March 20, 2008, and in this letter the applicant provided its updated version of
 
LRA Commitment No.6 as discussed above.
 
Based on this review, the staff finds that the applicant's enhancement of the program, as
 
described in Commitment No.6, in acceptable for aging management because the applicant
 
will inspect  those components that are identified as being most susceptible to corrosion
 
and because the applicant does perform some functional testing of the CCW system in
 
accordance with Vogtle TS. Based on this review, staff concludes that the enhancement of
 
the "parameters monitored/inspected" program element, as described in LRA Commitment No. 6, will make VEGP AMP B.3.6, consistent with GALL AMP XI.M21, "
 
Closed Cooling Water Program," and that th is enhancement of the program will provide additional assurance that the effects of aging will be adequately managed.
 
Operating Experience LRA Section B.3.6 states that the Closed Cooling Water Program is based on EPRI guidelines based on plant experience, research data, and expert opinion.
 
Industry, by consensus, periodically updates and improves these guidelines.
 
The staff noted that the applicant did identify some issues regarding nitrite intrusions in
 
some of its CCCW systems. The staff verified that the applicant had resolved most of the
 
issues with nitrite intrusions by implementing feed and bleed operations which brought the
 
nitrite concentrations back to acceptable values.
 
3-59 The staff noted however, that applicant did identify some issues regarding nitrite intrusions in the VEGP Unit 2 auxiliary component coolant water (ACCW) system that did lead to some stress corrosion cracking and some leakage in the system. The staff verified that, to
 
date, the SCC-induced leakage (caused by nitrite intrusion) has been limited to the VEGP
 
Unit 2 ACCW system. The staff noted that the applicant developed, credits, and implements its ACCW Carbon Steel Components Program solely for the purpose of managing SCC
 
induced cracking of the VEGP Unit 2 ACCW system. The staff evaluated the ability of this
 
program to manage SCC-induced cracking of the VEGP Unit 2 ACCW system in SER Section 3.0.3.3.1 Based on this review, the staff finds that the applicant has adequately
 
resolved the issues regarding nitrite intrusion in the CCCW systems. The staff verified that
 
the applicant has not identified any adverse trends with respect to iron and copper
 
concentrations in the CCCW systems.
 
The staff also noted that the applicant did identify some degradation of the composite
 
polymer (Ceram Alloy) coatings in the em ergency diesel generator system lube oil heat exchangers, and in particular minor blistering and flaking of the coating system without any
 
significant deterioration of the underlying base metals. The staff verified, however, that
 
VEGP is removing the Ceram Alloy coatings and that the applicant does not take any
 
license renewal credit for these coatings. Thus, the staff finds that this OE does not impact
 
the ability of the Closed Cooling Water System Program to manage the effects of corrosion
 
in those CCCW components that are exposed to the treated water environments of the
 
CCCW systems. 
 
Based on the aforementioned verification by staff, the staff concludes that the "operating
 
experience" program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.10
 
UFSAR Supplement
 
The staff reviewed the UFSAR Supplement summary description that was provided in LRA
 
Section A.2.6 for the Closed Cooling Water Program. The staff verified that, in LRA
 
Commitment No. 6 in the applicant's response letter dated March 20, 2008, the applicant
 
committed to enhance the program and associated documents to indicate the most
 
susceptible components for corrosion and to implement the Closed Cooling Water Program
 
prior to the period of extended operation. The staff also verified that the applicant has
 
placed this commitment on UFSAR Supplement summary description A.2.6 for Closed
 
Cooling Water Program. 
 
Based on this review, the staff finds that UFSAR Supplement Section A.2.6 provides an
 
acceptable UFSAR Supplement summary description of the applicant's Closed Cooling
 
Water Program, when enhanced will manage loss of material, cracking and reduction of
 
heat transfer in the closed-cycle cooling water systems and any components cooled by these systems and will be implemented as committed to in LRA Commitment No. 6
 
because it is consistent with those UFSAR Supplement summary description in the SRP-LR
 
for the Closed Cycle Cooling Water System. Therefore, the staff concludes that the UFSAR
 
supplement for this AMP provides an adequate summary description of the program, as
 
described by 10 CFR 54.21(d).
 
Conclusion On the basis of its audit and review of the applicant's Closed Cooling Water Program, the staff concludes that those program elements, for which the applicant claimed
 
consistency with the GALL Report, are consistent. In addition, the staff reviewed the 3-60 exceptions and their justifications and determined 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 its implement ation prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it
 
was compared. The staff concludes that the applicant has demonstrated that the effects of
 
aging will be adequately managed so that the intended functions will be maintained
 
consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
determined that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
 
3.0.3.2.5  External Surfaces Monitoring Program 
 
Summary of Technical Information in the Application LRA Section B.3.8 describes the new External Surfaces Monitoring Program as consistent, with exceptions, with GALL AMP XI.M36, "External Surfaces Monitoring." 
 
The applicant stated that the External Surfaces Monitoring Program inspects external
 
surfaces of mechanical system components in external air environments requiring aging management for license renewal at frequencies that assure management of the effects of
 
aging so system components will perform thei r intended functions during the period of extended operation.
 
The program detects corrosion, flange leakage, missing or damaged insulation, damaged
 
coatings, and indications of fretting or wear. The program also provides inspections of
 
insulated surfaces on a sampling basis which target areas that have been indicated by
 
baseline inspections and operating experience as the most susceptible. Inspection of
 
accessible polymers and elastomers is for age-related degradation, including cracking, peeling, blistering, chalking, crazing, delamination, flaking, discoloration, physical distortion, embitterment (hardening), and gross softening.
 
The applicant also stated that the program provides for inspections of systems and components normally inaccessible and not r eadily available when they are made accessible during outages, routine maintenance, or repair or by remote means (borescope, robotic camera, etc.).
 
The External Surfaces Monitoring Program will be implemented prior to the period of extended operation.
 
Staff Evaluation During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. 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 the applicant's license renewal basis evaluation documents and VEGP-
 
specific procedures for AMP B.3.8, "External Surface Monitoring Program," the license
 
renewal basis evaluation document, and VEGP-specific procedures that pertain to the
 
design, details, and implementation of this AMP. The applicant identifies that the External
 
Surfaces Monitoring Program is a new AMP that is designed to be consistent with the program elements in GALL AMP XI.M36, "Ext ernal Surface Monitoring Program," with exceptions.
3-61  This program consists of periodic visual inspections of steel components such as piping, piping components, ducting, and other components within the scope of license renewal and
 
subject to AMR in order to manage aging effects. The program manages aging effects
 
through visual inspection of external surfaces for evidence of material loss.
The staff concludes from its review of the license renewal basis evaluation document that
 
the program elements for the VEGP External Surface Monitoring Program are consistent with the program elements in GALL AMP XI.M36 with the following four exceptions. The
 
staff's evaluation on how these excepti ons provide for adequate aging management is described in the following: 
 
Exceptions Exception 1: The LRA states an exception to the "scope of program" and "parameters monitored/inspected" program elements in GALL AMP XI.M36, "External Surface Monitoring Program." Specifically, the exception states:
 
The VEGP program scope will include additional materials such as
 
elastomers, aluminum, and copper. The GALL program is described as
 
being applicable to steel components only.
 
The staff noted that the GALL AMP XI.M36 does not address age related degradation that
 
may occur in elastomers, aluminum and copper materials, susceptible to age related
 
degradation. 
 
The staff concludes that it is acceptable to include aluminum and copper components within
 
the scope of the AMP, because these materials are metals that can be susceptible to corrosive loss of material effects.
 
In RAI 3.3-1 and 3.4-1, the staff asked the applicant to clarify how the External Surface
 
Monitoring Program could be used to manage cracking and changes in material properties
 
for polymer based components (including elastomers) with a visual inspection only.
 
By letter dated July 17, 2008, the applicant provided its response to RAI 3.3-1 and 3.4-1. In
 
its response, the applicant stated that this AMP does not only credit visual examinations to
 
detect cracking and changes in material properties of polymers. The applicant further stated
 
that visual examinations will be performed to detect discontinuities and imperfections on the
 
surface of the component, and non-visual examinations such as tactile techniques, which
 
include scratching, bending folding, stretching and pressing will be performed in conjunction
 
with the visual examinations.
 
The staff noted that VEGP is crediting both visual examinations and tactile techniques to
 
detect for cracking and change in material properties for elastomers and polymers. The
 
staff further noted that applicant described the specific tactile techniques that may be used
 
in conjunction with the visual examination. The staff noted that these techniques include
 
scratching the material surface to screen for residues that may indicate a breakdown of the
 
polymer material, bending or folding of the component which may indicate surface cracking, stretching to evaluate resistance of the polymer material and pressing on the material to
 
evaluate the resiliency. Based on its review of the applicant's response, the staff finds it
 
acceptable because the applicant has indicated that VEGP is not crediting visual 3-62 examinations alone to detect cracking and change in material properties for elastomers and polymers, and that VEGP has credited tactile techniques, as described above, as well to
 
detect for such aging effects as cracking and change in material properties.
 
In addition, the staff reviewed the exception and its justification and determined that the
 
AMP, with the exception, is adequate to manage the aging effects for which it is credited.
 
The exception, therefore, is acceptable. 
 
Exception 2: The LRA states an exception to the "scope of program" and "detection of
 
aging effects" and "monitoring and trending" program elements in GALL AMP XI.M36, "External Surface Monitoring Program." Specifically, the exception states:
 
For areas that are inaccessible during both normal operations and refueling
 
outages, the VEGP program will inspect the area when it is made accessible
 
during maintenance or for other reasons. These areas may also be
 
inspected by remote means (borescope, robotic camera, etc.).
 
During the audit and review, the staff asked the applicant to justify the basis for taking this
 
exception. Specifically the staff asked the applicant to provide a clarification on when the alternative methods (such as borescope inspec tions or examinations by remote camera) will be implemented if the inaccessible regions are not made accessible in accordance with
 
a reasonable maintenance frequency.
 
In its response, dated February 8, 2008, the applicant stated:
The inaccessible areas will be inspected when made accessible during maintenance or for other reasons (opportunistic inspections).
 
In addition, these areas will be evaluated to ensure that accessible
 
systems and components are constructed of the same materials and
 
are exposed to the same or a more severe environment as the
 
systems and components in the inaccessible area. The intent of this
 
evaluation is to provide a degree of assurance that components in
 
the inaccessible area are not degrading faster than components
 
which are accessible for inspection.
If an opportunistic inspection is not performed within the inspection
 
interval established for that area, the inaccessible area will be
 
inspected either by making the area accessible or by remote means.
 
The determination as to whether the inspection will be performed by
 
direct or remote visual techniques will be performed on a case-by-
 
case basis depending upon factors such as radiation dose rates, personnel safety considerations, and size and configuration of the
 
area to be inspected. An area which is determined to be inaccessible
 
due to extreme personnel safety hazards, such as a very high
 
radiation area, will be inspected only when made accessible during
 
maintenance or for other reasons, or if there is evidence of leakage in
 
the area.
The existence of leakage detection capability combined with the
 
ability to isolate affected components ensures that leakage will be
 
detected and isolated prior to loss of a component intended function 3-63  The staff noted the applicant will inspect inaccessible areas during periods of opportunistic inspections and that VEGP will evaluate these inaccessible areas to ensure that these
 
materials are the same as those in the components and systems in the accessible area
 
with either an equivalent or less severe environment in the inaccessible area. The applicant
 
states that this evaluation is meant to provide assurance that the components in the inaccessible area are not degrading more rapidly than those in the accessible area. The
 
staff further noted that if an opportunistic inspection is not made available during the
 
inspection interval then either the area will be made available or inspected remotely. The staff concludes that the applicant's response is acceptable because inaccessible areas will
 
be inspected when an opportunity is made avail able by either making them accessible and performing direct inspection of the components or by using remote inspection techniques.
 
Based on this assessment, the staff concludes that this exception to the "scope of
 
program," "detection of aging effects," and "monitoring and trending," program elements is
 
acceptable and is adequate to manage the aging effects for which it is credited. 
 
Exception 3: The LRA states an exception to the "detection of aging effects," and monitoring and trending," program elements in GALL AMP XI.M36, "External Surface
 
Monitoring Program." Specifically, the exception states:
 
The VEGP External Surfaces Monitoring Program is not credited for
 
managing loss of material from internal surfaces. This is conservatively
 
treated as an exception to the GALL statement.
 
The staff reviewed the information in the VEGP AMP B 3.22, "Piping and Duct Internal
 
Inspection Program, which specifically is the program that is credited for managing loss of material from inner surfaces. This program is consistent with the program described in GALL Report, Section XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and
 
Ducting Components." The staff's evaluation is documented in Section 3.0.3.2.13 of this
 
SER.
 
This exception is acceptable, because the staff has verified that the applicant has credited
 
VEGP AMP B 3.22 for managing loss of material from inner surfaces instead of the applicant's External Surface Monitoring Program and because GALL AMP XI.M36 does not
 
intend that the External Surface Monitoring be credited for interior piping component
 
surfaces.
 
Based on this review, the staff finds that the exception and its justification is acceptable and
 
is adequate to manage the aging effects for which it is credited. 
 
Exception 4: The LRA states an exception to the "program scope,"" preventive actions," 
"parameters monitored/inspected," "detection of aging effects," "monitoring and trending,"
and "acceptance criteria" program elements in GALL AMP XI.M36, External Surface
 
Monitoring Program." Specifically, the exception states: 
 
The acceptance criteria in the program implementing procedures will not cite
 
specific design codes or standards. This is considered an exception to
 
GALL, which states:
Acceptance criteria include design standards, industry codes or standards, 3-64 and engineering evaluation. The scope of the VEGP External Surfaces Monitoring Program will include a wide range of systems covered by ASME Class 2, ASME Class 3, ANSI B.31.1, NFPA, AWWA, plumbing, and
 
Manufacturer's codes and standards in a variety of pipe and component
 
sizes, therefore specific quantitative acceptance criteria (e.g., minimum pipe
 
wall thickness) will not be included for practical considerations. The
 
inspections will be focused on identifying qualitative indications of corrosion.
 
The quantitative evaluation of deficient conditions, such as comparison of
 
pipe wall thickness with code minimum allowable, will be performed as part
 
of the corrective action process initiated when a Condition Report (CR) is
 
written for a deficient condition.
 
During the audit and review, the staff asked the applicant its basis for taking this exception
 
and to provide its basis, why AMP B.3.8, External Surfaces Monitoring Program does not
 
include specific acceptance criteria for each of the aging effects monitored by the AMP, as
 
based on one or more recommended source documents referenced in the "acceptance criteria" program element of GALL AMP XI.M36.
In its response, dated February 8, 2008, the applicant stated:
This exception was included to clarify that the VEGP External Surfaces Monitoring Program will not include specific quantitative
 
acceptance criteria derived from design standards or industry codes
 
such as the ASME Boiler & Pressure Vessel Code. The scope of this
 
program will include a wide range of systems covered by ASME Class 2, ASME Class 3, ANSI B.31.1, National Fire Protection
 
Association, American Water Works Association, plumbing, and
 
manufacturer's codes and standards in a variety of pipe and
 
component sizes. Therefore, the inspections will be focused on
 
identifying qualitative indications of corrosion. The quantitative
 
evaluation of deficient conditions, such as comparison of pipe wall
 
thickness with code minimum allowable, will be performed as part of
 
the corrective action process initiated by a Condition Report (CR).
 
The CR will identify the specific system and location to be evaluated, so the applicable codes or standards can be readily determined to
 
support the evaluation of the deficient condition and the
 
determination of corrective actions that will be performed in
 
accordance with the corrective action process.
 
The staff noted the scope of VEGP External Surface Monitoring Program includes a wide
 
range of systems and variety of pipe and component sizes, and that the applicant will apply
 
corrective actions in accordance with the design code or standard for the component upon
 
any detection of corrosion resulting from this AMP's inspections. The staff noted that the
 
applicant will use the specific code or standard applicable to the component design.
 
Based on this review, the staff finds that the exception and its justification is acceptable, and satisfies the criteria stated in the "acceptance criteria" program element in GALL AMP XI.M36 because the applicant uses detection of corrosion as a conservative acceptance
 
criterion for initiating appropriate corrective actions.
 
3-65 Operating Experience LRA Section B.3.8 states that this new program has no programmatic operating experience. However, the results of existing system monitoring and
 
material condition reporting programs are relevant to this program. The applicant stated
 
that visual inspection techniques are well proven in the industry and have been
 
demonstrated as an effective means for detecting degradation. Corrosion of external
 
surfaces has been reported in the course of performing various maintenance and
 
surveillance activities. These existing activiti es have proven effective in maintaining the material condition of plant systems.
 
During the audit and review, the staff reviewed the operating experience review discussed
 
in the basis document for the External Surfaces Monitoring Program and finds that the
 
applicant's reviews did not reveal any unusual or significant findings. The staff also finds
 
that the applicant did not identify any age-related related issues not bounded by the
 
industry operating experience.
 
Based on the aforementioned verification by staff, the staff concludes that the "operating
 
experience" program element satisfies the cr iterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. 
 
UFSAR Supplement In LRA Section A.2.8, the applicant provided the UFSAR supplement for the External Surfaces Monitoring Program. The staff verified Commitment No. 7
 
provided in the applicant's letter dated June 27, 2007 and confirmed that this new program
 
is scheduled to be implemented prior to the period of extended operation. The staff has
 
evaluated why this AMP when taken into account with LRA Commitment No. 7 will be
 
adequate to manage loss of material in external component surfaces that are within the
 
scope of this AMP. The staff reviewed the UFSAR Supplement 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).
 
Conclusion On the basis of its audit and review of the applicant's External Surfaces Monitoring Program, the staff concludes 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 determined that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.2.6  Fire Protection Program
 
Summary of Technical Information in the Application LRA Section B.3.9 describes the existing Fire Protection Program as consistent, with exceptions and enhancements, with GALL AMPs XI.M26, "Fire Protection," and XI.M27, "Fire Water System." 
 
The applicant stated that the Fire Protection Program includes inspections, performance
 
testing, and condition monitoring of water- and gas-based fire protection systems, fire
 
barriers, and fire pump diesels and their fuel oil supply components. Program
 
implementation through various plant proc edures will manage fire protection components 3-66 relied upon for 10  CFR 50.48 compliance effectively to maintain intended functions through the period of extended operation.
 
The gas-based fire protection systems m anaged by the program include fixed Halon gaseous suppression systems. VEGP does not rely upon fixed-CO 2 gaseous suppression systems to meet 10 CFR 50.48 requirements and thus there are no fixed-CO 2 fire suppression systems within the scope of license renewal. 
 
The program manages water-based fire suppression systems with sprinklers, nozzles, valves, hydrants, fittings, hose stations, standpipes, water storage tanks, and above-ground
 
and underground piping components. The program maintains water-based systems at
 
normal operating pressure and detects and remedies any loss of system pressure promptly. 
 
The applicant also stated that testing and inspection of water- and gas-based fire
 
suppression systems are in accordance with plant procedures based in part on National
 
Fire Protection Association codes and standards. Periodic inspections, performance
 
testing, and system monitoring effectively assures component functionality.
 
The fire barrier inspections include periodic visual inspection of structural fire barriers, including fire walls, floors, ceilings, fire penetration seals, and fire doors. 
 
Periodic inspections and tests of diesel-driven fire pumps and fuel oil supply components
 
ensure that the diesels, pumps, and fuel oil supply components can perform intended
 
functions. 
 
Enhancements to the Fire Protection Program will be implemented prior to the period of extended operation.
 
Staff Evaluation During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. 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 interviewed the applicant's technical staff and reviewed the Fire Protection
 
Program bases documents including VEGP-FSAR Tables 9.5.1-9 and 9.5.1-10.
 
Specifically, the staff reviewed the program elements and associated bases documents to determine consistency with GALL AMP XI.M26 and XI.M27. The staff noted that CO 2 suppression systems are not relied on at VEGP to meet the requirements of 10 CFR 50.48
 
and thus they are not within the scope of license renewal.
 
The staff reviewed those portions of the Fire Protection Program for which the applicant claims consistency with GALL AMP XI.M26 and found that they are consistent with the
 
GALL AMP. Furthermore, the staff concludes that the applicant's Fire Protection Program
 
reasonably assures management of aging effects so components crediting this program
 
can perform intended functions consistent with the CLB during the period of extended
 
operation. The staff finds the applicant's Fire Protection Program acceptable because it conforms to the recommended GALL AMP XI.M26, "Fire Protection," with an exception and
 
enhancements as described below
 
Exception. The LRA states the following exception to the GALL Report program element:
 
3-67 Element: 3: parameters monitored/inspected  4: detection of aging effects
 
Exception: Performance testing of the fixed Halon fire suppression system is performed at 18 month intervals rather than at least
 
once every 6 months as specified by NUREG-1801, Section XI.M26. 
 
During the audit and review, the staff asked the applicant to provide technical justification
 
why the proposed testing frequency is acceptable to detect degradation of the Halon fire
 
suppression system before the loss of the component's intended function. 
 
In its response, the applicant stated that there have been no age-related failures observed
 
in the fixed Halon fire suppression system, which would agree with industry experience in
 
the use of a dried gas. The applicant also stated that it also performs visual inspections of
 
the Halon system for corrosion, physical damage, and nozzles free of corrosion, and
 
obstruction, at 6-month intervals. In addition, if a trend in Halon system degradation is
 
observed during inspections, the VEGP correctiv e action program requires evaluation of the existing testing and surveillance frequencies. 
 
The staff noted that the GALL Report recommends a six-month periodicity for the full Halon
 
system functional test. In reviewing this exception, the staff noted that the VEGP Fire
 
Protection Program directs Halon fire suppression system surveillance that verifies
 
conditions of external surfaces of the Halon system, and Halon storage tank weight, level, and pressure every six months. Actuation of the system (automatic and manual, including dampers) and flow are verified every 18 months. The program also directs performance of functional operability testing and flow verification, including operation of associated
 
ventilation dampers and manual and automatic actuation. The staff also noted that the
 
current licensing basis for periodic inspection and functional test frequency of the Halon
 
system is every 18 months. 
 
Although the frequency of functional testing exceeds that recommended in GALL AMP XI.M26, the staff concludes that it is sufficient to ensure system availability and operability
 
with the existing surveillance which includes visual inspections of component external
 
surfaces for signs of corrosion and mechanical damage, and verification of Halon storage
 
tank weight, level, and pressure. In addition, the staff's review of the station operating
 
history indicates no aging-related events adverse ly affecting system operation exists at VEGP. Furthermore, since the VEGP Halon sy stems are small, one room systems where all system piping is subjected to the same controlled atmospheric environment, they are not subject to any corrosion mechanism. Based on its review of the applicant's program and
 
plant-specific operating experience, the staff finds that the 18-month frequency is adequate
 
for aging management considerations. On this basis, the staff finds this exception
 
acceptable.
 
Enhancements. The LRA states that the following enhancements to the GALL Report program elements prior to the period of extended operation:
 
Enhancement 1
 
Elements:  3. parameters monitored/inspected 3-68 4. detection of aging effects Enhancement:  The VEGP Fire Protection Program will be enhanced to perform wall thickness evaluations on water suppression
 
piping systems using non-intrusive volumetric testing or visual
 
inspections to ensure that wall thicknesses are within
 
acceptable limits, as specified by NUREG-1801, Section XI.M27. Initial wall thickness evaluations will be performed
 
before the end of the current operating term. Subsequent
 
evaluations are performed at plant specific intervals during
 
the period of extended operation. The plant specific
 
inspection intervals will be determined based on evaluation of
 
previous evaluations and site operating experience.
The staff concludes that this enhancement is acceptable because when the enhancement
 
is implemented, Fire Protection Program el ements "parameters monitored/inspected," and "detection of aging effects," will be consistent with GALL AMP XI.M27 program elements "parameters monitored/inspected," and "detection of aging effects," which state that w all thickness evaluations of fire protection piping are performed on system components using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of
 
material due to corrosion. These inspections are performed before the end of the
 
current operating term and at plant-specific intervals thereafter during the period of extended operation. As an alternative to non-intrusive testing, the plant maintenance process may include a visual inspection of the internal surface of the fire protection piping upon each entry to the system for routine or corrective maintenance, as long as
 
it can be demonstrated that inspections are performed (based on past maintenance history) on a representative number of locations on a reasonable basis.
The applicant identified this enhancement as Commitment No. 8 (NL-07-1261, dated June 27, 2007) to be implemented prior to the period of extended operation.
 
Enhancement 2
 
Elements:  4. detection of aging effects
 
Enhancement:  The VEGP Fire Protection Program will be enhanced to inspect a sample of sprinkler heads using the guidance of
 
NFPA 25 "Inspection, Testing and Maintenance of Water-
 
Based Fire Protection Systems" (1998 Edition), Section 2-
 
3.1.1, or NFPA 25 (2002 Edition), Section 5.3.1.1.1, as specified by NUREG-1801, Section XI.M27. Where sprinkler
 
heads have been in place for 50 years, they will be replaced
 
or representative samples from one or more sample areas will
 
be submitted to a recognized testing laboratory for field
 
service testing. This sampling is performed every 10 years
 
after the initial field service testing. The 50 years of time in
 
service begins when the system was placed in service, not
 
when the plant became operational.
 
The staff concludes that this enhancement is acceptable because when the enhancement
 
is implemented, Fire Protection Program element "detection of aging effects," will be 3-69 consistent with GALL AMP XI.M27 element "detection of aging effects," which states that the sprinkler heads are inspected before the end of the 50-year sprinkler head service life and at 10-year intervals thereafter during the period of extended operation to
 
ensure that signs of degradation, such as corrosion, are detected in a timely manner.
The applicant identified this enhancement as Commitment No. 8 (NL-07-1261, dated June 27, 2007).
 
Enhancement 3
 
Elements:  1. scope of program
: 3. parameters monitored/inspected
: 4. detection of aging effects
: 5. monitoring and trending
: 6. acceptance criteria Enhancement:  The VEGP Fire Protection Program will be enhanced to provide more detailed instructions for visual inspection of Fire
 
Pump Diesel fuel supply lines for leakage, corrosion, and
 
general degradation while the engine is running during fire
 
suppression system pump tests as specified by NUREG-1801, Section XI.M26.
 
The staff concludes that this enhancement is acceptable because when the enhancement
 
is implemented, Fire Protection Program elements "scope of program," "parameters monitored/inspected," "detection of aging effects," "monitoring and trending," and
 
"acceptance criteria" will be consistent with GALL AMP XI.M26 program elements "scope of program," "parameters monitored/inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria."  The applicant identified this enhancement as
 
Commitment No. 8 (NL-07-1261, dated June 27, 2007) to be implemented prior to the
 
period of extended operation.
 
Operating Experience LRA Section B.3.9 states that operating history shows that the Fire Protection Program has ensured the continued ability of fire protection systems to protect
 
safe-shutdown capability and to prevent radioactive releases as the result of fire. Internal
 
and external assessments have detected programmatic strengths and weaknesses and
 
prompted corrective actions effectively.
 
The applicant stated that there has been some age-related degradation of fire protection
 
systems and features. Fire water pump casings have lost some material to corrosion; one
 
pump has been replaced and the long-range plan is to replace the rest. Having observed
 
corrosion in the fire water storage tanks and noted tank coating degradation, the applicant
 
plans to replace the coating. The program observed minimal amounts of leakage and
 
corrosion in carbon steel fire protection piping components and took corrective actions.
 
Pinhole leaks discovered in underground cast iron fire protection piping headers were
 
corrected. Some fire penetration seals have experienced shrinkage and degradation that
 
required repairs. There was no loss of intended function as a result of these aging effects. 
 
The applicant also stated there were no age-related failures in the fixed-Halon fire
 
suppression systems. Other failures were from design, installation, or operation and not
 
age-related. Leaking mechanical joints have occurred in underground cast iron piping, a 3-70 typical problem with bell and spigot joints in buried fire protection piping due to system transient loadings and inadequate restraint. A fire protection header line broke due to a
 
water hammer event. Some under-designed sprinkler system brass valves were replaced
 
with heavier duty valves because of vibration-related cracks. 
 
The staff reviewed the above operating experience and interviewed the applicant's
 
technical staff and confirmed that the plant-specific operating experience did not reveal any
 
degradation not bounded by industry experience. The staff also reviewed the VEGP
 
operating experience reports, condition reports, and maintenance work orders associated
 
with the corrective actions taken for the identification of signs of degradation of fire
 
protection components. The staff confirmed that the condition reports were closed out by
 
repairs to the degraded fire barriers or performed adequate engineering evaluations for
 
their acceptability. The staff noted that the applicant performs periodic inspections and
 
placed identified deficiencies into their corrective action program to ensure appropriate
 
corrective actions are performed in a timely manner.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section A.2.9, the applicant provided the UFSAR supplement for the Fire Protection Program. The staff reviewed the applicant's license renewal
 
commitment list dated June 27, 2007, and confirmed that the implementation of the Fire
 
Protection Program is identified as Commitment No. 8. 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 Fire Protection Program, the staff concludes 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. Also, the staff reviewed the
 
enhancements and confirmed that their implem entation prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it
 
was compared. The staff concludes that the applicant has demonstrated that the effects of
 
aging will be adequately managed so that the intended function(s) will be maintained
 
consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
determined that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
 
3.0.3.2.7  Flow-Accelerated Corrosion Program 
 
Summary of Technical Information in the Application LRA Section B.3.10 describes the existing Flow-Accelerated Corrosion Program as consistent, with exceptions, with GALL AMP XI.M17, "Flow-Accelerated Corrosion." 
 
The applicant stated that the Flow-Accelerated Corrosion Program manages loss of
 
material (wall thinning) due to such corrosion in susceptible plant piping and other
 
components. The Flow-Accelerated Corrosion Program is based on the guidance of
 
Nuclear Safety Analysis Center (NSAC)-202L-R2, "Recommendations for an Effective 3-71 Flow-Accelerated Corrosion Program," including subsequent revisions. Program analyses determine susceptible locations, predictive modeling techniques, baseline inspections of
 
wall thickness, follow-up inspections, and repair or replacement of degraded components
 
as necessary. A program update will reflect NSAC-202L-R3.
 
The applicant also stated that VEGP has elected to replace some carbon steel piping and
 
piping components with flow-accelerated corrosion-resistant chrome-molybdenum alloy
 
steel. Although the alloy steel has increased resistance to flow-accelerated corrosion, the
 
components remain in the scope of the Flow-Accelerated Corrosion Program. The
 
applicant's AMR process defines carbon steel to include low-alloy steel piping which is
 
used as replacement material in lines susceptible to flow-accelerated corrosion. Since the
 
low-alloy steel is more resistant to flow-accelerated corrosion than carbon steel, the aging
 
effects of the carbon steel bound those of the low-alloy steel, resulting in a conservative
 
aging management approach.
 
The applicant further stated that VEGP also uses the Flow-Accelerated Corrosion Program
 
and its inspection techniques to manage wall thinning in piping components downstream of
 
the SG blowdown demineralizers due not to flow-accelerated corrosion but to the acidic
 
conditions of the demineralizer effluent. The low-temperature, low-pressure environment
 
eliminates flow-accelerated corrosion as a cause for this thinning. 
 
The program inspects and monitors the extent of wall thinning and initiates corrective
 
actions to replace affected components prior to loss of intended function.
 
Staff Evaluation During its audit and review, the staff confirmed 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 the information in LRA AMP B.3.10, Flow-Accelerated Corrosion
 
Program, the VEGP program basis documents, and VEGP-specific procedures that pertain to the design, details, and implementation of this AMP. The applicant identifies that the
 
Flow-Accelerated Corrosion Program is an existing AMP that is designed to be consistent with the program elements in GALL AMP XI.M17, Flow-Accelerated Corrosion, with
 
exceptions. The staff concludes, from its review of the LR basis evaluation document, that the program elements for the Flow-Accelerated Corrosion Program were consistent with the program elements in GALL AMP XI.M17 with the following seven exceptions. The staff's evaluations on how these exceptions pr ovide for adequate aging management in lieu of conforming to the criteria in the applicable recommended program elements of GALL AMP XI.M17, "Flow-Accelerated Corrosion" are described in the subsequent subsections. 
 
Exception  Exception 1: The LRA states an exception to the "scope of program" and "detection of aging effects" program elements in GALL AMP XI.M17, "Flow-Accelerated Corrosion."
 
Specifically, the exception states:
 
SNC continuously improves the program through updates to reflect industry
 
operating experience and guidance document revisions. NUREG-1801, Volume 2, Section XI.M17, cites NSAC-202L-R2, "Recommendations for an Effective Flow-
 
Accelerated Corrosion Program," as the accepted source document for 3-72 development of a Flow-Accelerated Corrosion (FAC) Program. EPRI Report 1011838 (NSAC-202L-R3) has been issued, which supersedes all prior versions of
 
NSAC-202L. SNC is updating the FAC Program to reflect the recommendations of
 
EPRI Report 1011838 (NSAC-202L-R3). The revised NSAC-202L contains
 
recommendations updated with the experience of members of the
 
CHECWORKSŽ Users Group, plus recent advances in detection, modeling, and
 
mitigation technology. These recommendations are intended to refine and
 
enhance those of earlier versions, without contradiction, so as to ensure the
 
continuity of existing plant FAC programs. The differences between revisions 2
 
and 3 of this report have been evaluated and are being incorporated into the
 
implementing procedures governing the FAC Program.
 
GALL AMP XI.M17 recommends that FAC programs be developed and implemented in accordance with the industry guidelines recommended in EPRI Report No. NSAC-202L-R2, "Recommendations for an Effective Flow Accelerated Corrosion Program" (April 1999). The
 
applicant has proposed to use the most recent version of the EPRI NSAC guidelines on
 
FAC, which are currently described in EPRI Report 1011838 (NSAC-202L-R3). 
 
During the audit and review, the staff noted that the applicant had performed a comparison
 
of the guidelines recommended in EPRI Report 1011838 from those previously
 
recommended in EPRI Report No. NSAC-202L-R2, in order to determine whether the
 
update of the recommendations would continue to provide adequate aging management of
 
FAC for those systems and components that are within the scope of the program. The staff
 
concludes that, like EPRI Report No. NSAC-202L-R2, EPRI Report 1011838 continues to
 
recommend: (1) that flow-accelerated corrosions program perform an integrated modeling
 
of the carbon steel systems and low chromium
(,< 1%-wt. Cr) low-alloy steel systems, (2) that the modeling be done in accordance of a industry-wide model such as CHECWORKS, (3) that the condition monitoring inspections be done by ultrasonic testing (UT), and (4) that
 
the inspection results be evaluated in accordance with an appropriate wear rate
 
assessment model and wear rate acceptance criter ia, such as that provided in the modeling of CHECWORKS. The staff concludes that the applicant's Flow-Accelerated Corrosion
 
Program including modeling and assessment of the VEGP plant-specific piping is in
 
accordance with the latest version of CHECWORKS developed by EPRI and that the
 
applicant performs examinations of accessibl e in-scope components using UT. Alternative inspection methods proposed by the applicant are evaluated under Exception 6. Based on
 
this assessment, the staff concludes that it is acceptable to use EPRI Report No. 1011838 (i.e. EPRI Report No. NSAC-202L-R3) as the alternative industry-basis document for the
 
applicant's Flow-Accelerated Corrosion Program because the updated report continues to
 
recommend plant-specific modeling and the type of NDE inspections that were previously recommended for implementation in EPRI Report  NSAC-202L-R2.
Exception 2: The LRA states an exception to the "scope of program" program element in GALL AMP XI.M17, "Flow-Accelerated Corrosion." Specifically, the exception states:
 
The NUREG-1801 program discussion includes steam generator
 
feedwater and steam outlet nozzle safe ends. The VEGP steam
 
generator feedwater nozzles and steam outlet nozzles do not have safe
 
ends. In addition, the VEGP steam outlet nozzles are not considered to
 
be FAC susceptible based on steam quality.
 
EPRI Report No. 1011838 (i.e. EPRI Report No. NSAC-202L-R3) recommends that carbon 3-73 steel or low Chromium content (< 1.0% Cr) low-alloy steel systems be incorporated into a plant's FAC program if they are subject to high energy single phase aqueous or two phase
 
water/steam environments. The staff asked the applicant to identify what the average
 
quality was for the steam environment for the steam generator steam outlet nozzles. The
 
applicant provided its response to the staff's question in a letter dated February 8, 2008.
 
The applicant responded that the steam quality for these components was 99.7% dry
 
steam. This is a sufficiently dry quality to ex clude this environment from being defined as a high energy two phase water/steam environment. Based on this determination, the staff
 
concludes that it is valid to exclude the steam generator outlet nozzles from the scope of
 
the applicant's flow-accelerated corrosion program. The staff also determined that the feed
 
water nozzle safe ends and steam generator outlet nozzle safe ends do not need to be
 
modeled within the scope of this program because they are not included in the plant's
 
design. Based on this assessment, the staff concludes that this exception is acceptable.
 
Exception 3: The LRA states an exception to the "scope of program" program element in GALL AMP XI.M17, "Flow-Accelerated Corrosion." Specifically, the exception states:
 
The GALL program implies that all syst ems constructed of carbon steel and containing any high-energy fluid (two phase as well as single phase) are within the
 
scope of the FAC program. The VEGP FAC Program takes exception to the
 
environments which are prone to FAC as implied by the GALL Scope statement.
The VEGP FAC Program excludes any syst ems that do not transport water or steam. Systems that transport superheated or "dry" steam are also excluded from the VEGP FAC Program. This is consistent with the guidance provided in EPRI
 
Report 1011838 (NSAC-202L-R3), Section 4.2.1, Potential Susceptible Systems.
 
The staff does not consider this to be an exception to the recommendation in GALL AMP XI.M17, Flow-Accelerated Corrosion. The applicable EPRI FAC guidelines (i.e.,
EPRI Report No. NSAC-202L-R2 as recommended in GALL AMP XI.M17 or EPRI
 
Report No. 1011838 as accepted by the staff under Exception 1 above) apply to FAC
 
that is induced by single phase water or two phase water/steam environments. The
 
applicable EPRI FAC guidelines indicate that dry steam or superheated steam (which
 
contains greater than 99.7% dry steam with extremely low aqueous water content
 
levels) are not conducive environments for initiation and development of FAC in the
 
manner that single phase water or two phase water/steam environments are. Thus, based on this assessment, the staff concludes that it is appropriate and acceptable to
 
exclude carbon steel or low Chromium content (< 1.0% Cr) low-alloy steel piping
 
systems from the scope of the Flow-Accele rated Corrosion Program if the environment for the components is either superheated or dry steam or if the piping system does not
 
transport water or steam because this is consistent with the recommendations in the
 
applicable EPRI FAC guidelines.
 
Exception 4: The LRA states an exception to the "scope of program" program element in GALL AMP XI.M17, "Flow-Accelerated Corrosion." Specifically, the exception states:
 
The GALL program explicitly limits the materials subject to FAC inspections to
 
carbon steel. The VEGP FAC Program includes an exception to the GALL
 
program scope by including low alloy steel with a chromium content of less than
 
1.25% as being susceptible to FAC. This is consistent with the guidance provided
 
in EPRI Report 1011838 (NSAC-202L-R3), Section 4.2.2, Exclusion of Systems
 
from Evaluation.
3-74 The "scope of program" program elements stat es that the program is applicable to carbon steel systems and does not specifically mention systems fabricated from  low-alloy steel materials, which are also ferritic steels. However, the guidelines in EPRI
 
Report No. NSAC-202L-R2 and in EPRI Report No. 1011838 indicate that low-alloy
 
steel systems may be susceptible to FAC if their Chromium levels are less than 1.0%
 
alloying content and if they are exposed to high energy single-phase aqueous or high
 
energy two-phase aqueous/steam environments.
The applicant has conservatively included those low-alloy steel systems within the scope of this AMP if their Chromium
 
content is less than 1.25 %-Wt. and if they are exposed to either a high energy single-
 
phase water environment or a high energy two-phase water/steam environment.
Carbon steel systems exposed to these environm ents are also within the scope of this AMP. The staff considers this to be consistent with GALL in that the applicant does
 
include carbon steel systems within the scope of this program. The staff also
 
determined that the inclusion of low Chromium content (< 1.25 %-Wt.) low-alloy steel
 
systems in the program is a conservative supplement of the program rather than an exception to GALL. 
 
Therefore, the staff concludes that it is acceptable and conservative to include low
 
Chromium content (< 1.25% Cr) low-alloy steel systems within the scope of the
 
applicant's Flow-Accelerated Corrosion Progr am if they exposed to a high energy single-phase water environment or a high energy two-phase water/steam environment.
 
Exception 5: The LRA states an exception to the "scope of program" program element in GALL AMP XI.M17, "Flow-Accelerated Corrosion." Specifically, the exception states:
 
The VEGP FAC Program will encompass wall thinning resulting from FAC and can
 
also be used to manage similar phenomena such as cavitation, impingement, and
 
erosion, for piping or components whose failure could result in personnel injuries
 
or detrimental operation effects in systems determined to be susceptible to FAC.
 
The GALL Program does not consider use of the FAC Program to monitor wall
 
thinning from mechanisms other than FAC.
 
The "scope of program" element in GALL AMP X I.M17, "Flow-Accelerated Corrosion," limits the scope of FAC programs only to loss of material in carbon steel systems that is induced
 
by FAC. The "scope of program" program element in GALL AMP XI.M17, Flow-Accelerated Corrosion, states that volumetric techniques such as ultrasonic testing (UT) or radiography
 
testing (RT) are acceptable to monitor for loss of material due to FAC. The scope of the
 
applicant's program includes UT examinati ons of both carbon steel systems and low Chromium content (< 1.25%) low-alloy steel systems that are exposed to high energy, single phase water or two phase water/steam environments. This is consistent with the "scope of program" program element in GALL AMP XI.M17 and is acceptable. However, the
 
same UT inspection techniques are capable of monitoring for other mechanisms the may
 
induce loss of material in these systems, such as cavitation, impingement (fretting), or
 
erosion. This is a conservative supplement of this program rather than an exception to GALL AMP XI.M17. Therefore, the staff concludes that it acceptable to include these
 
additional aging mechanisms within the scope of the applicant's Flow-Accelerated
 
Corrosion Program.
 
Exception 6: The LRA states an exception to the "detection of aging effects" program element in GALL AMP XI.M17, "Flow-Accelera ted Corrosion." Specifically, the exception states:
3-75  The VEGP FAC Program includes inspection methodology that is considered an
 
exception to the GALL program. In addition to UT and RT, the VEGP FAC
 
Program permits the use of other industry-accepted inspection techniques where
 
practical. In certain large-bore systems, visual inspection (VT) of the piping inner
 
surfaces may be performed. Visual inspec tions provide immediate indications of FAC. Follow-up UT may be used to confirm or to quantify visual inspection results.
 
This is consistent with the guidance provided in EPRI Report 1011838 (NSAC-
 
202L-R3).
 
The exception taken by the applicant would permit the use of RT and VT techniques under
 
certain circumstances. The staff informed the applicant that VT and RT examination
 
methods were not capable of sizing flaws throughout the depth of a component (through a
 
components thickness). The staff asked the applicant to justify how RT and VT as
 
techniques that could size relevant flaw indications throughout a components thickness. In
 
its response, the applicant stated that RT could be used as a sizing technique only for small
 
bore piping, in that an angle beam RT shot could achieve an indication of the components
 
thickness and that VT techniques could not be used to size the extent of a flaw into a
 
components thickness. The applicant stated that it would use UT as a follow-up sizing
 
technique for any flaws detected as a result of VT or RT tests on large bore piping and UT
 
or RT as a sizing technique for any flaws detected as a result of RT or VT on small-bore
 
piping.
 
The staff asked for additional clarification on how RT would be used as a sizing technique
 
for flaw indications. Specifically, the staff asked the applicant to clarify whether VEGP has
 
qualified RT as a sizing technique in accordance with the VEGP performance
 
demonstration initiative (PDI) or some other NRC-accepted qualification process and if so, identify the type of components and components sizes that the qualification process has
 
qualified RT for as a sizing technique. If RT has not been qualified as a sizing technique
 
under the PDI, justify why it is acceptable to use RT as a sizing technique for flaw
 
indications that are detected in ASME Code Class components.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that RT is used only as a technique to measure
 
wall thickness and is not used to detect the size of flaws in the piping. The applicant further
 
stated that since the RT is not used as a technique to detect or size flaws, it is not required
 
to be qualified in accordance with a performance demonstration initiative (PDI) qualification
 
process. The staff concludes that the applicant's response is acceptable because it
 
provided clarification that any RT techniques used in accordance with the FAC Program
 
would only be used for the detection of wall thickness and not used to size relevant flaw
 
indications that may be indicated as parts of the programs UT inspection techniques. This
 
question is resolved.
 
Exception 7: The LRA states an exception to the "acceptance criteria" program element in GALL AMP XI.M17, "Flow-Accelerated Corrosion." Specifically, the exception states:
 
The VEGP FAC Program includes pipelines or components that cannot be
 
accurately modeled due to widely varying or unknown operating conditions, or
 
other reasons. The GALL program does not address pipelines or components that
 
cannot be modeled. The inspection results for these unmodeled pipelines or 3-76 components are evaluated by engineering judgment. This is consistent with the guidance provided in EPRI Report 1011838 (NSAC-202L-R3).
 
The staff asked the applicant to provide more specific details on how in-scope components
 
in un-modeled systems would be scheduled for ex amination and how the results of these examinations would be evaluated. Specifically the staff asked the applicant to:
: a. Clarify what type of wear rate projection, flaw growth, or engineering criteria will be used to determine whether such unmodeled in-scope piping systems or
 
components will be scheduled for appropriate NDE examinations. b. Clarify what type of NDE methods will be applied for the inspections of the unmodeled components within the scope of this AMP. c. Clarify what type of engineering judgment criteria will be used to assess the inspection results for those unmodeled components that are scheduled and receive
 
the NDE examinations identified in your response to Part B of this question.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated the following:
: a. Systems which cannot be modeled are compared to the susceptibility criteria of EPRI Report 1011838 (NSAC-202L-R3). For systems which are considered
 
to be susceptible to FAC, a sample of components in each system is selected
 
for inspection based on known problem areas (such as pressure drops, changes in direction, and splitting or combining flows). b. The same NDE methods are applied for modeled and unmodeled components (primarily UT). c. Unmodeled components are evaluated using the same methods as modeled components, with the exception of the lack of a modeled prediction of wear.
 
Fitness for service and remaining service life is evaluated based on measured
 
wear, with a safety factor applied in accordance with EPRI Report 1011838 (NSAC-202L-R3).
The staff finds the applicant's response to be acceptable because it provided
 
clarification that it uses the susceptibility criteria in EPRI Report 1011838 (i.e.
 
NSAC-202L-R3) to assess those systems that cannot be adequately modeled
 
by CHECWORKS and to sample components for inspection if it is determined
 
that a non-modeled system is susceptible to FAC, and because the applicant
 
has stated that it uses the same NDE inspection and evaluation techniques as
 
those used for the systems that can be modeled in accordance with the
 
CHECWORKS predictive code, which are based on these EPRI guidelines.
 
Based on this assessment, the staff concludes that the applicant's Flow-
 
Accelerated Corrosion Program has an acceptable method for inspecting and
 
evaluating non-modeled steel systems (i.e., carbon steel or alloy steel
 
systems) because the applicant is applying an applicable EPRI guideline
 
document for the evaluation of these systems and because these EPRI
 
guidelines used by the applicant have been determined by the staff to be an acceptable basis for establishing and implementing the applicant's Flow-
 
Accelerated Corrosion Program (refer to the staff's acceptance of the EPRI
 
NSAC-202L-R3 guidelines in its evaluation of Exception 1 for this AMP). 
 
3-77 Based on this review, the staff has verified that those program element aspects which the applicant claims are consistent with the recommended program elements in GALL AMP XI.M17, Flow-Accelerated Corrosion," were indeed consistent with the corresponding
 
program element criteria in the GALL AMP, and are acceptable. The staff has also
 
evaluated those exceptions taken to the progr am element criteria that are recommended in GALL AMP XI.M17, "Flow-Accelerated Corrosion," and, based on the evaluations of these
 
exceptions provided in the previous paragraphs , has determined that the exceptions taken to GALL AMP XI.M17 will ensure adequate management of loss of material due to FAC and
 
other loss of material inducing mechanisms in those components that are within the scope
 
of Flow-Accelerated Corrosion Program. 
 
Based on the audit and review, the staff concludes that the Flow-Accelerated Corrosion Program is consistent with GALL AMP XI.M17, "Flow-Accelerated Corrosion," as modified
 
by the seven (7) exceptions that have been found to be acceptable by the staff, and is
 
acceptable to manage loss of material due to FAC and other loss of material inducing
 
mechanisms in the carbon steel and low alloy steel systems and components for which the
 
AMP is credited.
 
Operating Experience LRA Section B.3.10 states that program effectiveness is demonstrated by results, which are consistent with industry experience. Wall thickness
 
inspections since 1991 have replaced numerous components and piping segments in
 
susceptible systems, including more than 3100 ft of susceptible small-bore pipe replaced
 
with materials resistant to flow-accelerated corrosion. While the program continues to
 
detect areas of pipe wall thinning, there have been no leaks in large-bore piping on either
 
unit attributed to flow-accelerated corrosion since 1992. A small number of leaks from
 
small-bore piping (not modeled on CHECWORKS&#x17d;) continue but the frequency has
 
dropped significantly as piping replacement has progressed.
 
The applicant also stated that VEGP has experienced chemical wastage of piping
 
components downstream of the SG blowdown dem ineralizers believed to be due to acidic conditions of the demineralizer effluent. As the blowdown passes through the
 
demineralizers they strip out ammonia and leav e the effluent acidic. Inability to vent the demineralizer vessels completely introduces oxygen into the blowdown effluent, resulting in
 
higher oxidation rates. The low-temperature, low-pressure environment eliminates flow-accelerated corrosion as a cause for this thinning. Flow-Accelerated Corrosion Program
 
inspection techniques manage this aging effect.
 
The staff reviewed the "operating experience" program element description provided in the applicant's license renewal basis evaluation document for the Flow-Accelerated Corrosion Program, and determined that the program incorporates generic and VEGP-specific flow-accelerated corrosion events as part of the criteria for determining and selecting components for the UT inspections that are implemented in accordance with this AMP. The staff verified that the program incorporates relevant experience discussed in the following
 
NRC generic communications:
 
BL 87-01, "Thinning of Pipe Walls in Nuclear Power Plants," November 6, 1987. GL 89-08, "Erosion/Corrosion-Induced Pipe Wall Thinning," May 2, 1989. IN 89-53, "Rupture of Extraction Steam Line on High Pressure Turbine,"
November 6, 1987. IN 91-18, "High-Energy Piping Failures Caused by Wall Thinning," March 12, 1991. IN 92-35, "Higher Than Predicted Erosion/Corrosion in Unisolable Reactor Coolant 3-78 Pressure Boundary Piping Inside Containment at a BWR," May 6, 1992. IN 93-21, "Summary of NRC Staff Observations Compiled during Engineering audits or Inspections of Licensee Erosion/Corrosion Programs," March 25, 1993. IN 95-11, "Failure of Condensate Piping Because of Erosion/Corrosion at a Flow-Straightening Device," February 24, 1995. NRC Information Notice 97-84, "Rupture in Extraction Steam Piping as a Result of Flow-Accelerated Corrosion," December 11, 1997.
 
The staff noted, from its license renewal basis evaluation document for this AMP, that the
 
applicant has indicated that it had also assessed the most recent U.S. industry operating
 
experience discussed in NRC IN 2001-09, "Main Feedwater System Degradation in Safety-Related ASME Code Class 2 Piping Inside Containment of a Pressurized Water Reactor,"
 
dated June 12, 2001, but had concluded that the applicant's Flow-Accelerated Corrosion
 
Program bounds the relevant operating discussed in IN 2001-09, because: (1) the VEGP
 
program performs more FAC inspections than does the corresponding licensee for plants
 
discussed and analyzed in IN 2001-09,  (2) VEGP historically maintains excellent water
 
chemistry conditions, (3) VEGP continually maintains and updates its CHECWORKS code
 
to incorporate relevant VEGP-specific and generic operating experience, (4) the VEGP
 
program already incorporates inspections of susceptible counter-bored piping weld areas, and (5) VEGP does not limit selection of inspection locations to only those predicted by
 
CHECWORKS.
 
In NRC IN 2001-09, the NRC refers to an operational FAC-induced failure event that had
 
occurred in the moisture separator reheater drain line piping of a U.S PWR in 
 
August 11, 1999. This event is significant because the rate of flow-accelerated corrosion
 
that had occurred downstream of a moisture separator reheater drain line pipe elbow weld
 
had been exacerbated due to the presence of a backing bar in the weld configuration. The
 
presence of the backing bar resulted in more turbulent down-stream flow conditions (leading to a combination of FAC and cavitation) and had accelerated the rate of corrosion
 
in the failed piping beyond that which would have been predicted by CHECWORKS and
 
because the licensee did not conform to the EPRI FAC guideline recommendations for
 
inspecting piping downstream of a susceptible pipe weld location. 
 
The staff concludes that the current program is sufficient to address this industry
 
experience because it conforms to EPRI Report 1011838.
 
The staff asked the applicant to clarify how their CHECWORKS modeling bounds turbulent
 
flow conditions that could be induced by the presence of backing bars in the piping and to
 
clarify whether it implements the pipe length inspection criteria recommended in EPRI
 
Report NSAC-202L-R2, or its updates. The applicant provided its response to the staff's
 
question in a letter dated February 8, 2008. In its response, the applicant provided the
 
following response:
 
The VEGP Flow-Accelerated Corrosion (FAC) Program implements the guidance
 
of NSAC-202L, revision 3, which addressed the operating experience from the
 
1999 incident at Calloway and the related follow-up inspections that were
 
performed in 2001 and which are discussed in Information Notice 2001-09.
While VEGP typically has not used backing rings in piping with a design pressure of 600 psig or higher, for lower pressure piping the piping specification allows use
 
of backing rings for certain piping material classifications. Weld locations are 3-79 subject to more detailed inspection, in part because backing rings could exist in some piping. In accordance with the VEGP FAC UT inspection procedure, the
 
entire grid square is scanned for the grid adjacent to each side of each weld, as
 
opposed to scanning just the grid intersection points (NMP-ES-024-510, paragraph
 
12.2.5). This ensures identification of any accelerated wear occurring near the
 
weld such as might occur from undercutting of a backing ring.
The VEGP program implements the reco mmendations in EPRI Report NSAC-202L, revision 3, section 4.5.2, regarding grid coverage for piping components.
 
This section recommends that "the inspection grid extend from two grid lines
 
upstream of the toe of the upstream weld to a minimum of two grid lines or 6
 
inches (150 mm), whichever is greater, beyond the toe of the downstream weld." 
 
For expanding components it is further recommended that "The grid should be
 
extended upstream 2 grid lines or six inches (150 mm), whichever is greater." Grid extensions beyond that are only needed if a degrading trend or significant damage is noted. The "two diameters" figure is provided as a consideration to
 
avoid the potential for having to expand grid coverage after initial inspection. The
 
SNC procedure, NMP-ES-024-510, paragraph 10.5, specifies grid coverage of 2
 
grids or 4" upstream to 2 grids or 12" downstream. For expanding components the upstream grid is 2 grids or 12", therefore SNC practices envelope the actual
 
NSAC-202L recommendations.
The staff concludes that the Flow-Accelerated Corrosion Program bounds the operating experience discussed in IN 2001-09 because (1) the program elements of the AMP have been determined to be consistent with recommended inspection guidelines of EPRI Report
 
No. 1011838, (2) the applicant's CHECWORKS modeling of the VEGP piping accounts for
 
pipe welds that could have potentially counter-bored weld geometries and backing bars in
 
service, and (3) the applicant's criteria for performing the UT inspections under this
 
program conforms to the criterion in EPRI Report No. 1011838 for inspecting lengths of
 
pipe upstream and downstream of carbon steel or low alloy steel pipe welds.
 
Based on this review, the staff concludes that the applicant's Flow-Accelerated Corrosion
 
Program adequately addresses industry operating experience related to FAC. 
 
Based on this review, the staff confirmed that the "operating experience" program element
 
satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable.
 
UFSAR Supplement In LRA Section A.2.10, 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 concludes 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 3-80 the UFSAR supplement for this AMP and determined that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.2.8  Flux Thimble Tube Inspection Program 
 
Summary of Technical Information in the Application LRA Section B.3.11 describes the existing Flux Thimble Tube Inspection Program as consistent, with enhancement, with GALL AMP XI.M37, "Flux Thimble Tube Inspection."
 
The applicant states that the Flux Thimble Tube Inspection Program manages loss of
 
material due to fretting or wear of the incore flux detector thimble tubes. The program
 
responds to NRC Bulletin No. 88-09, "Thimble Tube Thinning in Westinghouse Reactors,"
 
using proven nondestructive examination techniques to monitor for wear of the flux thimble tubes. The program evaluated the test results to determine the wear rate using proprietary
 
methodology which applies an allowance for uncertainty to the measured wear data, then
 
compares the wear rate predictions against the acceptance criteria to determine the need
 
for corrective actions (e.g., repositioning, capping, or replacing a flux thimble tube). The
 
wear rate predictions also establish the interval to the next inspection. The Flux Thimble
 
Tube Inspection Program will be enhanced prior to the period of extended operation.
 
Staff Evaluation During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. 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.
 
The staff reviewed those portions of the Flux Thimble Tube Inspection Program for which the applicant claims consistency with GALL AMP XI.M37 and found that they are consistent
 
with the GALL Report AMP. Furthermore, the staff concludes that the applicant's Flux
 
Thimble Tube Inspection Program is an acceptable program to manage aging of incore flux
 
detector thimble tubes for the period of extended operation. The staff finds the applicant's
 
Flux Thimble Tube Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M35, "Flux Thimble Tube Inspection," with the enhancement
 
as described below:
 
Enhancement
: The LRA states the following enhancement to the following GALL Report program element:
 
Element: 7:  corrective actions
 
Enhancement: An overall program procedure will be prepared which describes the activities and controls which have been
 
implemented to manage wall thinning of the flux thimble
 
tubes.
In Enclosure 2 of the letter dated June 27, 2007, the applicant made a commitment (Commitment No. 9) to enhance the Flux Thimble Tube Inspection Program by preparing
 
an overall program procedure documenting t he Flux Thimble Tube Inspection Program administration and implementing activities credited for license renewal. The staff finds this
 
enhancement and commitment acceptable, since the enhanced program implementing
 
procedures will address the recommendations of the GALL Report and be consistent with
 
the corrective actions program element.
3-81  The staff reviewed the results of the Vogtle flux thimble eddy current inspection data
 
evaluation for refueling outages 1R12 and 2R12 for Unit 1 and Unit 2, respectively. The
 
evaluation contained the results of previous eddy current data. The staff noted that no
 
adverse trends were identified by the inspections. The staff also noted that the inspection
 
data specified the acceptance criteria threshold that determines whether corrective action is
 
required. The staff finds this commitment acceptable, since the program enhancement will
 
address the recommendations of the GALL Report. 
 
Operating Experience LRA Section B.3.11 states that no through-wall leaks of flux thimble tubes have been observed, but that wear has exceeded the acceptance criteria in several
 
flux thimble tubes resulting in corrective measures. Some tubes have been repositioned to
 
introduce new wear surfaces, other tubes have been capped.
 
The applicant's evaluation of the latest eddy current test data for Unit 1 during the Unit 1
 
twelfth refueling outage (Spring 2005) indicated that the in-service flux thimble tubes would
 
be satisfactory for continued operation through the fourteenth refueling outage and that two
 
tubes would be within 1 percent of the administrative acceptance criteria limit of 70-percent
 
through-wall wear if they continue in operation until then. 
 
The applicant's evaluation of the latest eddy current test data for Unit 2 during the Unit 2
 
twelfth refueling outage (Spring 2007) indicated that the in-service flux thimble tubes would
 
be satisfactory for continued operation and would not approach the acceptance criteria limit
 
through the fourteenth refueling outage. 
 
During the audit and review, the staff reviewed the inspection results from its most recent
 
flux thimble inspections and their evaluations. The staff confirmed the results of the
 
inspection did not indicate actual flux thimble tube wear outside of predicted values.
 
The staff reviewed the operating experience in the LRA which is consistent with industry
 
operating experience. Additionally, the staff compared the recommendations of IE Bulletin
 
88-09, "Thimble Tube Thinning in Westinghouse Reactors," to determine consistency with
 
the Flux Thimble Tube Inspection Program. The staff finds that the Flux Thimble Tube
 
Inspection Program is consistent with the recommendations of IE Bulletin 88-09, which is
 
based on industry operating experience. 
 
On the basis of its review of the above plant-specific operating experience and discussions
 
with the applicant's technical staff, the staff finds that the applicant's Flux Thimble Tube
 
Inspection Program will adequately manage the aging effects for which the AMP is credited.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section A.2.11, the applicant provided the UFSAR supplement for the Flux Thimble Tube Inspection Program. Also, in a letter dated June 27, 2007, the
 
applicant provided Commitment No. 9 to enhance the Flux Thimble Tube Inspection
 
Program prior to the period of extended operation. 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).
 
3-82 Conclusion On the basis of its audit and review of the applicant's Flux Thimble Tube Inspection Program, the staff concludes that those program elements, for which the
 
applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed
 
the enhancement and confirmed that its implementation through Appendix A, Commitment
 
No. 9 prior to the period of extended operation would make the existing AMP consistent
 
with the GALL Report AMP to which it was compared. The staff concludes that the
 
applicant has demonstrated that the effects of aging will be adequately managed so that
 
the intended function(s) will be maintained consistent with the CLB for the period of
 
extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR
 
supplement for this AMP and determined that it provides an adequate summary description
 
of the program, as required by 10 CFR 54.21(d).
 
3.0.3.2.9  Generic Letter 89-13 Program 
 
Summary of Technical Information in the Application LRA Section B.3.12 describes the existing Generic Letter 89-13 Program as c onsistent, with exception and enhancements, with GALL AMP XI.M20, "Open-Cycl e Cooling Water System." 
 
The applicant stated that Generic Letter 89-13 Program responds to the recommendations
 
of GL 89-13, "Service Water System Probl ems Affecting Safety-Related Equipment." The Generic Letter 89-13 Program includes mitigation as well as performance- and condition-
 
monitoring techniques to manage the effects of aging on the NSCW system and on
 
components the system supplies.
 
The applicant also stated that the prevention or mitigation of fouling and loss of material in
 
the NSCW system and NSCW-supplied components is achieved in part by intermittent injection of appropriate water treatment chemicals. Other preventive and monitoring aspects of the Generic Letter 89-13 Program include periodic flushing of lines to mitigate or
 
prevent fouling, periodic measurement of fl ow rates through selected components, periodic analysis of corrosion coupons, periodic cleansing of selected heat exchangers, and visual
 
inspection of some components for fouling or loss of material. Volumetric examination may
 
detect degradation. Enhancements to the Generic Letter 89-13 Program will be
 
implemented prior to the period of extended operation.
 
Staff Evaluation During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. 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 Generic Letter 89-13 Program for which the
 
applicant claims consistency with GALL AMP XI.M20, "Open-Cycle Cooling Water System,"
and found that they are consistent with the GALL Report AMP. Furthermore, the staff
 
concludes that the applicant's Generic Le tter 89-13 Program will properly manage the aging of the NSCW system components and components this system supplies for the period of extended operation. The staff finds the applicant's Generic Letter 89-13 Program acceptable because it conforms to the recommended GALL AMP XI.M20 with the exception
 
and enhancements as described below.
 
The LRA states an exception to the following GALL Report program element:
 
Element: 5:  monitoring and trending 3-83 Exception: The VEGP Generic Letter 89-13 Program activities are performed at a variety of intervals depending on the
 
component, the parameter being monitored, and results of
 
previous inspections. 
 
The GALL Report states that testing and inspections are
 
done annually and during refueling outages.
The Generic Letter 89-13 Program activities are
 
performed at intervals consistent with the VEGP
 
commitments made in response to GL 89-13. Inspection
 
intervals range from monthly for some flow measurements
 
to ten years for NSCW pump removal and refurbishment.
 
The staff finds that this exception is acceptable because it has been previously reviewed
 
and accepted by the staff and is part of the CLB.
 
The applicant's LRA for the Generic Letter 89-13 Program stated the following
 
enhancements:
 
Enhancement
: 1. The LRA states an enhancement to the following GALL Report program element:
Element: program description
 
Enhancement: An overall program procedure will be prepared which describes the various program activities that
 
comprise Generic Letter 89-13 Program and their
 
implementing controls such as chemistry
 
procedures, maintenance activities, scheduled
 
surveillances, or other mechanisms.
 
In Enclosure 2 of letter dated, June 27, 2007, the applicant made a commitment (Commitment No. 11) to enhance the Generic Letter 89-13 Program by preparing an overall program procedure documenting the program adm inistration and implementing activities credited for license renewal. The staff finds this commitment and enhancement acceptable
 
because the applicant has committed to develop a comprehensive program procedure to
 
govern the overall activities to be perfo rmed under the Generic Letter 89-13 Program. The staff finds this to be an acceptable way to document, communicate and control all of the
 
activities which are committed to under this program.
 
Enhancement
: 2. The LRA states an enhancement to the following GALL Report program element:
Element: 3:  parameters monitored or inspected
 
Enhancement: The VEGP Generic Letter 89-13 Program activities will be enhanced to include:
Inspection of the NSCW transfer pumps' casings and bolting 3-84  Inspection of the NSCW cooling tower spray nozzles as a specific item to be inspected
 
during cooling tower inspections
 
In Enclosure 2 of the letter dated, June 27, 2007, the applicant also included in
 
Commitment No. 11 the expansion of the Generic Letter 89-13 Program by including the
 
above component inspections. 
 
The staff finds this enhancement and the associated expansion to Commitment No. 11
 
acceptable because it expands the scope of the GL 89-13 Program to include additional
 
components.
 
The staff reviewed those portions of the GL 89-13 Program that the applicant claimed are
 
consistent with the GALL Report and found them consistent. The staff found the exception
 
acceptable because it has been previously approved by the staff and is part of the CLB.
 
Further, the staff found the enhancement acceptable because it expands the scope of the
 
program to include additional components in the program. Therefore, the staff finds the
 
licensee's implementation of the GL 89-13 Program to be acceptable.
 
Operating Experience LRA Section B.3.12 states that implementation of an inspection program for safety-related heat exchangers began with the Fall 1990 Unit 2 refueling
 
outage in response to concerns raised in GL 89-13. Inspection results typically indicated
 
traces of silt. A small number of those early inspections found minor amounts of debris in
 
some heat exchangers. In 1993 the heat exchanger inspection frequency was extended
 
due to the favorable results.
 
The applicant stated that beginning in 1993, various inspections found debris sufficient to
 
block tubes in several heat exchangers. In addition, investigation of a high component
 
cooling water motor-winding temperature revealed the motor cooler's NSCW supply flow
 
orifice blocked by debris and blockage in the NSCW supply to an NSCW pump motor
 
cooler. Due to the repeated instances of NSCW component fouling, in October 1995, the
 
staff issued Unresolved Item 424, 425/95-12-04, which was closed in December 1995 when
 
the staff opened Level 4 Violation 424, 425/95-27-04.
 
To address the flow blockage, the applicant stated that in 1995 it instituted periodic flow
 
measurements for small-diameter flow orif ices, implemented several modifications to prevent debris from entering the NSCW cooling towers, inspected and cleaned the cooling
 
tower basins by diving services, and expanded the scope of inspection during the 1996
 
refueling outage on each unit. Furthermore, analysis indicated that some debris was the
 
result of Colmonoy coating flaking off of NSCW pump sleeves and wear rings. The
 
applicant refurbished the NSCW pumps to eliminate this coating as a source of debris.
 
The applicant also stated that more aggressive monitoring and inspection program in
 
response to the flow blockage has detected fouling of flow orifices and heat exchangers
 
effectively prior to loss of function (e.g., measured NSCW flows outside of the "expected" range but within the "acceptable" range and accumulation of minor amounts of debris with
 
no effect on heat exchanger performance).
 
The applicant further stated that loss of material has caused leaks at the containment
 
cooler tube to header connections. The long-range plan for containment coolers
 
recommended replacement of the cooling coils with stainless steel tubing material and of 3-85 the header design with a waterbox-type design. Three Unit 2 coils and one Unit 1 coil had been replaced as of Fall 2006.
 
As a result of observations of scale material (calcium and silica) made by the applicant from
 
the well water makeup system on the spray ring header of the NSCW towers, VEGP
 
monitors the Ryznars Stability Index, which indicates conditions leading to the formation of
 
scale. Blowdown maintains this index within limits.
 
During the audit and review, the staff confirmed by reviewing selected operating experience
 
documents that the VEGP actions taken in response to GL 89-13 have been effective in
 
identifying fouling of flow orifices and heat exchangers, and in identifying loss of material
 
from NSCW-supplied components, prior to loss of intended function.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section A.2.12, the applicant provided the UFSAR supplement for the Generic Letter 89-13 Program. Also, in a letter dated June 27, 2007, the applicant
 
provided Commitment No. 11 to enhance the Generic Letter 89-13 Program prior to the
 
period of extended operation. 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 Generic Letter 89-13 Program, the staff concludes 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 justification 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 through Commitment No. 11 prior
 
to the period of extended operation would make the existing AMP consistent with the GALL
 
Report AMP to which it was compared. The staff concludes 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 determined that it provides an adequate summary description of the program, as
 
required by 10 CFR 54.21(d).
 
3.0.3.2.10  Oil Analysis Program 
 
Summary of Technical Information in the Application LRA Section B.3.16 describes the existing Oil Analysis Program as consist ent, with exception and enhancements, with GALL AMP XI.M39, "Lubricating Oil Analysis." 
 
The Oil Analysis Program maintains the lubric ating oil and hydraulic fluid environments in the in-scope mechanical systems to the required quality. The Oil Analysis Program
 
maintains lubricating oil and hydraulic flui d system contaminants (primarily water and particulates) within acceptable limits to preserve an environment that is not conducive to
 
deleterious aging effects. The program samples and analyzes lubricating oil and hydraulic
 
fluid for detrimental contaminants. The One-Time Inspection Program verifies the 3-86 effectiveness of the Oil Analysis Program. E nhancements to the Oil Analysis Program will be implemented prior to the period of extended operation.
 
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. 
 
Staff noted that the applicant identifies that the Oil Analysis Program is consistent with the program described in GALL AMP XI.M39, "Lubric ating Oil Analysis Program (henceforth referred to as GALL AMP XI.M39), with two exceptions to the "scope of program,"
 
"preventative actions," "parameters monitored/inspected," "detection of aging effects,"
 
"monitoring and trending," "acceptance criteria," and "operating experience" program elements in GALL AMP XI.M39 and three enhancements of the AMP.
 
The staff reviewed those portions of the Oil Analysis Program for which the applicant claims consistency with GALL AMP XI.M39. Specifically , the staff reviewed the information in AMP B.3.16, "Oil Analysis Program," the licens e renewal basis evaluation document, and VEGP-specific procedures that pertain to the design, details, and implementation of this AMP. As
 
part of its review of these documents, the staff reviewed the "scope of program,"
 
"preventative actions," "parameters monitored/inspected," "detection of aging effects,"
 
"monitoring and trending," "acceptance criteria," and "operating experience" program
 
element descriptions for the Oil Analysis Program, and information in supporting
 
documents, and compared them to the corres ponding program element criteria in GALL AMP XI.M39 in order to determine whether those program elements claimed as being consistent with GALL were consistent with the corresponding program element criteria in GALL AMP XI.M39. Based on its review, the staff verified that the program element aspects
 
claimed as being consistent with GALL included all the program element criteria recommended in the corresponding program elements in GALL AMP XI.M39. Based on this
 
review, the staff finds that these program elem ent aspects of the Oil Analysis Program are acceptable because the staff has verified that they are consistent with the corresponding program elements in GALL AMP XI.M39.
 
The staff also reviewed the exceptions and enhancements to determine whether the AMP, as subject to the activities defined in the exceptions and enhancements, will be adequate to
 
manage the aging effects for which it is credited. The staff's evaluation of the exceptions taken to GALL AMP XI.M39 and the applicant's enhancements of the AMP are described in
 
the subsections that follow.
 
Exception Exception 1: The LRA section B.3.16 (amended by letter dated March 20, 2008) states that
 
the Oil Analysis Program includes the following exception to the "program scope,"
 
"preventive actions," "parameters monitored/inspected," "detection of aging effects,"
 
"monitoring and trending," "acceptance criteria," and "operating experience," program elements in GALL AMP XI.M39, "Oil Analysis Program: 
 
The VEGP Oil Analysis Program includes hydraulic fluid in addition to
 
lubricating oil. In accordance with manufacturers' recommendations and
 
good engineering practice, hydraulic fluid is sampled for particulates, water
 
content, viscosity, and neutralization number. Since the hydraulic fluids in
 
use at VEGP are inherently fire-resistant, flash point is not an appropriate
 
analysis criteria and is not performed for hydraulic fluid. The standard and 3-87 acceptance criteria used for hydraulic fluid are in accordance with manufacturers' recommendations.
 
The staff noted that this exception is an augmentation of the applicant's existing program to
 
include hydraulic oil in the scope of the program. The staff finds the inclusion of
 
components with hydraulic fluid into the scope of the AMP represents an acceptable conservative augmentation of the AMP that goes beyond the GALL AMP XI.M39
 
recommendations and therefore is not an exception to the GALL AMP. The staff therefore
 
determines that this exception to the "progr am scope," "preventive actions," "parameters monitored/inspected," "detection of aging effects," "monitoring and trending," "acceptance
 
criteria," and "operating experience," program elements is acceptable.
 
In the applicant's letter of March 20, 2008, the applicant amended the LRA to include an
 
additional exception to the "parameters monitored/inspected" and "acceptance criteria"
 
program elements, as discussed below. 
 
Exception 2: In the applicant's letter of March 20, 2008, the applicant amended the LRA to
 
include the following additional exception to the "parameters monitored/inspected" and
 
"acceptance criteria" program elements in GALL AMP XI.M39, "Oil Analysis Program:
The VEGP Oil Analysis Program screens all lubricating oil samples for wear
 
metal content. This wear metal content screening constitutes an exception
 
to GALL in that the screening does not provide a particle count as
 
described in ISO 4406. VEGP's experience with this wear metal content
 
screening process indicates that the process is very sensitive to the
 
presence of particulate contaminants and therefore is a reliable method to
 
monitor and trend particulate contamination.
 
The staff noted in the "acceptance criteria" program element in GALL AMP XI.M39 only
 
refers to Standard ISO 4406 as one of many standards that may be used for particulate
 
counting and that the GALL AMP in no means mandated this standard for implementation.
 
The applicant has taken the position that any particulates in the lubricating oil or hydraulic
 
fluid would consist of metallic species and therefore has proposed to perform wear metal
 
content screening as the basis for assessing the lubricating oil and hydraulic fluid
 
inventories for particulates. The staff noted that ISO 4406 categorizes particulates by
 
number of particulates counted according to size in micrometers. Although the applicant
 
program does not monitor for particulates by counting the number of particulates falling
 
within particular size ranges, the applicant's program does screen for particulates based on
 
concentrations of particulates that are greater than 5 microns in size and propose
 
appropriate corrective actions if the concentration of metallic wear particulate greater than 5
 
microns in size is exceeded. The staff finds the applicant's alternative for particulate counting to be acceptable because: (1) GALL AMP XI.M39 does not mandate ISO 4406 for
 
use, and (2) like ISO 4406, the applicant's basis is based on size and concentration, and
 
(3) the applicant's alternative proposes appropriate corrective actions if the limits on
 
concentration are exceeded. 
 
Enhancements
:
Enhancement 1: The LRA section B.3.16, (amended by letter dated March 20, 2008)
 
identifies that the Oil Analysis Program include the following enhancement of the
 
"parameters monitored/inspected," "detection of aging effects," "monitoring and trending,"
3-88 "acceptance criteria," and "operating experience" program elements in GALL AMP XI.M39, "Oil Analysis Program:" 
 
An overall program procedure or guideline formalizing the sampling and
 
analysis activities performed by this program will be issued.
 
In letter dated March 20, 2008, the applicant amended Commitment No.14, which reflects
 
this enhancement to the Oil Analysis Program. The staff noted that in Commitment No.14
 
the applicant states the parameters (viscosity, relative level of oxidation, and flash point)
 
that will be monitored; the methods in wh ich they will be monitored and the corrective actions that will be taken if the analysis indicated monitored levels are exceeded.
 
The staff concludes that this enhancement is acceptable because when the enhancement
 
is implemented, as described in Commitment No
.14, the Oil Analysis Program elements will be consistent with GALL AMP XI.M39 program elements, including protocols for periodic
 
sampling and analysis of lubricating oil and hydraulic fluid inventories. 
 
Enhancement 2: The LRA section B.3.16 (amended by letter dated March 20, 2008)
 
identifies that the Oil Analysis Program includes the following enhancement of the "parameters monitored/inspected" program element for the AMP:
 
For the components in the scope of license renewal determination of the
 
viscosity, relative level of oxidation, and flash point of lubricating oil samples
 
will be required for components where the lubricating oil is changed based
 
on its analyzed condition instead of being changed on a regular schedule
 
regardless of condition. The relative level of oxidation of the lubricating oil
 
will be monitored by analysis of the neutralization number or other
 
appropriate parameter(s). Flash point monitoring will be performed for those
 
components which have the potential for contamination of the lubricating oil
 
with a light hydrocarbon such as fuel oil.
 
During the audit and review, the staff asked the applicant to clarify whether the intent of this
 
enhancement and Commitment No. 14 is to invoke viscosity testing, neutralization number
 
testing, and flash point testing for both oil that is replaced or replenished on a periodic basis
 
and does not get replaced or replenished on a periodic basis or whether the intent of the
 
enhancement is to invoke viscosity testing, neutralization number testing, and flash point
 
testing only for oil that is replaced or replenished on a periodic basis. If the later intent is
 
meant, provide your basis for not crediting these tests for lubricating oil that does not get
 
replaced or replenished on a regular basis.
 
In its response, dated February 8, 2008 the applicant stated that the lubricating oil at VEGP
 
presently falls into one of two following categories: 1) Oil that is replaced based on its analyzed condition; 2) Oil that is replaced on a regular schedule regardless of condition.
 
The applicant also stated:
 
Oil that is replaced on a regular schedule will continue to be replaced on that
 
schedule during the period of extended operation in accordance with the current
 
requirements of the Oil Analysis Program (with the stipulation that the SNC fleet-3-89 wide Oil Analysis Program currently in development could make changes determined by identification of best practices).
 
For oil that is changed based on its analyzed condition, the Oil Analysis Program is being enhanced to require viscosity testing, relative level of oxidation testing, and
 
flash point testing, which may or may not be presently performed for the various
 
affected components included in the program.
The relative level of oxidation of the lubricating oil will be monitored by analysis of
 
the neutralization number (also known as acid number or base number per the
 
current version of ASTM D974) or other appropriate parameter(s), such as
 
conductivity, which measure changes in the relative level of oxidation of the
 
lubricating oil.
The evaluation of this element included an enhancement that the flash point would
 
be determined for lubricating oil samples where the oil is changed based on
 
analyzed condition instead of at regular intervals. SNC would like to clarify this
 
enhancement in that the flash point of lubricating oil will be monitored for those
 
components where the oil is changed based on analyzed condition instead of at
 
regular intervals, and which have the potential for contamination of the lubricating oil
 
with a light hydrocarbon such as fuel oil. Flash point monitoring can provide useful
 
information regarding the condition of lubricating oil which could be diluted by a light
 
hydrocarbon. For components where there is no potential for contamination of the
 
lubricating oil with a light hydrocarbon, other analyses provide direct monitoring of
 
the parameters relevant to the condition of the oil. In these cases flash point
 
monitoring is superfluous.
The staff's evaluation of the applicant's proposed enhancement depends on two different
 
categorizations of lubricating oil/hydraulic fluid oil. The first pertains to tests for lube oils and
 
hydraulic fluid oils that are replaced on a regular basis. For lubricating and hydraulic fluid
 
oils falling into this category, the staff noted that the applicant stated that the program, when enhanced, will perform viscosity testing, neutralization number testing, and flash point
 
testing on the sample of oil taken from the components' oil reservoirs. The staff verified that
 
this is consistent with the program element "Parameters Monitored/Inspected" of GALL AMP XI.M39, and based on this determination finds the applicant enhancement with
 
respect to oils that are replaced on a regular basis to be acceptable. The second category
 
pertains to lube oils and hydraulic fluid oils that are not replaced on a regular basis, but are
 
replaced when the analysis indicates that there is a need for replacement. For oils falling
 
into this category the applicant stated that, when the program is enhanced, the program will
 
perform viscosity testing, relative level of oxidation testing, and flash point testing. Based on
 
both of these assessments of the applicant's Oil Analysis Program, the staff concludes that
 
when the program is enhanced as described in the applicant's response and Commitment No. 14, this program will be consistent with GALL AMP XI.M39.
 
The staff verified that the applicant amended LRA Commitment No. 14, dated March 20, 2008 to clarify the above enhancement. The staff concludes that this enhancement is
 
acceptable because when the enhancement is impl emented, Oil Analysis Program element "parameters monitored/inspected," will be consistent with GALL AMP XI.M39 program element "parameters monitored/inspected."
 
Enhancement 3: The LRA section B.3.16 identifies that the Oil Analysis Program include 3-90 the following enhancement of the "parameters m onitored/inspected," program element in GALL AMP XI.M39, "Oil Analysis Program: "
 
Detailed particle counting, analytical ferrography or elemental
 
analysis will be performed as necessary to validate the initial
 
screening results and to diagnose the source of the
 
particulates when a lubricating oil sample's wear metal
 
content screening results exceed established limits or action
 
levels for the components in the scope of license renewal.
 
The staff asked the applicant to provide the basis why the implementation of ferrography
 
and elemental analysis will be implemented only if of the particulate counts from the
 
particulate testing exceeds the acceptance criteria limits for particulate count.
 
In its response, the applicant stated the following:
VEGP currently screens all lubricating oil samples for kinematic viscosity, water content and wear metal content. This applies both to components with
 
periodic lubricating oil changes and to components where the lubricating oil
 
is changed based on analyzed condition.
 
The wear metal content screening provides a relative measure of the
 
change in the amount of ferrous wear products in the lubricating oil sample
 
versus a baseline sample. The ferrous wear index measures the
 
concentration and size of ferrous particles greater than five microns in size.
 
The value is reported as a non-dimensional value (no units of
 
measurement). Comparison of subsequent lubricating oil sample results to
 
the baseline sample provides the ability to trend changes in the
 
concentration of ferrous wear products in the lubricating oil.
 
Elemental analysis and neutralization number testing are also performed for
 
certain components in the scope of license renewal where the lubricating oil
 
is changed based on analyzed condition instead of at regular intervals.
 
Components selected for these analyses are selected based on EPRI
 
guidelines, manufacturer's recommended testing and radiological shipping
 
requirements.
 
For both components with periodic lubricating oil changes and components
 
where the lubricating oil is changed based on analyzed condition, if a
 
lubricating oil sample exceeds the limits established for the wear metal
 
content screening, the lubricating oil from that component will be subjected
 
to additional testing. 
 
The additional testing may include detailed particle counting, elemental
 
analysis, or analytical ferrography as necessary to validate the initial
 
screening results and to diagnose the source of the particulates.
 
The wear metal content screening process described above constitutes an
 
exception to GALL AMP in that the screening does not provide a particle
 
count as described in ISO 4406. VEGP's experience with this wear metal
 
content screening process indicates that the process is very sensitive to the 3-91 presence of particulate contaminants and therefore is a reliable method to monitor and trend particulate contamination. The applicant states that it will
 
require a License Renewal Application amendment to document this
 
exception.
 
Phosphate ester hydraulic fluid is tested in accordance with manufacturer's
 
recommendations. This fluid is sampled for viscosity, acidity (neutralization
 
number), particle count and water content. For phosphate ester hydraulic
 
fluids, elemental analysis and analytical ferrography are not components of
 
the manufacturer's recommended testing and therefore are not routinely
 
performed. Elemental analysis and analytical ferrography may be performed
 
if deemed necessary to assist in diagnosing potential problems indicated by
 
the manufacturers recommended testing.
 
The staff noted that enhancement required testing for both oil that is changed based on
 
analytical results or for oil that is periodically changed on a specified schedule. The staff
 
noted that the applicant's testing for wear metal particles accomplishes two purposes: initial
 
screening for particulates and trending in order to determine whether additional analytical
 
testing by ferrography needs to be performed on samples taken from the components' oil reservoirs. The staff verified that the applicant amended the LRA and incorporated this
 
enhancement into the LRA, Commitment No. 14, in its letter dated March 20, 2008, to
 
clarify the above enhancement and the enhancement is scheduled for implementation prior
 
to the period of extended operation. The staff finds that this enhancement is acceptable
 
because when the enhancement is implement ed, Oil Analysis Program element "parameters monitored/inspected," will achiev e the objectives of the tests recommended in program element "parameters monitored/in spected" program element in GALL AMP XI.M39, because the process would provide the applicant the ability to trend changes in the
 
concentration of particulates and ferrous wear products in the lubricating oil and hydraulic
 
fluid. Based on this review, the staff finds this enhancement of the program to be
 
acceptable.
 
Operating Experience LRA Section B.3.16 states that operating experience associated with the Oil Analysis Program shows that it has prevented component failures due to oil contamination or degradation effectively. The LRA section states that the program has
 
detected lubricating oil and hydraulic fluid samples with water or particulate contamination
 
in excess of established limits and that correct ive actions have been in accordance with the Corrective Action Program. The LRA section states that there have been no component
 
failures attributed to lubricating oil or hydraulic fluid contamination or degradation.
 
The staff reviewed the above operating experience including the applicant's operating
 
experience evaluations and interviewed the app licant's technical staff and confirmed that the plant-specific operating experience did not reveal any degradation not bounded by
 
industry experience. The staff also reviewed the VEGP operating experience reports and a
 
sample of condition reports and maintenance work orders associated with the corrective
 
actions taken for the identification of signs of degradation of oil from plant components. The
 
staff confirmed that the condition reports were closed out by repairs or performed adequate
 
engineering evaluations for their acceptability.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
3-92  UFSAR Supplement In LRA Section A.2.16, the applicant provided the UFSAR supplement for the Oil Analysis Program. The staff reviewed the applicant's license renewal
 
commitment list dated June 27, 2007, and confirmed that the implementation of the Oil
 
Analysis Program enhancements are identified as Commitment No.14, to be implemented
 
before the period of extended operation. The staff reviewed UFSAR Supplement 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 Oil Analysis Program, the staff concludes 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
 
justification 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 Report AMP to which it was compared. The staff
 
concludes that the applicant has demonstrated that the effects of aging will be adequately
 
managed so that the intended function(s) will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.0.3.2.11  One-Time Inspection Program for ASME Class 1 Small Bore Piping 
 
Summary of Technical Information in the Application LRA Section B.3.18 describes the new One-Time Inspection Program for ASME Class 1 Small Bore Piping as consistent, with exceptions, with GALL AMP XI.M35, "One-Ti me Inspection of ASME Code Class 1 Small-Bore Piping." 
 
The applicant stated that the One-Time Inspection Program for ASME Class 1 Small Bore
 
Piping addresses staff concerns on potential cracking of Class 1 piping with a diameter less than NPS 4. As stated in GALL Report Section XI.M35, the staff believes a one-time
 
inspection program of ASME Code Class 1 Piping less than NPS 4 is necessary to detect
 
SCC and cracking from thermal and mechanical loading. 
 
The applicant also stated that volumetric examination of a sample population of ASME
 
Code Class 1 piping butt welds less than NPS 4 will address SCC concerns. Selection of
 
examination locations will use a risk-based approach considering susceptibility, inspectability, dose, and operating experience.
 
To address unanticipated thermal fatigue cracking of ASME Code Class 1 piping less than
 
NPS 4, VEGP will screen and evaluate pipe lines using Materials Reliability Program (MRP)-146, "Management of Thermal Fatigue in Normally Stagnant Non-Isolable Reactor Coolant System Branch Lines," or later updated guidance. There will be small-bore piping inspections to detect thermal fatigue only at piping locations that fail screening and are not
 
monitored for thermal cycling. 
 
The applicant further stated that program examinations may be incorporated into a staff-
 
approved risk-informed inservice inspection progr am. The inspections will be within the ten years preceding the period of extended operation.
 
VEGP will not examine socket welds volumetr ically. Currently, a reliable and effective volumetric examination to detect cracking in socket welds is not available. There are 3-93 Inservice Inspection (ISI) Program VT-2 visual examinations of ASME Class 1 piping socket welds at each refueling outage.
Staff Evaluation During its audit and review, the staff confirmed 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 One-Time Inspection Program for ASME Code
 
Class 1 Small-Bore Piping for which the applicant claims consistency with GALL AMP XI.M35 and found that they are consistent with the GALL Report AMP. Furthermore, the
 
staff concludes that the applicant's One-Time Inspection Program for ASME Code Class 1
 
Small-Bore Piping will properly manage the agi ng of ASME Code Class 1 small bore piping for the period of extended operation. The staff finds the applicant's One-Time Inspection
 
Program for ASME Code Class 1 Small-Bore Piping acceptable because it conforms to the recommended GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1
 
Small-Bore Piping," with the exceptions as described below.
 
Exception 1. The LRA states an exception to the following GALL Report program element:
Element: 5:  monitoring and trending Exception: GALL AMP XI.M35 specifies volumetric examination to detect cracking due to thermal fatigue. VEGP will screen and
 
evaluate pipe lines using MRP-146, or later updated
 
guidance. Inspections of small bore piping to detect thermal
 
fatigue will be performed only at piping locations that fail the
 
screening and are not monitored for thermal cycling.
 
The staff finds this exception acceptable because the applicant has committed to use the
 
latest industry guidance to screen for those pipe locations that are potentially susceptible to
 
cracking due to thermal fatigue and should be inspected. The locations selected for
 
inspection are those that are not screened out or for which thermal monitoring are not
 
performed. The resulting locations are inspected under the applicant's Inservice Inspection (ISI) Program.
 
During the audit and review, the staff noted that the VEGP program will not specifically
 
perform volumetric examinations of the socket welds, but instead credits periodic VT-2
 
visual examinations of the ASME Code Class 1 piping socket welds under the VEGP
 
Inservice Inspection Program. The staff asked the applicant to provide the basis as to how
 
a VT-2 visual examination, in of itself, can assure the integrity of the small bore ASME
 
Class 1 socket welds in lieu of conforming to the GALL Report recommendation. In addition
 
the applicant was asked to provide the basis for why the surface examination requirements for small bore socket welds in ASME Section XI Examination Categories B-F and B-J
 
should not be credited in addition to the VT-2 visual examinations required under
 
Examination Category B-P.
 
In its response, the applicant stated that the issue of volumetric examination of ASME
 
Class 1 socket welds was recently resolved and included in the NRC's summary dated
 
March 6, 2007 of the license renewal telephone conference call and meeting between the 3-94 NRC staff and the License Renewal Task Force held on February 21, 2007 (ADAMS Accession No. ML070580498). 
 
In the summary, the staff presented its position on small bore socket welds. The GALL
 
AMP, "One-Time Inspection of ASME Class 1 Small Bore Piping," does not mention socket welds. ASME Section XI, ISB-2500, Category B-J requires a surface examination for small
 
bore socket welds larger than one inch in diameter. The industry proposed a substitution of
 
VT-2 examinations in place of the code required surface examination or volumetric
 
examination of socket welds. ASME Code Case N-587-1 permits VT-2 examination of
 
socket welds in place of the code required surface examination during each refueling
 
outage for several reasons. There are no qualified, volumetric examinations for socket
 
welds. Industry experience has shown that cracks in socket welds normally initiate from the
 
inside surface of the socket welds and surface examination is ineffective in detecting the
 
presence of these cracks until they become through wall cracks. Once the cracks become
 
through wall, a VT-2 examination is effective in detecting the associated leakage. The staff
 
agreed that VT-2 examinations of socket welds are acceptable.
 
Exception 2. The LRA states an exception to the following GALL Report program element:
Exception: 6:  acceptance criteria Exception: Acceptance criteria at the time of inspection will be based on the plant-specific VEGP Inservice Inspection Program in conformance with 10 CFR 50.55a. GALL AMP XI.M35 specifies acceptance criteria from ASME Section XI, 2001
 
Edition with 2002 and 2003 Addenda.
 
During the audit and review, the staff noted that the VEGP Inservice Inspection Program
 
second inspection interval ended in May 2007. The staff further noted that the VEGP third inservice inspection interval requirements are based on ASME Section XI, 2001 Edition
 
including the 2002 and 2003 Addenda which are consistent with the GALL Report
 
recommendations. The staff asked the applicant to clarify its position in regard to the above
 
exception. The applicant responded that the LRA will be amended to delete this exception
 
and to revise the program description to state that the current ASME code edition is the
 
2001 Edition with the 2002 and 2003 Addenda. The staff finds this response acceptable
 
because the program will be consistent with the GALL Report recommendations.
 
Furthermore, the staff confirmed that the applicant revised the LRA in a letter dated August 11, 2008 (LRA Amendment No. 3).
 
Under the "monitoring and trending" program element, GALL AMP B.3.18, "One-Time
 
Inspection Program for ASME Class 1 Small Bore Piping," recommends that the number of
 
inspection locations, or sample size, be based on susceptibility, inspectability, dose
 
considerations, operating experience, and limiting locations of the total population of ASME
 
Code Class 1 small-bore piping locations. However, LRA Section B.3.18 states that the
 
examination locations will be selected using a risk-based approach that will consider the
 
susceptibility, inspectability, dose, and operating experience. During the audit and review, the staff asked the applicant to explain how risk is to be used in selecting the examination
 
locations and how a representative sample size for aging management is to be established.
 
In its response, the applicant stated that risk is incorporated into the selection of
 
examination locations in that the VEGP One-Time Inspection Program for ASME Class 1
 
Piping required for license renewal is implem ented at VEGP using the framework of the 3-95 VEGP Risk-Informed ISI (RI-ISI) Program. Under the RI-ISI program, ASME Class 1 piping was broken out into segments based on size of the piping and the consequence of failure.
 
Failure probabilities were calculated for each segment considering failure mechanisms
 
such as thermal stratification and mixing, vibration, stress corrosion cracking, mechanical
 
loading, thermal loading, and transient loading. Consequence of failure and failure
 
probabilities were then integrated to determine the highly safety significant (HSS) segments
 
to be examined. By definition, these piping segments carry a higher risk of failure and a higher risk of significant consequences if failure occurs. The applicant further stated that
 
operating experience at Vogtle and other operating nuclear plants was factored into the
 
evaluation through the use of an expert panel. A statistical model was used to select the
 
minimum number of locations to be examined within each HSS segment to ensure that an
 
acceptable level of piping reliability will be maintained. For each piping segment, the results
 
of the statistical model must show that the number of weld locations selected for inspection
 
results in a confidence level equal to or greater than 95 percent that current safety margins
 
and the integrity of the piping segment will be maintained. The staff finds this acceptable
 
because the selection process provides an inspection sample that provides a 95 percent
 
confidence level that the current safety margins will be maintained and piping reliability
 
maintained.
 
Operating Experience LRA Section B.3.18 states that there is no programmatic operating experience specifically applicable to this new program but that the selection of the
 
component sample set will consider plant-specific and industry operating experience.
 
Screening, evaluation, and inspection of piping locations for thermal fatigue will be based
 
on industry guidance that incorporates operating experience and research data.
 
The applicant stated that VEGP experienced leakage in small-bore residual heat removal (RHR) bypass lines due to inadequate design. Four leakage events occurred on an RHR
 
loop suction valve bypass line between December 2005 and March 2006, resulting in
 
nonisolable RCS pressure boundary leakage. There had been no through-wall leakage in
 
the bypass line since original construction and start-up 16 years earlier. 
 
The 3/4-inch diameter bypass line was part of the original design. Its purpose is to relieve
 
pressure between the two RHR loop suction isolation gate valves. In 2002, a modification
 
used this original line to relieve excess pressure in the valve bonnet and between the valve
 
disks back towards the RCS. The first leak in December 2005 was at one of the 2002
 
modification welds.
 
The applicant further stated that an extensive evaluation to determine the cause of the
 
leaks found the RHR pipe from the RCS nozzle to the closed valve pulsing from acoustic
 
vibration caused by RCS flow past the nozzle causing vortex shedding based on flow rate
 
and nozzle size. Energy from the vortex shedding drives the acoustic vibration of the RHR
 
pipe. Because the bypass line was not axially restrained, resonance from the vortex
 
shedding and other factors caused the RHR piping to vibrate with sufficient force to
 
increase stress at the break locations above the endurance limit of the material, resulting in
 
fatigue cracks.
 
The applicant removed the bypass line and leak-off lines on Unit 2, Loop 1, where the
 
leakage occurred and installed temporary accelerometers on both Unit 2 bypass lines
 
currently monitored. So far the vibration levels remain acceptable. From the results of the
 
evaluation, the applicant determined that the problem is design-related and not an AERM. 
 
3-96 During the on-site audit, the staff confirmed that VEGP has ongoing programs to monitor industry and site specific operating experience. These programs include mechanisms to
 
update or modify plant procedures or practices to incorporate lessons learned.
 
Furthermore, the staff confirmed that there were no aging related degradation failures in the
 
Vogtle small bore piping. On the basis of its review of the above plant-specific operating
 
experience and discussions with the applicant's technical staff, the staff finds that the
 
applicant's One-Time Inspection Program for ASME Code Class 1 Small Bore Piping when
 
implemented will adequately manage the aging effects for which the AMP is credited.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section A.2.18, the applicant provided the UFSAR supplement for the One-Time Inspection Program for ASME Class 1 Small Bore Piping. The staff
 
reviewed the applicant's license renewal commitment letter (NL-07-1261, dated June 27, 2007) and confirmed that this program is identified as Commitment No. 16 to be
 
implemented before the period of extended operation. The staff reviewed LRA
 
Section A.2.18 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).
 
Conclusion On the basis of its audit and review of the applicant's One-Time Inspection Program for ASME Class 1 Small Bore Piping, the staff finds, with the implementation of
 
Commitment No. 16, 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 determined that it provides an adequate summary description
 
of the program, as required by 10 CFR 54.21(d).
 
3.0.3.2.12  One-Time Inspection Program for Selective Leaching 
 
Summary of Technical Information in the Application LRA Section B.3.19 describes the new One-Time Inspection Program for Selective Leac hing as consistent, with exception, with GALL AMP XI.M33, "Selective Leaching of Materials." 
 
The applicant stated that the One-Time Inspection Program for Selective Leaching
 
assesses selective leaching in susceptible cast iron and copper alloy components. The
 
program includes a one-time examination of a sample population of components most likely
 
to exhibit selective leaching. If initial examinations to be completed prior to the period of
 
extended operation find degradation due to selective leaching there will be additional
 
examinations.
 
Examination techniques may include hardness measurement (where feasible based on
 
form and configuration), visual examination, metallurgical evaluation, or other techniques
 
proven effective in detecting and assessing the extent of selective leaching. The
 
inspections will be within the ten years preceding the period of extended operation.
 
3-97 Staff Evaluation During its audit and review, the staff confirmed 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.
 
During the audit, the staff interviewed the applicant's technical staff and reviewed
 
documents related to the One-Time Inspection Program for Selective Leaching, including
 
the license renewal basis document in which the applicant assessed whether the program elements are consistent with GALL AMP XI.M33. The staff finds for those portions of the
 
program for which the applicant claims consistency with the GALL Report AMP that they
 
are consistent. Furthermore, the staff concludes that the applicant's One-Time Inspection
 
Program for Selective Leaching will properly m anage the selective leaching of susceptible cast iron and copper alloy components for the period of extended operation. The staff finds
 
the applicant's One-Time Inspection Program for Selective Leaching acceptable because it conforms to the recommended GALL AMP XI.M33, "Selective Leaching of Materials," with
 
the exception as described below.
 
The LRA states an exception to the following GALL Report program element:
 
Element: 4:  detection of aging effects
 
Exception: GALL AMP XI.M33 specifies visual inspection and hardness measurement to detect selective leaching. The VEGP Selective
 
Leaching Program may use other detection techniques instead of, or
 
in addition to, visual examination and hardness measurement. For
 
some component locations, visual examination and hardness
 
measurement may not be feasible due to geometry and configuration
 
issues. Additionally, other examination methods may be shown to be
 
equally effective in detecting and assessing the extent of selective
 
leaching.
 
During the audit and review, the staff reviewed the exception with the applicant to clarify the
 
use of the proposed alternate examination techniques that may be used to detect selective
 
leaching in some materials and their configurations. The staff finds this exception
 
acceptable because the alternate techniques are capable of detecting the presence of
 
selective leaching and are being used in addition to visual inspections as recommended by
 
the GALL Report. Therefore, the program will address the recommendations of the GALL
 
Report and be consistent with the "detection of aging effects" program element. 
 
Operating Experience LRA Section B.3.19 states that operating experience for license renewal shows no incidents of selective leaching. There is no programmatic operating
 
experience for the new one-time inspections for selective leaching but the selection of the
 
initial component sample set will consider plant-specific and industry operating experience.
 
During the audit and review, the staff reviewed the program documents that explained how
 
operating experience is captured. The program documents state that a condition report will
 
be prepared documenting the results of the inspections, which will include a detailed
 
description of the visual examination and hardness testing locations. Additionally, the
 
documents state that if any conditions are observed which do not meet the acceptance
 
criteria, then appropriate actions will be taken to prevent the component from being
 
returned to service until required corrective actions have been completed. The documents 3-98 further state that the applicant's Engineering Support group will evaluate the inspection results for operability, component life, repair options, or other corrective actions as
 
appropriate. The staff's finds that this monitoring assessment and corrective action is
 
acceptable.
 
On the basis of its review and discussions with the applicant's technical staff, the staff finds
 
that the applicant's One-Time Inspection Program for Selective Leaching, when
 
implemented, will adequately manage the aging effects for which the AMP is credited.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. 
 
The staff finds this program element acceptable.
 
UFSAR Supplement In LRA Section A.2.19, the applicant provided the UFSAR supplement for the One-Time Inspection Program for Selective Leaching. The staff reviewed the
 
applicant's license renewal commitment letter (NL-07-1261, dated June 27, 2007) and
 
confirmed that this program is identified as Commitment No. 17 to be implemented before
 
the period of extended operation. 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 One-Time Inspection Program for Selective Leaching, the staff finds, with the implementation of Commitment No.
 
17, 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
 
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 determined that it provides an adequate summary description of the program, as
 
required by 10 CFR 54.21(d).
 
3.0.3.2.13  Piping and Duct Internal Inspection Program 
 
Summary of Technical Information in the Application LRA Section B.3.22 describes the new Piping and Duct Internal Inspection Program as consistent, with exceptions, with GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting
 
Components." 
 
The applicant stated that the Piping and Duct Inspection Program manages corrosion of
 
steel, stainless steel, and copper alloy components and degradation of elastomer
 
components due to changes in material properties. Components included in the scope of
 
this program are not addressed by other AMPs.
Inspections normally will be concurrent with scheduled preventive maintenance, surveillance testing, and corrective maintenance.
 
Specific examinations not coordinated with scheduled work activities also may proceed at the discretion of the program owner. Inspection locations and intervals will be dependent on
 
the likelihood of significant degradation and on current industry and plant-specific operating
 
experience.
 
3-99 The applicant also stated that examination techniques will be appropriate to detect and assess the aging mechanism of concern and may include visual examination and non
 
visual nondestructive examination (e.g., ultrasonic testing or radiography, physical manipulation of elastomers, etc). The new Piping and Duct Internal Inspection Program will
 
be implemented prior to the period of extended operation.
 
Staff Evaluation During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. 
 
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 also reviewed the information in the VEGP Piping and Duct Internal Inspection
 
Program, the license renewal (LR) basis evaluation document, and VEGP-specific
 
procedures that pertain to the design, details, and implementation of this AMP.
 
The staff noted that the applicant identifies the Piping and Duct Internal Inspection Program
 
as a new AMP that is designed to be consistent with the program elements in GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components"
 
with exceptions.
 
The staff concludes from its review of the LR basis evaluation document that the program elements for the "Piping and Duct  Internal Inspection Program" were all consistent with the program element criteria recommended in GALL AMP XI.M38 with the following four
 
exceptions. The staff's evaluation on how these exceptions provide for adequate aging
 
management is described in the following section.
 
Exceptions
:
Exception 1: The LRA section B.3.22 identifies that the Piping and Duct Internal Inspection
 
Program includes the following exception to t he "scope of program", program element in GALL AMP XI.M38:
 
The program scope described in NUREG-1801, Section XI.M38 includes
 
only steel piping, piping components, ducting, and other components. The
 
VEGP Piping and Duct Internal Inspection Program also includes stainless
 
steel, copper alloy and elastomer components."
 
The staff noted that this exception is an augmentation of the applicant's new program to
 
include stainless steel, copper alloy and elastomer components in the scope of the
 
program. Stainless steel materials are designed to be corrosion resistant in an uncontrolled
 
air environment. Copper alloy materials typica lly develop copper oxide surface layer in an air environment that protects the alloy from further corrosion. Since these materials have
 
innate corrosion resistance, the staff finds the inclusion of stainless steel and copper alloy
 
within the scope of this AMP is conservative and acceptable. The staff finds the inclusion of
 
components with the stainless steel, copper alloy, and represents an augmentation of the
 
AMP that exceeds the recommended program criteria in the GALL AMP XI.M38.
 
The staff questioned the applicant on extending this AMP to elastomeric components, and
 
with simply using visual examination methods to manage cracking or changes in the
 
material properties for these materials. In RAI 3.3-1/3.4-1, the staff asked the applicant to 3-100 justify its basis for crediting the AMP to manage cracking or changes that might occur in the material properties in the type of materials for AMPs that credit visual examinations of
 
external polymer (including thermo, thermo set, elastomer or rubber) surfaces. The staff
 
also asked the applicant to clarify how a visual examination alone would be capable of
 
detecting cracking or a change in specific material properties for these types of materials.
 
By letter dated July 17, 2008, the applicant provided its response to RAI 3.3-1 and 3.4-1. In
 
its response, the applicant stated that this AMP does not, "only credit visual examinations to
 
detect cracking and changes in material properties of polymers."  The applicant further
 
stated that visual examinations will be performed to detect discontinuities and imperfections
 
on the surface of the component, and non-visual examinations such as tactile techniques, which include scratching, bending folding, stretching and pressing, will be performed in
 
conjunction with the visual examinations.
 
The staff noted that VEGP is crediting both visual examinations and tactile techniques to
 
detect for cracking and change in material properties for elastomers and polymers. The
 
staff further noted that the applicant described the specific tactile techniques that may be
 
used in conjunction with the visual examine. The staff noted that these techniques include
 
scratching the material surface to screen for residues that may indicate a breakdown of the
 
polymer material, bending or folding of the component which may indicate surface cracking, stretching to evaluate resistance of the polymer material and pressing on the material to
 
evaluate the resiliency. Based on its review of the applicant's response, the staff finds it
 
acceptable because the applicant has indicated that VEGP is not crediting visual
 
examinations alone to detect cracking and change in material properties for elastomers and
 
polymers, and that VEGP has credited tactile techniques, as described above, as well to
 
detect for such aging effects as cracking and change in material properties.
 
Based on this review, the staff finds that this exception to the "scope of program", program elements in the GALL AMP XI.M38 is acceptable because the added component types
 
within the scope of the applicant's AMP have adequate detection and mitigative actions to
 
detect the aging effects of external polymer surfaces. 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. 
 
Exception 2: The LRA section B.3.22 identifies that the Piping and Duct Internal Inspection
 
Program includes the following exception to t he "parameters monitored/inspected," program element in GALL AMP XI.M38:
 
The VEGP Piping and Duct Inspection Program will monitor not only
 
Component surfaces through visual examination, but may also use non-
 
visual techniques to monitor parameters such as wall thickness and
 
ductility.
 
The staff noted that this exception is an augmentation of the applicant's new program to
 
include monitoring, not only component surfaces through visual examination and non -
 
visual examination, but may also monitor parameters such as wall thickness and ductility.
 
The staff finds the inclusion of monitoring the parameters such as wall thickness and
 
ductility represents an acceptable augmentation of the AMP that goes beyond the recommended program criteria in the GALL AMP XI.M38. The inclusion of monitoring 3-101 parameters such as wall thickness and ductility will enable the program to monitor the changes such as effects of erosion in Piping and Duct Internal materials.
 
Based on this review, the staff finds that this exception to the "Parameters
 
Monitored/Inspected," program element in GALL AMP XI.M38 is an augmentation of the program Element and determines that the AMP with the exception is adequate to manage
 
the aging effects for which it is credited. Therefore, this exception is acceptable. 
 
Exception 3: The LRA section B.3.22 identifies that the Piping and Duct Internal Inspection
 
Program includes the following exception to the "detection of aging effects," and "monitoring and trending," program elements in GALL AMP XI.M38:
 
The VEGP Piping and Duct Internal Inspection Program may use other
 
detection techniques instead of, or in addition to, visual examination. For
 
some materials or component locations, visual examination may not be the
 
most appropriate inspection technique or may not be feasible due to
 
geometric or other limitations. This difference is justified because other
 
examination methods can be shown to be equally effective in detecting and
 
assessing degradation. The VEGP Piping and Duct Inspection Program will
 
monitor not only component surfaces through visual examination, but may
 
also use non-visual techniques to monitor parameters such as wall thickness
 
and ductility.
 
The staff noted that this exception is an augmentation of applicant's new program to include
 
monitoring not only component surfaces through visual examination, but may also use non-
 
visual techniques to monitor parameters such as wall thickness and ductility. The staff finds
 
the inclusion of monitoring not only component surfaces through visual examination, but
 
also the use of non-visual techniques to monitor parameters, such as wall thickness and
 
ductility in the scope of the AMP represents an acceptable augmentation of the AMP that goes beyond the recommended program criteria in the GALL AMP XI.M38. The staff finds
 
that the applicant has proposed to implement the AMP in a manner that will provide added assurance to manage and detect the age related degradation in this new Piping and Duct
 
Internal Inspection Program.
 
In RAI 3.3-1/3.4-1, the staff sought additional clarification on how visual examination
 
methods alone would be capable of detecting cracking or change in material properties for
 
elastomer/polymer components that are within the scope of this AMP. This applicant's
 
response to RAI # 3.3-1 and 3.4-1 is relevant to whether the inspection techniques credited
 
under this AMP, including those supplemental techniques addressed in the exception 3, are
 
capable of managing loss of material, cracking, or material property changes in
 
polymer/elastomer components.
 
By letter dated July 17, 2008, the applicant provided its response to RAI 3.3-1 and 3.4-1. In
 
its response, the applicant stated that this AMP does not, "only credit visual examinations to
 
detect cracking and changes in material properties of polymers."  The applicant further
 
stated that visual examinations will be performed to detect discontinuities and imperfections
 
on the surface of the component, and non-visual examinations such as tactile techniques, which include scratching, bending folding, stretching and pressing will be performed in
 
conjunction with the visual examines.
 
The staff noted that VEGP is crediting both visual examinations and tactile techniques to 3-102 detect for cracking and change in material properties for elastomers and polymers. The staff further noted that the applicant described the specific tactile techniques that may be
 
used in conjunction with the visual examination. The staff noted that these techniques
 
include scratching the material surface to screen for residues that may indicate a
 
breakdown of the polymer material, bending or folding of the component which may
 
indicate surface cracking, stretching to evaluate resistance of the polymer material and
 
pressing on the material to evaluate the resiliency. Based on its review of the applicant's
 
response, the staff finds it acceptable because the applicant has indicated that VEGP is not
 
crediting visual examinations alone to detect cracking and change in material properties for
 
elastomers and polymers, and that VEGP has credited tactile techniques, as described
 
above, as well to detect for such aging effects as cracking and change in material
 
properties.
 
Based on this review, the staff finds that this exception to the "detection of aging effects,"
and "monitoring and trending," program element in the GALL AMP XI.M38 is acceptable
 
because tactile techniques were added to the program to detect cracking and changes in
 
material properties of polymers/elastomer components. 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 exception therefore is acceptable.
 
Exception 4: The LRA section B.3.22 identifies that the Piping and Duct Internal Inspection
 
Program includes the following exception to t he "acceptance criteria," program element in GALL AMP XI.M38:
 
The VEGP Piping and Duct Internal Inspection Program will include
 
Acceptance criteria for both visual and non-visual techniques. Acceptance
 
criteria will be defined in program procedures. For physical manipulation or 
 
destructive examination of elastomers, no indication of unacceptable
 
hardening, de-lamination, or cracking of the elastomer is acceptable.
For thickness measurements of steel, stainless steel, and copper alloy
 
components, remaining wall thickness must be sufficient to provide
 
reasonable assurance that the component will continue to perform its
 
component function until the next scheduled inspection.
 
The applicant's inclusion in this exception to include "Acceptance Criteria" for both visual
 
and non-visual techniques will augment this AMP with exception to adequately manage the
 
aging effects for which it is credited.
 
The staff noted that the applicant's inclusion of the both visual and non-visual techniques
 
required the acceptance criteria to be expanded so that it included relevant updates to
 
implementing procedures with the proper acceptance criteria for the additional non-visual
 
inspection techniques. On the basis of its review, the staff has determined this exception is
 
acceptable because the applicant has included an expansion of its acceptance criteria and
 
will provide updates to the implementing procedures for this program to reflect the
 
additional non-visual inspection techniques that this program will use to manage the aging
 
effects with in the scope of this program. 
 
The staff also noted that the applicant has included the need for initiating and conducting its
 
implementation of this AMP in LRA Commitment No.19, letter dated March 20, 2008.
 
3-103 The staff finds that the applicant has proposed to implement the AMP in a manner that will provide adequate management and detection of the age related degradation in this new
 
Piping and Duct Internal Inspection Program.
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. Therefore, this exception is acceptable.
 
Operating Experience LRA Section B.3.22 states that there is no specific programmatic operating experience for this new program because it is a new program and it has not been
 
implemented yet. The applicant indicated that the selection of inspection locations, inspection intervals, and prescriptions of appropriate inspection techniques will consider
 
plant-specific and industry operating experience. Because this is a new program, by letter
 
dated March 20, 2008, the applicant committed (Commitment No.19) to initiating and
 
implementing the Piping and Duct Internal Inspection Program prior to the period of
 
extended operation.
 
During the staff audit, the staff discussed the aspect of new AMPs with the plant personnel;
 
the applicant stated that there is no programmatic operating experience specifically
 
applicable to this new program. However, the results of existing maintenance inspections
 
are relevant to this program. Degradation of components identified during a maintenance
 
inspection is required to be documented in a Condition report (CR). The review of VEGP
 
operating experience identified a small num ber of CR's which have been submitted for degradation of internal surface of the components in the scope of this program. No
 
occurrence of aging of internal surfaces of a component exposed to an air environment was
 
identified. Some degradation of the internal surfaces of carbon steel components exposed
 
to raw water environment was been identified. The Piping and Duct Internal Inspection
 
Program will manage aging of internal surfaces of components in the scope of this program during the period of extended operation. Plant and industry operating experience will be
 
considered in selecting Inspection locations determining inspection intervals, and
 
prescribing appropriate inspection techniques.
The staff noted the inspection techniques and nondestructive examination techniques are
 
well proven in the industry and have been demonstrably effective in detecting degradation.
 
Inspections of internal surfaces during maintenance have proven effective in maintaining
 
the material condition of plant systems and components.
 
The program is based on the GALL Report program, which is based in turn on industry
 
operating experience. The plant does not have plant-specific operating experience
 
consistent with the operating experience described in the GALL AMP.
 
During the audit and review, the staff reviewed the operating experience discussed in the
 
LRA and in the basis document for the Piping and Duct Internal Inspection Program. In
 
addition, the staff reviewed a sample of condition reports for degraded piping and duct
 
components. The staff finds that the review of the operating experience documented in the
 
LRA and basis document for the Piping and Duct Internal Inspection Program did not reveal
 
any unusual or significant findings. 
 
The staff also finds that the applicant did not identify any age-related related issues not
 
bounded by the industry operating experience.
 
The staff also noted when the above aspects of Exception # 4 of this program (1) Operating
 
experience is documented (2) RAIs # 3.3-1 and #.3.4-1 are resolved and accepted (3) LRA 3-104 Commitment No.19, as described in the response letter dated March 20, 2008, is fully implemented, the program bounds operating experience that may occur in the future and
 
the program will be capable of managing the aging effect during the period of extended
 
operation.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement The staff reviewed the UFSAR Supplement summary description that was provided in LRA Section A.2.22 for the Piping and Duct Internal Inspection Program.
 
The staff verified that, in LRA Commitment No. 19 in the applicant's response letter dated
 
March 20, 2008, the applicant committed to implement the Piping and Duct Internal
 
Inspection Program prior to the period of extended operation. The staff also verified that the
 
applicant has placed this commitment on UFSAR Supplement summary description A.2.22
 
for Piping and Duct Internal Inspection Program. 
 
Based on this review, the staff finds that UFSAR Supplement Section A.2.22 provides an
 
acceptable UFSAR Supplement summary description of the applicant's Piping and Duct
 
Internal Inspection Program, which uses appropriate examination techniques on locations
 
likely to have significant degradation in materials such as steel, stainless steel, copper and
 
elastomer components, and will be implemented as committed to in LRA Commitment No.
: 19. 
 
Therefore, the staff concludes that the UFSAR supplement for this AMP provides an
 
adequate summary description of the program, as described by 10 CFR 54.21(d).
 
Conclusion On the basis of its audit and review of the applicant's Piping and Duct Internal Inspection Program, the staff concludes 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 determined that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.2.14  Reactor Vessel Closure Head Stud Program
 
Summary of Technical Information in the Application LRA Section B.3.23 describes the existing Reactor Vessel Closure Head Stud Program as consistent, with exceptions, with GALL AMP XI.M3, "Reactor Head Closure Studs." 
 
The applicant stated that the Reactor Vessel Closure Head Stud Program has preventive
 
measures as described in Regulatory Guide 1.65 and Inservice Inspection (ISI) programs to
 
manage loss of material and cracking in the reactor vessel closure head studs, nuts, and
 
washers.
 
The applicant also stated that preventive measures include material controls and the use of
 
approved lubricants. Reactor vessel head studs are fabricated from modified SA-540 Grade 3-105 B24 material as specified in ASME Boiler and Pressure Vessel Code Case 1605. This code case is not specified in Regulatory Guide 1.65 but is approved by Regulatory Guide 1.85.
 
Actual stud material properties have ultimate tensile strengths less than 170 ksi. Each
 
reassembly lubricates the reactor vessel closure head studs and nuts with an approved, stable lubricant.
 
The applicant further stated that condition monitoring includes visual and volumetric
 
examinations and leakage detection consistent with the ISI Program. These inspections are
 
in accordance with 10 CFR 50.55(a), which imposes the ISI requirements of ASME Code Section XI for Classes 1, 2, and 3 pressure-retaining components and their attachments.
 
The ISI Program second inspection interval ended in May 2007. The third ISI interval requirements are based on ASME Code Section XI, 2001 Edition and 2002 and 2003
 
Addenda.
 
Staff Evaluation During its audit and review, the staff confirmed 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.
 
During the audit, the staff interviewed the applicant's technical staff and reviewed
 
documents related to the Reactor Head Closure Studs Program, as listed in the audit
 
summary, including the license renewal program basis document in which the applicant
 
assessed whether the program elements, with the exceptions described below, are consistent with GALL AMP XI.M3.
 
On the basis of its review, the staff concludes that the VEGP Reactor Vessel Closure Head
 
Stud Program includes preventive measures and condition monitoring examinations to adequately manage loss of material and cracking in the reactor vessel closure head studs, nuts, and washers during the period of extended operation. The staff finds LRA B.3.23
 
program elements, with the exception described below, consistent with the GALL AMP XI.M3.
 
Exception In the LRA, the applicant identified two exceptions to the GALL AMP XI.M3 program elements. 
 
Exception (1)- The LRA B.3.23 states an exception to the following GALL Report program
 
elements:
 
Elements 3: Parameters Monitored/Inspected 4: Detection of Aging Effects 
 
5: Monitoring and Trending
 
6: Acceptance Criteria
 
Exception NUREG-1801, Section XI.M3, describes the program as conforming to the requirements of ASME Section XI, 2001 Edition including the
 
2002 and 2003 Addenda. However, 10 CFR 50.55a governs the
 
application of Codes and Standards. While the VEGP Inservice
 
Inspection Program for the 3rd inspection interval will use the 2001
 
Edition including the 2002 and 2003 Addenda, the program will be 3-106 updated in conformance with 10 CFR 50.55a for future inspection intervals.
Additionally, volumetric examinations are in compliance with
 
the performance demonstration initiative. This initiative
 
program is currently based on Appendix VIII, 2001 Edition of Section XI as mandated by 10 CFR 50.55a.
 
These differences are considered to be an exception to NUREG-1801, Rev. 1 Section XI.M3.
Exception (2)- The LRA B.3.23 states an exception to the following GALL Report program
 
elements:
 
Elements 4: Detection of Aging Effects
 
Exception The program described in NUREG-1801, Rev. 1, Section XI.M3 includes visual, surface, and volumetric examinations.
 
The VEGP 3rd inservice inspection interval requirements will be based on ASME Section XI, 2001 Edition including the
 
2002 and 2003 Addenda. This edition of the ASME Code
 
does not require surface examinations and the VEGP
 
program will not include surface examination of the reactor
 
vessel closure head studs unless required by a future Code
 
Edition specified in 10 CFR 50.55a
 
The staff noted that the first exception in LRA AMP B.3.23, "Reactor Vessel Closure Head
 
Stud Program," for program elements 3, 4, 5, and 6 states that VEGP Inservice Inspection
 
Program for the 3rd inspection interval will use the 2001 Edition, inclusive of 2002 and 2003 Addenda. However, the ASME Code Section XI Edition 2001, including the 2002 and 2003 Addenda, is also referenced in GALL AMP XI.M3. The staff recognized that the applicant
 
had used a similar approach for identifying exceptions to several LRA aging management
 
program. During the audit and review, the staff asked the applicant to explain why the
 
relevant statement on the ASME Code edition for the LRA AMPs is considered to be an
 
exception to GALL AMPs, or clarify if the LRA needs to be amended to delete this
 
exception based on the staff's determination.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. The applicant in its response stated that VEGP understands it is the staff's interpretation that use of later Editions of ASME Section XI than the edition specified in the
 
GALL Report, Revision 1, for future inspection intervals is not an exception to the GALL Report, provided the Edition of ASME Section XI currently used is the same Edition
 
referenced in the GALL Report, Revision 1. As a result, the applicant in its letter dated
 
March 20, 2008 amended the LRA Section B.3.23 to remove this exception. In addition, the
 
applicant revised the "Program Description" text for VEGP license renewal application section B.3.23 and confirmed that VEGP is currently using the ASME Code Section XI
 
Edition 2001, including the 2002 and 2003 Addenda that is consistent with the GALL AMP XI.M3 recommendation. The staff finds the applicant's response and the revision to the
 
LRA acceptable; on the basis this portion of the program is consistent with the GALL AMP XI.M3 recommendation.
 
3-107 In its review of Exception (1), the staff noted that LRA AMP B.3.23, "Reactor Vessel Closure Head Stud Program," states that volumetric examinations are in compliance with
 
the performance demonstration initiative (PDI) and the applicant considered this as an exception to the GALL AMP XI.M3, "Reactor Head Closure Studs," recommendations.
However, the staff recognized that GALL AMP XI.M3 recommends volumetric examination
 
in accordance with the general requirements of Subsection IWA-2000 and does not
 
mention specifically compliance with the PDI criteria of 10 CFR 50.55a. During the audit
 
and review, the staff requested that the applicant clarify whether its PDI program activities
 
for volumetric examinations are exceptions to the criteria in GALL AMP XI.M3 or they are beyond the recommendations of GALL AMP XI.M3. The staff also asked the applicant to
 
discuss how its PDI activities for the volumetric examinations of the closure studs ensure
 
that the volumetric examinations would be capable of detecting the aging effects that are
 
applicable to the studs for the period of extended operation.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. The applicant in its response stated that:
 
ASME Section XI, Mandatory Appendix VIII addressed performance demonstration for
 
ultrasonic examination systems. The performance demonstration requirements implemented in Appendix VIII to ASME Section XI include requirements for examination procedures, personnel qualification, and examination qualification testing. This approach
 
provides a high level of assurance that the combination of equipment, personnel, and
 
procedure is capable of detecting flaws during volumetric examinations. The techniques described in Appendix VIII to ASME Section XI were developed using a consensus process
 
and have been approved for use by the staff via 10 CFR 50.55a. Examinations qualified to
 
meet Appendix VIII requirements provide a higher level of assurance that flaws will be detected and accurately sized when compared with previously used volumetric examination requirements.
 
Regarding implementation of Appendix VIII, 10 CFR 50.55a (g)(6)(C) states:
 
"Implementation of Appendix VIII to Section XI. (1) Appendix VIII and the supplements to Appendix VIII to Section XI, Division 1, 1995 Edition with the 1996 Addenda of the ASME
 
Boiler and Pressure Vessel Code must be implemented in accordance with the following
 
schedule: Appendix VIII and Supplements 1, 2, 3, and 8--May 22, 2000; Supplements 4
 
and 6--November 22, 2000; Supplement 11--N ovember 22, 2001; and Supplements 5, 7, and 10--November 22, 2002."  And, 10 CFR 50.55a (b)(1)(xxiv) states:
 
"Incorporation of the Performance Demonstration Initiative and Addition of
 
Ultrasonic Examination Criteria. The use of Appendix VIII and the supplements to Appendix VIII and Article I-3000 of Section XI of the ASME
 
BPV Code, 2002 Addenda through the latest edition and addenda
 
incorporated by reference in paragraph (b)(2) of this section, is prohibited."
 
Appendix VIII, Supplement 8 provides qualification standards for bolts and
 
studs. Therefore, SNC was required by 10 CFR 50.55a (g)(6)(C) to
 
implement PDI requirements for exami nation of reactor vessel closure head studs no later than May 22, 2000. Additionally, SNC is currently prohibited by
 
10 CFR 50.55a (b)(1)(xxiv) from using Appendix VIII and the supplements to 3-108 Appendix VIII from the 2002 Boiler & Pressure Vessel Code, or any later edition and addenda incorporated into 50.55a.
 
As a result, this exception is intended to clarify that examinations of reactor
 
vessel closure head studs will comply with ISI Program requirements as
 
implemented consistent with 10 CFR 50.55a and not any specific ASME Section XI Code edition and addenda cited in NUREG-1801, Section XI.M3.
 
The staff reviewed the above applicant's response and determined that 1)
 
the applicant clearly explained that VEGP is required to incorporate PDI
 
qualifications instead of the supplements to Appendix VIII and Article I-3000 of Section XI of the ASME Code, 2002, and 2) the staff verified that the
 
required PDI qualifications are more restrictive than the requirements ASME Section IX, IWB-3500 that are recommended by GALL XI.M3. 
 
On the basis of its review, the staff finds the applicant's response and this
 
portion of Exception (1) acceptable.
 
In its review of the exception (2), the staff noted that LRA AMP B.3.23, "Reactor Vessel Closure Head Stud Program," states that VEGP will not include surface examination in this program, since ASME Code, Section XI, 2001 Edition, including the 2002 and 2003 addenda, does not require
 
surface examination. However, the staff recognized that the GALL AMP XI.M3, "Reactor Head Closure Studs," program element "detection of aging
 
effects," states the program uses visual, surface, and volumetric
 
examinations in accordance with the general requirements of Subsection IWA-2000. The GALL AMP XI.M3 also states that the program uses
 
magnetic particle, liquid penetration, or eddy current surface examination to
 
indicate the presence of surface discontinuities and flaws. Also, in RG 1.65, Paragraph C.4, the NRC recommended that the requirements of Section XI
 
of the ASME Code should be supplemented to include a surface
 
examination in accordance with paragraph NB-2545 or NB-2546 of Section
 
III of the ASME Code. During the audit and review, the staff asked the
 
applicant to provide technical justification for excluding surface examinations
 
from the scope of this program, or enhance the VEGP program to include
 
surface examinations as recommended by the GALL AMP XI.M3.
The applicant provided its response to the staff's question in a letter dated February
 
8, 2008. The applicant in its response stated that VEGP UFSAR Section 1.9.65.2
 
describes the VEGP position regarding conformance with NRC Regulatory Guide
 
1.65. VEGP UFSAR Section 1.9.65.2, Item3, states that all bolting surface examinations will be performed in accordance with ASME Section XI in lieu of
 
paragraph NB-2545 or NB-2546 of ASME Section III. The applicant also stated that
 
volumetric examination techniques, especially those in conformance with Appendix VIII to ASME Section XI are much improved over the volumetric techniques
 
available at the time Regulatory Guide 1.65 was issued (October 1973) and
 
currently, surface examination in addition to volumetric examination does not
 
provide a significant improvement in assurance of the level of quality and safety.
 
The staff discussed the applicant's response with the applicant's technical staff during the
 
audit and review. The staff also reviewed the Reactor Vessel Closure Head Stud Program 3-109 related documents and the VEGP Units 1 and 2 Inservice Inspection Summary Reports for the reactor closure head studs. The staff concludes that VEGP reactor closure studs examinations in conformance to ASME Section XI. The applicants program is in accordance with a later addition to the ASME Section XI code and therefore provides an
 
acceptable basis for the exception to GALL Report. 
 
On the basis of this review, the staff finds the applicant's response and the exception (2) to the GALL AMP XI.M3 acceptable.
 
Operating Experience LRA Section B.3.23 states that Reactor Vessel Closure Head Stud Program inspections are based on ASME Code requirements. Because the ASME Code is
 
a consensus document widely used over a long period, it has been effective in managing
 
aging effects in components and their attachments.
 
The applicant stated that the Reactor Vessel Closure Head Stud Program is in accordance
 
with general requirements for engineering programs. Periodic program reviews ensure
 
compliance with regulatory, process, and procedural requirements. 
 
Recent VEGP records show pitting of the nuts and washers for three Unit 2 closure stud
 
assemblies. In the applicant's engineering judgment, the pitted nuts and washers no longer
 
met minimum contact surface requirements and were replaced.
 
The applicant also stated that GALL AMP XI.M3, "Operating Experience" element states
 
that the SCC has occurred in BWR pressure vessel head studs (Stoller 1991). The aging
 
management program has provisions regardi ng inspection techniques and evaluation, material specifications, corrosion prevention, and other aspects of reactor pressure vessel
 
head stud cracking. The applicant further stated that implementation of the program
 
provides reasonable assurance that the effects of cracking due to SCC or IGSCC and loss
 
of material due to wear will be adequately managed so that the intended functions of the
 
reactor head closure studs and bolts will be maintained consistent with the current licensing
 
basis for the period of extended operation.
 
During the audit and review, the staff noted that the applicant in the operating experience
 
section of the Reactor Vessel closure Head Stud Program states that review of recent
 
VEGP records identified pitting of the nuts and washers for three Unit 2 closure stud
 
assemblies. However, the staff recognized that neither LRA AMR tables, nor GALL Volume
 
2 tables, includes managing loss of material due to corrosion pitting for closure head stud
 
assemblies in the scope of this program. The staff asked the applicant to clarify whether, or
 
not, loss of material due to pitting is included in this program. Also, the staff requested that
 
the applicant discuss how this aging effect is managed by Rector Closure Stud Program, and to provide additional details on identification of pitting of the nuts and washers and the
 
associated corrective actions. 
 
Further, the staff asked the applicant to provide additional details on VEGP's operating
 
experience related to this program, with emphasize on identification of cracking, loss of
 
material, or leakage, during the last five years of operation.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. The applicant in its response stated that an AMR line item to address corrosion of the
 
VEGP RPV closure head studs was inadvertently omitted from Table 3.1.2-1. The staff confirmed that the applicant in its letter dated March 20, 2008 added an Item"6d" to VEGP 3-110 LRA Table 3.1.2-1 to address corrosion of closure studs, nuts, and washers, and credited the Reactor Vessel Closure Head Stud Program to manage this aging effect.
 
The staff finds this response acceptable and that the applicant has addressed the relevant
 
operating experience because: (1) the applicant appropriately amended the LRA to include
 
an AMR on loss of material due to corrosion of closure studs, nuts, and washers in LRA
 
Table 3.1.2-1, (2) the program is designed to manage and detect the aging effects that are
 
applicable to the RV closure stud assembly components, and (3) the program has been determined to be consistent with GALL AMP X1.M3 "Reactor Head Closure Studs".
 
The staff confirmed that the "operating experienc e" program element satisfies the criteria defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section A.2.23, the applicant provided the UFSAR supplement for the Reactor Vessel Closure Head Stud 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).
 
Conclusion On the basis of its audit and review of the applicant's Reactor Vessel Closure Head Stud Program, the staff concludes 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 determined 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 determined that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.2.15 Reactor Vessel Surveillance Program 
 
Summary of Technical Information in the Application LRA Section B.3.25 describes the existing Reactor Vessel Surveillance Program (RVSP) as consistent, with exceptions and enhancements, with GALL Report, XI.M31, "Reactor Vessel Surveillance". 
 
The applicant stated that the RVSP is an existing condition monitoring program that
 
manages loss of fracture toughness due to neutron embrittlement in reactor vessel alloy
 
steel materials exposed to neutron fluence exceeding 1 x 10 17 n/cm 2 (E > 1.0 MeV). The program is based on 10 CFR 50, Appendix H, "Reactor Vessel Material Surveillance
 
Requirements" and ASTM E 185-82, "Standard Practice for Conducting Surveillance Tests
 
for Light-Water Cooled Nuclear Power Reactor Vessels." 
 
Capsules are periodically removed during the course of plant operating life. Neutron
 
embrittlement is evaluated through surveill ance capsule testing and evaluation, fluence calculations and benchmarking, and monitoring of effective full power years (EFPYs).
 
Exception The LRA states an exception for both the VEGP, Unit 1 and 2 RVs, that capsules with accumulated neutron fluence equivalent to 60 years of operation have already been 3-111 pulled and tested. The exception also stated that the remaining capsules (2 capsules in each unit) will be removed such that, at the time of removal, each of the remaining capsules
 
will have accumulated neutron fluence that is not less than once, nor greater than twice, the
 
peak end of life fluence expected for an additional 20-year license renewal term (80 years of operation).
 
Enhancement 1 The LRA stated an enhancement that would involve revision of program documents , prior to completion of testing of the last surveillance capsule in each unit, to
 
require that tested and untested specimens from all capsules removed from the VEGP RVs remain in storage. Also, alternate dosimetry would be installed to monitor neutron fluence
 
on the RVs after removal of the last surveillance capsule from each unit. This enhancement
 
will be implemented prior to removal of the last surveillance capsule in each unit.
 
Staff Evaluation The staff reviewed the applicant
=s proposed RVSP with its exception and enhancements to the NUREG-1801, Section XI.M31, "Reactor Vessel Surveillance,"
requirements to determine whether the AMP remains adequate to manage the aging effects
 
for which it is credited. 
 
The RVSP, which is designed and implemented in accordance with 10 CFR Part 50, Appendix H, uses testing of the RV surveillance capsule test specimens as the basis for
 
monitoring for neutron irradiation-induced embrittlement in base metals (plate or forgings)
 
and welds that are located in the beltline region of the low alloy steel RV. VEGP
=s RVSP consisted of six surveillance capsules. Fracture toughness of beltline materials is indirectly monitored through measurement of the impac t energy of Charpy V-Notch specimens. To date, four surveillance capsules were removed from the VEGP RV and tested. For both the
 
VEGP, Unit 1 and 2 reactor vessels, capsules with accumulated neutron fluence equivalent
 
to 60 years of operation have already been pulled and tested. The remaining capsules
 
(2 capsules in each unit) will be removed such that, at the time of removal, each of the
 
remaining capsules will have accumulated neutron fluence that is not less than once, nor
 
greater than twice, the peak end of life fluence expected for an additional 20-year license
 
renewal term (80 years of operation).
 
The staff confirmed that Capsule X (3.53 x 10 19 , n/cm 2 , E > 1 MeV) from VEGP, Unit 1 and Capsule W (2.98 x 10 19 n/cm 2 , E > 1 MeV) from VEGP, Unit 2 were exposed to fluences greater than the peak projected neutron fluence for their associated RV at 60 years of
 
operation. Hence, the applicant has already met all RVSP requirements to support
 
operation of VEGP, Units 1 and 2 through 60 years of operation. Removal of the remaining
 
capsules at a fluence equivalent to 80 years of operation is appropriate because capsule
 
data for fluences equivalent to 60 years of operation fluence has already been obtained.
 
The applicant stated that the enhancement would involve revision of program documents, prior to completion of testing of the last surveillance capsule in each unit, to require that
 
tested and untested specimens from all capsules removed from the VEGP RVs remain in
 
storage. Also, alternate dosimetry would be installed to monitor neutron fluence on the RVs
 
after removal of the last surveillance capsule from each unit. This enhancement will be
 
implemented prior to removal of the last surveillance capsule in each unit.
 
The staff finds this response acceptable because future capsule testing will provide
 
assurance that neutron irradiation-induced embrittlement in the RV beltline materials as a
 
result of any change in projected neutron fluence can be monitored effectively during the
 
period of extended operation. 
 
3-112 The staff accepts the applicant
=s RVSP based on the following:
$ the testing of the surveillance capsules in accordance with the proposed schedule provides assurance that the neutron-induced embrittlement in low
 
alloy steel RV base metals and their associated welds will be adequately
 
monitored during the period of extended operation 
$ the applicant
=s RVSP complies with the requirements of the 10 CFR Part 50, Appendix H.
 
The staff finds this program element acceptable because the applicant
=s discussion of the operating experience program element satisfies the criteria defined in the GALL Report.
 
Operating Experience The AMP B.3.25 states that the RVSP is an existing condition monitoring program that manages loss of fr acture toughness due to neutron embrittlement in RV alloy steels exposed to neutron fluence exceeding 1 x 10 17 n/cm 2 (E > 1.0 MeV). The applicant stated that the staff has approved the use of the program during the period of
 
current operation. Surveillance specimens have been removed and tested. Where
 
applicable, credible data from these specim ens have been used to verify embrittlement rates and predict future performance of RV materials with regard to neutron embrittlement.
 
For VEGP, Unit 1, the most recent results submitted to the NRC are documented in WCAP-16278-NP, Revision 0, "Analysis of Capsule X from the Southern Nuclear Operating
 
Company, Vogtle Unit 1 Reactor Vessel Radiat ion Surveillance Program."  For VEGP, Unit 2, the most recent results submitted to the NRC are documented in WCAP-16382-NP, Revision 0, "Analysis of Capsule W from t he Southern Nuclear Operating Company, Vogtle Unit 2 Reactor Vessel Radiation Surveillance Program."  Both of these reports include data
 
from surveillance capsules exposed to a neutron fluence equivalent to 60 years of
 
operation. 
 
UFSAR Supplement In LRA Section A.2.25, the applicant provided the UFSAR supplement for the Reactor Vessel Surveillance Program. The staff reviewed the applicant's license
 
renewal commitment list dated August 11, 2008 and confirmed that this program
 
enhancement is identified as Commitment No. 21 to be implemented prior to the period of extended operation. 
 
Conclusion On the basis of its review of the applicant
=s RVSP, the staff concludes that those program elements, for which the applicant claimed consistency with the GALL REPORT, are consistent. Also, the staff reviewed the exception and enhancement and
 
confirmed that their implementation prior to the period of extended operation would support the requirements of the 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 current licensing basis for the period of extended operation, as required by 10 CFR 54.21(a)(3). 
 
3.0.3.2.16  Steam Generator Tubing Integrity Program 
 
Summary of Technical Information in the Application LRA Section B.3.26 describes the existing Steam Generator Tubing Integrity Program as consistent, with exception, with GALL AMP XI.M19, "Steam Generator Tube Integrity." 
 
The applicant stated that the existing Steam Generator (SG) Tubing Integrity Program is a
 
subprogram of the integrated Steam Generat or Program for managing the SGs. The Steam 3-113 Generator Tubing Integrity Program focuses on SG tube integrity, tube plugging, and the management and repair of SG tubing. The program complies with the program described in
 
NEI 97-06, "Steam Generator Program Guidelines," and VEGP Technical Specifications
 
Section 5.5.9. 
 
Preparation and approval of program deviations from NEI 97-06 are in accordance with Section 2 of the EPRI steam generator m anagement program administrative procedures.
 
The applicant also stated that the Steam Generator Tubing Integrity Program incorporates
 
performance criteria for structural integrity, accident-induced leakage, and operational
 
leakage consistent with NEI 97-06 and VEGP Technical Specifications.
 
The program includes a balance of prevention, inspection, evaluation and repair, and
 
leakage monitoring. Major program elements are degradation assessments, inspection, integrity assessments, leakage monitoring, and chemistry controls.
 
The applicant further stated that NEI 97-06 refers to EPRI guidelines for SG examination, integrity assessment, primary to secondary leakage monitoring, in-situ testing, and water chemistry controls. The Water Chemistry Control Program maintains water chemistry
 
controls for primary and secondary water chemistry.
 
Staff Evaluation During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether
 
the AMP, with the exception, remained adequate to manage the aging effects for which it is
 
credited.
 
During its audit and review, the staff reviewed the program elements of the LRA B.3.26, "Steam Generator Tubing Integrity Program," for which the applicant claims consistency with GALL AMP XI.M19, "Steam Generator Tube Integrity," with the exception described
 
below. The staff also reviewed the license renewal program basis document for the
 
applicant's Steam Generator Tube Integrity Pr ogram and interviewed VEGP staff members involved with implementation of the Steam Generator Tube Integrity Program.
 
In the "operating experience" program elem ent for AMP B.3.26, "Steam Generator Tubing Integrity Program, the applicant states that wear due to interaction with loose parts or
 
foreign objects has been identified for VEGP. During the audit and review, the staff asked
 
the applicant to discuss how loose or foreign objects are detected and controlled under the
 
Steam Generator Integrity Program.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. The applicant stated in its response that detection and control of foreign objects in
 
the secondary side of the VEGP steam generators is achieved through diverse means.
 
Inspections during outages for loose parts and foreign objects are accomplished through
 
eddy current inspections and secondary-side foreign object search and retrieval. Removal
 
of foreign objects is achieved in the foreign object search and retrieval or in sludge lance
 
cleaning. The applicant provided additional details on the eddy current inspections, secondary side foreign object search and retrieval, and sludge lance cleaning. 
 
During the audit and review, the staff reviewed procedures for performing these activities
 
and finds the applicant's approach adequate to detect and control loose or foreign objects.
3-114 On the basis of this review, the staff finds the LRA B.3.26 program elements, with the exception described below, consistent with the GALL AMP XI.M19.
 
Exception In the LRA, the applicant identified an exception to the GALL Report program element "Program Scope," "Preventive Acti ons," "Detection of Aging Effects," and "Monitoring and Trending" elements. Specifically, AMP XI.M19, of the GALL Report references Revision 1 of NEI 97-06, "Steam Generator Program Guidelines."  Currently, the
 
VEGP Steam Generator Tube Integrity Program is implemented in accordance with
 
Revision 2 of NEI 97-06. The LRA considers this difference an exception to the GALL
 
Report.
 
During the audit, the staff asked the applicant to clarify how NEI 97-06 Revision 2 differs
 
from Revision 1 and explain how the program elements are affected by the differences.
Also, the staff requested that the applicant provide justification if any of the requirements of
 
the program is relaxed /reduced.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. The applicant, in its response, stated that there is no functional reduction in program
 
requirements in the NEI 97-06 Revision 2. The applicant has retained the original guidance
 
or added guide lines referenced in NEI 97-06 or EPRI Steam Generator Management
 
Program procedures, where the guidance level of detail in NEI 97-06 was reduced. The
 
applicant further stated that in the NEI correspondence with the NRC dated September 9, 2005, NEI states that Revision 2 of NEI 97-06 is consistent with Technical Specification
 
Task Force Traveler (TSTF)-449 Revision 4, and that the NRC staff reviewed and approved
 
TSTF-449, Revision 4, as documented in Generic Letter 2006-01. The applicant stated that
 
staff's approval of TSTF-449, Revision 4 justifies use of Revision 2 of NEI 97-06.
 
On the basis that the applicant stated there is no functional reduction regarding use of NEI
 
97-06, Revision 2, for implementation of the VEGP Steam Generator Tubing Integrity
 
Program, and because the NRC staff has reviewed and approved the Technical
 
Specification Amendments based on NEI 97-06, Revision 2, the staff finds the applicant's
 
response to the above question and the exception to the program acceptable.
 
Operating Experience LRA Section B.3.26 states that the Westinghouse Model F SGs have thermally-treated Alloy 600 tubes hydraulically expanded for the full depth of the tubesheet
 
at each end with stainless steel broached-hole quatrefoil tube supports and chrome-plated
 
Inconel anti-vibration bars. The tubes are arranged on a square pitch.
 
Active degradation mechanisms recognized by the applicant in the Unit 1 SGs include
 
PWSCC of tubesheet joint bulges and over-expansions, circumferential outside diameter
 
SCC (ODSCC) at the expansion transition, and axial ODSCC at the top of the tubesheet.
 
The applicant detected PWSCC in Unit 1 tubesheet bulges during the spring 2005 refueling
 
outage and ODSCC at the expansion region during the fall 2006 refueling outage. After
 
these PWSCC and ODSCC detections in Unit 1, the applicant has plugged and stabilized a
 
number of tubes.
 
No active degradation mechanisms have been detected by the applicant in the VEGP Unit
 
2 steam generators. The most recent Unit 2 steam generators eddy current inspection
 
during the spring 2007 refueling outage detected no degradation mechanisms and no
 
steam generator tubes were plugged.
 
3-115 VEGP has detected anti-vibration bar wear and tube wear due to interaction with loose parts or foreign objects as relevant degradation mechanisms (those found in similar plants
 
with the same tubing material and with similar design features).
 
In 2002, an inadvertent addition of sodium hexametaphosphate to the condensate chemical feed tanks on both units exceeded the action level 3 limits for sodium in the steam
 
generators. Both units were shut down immediately to reduce the high sodium and
 
phosphate concentrations. Fill and drain processes effectively removed the sodium but
 
significant phosphate residuals remain trapped in the steam generator due to interaction
 
with internal surfaces and sludge. Small, but significant phosphate levels return during
 
start-ups. Water Chemistry Control Program modifications included phosphate action levels
 
and discontinued molar ratio control. During the last refueling outage for each VEGP unit, chemical cleaning of the secondary side removed approximately 7000 pounds of scale
 
deposit from Unit 1 and 5000 from Unit 2. Following the removal of scale deposit and
 
adsorbed phosphate, the applicant has monitored plant chemistry parameters to determine
 
the best time to re-initiate molar ratio control.
 
The Steam Generator Tubing Integrity Program incorporates new industry operating
 
experience and research data for periodi c program improvement. The EPRI steam generator guidelines that form the technical bases for the program are the results of a
 
consensus, which is periodically updated by EPRI. The Steam Generator Program is in accordance with general requirements for engineering programs. Periodic program reviews
 
and assessments ensure compliance with regulatory, process, and procedural
 
requirements. 
 
Review of recent Steam Generator Program performance results show that the program has found and corrected degradation attributable to aging effects requiring management (AERMs) effectively. 
 
During the audit and review, the staff reviewed the above operating experience in the LRA
 
and some of the operating experience referenced in the program basis document for the
 
Steam Generator Tubing Integrity Program and steam generators inspection reports for the
 
previous refueling outages. The staff noted that in the "operating experience" program
 
element for AMP B.3.26, "Steam Generator Tubing Integrity Program, the applicant stated
 
that active degradation mechanism identified in VEGP, Unit 1 steam generators during
 
spring 2005 refueling related to PWSCC and ODSCC. The applicant added that as a result, a number of tubes have been plugged and stabilized. However, no active degradation
 
mechanisms have been identified in the VEGP Unit 2 and no SG tubes were plugged
 
during the spring 2007 refueling outage.
 
The staff requested that for each Unit, the applicant provide the number of tubes of each
 
replaced steam generator that have been repaired, stabilized or plugged to date, and clarify
 
if any additional age-related degradation mechanisms have induced aging effects in the
 
VEGP Unit 1 SG tubes. The staff also asked the applicant to discuss the non-destructive
 
examination (NDE) detection methods (including NDE probe used) that were used to detect
 
the relevant aging mechanisms (including PWSCC and ODSCC).
 
In addition, the staff asked the applicant to provide an explanation on why VEGP Unit 1
 
steam generator components have degraded faster than Unit 2 steam generator
 
components. Also, the staff asked the applicant whether or not the degradation
 
mechanisms that occurred in the Unit 1 steam generator components could potentially 3-116 occur in the Unit 2 steam generator components during the period of extended operation and if so, whether they need to be managed.
 
The applicant provided its response to the staff's questions in a letter dated February 8, 2008. The applicant stated that the repair of tubes at VEGP Unit 1 has involved only
 
plugging and stabilization, and that the repaired tubes are the same as those that are
 
plugged, some of which are also stabilized. 
 
The numbers of tubes in VEGP Unit 1 and Unit 2 that are plugged or stabilized are provided
 
in the following table:
 
Steam Generator Unit 1 Tubes Plugged Unit 1 Tubes Stabilized Unit 2 Tubes Plugged Unit 2 Tubes Stabilized 1 9 3 5 1 2 14 6 12 2 3 25 3 4 3 4 26 11 21 2
 
The applicant, in its response, clarified that the additional age-related degradation
 
mechanisms that have induced aging effects in the VEGP Unit 1 are wear at tubing
 
intersections with anti-vibration bars, wear due to secondary-side foreign objects, wear at
 
the flow distribution baffle plate (due to pressure pulse cleaning), and possible wall loss
 
from ultrasound energy cleaning cavitation. The applicant stated that though the anti-
 
vibration bar wear, foreign object wear, and flow distribution baffle plate wear degradation
 
mechanisms are frequently found in VEGP Unit 1 outages, they have not been detected to
 
the extent required to meet the industry criteria threshold for an active damage mechanism. 
 
The applicant also responded that eddy current examinations using rotating coil probes, Ghent probes, and bobbin probes have been used to detect Unit 1 age-related degradation
 
mechanisms.
 
The staff finds this response acceptable on the basis that the additional age-related
 
degradation mechanisms identified by the applicant are well known in industry, have been
 
seen at levels that do not meet the criteria for active damage mechanisms, and the
 
applicant has a program in place that will adequately monitor these age-related degradation
 
mechanisms. Also, the staff's review of the program operating experience, documented in
 
the basis document for the Steam Generator Tubing Integrity Program, did not reveal any unusual or significant findings.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section A.2.26, the applicant provided the UFSAR supplement for the Steam Generator Tubing Integrity 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 Steam Generator Tubing Integrity Program, the staff concludes that those program elements, for which the applicant
 
claimed consistency with the GALL Report, are consistent. In addition, the staff reviewed the applicant's exception to GALL AMP XI.M19, "Steam Generator Tube Integrity" and its 3-117 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 determined that it provides an adequate summary description of the program, as
 
required by 10 CFR 54.21(d).
 
3.0.3.2.17  Structural Monitoring Program 
 
Summary of Technical Information in the Application LRA Section B.3.32 describes the existing Structural Monitoring Program as consistent, with enhancements, with GALL AMP XI.S6, "Structures Monitoring Program." 
 
The Structural Monitoring Program is based upon the requirements and guidance of
 
10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear
 
Power Plants," and Regulatory Guide 1.160, Revision 2, "Monitoring the Effectiveness of
 
Maintenance at Nuclear Power Plants." VEGP uses the Structural Monitoring Program to
 
monitor the condition of structures and structural components within the scope of the
 
Maintenance Rule for reasonable assurance there is no loss of structure or structural
 
component intended function. Enhancements to the Structural Monitoring Program will be
 
implemented prior to the period of extended operation.
 
Staff Evaluation During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. 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 interviewed the applicant's technical staff and reviewed the Structures Monitoring 
 
Program bases documents. Specifically, t he staff reviewed the program elements and associated bases documents to determine consistency with GALL AMP XI.S6.
 
The staff finds the applicant's Structures Monitoring Program acceptable because it conforms to the recommended GALL AMP XI.S6, "Structures Monitoring Program," with
 
enhancements as described below.
 
Enhancement 1: In the LRA, the applicant stated an enhancement to the GALL Report program element "Program Scope." S pecifically, the enhancement states:
 
The Scope of the Structures Monitoring Program will be expanded to include the additional structures that require monitoring for license renewal. 
 
The staff reviewed the applicant's Structural Monitoring Program, and their Aging Effect
 
Requiring Managements (AERMs) under the scope of the structural monitoring program.
 
The staff finds that the additional structures that require monitoring for license renewal
 
during the period of extended operation are:
 
Alternate Radwaste Building  Dry Active Waste (DAW) Warehouse  DAW Processing Facility  Radwaste Process Facility 3-118  Radwaste Transfer Building  Radwaste Transfer Tunnel (Portion near Auxiliary Building only)  Fire Water Pump House (including Diesel Storage Tank Support Structure)  Fire Protection Valve House  Fire Water Storage Tank Structure  Valve Boxes and Pull Boxes
 
The staff finds this enhancement acceptable because when enhancement is implemented, VEGP AMP B.3.32, "Structures Monitoring Pr ogram," will be consistent with GALL AMP XI.S6 and provide additional assurance that the effects of aging will be adequately
 
managed.
 
Enhancement 2: In the LRA, the applicant stated an enhancement to the GALL Report program element "Program Scope." S pecifically, the enhancement states:
 
The scope of inspection for structures that require monitoring for license renewal will be clarified. An area-based inspection will be performed unless a detailed inspection
 
scope is provided.
 
The staff reviewed the applicant's Structural Monitoring Program, and their AERMs under
 
the scope of the structural monitoring program. The staff finds that the additional structures
 
that require monitoring for license renewal during the period of extended operation will be
 
clarified and area-based inspections will include the structure and structural components, including foundations, hangers and supports (both safety-related and nonsafety-related).
 
The staff finds this enhancement acceptable because when enhancement is implemented, VEGP AMP B.3.32, "Structures Monitoring Program," will be consistent with GALL AMP XI.S6 and provide additional assurance that the effects of aging will be adequately
 
managed.
 
Enhancement 3: In the LRA, the applicant stated an enhancement to the GALL Report program element "Program Scope." S pecifically, the enhancement states:
 
The Structural Monitoring Program scope for hangers and supports will be clarified.
 
The staff reviewed the applicant's Structural Monitoring Program, and their AERMs under
 
the scope of the structural monitoring program. The staff finds that the additional structures
 
that require monitoring for license renewal during the period of extended operation are
 
properly identified in the program scope (nonsafety-related as well as safety-related
 
hangers and supports). The program document currently indicates only Category 1 hangers
 
and supports.
 
The staff finds this enhancement acceptable because when enhancement is implemented, VEGP AMP B.3.32, "Structures Monitoring Pr ogram," will be consistent with GALL AMP XI.S6 and provide additional assurance that the effects of aging will be adequately
 
managed.
 
Enhancement 4: In the LRA, the applicant stated an enhancement to the GALL Report program elements "Parameters Monitored or Inspected, Monitoring and Trending, and Acceptance Criteria." Specifically, the enhancement states:
 
3-119  The Structures Monitoring Program will be enhanced to include periodic ground water monitoring to confirm it remains non-aggressive as defined in NUREG 1801.
The staff reviewed the applicant's Structural Monitoring Program, and their AERMs under
 
the parameters monitored or inspected, monitoring and trending, and acceptance criteria of
 
the structural monitoring program. The staff finds that the additional structures that require
 
monitoring for license renewal during the period of extended operation includes periodic
 
ground water samples will be obtained from locations near the power block structures.
 
Samples will be monitored and evaluated for sulfates, chlorides, and pH; phosphate levels
 
to confirm it remains non-aggressive as defined in GALL Report.
 
During the audit and review the staff asked the applicant to clarify the ground water
 
monitoring frequency and its basis to confirm it remains non-aggressive. Also, to provide
 
the most recent ground water monitoring and the results of this monitoring. In its response, the applicant stated that the Structures Monitoring Program will be enhanced to perform
 
ground water monitoring at a maximum interval of five years irrespective of whether the
 
below grade environment is aggressive or not. In itially, this period was set at five years based on the non-aggressive nature of under ground environment noted so far. Ground
 
water monitoring frequency may be subject to modification (increased monitoring) based on plant specific environments, observed degradation or noticeable change in ground water
 
chemistry. Ground water is considered aggressive when environmental conditions exceed
 
threshold values (Chlorides > 500 ppm, Sulfates >1500 ppm, and pH < 5.5). The staff
 
reviewed the results of the recently samples and found that they are non-aggressive as
 
indicated in the table below:
 
Chemical Parameter Groundwater  FSAR (1) Recent Lab Test (2) Recent Lab Test (3) pH 6.1 - 11.3 7.42 - 8.24 5.77 -  6.34 Chlorides (ppm) 1.0 - 198.4 1.95 - 8.71 4.97 - 7.95 Sulfates (ppm) 3.6 - 36.6 2.9 - 12.5 1.63 - 11.95 Notes: (1)  Refer UFSAR Section 2.4 Table 2.4.12-3 (2) Recent test has been conducted by General Test Laboratory between 11/2/05 to 11/21/05. (3) Recent test has been conducted by General Test Laboratory between 05/08/07 to 05/09/07.
The staff finds this enhancement acceptable because when enhancement is implemented, VEGP AMP B.3.32, "Structures Monitoring Pr ogram," will be consistent with GALL AMP XI.S6 and provide additional assurance that the effects of aging will be adequately
 
managed.
 
Enhancement 5: In the LRA, the applicant stated an enhancement to the GALL Report program elements "Program Scope, Parameters Monitored or Inspected, and Acceptance
 
Criteria." Specifically, the enhancement states:
 
Under water inspection of the NSCW cooling tower basins, including appropriate inspection and acceptance criteria, will be added to the Structural Monitoring
 
Program.
The staff reviewed the applicant's Structural Monitoring Program, and their AERMs under
 
the "scope," "parameters monitored or ins pected," and "acceptance criteria," program 3-120 elements of the structural monitoring program. The staff finds that the additional structures that require monitoring for license renewal are appropriately included in the Structural
 
Monitoring program. The staff also found the addition of inspection and acceptance criteria
 
for under water inspection of the NSCW cooling tower basins to the Structural Monitoring
 
program acceptable because when enhancement is implemented, VEGP AMP B.3.32, "Structures Monitoring Program," will be consistent with GALL AMP XI.S6 and provide additional assurance that the effects of aging will be adequately managed. 
 
The applicant also stated that LRA Section A.2.32 will be implement the above five
 
enhancements to the Structures Monitoring Program as indicated in the letter dated June
 
27, 2007, (Commitment No. 23).
 
On this basis, the staff finds these enhancements acceptable because when enhancements
 
are implemented, the Structural Monitoring Program will be consistent with GALL AMP XI.S6 and will provide that the effects of aging are adequately managed.
 
Operating Experience LRA Section B.3.32 states that the Structural Monitoring Program is in accordance with general requirements for engineering programs. Periodic program
 
reviews ensure compliance with regulatory, process, and procedural requirements.
 
The 1998 baseline inspections established a reference condition for comparison during
 
later inspections. Periodic inspections commenced in April 2000 planned for every 10 years
 
for the duration of plant operation.
 
The 1998 Structural Monitoring Program baseline inspections found the condition of the
 
EDG exhaust enclosure unacceptable. After an evaluation the Corrective Action Program
 
replaced the enclosure with an improved design.
 
Periodic inspections in 2005 found the rooms and areas structurally acceptable with only a
 
few items noted as "acceptable with deficiency." The Corrective Action Program increased
 
the monitoring frequency. An example of an "acceptable with deficiency" condition is
 
evidence of slight water intrusion on the north wall and floor of Auxiliary Building Level C.
 
None of the deficient items required immediate action to maintain intended functions, and
 
monitoring will continue for any change in condition.
 
The operating experience review has concluded that administrative controls are effective in detecting age-related degradation and initiating corrective action.
 
During the audit and review, the staff reviewed the above operating experience and the
 
operating experience described in the program basis document and in various condition
 
reports (CR), and interviewed the applicant's technical staff to confirm that the operating
 
experience did not reveal any degradation not bounded by industry experience. Most of the documented conditions were rusted, cracked, leaked, and/or corroded structural
 
components such as pipe supports, studs. The applicant corrected the conditions through
 
their corrective action program. The staff did not identify any age-related related issues not
 
bounded by the industry operating experience. 
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
3-121 UFSAR Supplement In LRA Section A.2.32, the applicant provided the USAR supplement for the Structures Monitoring Program. The staff reviewed the applicant's license renewal
 
commitment letter (NL-07-1261, dated June 27, 2007) and confirmed that these
 
enhancements to this program is identified as Commitment No. 23 to be implemented before the period of extended operation. The staff reviewed UFSAR Supplement section and determined that the information in the USAR 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 Structural Monitoring Program, the staff concludes that those program elements, for which the applicant claimed
 
consistency with the GALL Report are consistent. Also, the staff reviewed the
 
enhancements and confirmed that their implem entation prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it
 
was compared. The staff concludes that the applicant has demonstrated that the effects of
 
aging will be adequately managed so that the intended function(s) will be maintained
 
consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
determined that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
 
3.0.3.2.18  Structural Monitoring Program - Masonry Walls
 
Summary of Technical Information in the Application LRA Section B.3.33 describes the existing Structural Monitoring Program - Ma sonry Walls as consistent, with enhancement, with GALL AMP XI.S5, "Masonry Wall Program." 
 
The Structural Monitoring Program - Masonry Walls is part of the Structural Monitoring
 
Program implementing 10 CFR 50.65 structur e monitoring requirements. The existing Masonry Wall Program manages aging of masonry walls and their structural steel restraint
 
systems within the scope of license renewal. The program includes the concrete masonry
 
units and restraint systems that seal and shield some access openings in the Seismic
 
Category I structures from radiation.
 
There are no masonry walls in Seismic Category I structures but some Auxiliary Building
 
access openings are sealed with concrete masonry units for radiation shielding and
 
maintenance purposes. Steel angle or steel beam structural elements hold these concrete
 
units in place. 
 
The turbine building, the switch house located in the high-voltage switchyard, the dry active
 
waste warehouse, dry active waste processing facility, radwaste process facility, radwaste
 
transfer building, and the fire water pump houses are non-Category I structures that utilize
 
masonry walls. The program has inspection guidelines that list attributes that cause
 
masonry wall aging monitored during structural inspections and that establish examination
 
criteria, evaluation requirements, and acceptance criteria. The program is based on
 
guidance in NRC Office of Inspection & Enforcement (IE) Bulletin 80-11, "Masonry Wall
 
Design," and NRC Information Notice 87-67, "Lessons Learned from Regional Inspections
 
of Licensee Actions in Response to NRC IE Bulletin 80-11". The Structural Monitoring
 
Program - Masonry Walls will be enhanced prior to the period of extended operation.
 
Staff Evaluation During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancement to determine 3-122 whether the AMP, with the enhancement, remained adequate to manage the aging effects for which it is credited.
 
The staff reviewed those portions of the Masonry Wall Program for which the applicant claims consistency with GALL AMP XI.S5 and finds that they are consistent with the GALL Report AMP. The staff finds the applicant's Masonry Wall Program acceptable because it conforms to the recommended GALL AMP XI.S5, "Masonry Wall," with the enhancement as
 
described below.
 
Enhancement The LRA states an enhancement to the GALL Report program element "Scope of Program," specifically:
 
The scope of the Structures Monitoring Program - Masonry Walls will be
 
expanded to include monitoring of masonry walls in the structures which are
 
in scope for license renewal but are not currently monitored under this
 
program. 
 
The staff reviewed the applicant's Structures Monitoring Program - Masonry Walls
 
Program, the masonry wall structures, structural components, and their AERMs which are
 
under the scope of the Structures Monitoring Program - Masonry Walls. The staff finds that
 
the additional structures and components that require monitoring for license renewal during
 
the period of extended operation are structures such as Radwaste Structures. Visual
 
inspections of these plant structures are at ten-year intervals. However, more frequent
 
inspections will be based on past inspection results, industry experience, or exposure to a
 
significant event (e.g., tornado, earthquake, fire, etc.).
 
The staff finds this enhancement acceptable because when implemented the Structures Monitoring Program - Masonry Walls will be consistent with GALL AMP XI.S5 and provide
 
additional assurance that the effects of aging will be adequately managed.
Operating Experience LRA Section B.3.33 states that plant-specific operating experience comes from condition report searches, personnel interviews, and Structural Monitoring
 
Program inspection report reviews. The 1998 baseline inspections established a reference
 
in time for comparison to later inspections. Periodic inspections commenced in April 2000
 
planned for every 10 years for the duration of plant operation.
 
The operating experience review has concluded that administrative controls are effective in detecting age-related degradation and initiating corrective action.
 
The staff reviewed the operating experience presented in the LRA and in the program basis
 
document and interviewed the applicant's technical personnel and confirmed that the plant-
 
specific operating experience revealed no degradation not bounded by industry experience. 
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section A.2.33, the applicant provided the UFSAR supplement for the Structural Monitoring Program - Masonry Walls. The staff reviewed the applicant's
 
license renewal commitment letter (NL-07-1261, dated June 27, 2007) and confirmed that
 
these enhancements to this program is identified as commitment No. 24 to be implemented 3-123 before the period of extended operation. The staff reviewed UFSAR Supplement 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 Structural Monitoring Program - Masonry Walls, the staff concludes that those program elements, for which the
 
applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed
 
the enhancement and confirmed that their impl ementation prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it
 
was compared. The staff concludes that the applicant has demonstrated that the effects of
 
aging will be adequately managed so that the intended function(s) will be maintained
 
consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
determined that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
 
3.0.3.2.19  Fatigue Monitoring Program 
 
Summary of Technical Information in the Application LRA Section B.3.38 describes the existing Fatigue Monitoring Program as consistent, with enhancements, with GALL AMP X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary." 
 
The applicant stated that the Fatigue Monitoring Program consists of two existing
 
programs, the Fatigue and Cycle Monitoring Program and Thermal Stratification Data
 
Collection Program. The Fatigue and Cycle Monitoring Program, also known as the
 
Component or Cyclic Transient Limit Program, is described in VEGP Technical
 
Specification Section 5.5.5. Program controls track the transient cycles to maintain
 
components within the design limit. The component cyclic or transient design limits are in VEGP UFSAR Section 3.9.N.1. 
 
The Thermal Stratification Data Collection program monitors for adverse thermal
 
stratification and cycling from isolation valve leakage in the normally stagnant nonisolable
 
RCS branch lines identified in the VEGP response to IE Bulletin 88-08.
 
The applicant also stated that the Fatigue Monitoring Program monitors fatigue for ASME
 
Code Class 1 components by software (FatiguePro&#x17d; software) that has three different
 
modules: cycle counting, cycle-based fatigue monitoring, and stress-based fatigue (SBF)
 
monitoring. 
 
Cycle Counting - The cycle-counting module counts and tracks the number of selected design transients that have occurred. Counting these cycles and
 
demonstrating that current and projected cycles are fewer than assumed in
 
design fatigue calculations validates those assumptions and confirms the
 
expectation that fatigue usage will remain below the ASME Code Section III
 
design limit. Cycle-Based Fatigue Monitoring - This module computes cumulative usage fatigue for each event that actually occurs using the design-basis severity
 
specific to the monitored location.
3-124  SBF Monitoring - The SBF monitoring module is the most precise of the three for monitoring fatigue usage. This module uses the actual temperature, pressure, and flow measurement data to calculate stress intensity ranges
 
and fatigue at the monitored location.
Calculated current and projected fatigue usage demonstrate that fatigue usage will continue
 
to be below the design limit.
 
The applicant further stated that transients and components required to be monitored by
 
the UFSAR are based on the following methodology (projections are based on a 60-year
 
operating period): 
 
Determination of Class 1 components to be monitored is by comparison of both the design fatigue usage and the projected fatigue usage for the
 
component to a screening value of cumulative usage fatigue less than 0.1. Determination of plant cycles to be monitored is by evaluation of the contribution of the lifetime projected plant cycles to the fatigue usage for any
 
Class 1 component and by a screening level for the lifetime projected plant
 
cycles of approximately 10 percent of the design allowable cycles. Fatigue monitoring (e.g., SBF monitoring) of the limiting component(s) affected by a cycle may show that the ASME Code acceptance criterion of
 
cumulative usage fatigue less than or equal to 1.0 remains valid even if the
 
assumed number of cycles has been exceeded. Selection of screening levels accommodated the maximum anticipated effect of reactor water environmental factors for a projected 60-year operating
 
period. The UFSAR requires fatigue monitoring of specific components on each unit and of specific
 
plant cycles. LRA Section 4.3.1 on metal fatigue TLAA evaluations details the monitored
 
cycles and components and the fatigue monitoring module in use.
 
The applicant stated that the Fatigue Monitoring Program uses a combination of cycle-
 
counting, cycle-based fatigue monitoring, and SBF monitoring to track fatigue usage. The
 
software counts cycles and calculates fatigue usage for selected high-usage components.
 
The fatigue-monitoring software counts most of the transient cycles required to be
 
monitored by changes in plant instrument readings. Cycles that cannot be counted by
 
installed instrumentation are counted manually (and then entered into the software). For
 
some specific transients, VEGP uses SBF monitoring of bounding locations in lieu of cycle
 
counting.
 
VEGP uses SBF monitoring of the main and auxiliary feedwater nozzles, the bounding
 
locations for the feedwater cycling events, rat her than counting of feedwater cycling events.
VEGP uses SBF monitoring of the normal and alternate charging nozzles, the bounding
 
locations in the Class 1 portion of the charging and letdown systems, rather than counting
 
of loss of charging, loss of letdown events, or both.
 
3-125 In response to IE Bulletin 88-08, nonisolable sections of piping for the safety injection, normal and alternate charging, and auxiliary spray lines connected to the RCS have
 
instrumentation to detect adverse thermal stratification and cycling due to potential isolation
 
valve leakage into the RCS boundary. Temperat ure measurements detect fluid leakage by resistance temperature detectors strapped on the pipes. Temperature data periodically
 
recorded and evaluated for thermal stratification and cycling determine impact on piping
 
structural integrity. Additionally (on Unit 2 only), two 12-inch RHR suction lines attached to
 
the reactor coolant loop hot leg have resistance temperature detectors. This monitoring is
 
currently performed using equipment that is not part of the FatiguePro monitoring software.
 
The SBF fatigue-monitoring software module calculates the actual amount of fatigue from
 
changes in temperature, pressure, or other parameters affecting the surge line and lower
 
pressurizer and accounts for insurge/outsurge and thermal stratification effects. Thus, the
 
applicant addresses WCAP-14574A Renewal Applicant Action Item 3.3.1.1.-1 for license
 
renewal by using the SBF monitoring software for the pressurizer lower head and surge line
 
nozzles. 
 
The applicant also stated that it has evaluated environmentally-assisted fatigue of piping in
 
the reactor coolant pressure boundary for locations equivalent to those in NUREG/CR-6260
 
Section 5.4 using NUREG/CR-5704 formulas for stainless steel components and
 
NUREG/CR-6583 formulas for low-alloy steel components. All locations evaluated were
 
acceptable for 60 years. The Fatigue Monitoring Program tracks the cumulative fatigue
 
usage at four of these six components. The acceptance criterion for cumulative fatigue
 
usage of those components is reduced to account for the environmental fatigue factor value
 
determined in the environmentally-assisted fatigue evaluation. The design cumulative
 
usage fatigue of the other two components is low enough that cycles monitoring ensures
 
that the evaluation of environmentally-assisted fatigue remains valid. To manage
 
environmental fatigue effects during the period of extended operation, the UFSAR will
 
change to indicate that two locations not currently in the UFSAR, the accumulator/RHR
 
nozzle and the pressurizer heater penetration, require fatigue monitoring. 
 
Weld overlays were installed on the Unit 2 pressurizer spray nozzle, pressurizer safety and
 
relief nozzles, and the pressurizer surge nozzle and will be installed on the corresponding
 
Unit 1 pressurizer nozzles during the next 2008 refueling outage. This change does not
 
affect the cycle-counting and cycle-based fatigue modules of the Fatigue Monitoring
 
Program; however, the effects of the weld overlay on the stress-based module for
 
monitoring the cumulative usage fatigue of the spray and surge nozzles is still under
 
evaluation. 
 
The applicant indicated that it intends to submit a license amendment request for a
 
measurement uncertainty recapture power uprate in the near future. The applicant stated
 
that it expects the number of assumed tr ansients not to change and the cycle-based fatigue and SBF modules to remain unaffected; therefore, the Fatigue Monitoring Program should
 
not be affected materially. The applicant stated that it will notify the staff as part of the
 
10 CFR 54.21(b) annual update of any CLB changes that materially affect the LRA.
 
Enhancements to the Fatigue Monitoring Program will be implemented prior to the period of extended operation. 
 
Staff Evaluation During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancements to determine 3-126 whether the AMP, with the enhancements, remained adequate to manage the aging effects for which it is credited.
 
During the audit, the staff interviewed the applicant's technical staff and reviewed the basis
 
documents related to the Fatigue Monitoring Program, including the license renewal program evaluation report in which the applic ant assessed whether the program elements are consistent with the GALL AMP X.M1. 
 
The staff reviewed those portions of the Fatigue Monitoring Program for which the applicant claims consistency with GALL AMP X.M1 and finds that they are consistent with the GALL Report AMP. The staff finds the applicant's Fatigue Monitoring Program acceptable because it confirms to the recommendation of the GALL AMP X.M1, "Metal Fatigue of
 
Reactor Coolant Pressure Boundary," with enhancements as described below.
 
Enhancement
: 1. In the LRA, the applicant stated an enhancement to the GALL Report "program description."  Specifically, the enhancement stated:
 
The effect of the full structural weld overlays applied to the pressurizer spray and
 
surge nozzles on the stress-based module for monitoring their CUF is still being
 
evaluated. If the existing module is not conservative, the module will be revised so
 
that it continues to provide valid results. 
 
The staff reviewed the enhancement and determined that the enhancement is a
 
conservative approach to monitoring CUF of full structural weld overlays applied to
 
pressurizer spray and surge nozzles. In addition, the staff noted that LRA provides the CUF
 
value of the limiting surge nozzle location for 60 years, which shows adequate margin to
 
account for any changes due to the weld overlay. The staff verified that the applicant has
 
incorporated this enhancement in Commitment No. 28 to the LRA, which was provided in
 
the applicant's letter of June 27, 2007. The staff finds this enhancement acceptable
 
because when enhancement is implemented, VEGP AMP B.3.38, "Fatigue Monitoring Program," will be consistent with GALL AMP XI.M1 and provide additional assurance that
 
the effects of aging will be adequately managed. 
 
Enhancement
: 2. In the LRA, the applicant stated an enhancement to the GALL Report program element "parameters monitored.
"  Specifically, the enhancement stated:
The UFSAR will be changed to require fatigue monitoring of the Accumulator/RHR
 
nozzles and of the pressurizer heater penetration. These components are currently
 
monitored but not specified in the UFSAR. These components were evaluated for
 
environmental fatigue effects and monitoring of these components is required or
 
desired for the period of operation.
 
The staff reviewed the enhancement and determined that the applicant already formalized the monitoring of the Accumulator/RHR nozzles on the cold legs and the pressurizer heater
 
penetration in its operating procedure. The staff verified that the applicant has incorporated
 
this enhancement in Commitment No. 28 to the LRA, which was provided in the applicant's
 
letter of June 27, 2007. The staff finds this enhancement acceptable because when
 
enhancement is implemented, VEGP AMP B.3.38, "Fatigue Monitoring Program," will be consistent with GALL AMP XI.M1 and provide additional assurance that the effects of aging
 
will be adequately managed. 
 
3-127 Enhancement
: 3. In the LRA, the applicant stated an enhancement to the GALL Report program element "acceptance criteria."
Specifically, the enhancement stated:
The implementing procedure for the Fatigue Monitoring Program will be enhanced
 
to reduce the acceptable CUF value to account for environmental fatigue effects for
 
those NUREG
-6260 locations monitored for fatigue. The acceptable CUF for those locations will be reduced from the design code limit of 1.0 to 1 divided by the Fen
 
value used for the environmental fatigue evaluation of that location.
 
The staff reviewed the GALL Report program element "acceptance criteria" and noted that
 
it involves maintaining the fatigue usage below the design code limit considering
 
environmental fatigue. The staff noted that the enhancement is more stringent than that
 
stated in the GALL Report. The staff verified that the applicant has incorporated this
 
enhancement in Commitment No. 28 to the LRA, which was provided in the applicant's
 
letter of June 27, 2007. The staff finds this enhancement acceptable because when the
 
enhancement is implemented, VEGP AMP B.3.38, "Fatigue Monitoring Program," will be consistent with GALL AMP XI.M1 and provide additional assurance that the effects of aging
 
will be adequately managed. 
 
Enhancement
: 4. In the LRA, the applicant stated an enhancement to the GALL Report program element "corrective actions."
Specifically, the enhancement stated:
The implementing procedure for the Fatigue Monitoring Program will be enhanced
 
to explicitly require that the corrective actions initiated for exceeding an acceptance
 
criterion include a review to identify and assess any additional affected reactor
 
coolant pressure boundary locations. 
 
The staff finds this enhancement acceptable because when enhancement is implemented, VEGP AMP B.3.38, "Fatigue Monitoring Program," will be consistent with GALL AMP XI.M1 and provide additional assurance that the effects of aging will be adequately managed. The
 
staff verified that the applicant has incorporated this enhancement in Commitment No. 28 to
 
the LRA, which was provided in the applicant's letter of June 27, 2007.
 
During the audit, the staff noted that the applicant did not establish an implementation
 
schedule for these enhancements to the existing Fatigue Monitoring Program. The staff
 
asked the applicant to provide clarification on when these enhancements will be
 
implemented. In its response, the applicant stated the LRA will be amended to reflect that
 
the enhancements to the Fatigue Monitoring Pr ogram will be implemented at least two years prior to the period of extended operation. The staff finds the applicant's response
 
acceptable because these enhancements will be adopted prior to the period of extended
 
operation. In a letter dated August 11, 2008, the applicant amended the application and
 
identified Commitment No. 28 to be implemented no later than two years prior to the period of extended operation. The Commitment List reflects the above response.
 
During the audit, the staff also requested the applicant to provide a list of components that
 
rely on SBF monitoring by Fatigue Monitoring Program to disposition the fatigue TLAA. In
 
its response, the applicant provided a list of those components and proposed to amend its
 
application so that list is included in its LRA. In its letter dated June 26, 2008, the applicant
 
amended the application by adding the list of components that rely on SBF monitoring. The
 
staff finds the applicant's response acceptable since it provides clarification to show which
 
components are managed by SBF monitoring method.
3-128  The staff also asked the applicant, during the audit, to explain how each of the locations
 
evaluated for environmentally assisted fatigue was shown to be acceptable. In its response, the applicant proposed to amend the application so it is clear how these locations were
 
acceptable. Specifically, each component's 60-y ear projected CUF is multiplied by its Fen value and the result is less than 1. The design limit for these components is 1.0 and
 
therefore, the staff concludes that the components meet the acceptance criteria as stated in
 
the LRA. On this basis, the staff finds the applicant's response acceptable. In its letter
 
dated June 26, 2008, the applicant amended the LRA to show how each of the locations
 
evaluated for environmentally assisted fatigue was acceptable.
 
The applicant stated in the LRA that it will notify the staff, as part of the 10 CFR 54.21(b)
 
annual update of any CLB changes that materially affect the LRA, specifically fatigue
 
monitoring program during a measurement uncer tainty recapture power uprate process.
The staff identified this commitment as a confirmatory Item(CI- 3.0.3.2.19-1).
In a letter dated June 26, 2008, the applicant indicated that they had completed a review of the pertinent documentation and identified the following changes, which materially affect
 
the contents of the VEGP LRA:
Implementation of Measurement Uncertainty Recapture (MUR) Power Uprate  Installation of full structural weld overlays on the Unit 1 pressurizer spray nozzle, pressurizer safety and relief nozzles, and the pressurizer surge
 
nozzle  Enclosure 1 of the June 26 letter describes the LRA changes made necessary by both the
 
annual update and the RAI response. The staff reviewed the applicant's approach and finds
 
it acceptable because the applicant appropriately provided the CLB changes that materially
 
affect the LRA, including the fatigue monitori ng program, during a measurement uncertainty recapture power uprate process. 
 
During the audit, the staff asked the applicant regarding the benchmarking process and
 
validation results for the software using transient data. The applicant's response was
 
reviewed in parallel with the environmentally assisted fatigue evaluation, and the results on
 
those responses are discussed in the TLAA Section 4.3.1 of this SER. 
 
In a letter dated March 20, 2008, the applicant submitted an amendment to the LRA, which
 
consisted of editorials changes to the LRA. The staff reviewed these editorial changes and
 
determined that they do not affect the staff's assessment of acceptability of the Fatigue
 
Monitoring Program. 
 
Operating Experience LRA Section B.3.38 states that the set of design-basis transients was a conservative estimate of the number, types, and severity of events that could occur
 
during normal and accident conditions. Actual operating transients, however, determine the
 
real fatigue usage on components. Westinghouse pressurized-water reactor plant
 
experience indicates that actual operating transients are often fewer and less severe than
 
postulated in the design basis. 
 
3-129 The applicant stated that industry and plant-specific operating experience were factored into the Fatigue Monitoring Program when it was established. Monitored locations include
 
those that operating experience shows are likely to accumulate significant fatigue usage at
 
Westinghouse plants. The Operating Experience Program reviews industry operating
 
experience, disseminates that information to appropriate personnel (including the engineer
 
responsible for fatigue monitoring), collects plant-specific operating experience, and
 
disseminates that information to the rest of the industry when appropriate. Operating
 
experience shows the program's ability to monitor cycles and fatigue usage and to make
 
program changes as necessary. 
 
The applicant also stated that Fatigue Monitoring Program incorporated fatigue-monitoring
 
software in 1995. A fatigue and cycle-monitori ng report every 18 months provides the current count of cycles requiring monitoring and the current fatigue usage for components
 
requiring fatigue monitoring. The report also provides 40- and 60-year projections for both
 
monitored cycles and fatigue usage at monitored components. Review of these reports
 
determines whether any monitored locations require further action. As an example, the
 
feedwater and auxiliary feedwater nozzles we re changed from cycle-counting to fatigue-calculated monitoring when projected cycles of feedwater cold water slug events exceeded the assumed limit. Similarly, the program changed to use SBF monitoring based on cycle-counting results for the charging nozzles.
 
The staff reviewed the operating experience provided in the LRA and in the program basis
 
document and interviewed the applicant's technical staff to confirm that the plant-specific
 
operating experience did not reveal any degradation not bounded by industry experience.
The staff asked the applicant to provide operating experience on the temperature
 
measurement of normally stagnant non-isolable RCS branch lines. In its response, the
 
applicant provided operating experience on the applicable resistance temperature detectors (RTD). The applicant identified only one instance where RTDs indicated a problem, which
 
was corrected by having a valve repacked. The staff noted that this problem was corrected
 
as the thermal stratification data was gathered and analyzed for several weeks. Therefore, the staff finds the applicant's response acceptable. Based on the above reviews, staff
 
confirmed that the plant-specific operating experience did not reveal any degradation not bounded by industry experience
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section A.2.38, the applicant provided the UFSAR supplement for the Fatigue Monitoring Program. The staff also verified that Commitment No. 28 for
 
enhancements of the program is scheduled for implementation prior to the period of
 
extended operation. 
 
The staff reviewed UFSAR Supplement 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 Fatigue Monitoring Program, the staff concludes that those program elements, for which the applicant claimed
 
consistency with the GALL Report are consistent. Also, the staff reviewed the
 
enhancements and confirmed that their implem entation prior to the period of extended 3-130 operation would make the existing AMP consistent with the GALL Report AMP to which it was compared. As provided above, the applic ant appropriately resolved confirmatory Item3.0.3.2.19. The 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 determined 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:
 
ACCW System Carbon Steel Components Program  Bolting Integrity Program  Diesel Fuel Oil Program  Inservice Inspection (ISI) Program  Nickel Alloy Management Program for Non-Reactor Vessel Closure Head Penetration Locations  Periodic Surveillance and Preventive Maintenance Activities  Reactor Vessel Internals Program  Steam Generator Program for Upper Internals  Inservice Inspection Program - IWE  Inservice Inspection Program - IWL  Non-EQ Cable Connections One-Time Inspection 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 staff's
 
review of these plant-specific AMPs is documented in the following sections.
 
3.0.3.3.1  ACCW System Carbon Steel Components Program 
 
Summary of Technical Information in the Application LRA Section B.3.1 describes the new ACCW System Carbon Steel Components Program as a plant-specific program. 
 
The applicant stated that the Auxiliary Com ponent Cooling Water (ACCW) System Carbon Steel Components Program manages, by a combination of leakage monitoring and routine
 
and periodic inspections, cracking of carbon steel components exposed to ACCW. The
 
program responds to operating experience with nitrite-induced SCC and subsequent
 
ACCW system component leakage. The scope of this program covers the carbon steel
 
components exposed to ACCW, including the Units 1 and 2 ACCW systems as well as 3-131 carbon steel components serviced by those systems. The ACCW system services nonsafety-related heat loads.
 
The applicant also stated that there has been nitrite-induced SCC in the Unit 2 ACCW
 
system and the scope of this program conserva tively includes the Unit 1 ACCW system due to similarities in chemistry control regime, normal operating temperatures, materials of
 
construction, and design.
 
The applicant further stated that the  program formalizes some activities and adds new
 
activities. The program relies upon leakage detection monitoring, routine walk-downs, and
 
periodic visual examinations. Operating ex perience shows that the program detects and repairs ACCW system leaks attributed to nitr ite-induced SCC prior to any loss of system intended function or any significant impact on system pressure, flow, or integrity.
 
The program also has preventive measures for repairs and modifications to minimize crack initiation sites, lower stresses, and improve inspectability. The ACCW System Carbon Steel
 
Components Program will be implemented prio r 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.3.1 on the applicant's demonstration of the ACCW System Carbon Steel
 
Components 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 ACCW System Carbon Steel Components Program against the
 
staff's recommended program element criteria that are provided in SRP-LR Section A.1.2.3, and in SRP-LR Table A.1-1. The staff focused its review on assessing how the plant-
 
specific program elements for the ACCW System Carbon Steel Components Program would ensure adequate aging management when compared to the recommended program element criteria that are described in SRP-LR Section A.1.2.3. Specifically, the staff
 
reviewed the following seven (7) program elements of the applicant's program against their
 
corresponding program element criteria that are provided in the subsections to SRP-LR
 
Section A.1.2.3: (1)"scope of the program," (2) "preventive actions," (3) "parameters
 
monitored or inspected," (4) "detection of aging effects," (5) "monitoring and trending,"
 
(6) "acceptance criteria," and (10) "operating experience."
 
The applicant indicated that program elements (7) "corrective actions,"(8) "confirmation
 
process," and (9) "administrative controls" are parts of the site-controlled QA program. The
 
staff evaluated the Inservice Inspection Program's "confirmatory process" and
 
"administrative controls" program elements as part of the staff's evaluation of the applicant's Quality Assurance Program. The staff's evaluation of the applicant's Quality
 
Assurance Program is described in SER Section 3.0.4. The staff's evaluation of the
 
remaining program elements are described in the paragraphs that follow:
 
(1) Scope of the Program - The "scope of the program" program element criterion in SRP-LR Section A.1.2.3.1 requires that the program scope include the specific
 
structures and components addressed with this program.
 
The applicant states in LRA Section B.3.1 that the carbon steel components in both Units 1 and 2 ACCW systems and the carbon steel components
 
serviced by the ACCW systems are included within the scope of this 3-132 program. Although the high-temperature and highly-stressed ACCW system portions are critical locations for nitrite-induced SCC, the scope of this
 
program conservatively includes all of the carbon steel components exposed
 
to ACCW. Operating experience with nitrite-induced SCC in the Unit 2
 
ACCW system necessitates this program. There have been no nitrite-
 
induced SCC leaks in the Unit 1 ACCW system, but this system is included
 
conservatively in the program scope due to its similar chemistry control
 
regime, normal operating temperatures, materials of construction, and
 
design. During the audit and review, the staff reviewed the applicant's program basis
 
documents and determined that it adequately identified all the components
 
within the scope of this AMP. Additionally, the staff noted that although there
 
have been no nitrite-induced SCC leaks in the Unit 1 ACCW system; those
 
components are included within the scope of this AMP. The staff finds the
 
"scope of the program" acceptable since it specifically identifies the
 
components within the scope of the ACCW System Carbon Steel
 
Component Program.
The staff confirmed that the "scope of the program" program element
 
satisfies the criterion defined in SRP-LR Section A.1.2.3.1. On this basis
, the staff finds this program element acceptable.
(2) Preventive Actions - The "preventive acti ons" program element criterion in SRP-LR Section A.1.2.3.2 is that condition moni toring programs do not rely on preventive actions, and thus, preventive actions need not be provided.
The applicant states in LRA Section B.3.1 that the ACCW System Carbon Steel Components Program has the following design controls on ACCW system carbon
 
steel component repairs and new installations to prevent recurrence of SCC:
New installations and component repairs will prevent the creation of crevices shown by operating experience to serve as SCC initiation sites. Butt-welded
 
piping will not use backing rings. For critical locations (high temperature, high stress, or both), socket welds will be avoided when possible. System stresses in new installations and component repairs will be reduced where practical. New installation and component repair processes will
 
include guidance to reduce assembly stresses.
During the audit and review, the staff reviewed the applicant's program basis
 
documents for this program which adequately described the mitigative actions that
 
are focused on prevention of SCC recurrence and primarily consist of design
 
controls on new installations and repairs. Further, the program basis documents
 
state that, although the mitigative aspects are not currently implemented, those
 
actions will be implemented prior to the period of extended operation. The staff
 
noted that the program basis documents describe that the mitigative actions include
 
revising piping specifications to prohibit the use of backing rings in susceptible
 
locations, favor the use of butt-welded joints over socket welded fittings, and require 3-133 post weld heat treatment (PWHT) stress relief. The staff also noted that the ACCW System Carbon Steel Components Program will use multiple engineering methods
 
to reduce the stresses that contribute toward the occurrence of nitrite-induced SSC.
 
On this basis, the staff finds this program element acceptable.
 
The staff confirmed that the "preventive actions" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.2. The staff finds this program element
 
acceptable.
 
(3) Parameters Monitored or Inspected - The "parameters monitored or inspected" program element criterion in SRP-LR Section A.1.2.3.3 are:
The parameters to be monitored or inspected should be
 
identified and linked to the degradation of the particular
 
structure and component intended function(s).
The parameters monitored or inspected should detect the presence and extent of aging effects.
The applicant states in LRA Section B.3.1 that the ACCW System Carbon Steel
 
Components Program inspects and monitors for ACCW component leakage
 
indicative of through-wall cracking due to nitrite-induced SCC. Parameters
 
monitored include indications of component leakage based on observations, system
 
make-up needs, room leakage alarms, and visual inspections.
During the audit and review, the staff reviewed the applicant's program basis
 
documents for this program which adequately described the parameters monitored
 
or inspected include leak detection and other signs of leakage. The staff noted that
 
operating experience has shown that leaks are properly entered into the applicant's
 
corrective actions program to ensure that corrective actions are taken prior to loss of
 
system intended functions. Further, the staff noted that the AMP includes periodic
 
visual inspections during operator rounds and engineering walkdowns, and visual
 
examinations at normal operating pressure. The applicant described that current
 
NDE technologies are not available to reliably detect and discriminate SCC cracks, especially in butt-welds with backing rings, and in socket welds. 
 
The staff noted that leakage detection is used to identify nitrite-induced SCC
 
because current NDE technologies are available for detection in various carbon
 
steel piping configurations. On this basis, the staff finds the parameters monitored
 
acceptable to manage the AERM for which the AMP is credited.
 
During the audit and review, the staff interviewed the applicant's technical staff who
 
explained that the ACCW System Carbon Steel Components Program monitors all components susceptible to nitrite-induced SCC and that leak detection is effective in
 
identifying nitrite-induced SCC. The applicant's technical staff also presented the
 
program basis documents that identified that all components within the Unit 1 and
 
Unit 2 ACCW systems and the carbon st eel components serviced by the ACCW systems, are included within the scope of the ACCW System Carbon Steel
 
Components Program and that the inspections are inclusive.
 
3-134 The staff confirmed that the "parameters m onitored or inspected" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff finds this
 
program element acceptable.
 
(4) Detection of Aging Effects - The "detection of aging effects" program element criteria in SRP-LR Section A.1.2.3.4 are:
 
Detection of aging effects should occur before there is a loss of the
 
structure and component intended function(s). The parameters to be
 
monitored or inspected should be appropriate to ensure that the structure
 
and component intended function(s) will be adequately maintained for
 
license renewal under all CLB design conditions. Provide information that
 
links the parameters to be monitored or inspected to the aging effects
 
being managed. Describe "when," "where," and "how" program data are
 
collected. 
 
The method or technique and frequency may be linked to plant-specific
 
or industry-wide operating experience. Provide justification, including
 
codes and standards referenced, that the technique and frequency are
 
adequate to detect the aging effects before a loss of SC intended
 
function. A program based solely on detecting SC failures is not
 
considered an effective aging management program.
 
When sampling is used to inspect a group of SCs, provide the basis for
 
the inspection population and sample size. The inspection population
 
should be based on such aspects of the SCs as a similarity of materials
 
of construction, fabrication, procurement, design, installation, operating
 
environment, or aging effects. The sample size should be based on such
 
aspects of the SCs as the specific aging effect, location, existing
 
technical information, system and structure design, materials of
 
construction, service environment, or previous failure history. The
 
samples should be biased toward locations most susceptible to the
 
specific aging effect of concern in the period of extended operation.
 
Provisions should also be included on expanding the sample size when
 
degradation is detected in the initial sample.
 
The applicant states in LRA Section B.3.1 that plant-specific and industry operating experience show that detection of nitrite-induced SCC is difficult prior to system
 
leakage. Plant-specific operating experience indicates that detection of leakage is
 
possible well before leaks reach a size that can significantly impact system integrity.
The applicant stated that the ACCW System Carbon Steel Components Program
 
includes the following detection methods.
ACCW surge tank low-level alarms. The program credits alarms and indicators for detection of significant system leakage. The Operations staff
 
investigates abnormal tank level changes and detects significant leaks  Leakage detection systems for ACCW components and equipment served by ACCW are monitored. Abnormal indications are cause for investigation by
 
the Operations staff to determine the leakage source.
3-135 - Containment leakage monitoring detects ACCW system leakage during power operations when the containment is inaccessible.
- Leakage-monitoring systems for other locations with ACCW components and equipment served by ACCW monitor sumps and floor drain tanks. Visual observations of accessible areas by Operations Department personnel during routine rounds. Operations Department personnel conduct
 
rounds of areas with accessible portions of the ACCW systems to detect
 
evidence of leakage. ACCW system engineer walk-down visual inspections of accessible portions of the ACCW system. Periodic visual inspections of the external surfaces of the ACCW system under the External Surfaces Monitoring Program. The program's inspection
 
criteria include signs of system leakage. Periodic VT-2 visual examinations at normal operating pressures for the safety-related portions of the system under the Inservice Inspection (ISI)
 
Program. During the audit and review, the staff reviewed the applicant's program basis documents for this program which described that the detection of aging effects or
 
inspections include leak detection systems, alarms, and other signs of leakage. The
 
staff noted that the AMP includes periodic visual inspections during operator rounds
 
and engineering walkdowns, and visual examinations at normal operating pressure. 
 
On this basis, the staff finds the detection of aging effects acceptable to manage the
 
AERM for which the AMP is credited.
 
The staff confirmed that the "detection of aging effects" program element satisfies
 
the criterion defined in SRP-LR Section A.1.2.3.4. The staff finds this program
 
element acceptable.
(5) Monitoring and Trending - The "monitoring and trending" program element criteria in SRP-LR Section A.1.2.3.5 are:
Monitoring and trending activities should be described, and they should
 
provide predictability of the extent of degradation and thus effect timely
 
corrective or mitigative actions. Plant-specific and/or industry-wide
 
operating experience may be considered in evaluating the
 
appropriateness of the technique and frequency.
 
This program element should describe "how" the data collected are
 
evaluated and may also include trending for a forward look. This includes
 
an evaluation of the results against the acceptance criteria and a
 
prediction regarding the rate of degradation in order to confirm that
 
timing of the next scheduled inspection will occur before a loss of SC
 
intended function. The parameter or indicator trended should be 3-136 described. The methodology for analyzing the inspection or test results against the acceptance criteria should be described.
 
The applicant states in LRA Section B.3.1 that ACCW surge tank levels are monitored, alarms are monitored continuously, and containment leakage is trended.
 
Operations Department personnel conduct rounds of the accessible portions of the
 
ACCW system at least daily. The ACCW system engineer conducts walk-down inspections at least every refueling cycle with the system at normal operating
 
pressure. Inaccessible portions are inspected when made accessible. 
 
During the audit and review, the staff reviewed the applicant's program basis
 
documents for this program which adequately described the monitoring and trending
 
includes leak detection as described above and that any unacceptable conditions
 
are documented by the condition reporting process. The staff noted that the
 
corrective actions program is used to identify adverse trends in lieu of this program
 
element. On this basis, the staff finds the monitoring and trending program element
 
acceptable to manage the AERM for which the AMP is credited.
 
The staff confirmed that the "monitoring and trending" program element satisfies the
 
criterion defined in SRP-LR Section A.1.2.3.5. 
 
The staff finds this program element acceptable.
(6) Acceptance Criteria - The "acceptance criteria" program element criteria in SRP-LR Section A.1.2.3.6 are:
The acceptance criteria of the program and its basis should be
 
described. The acceptance criteria, against which the need for corrective
 
actions will be evaluated, should ensure that the SC intended function(s) 
 
are maintained under all CLB design conditions during the period of
 
extended operation.
 
The applicant states in LRA Section B.3.1 that for visual inspections no indications of leakage are acceptable.
 
During the audit and review, the staff reviewed the applicant's program basis
 
documents for this program which described the acceptance criteria. The staff noted
 
that the program basis documents stated that acceptance criteria of zero leakage
 
ensures that any identified degradation of the system will be evaluated and resolved prior to any loss of system or component intended function. Further, the staff noted
 
that the corrective actions program is used to evaluate and trend unacceptable
 
conditions. On this basis, the staff finds the acceptance criteria acceptable to
 
manage the AERM for which the AMP is credited.
The staff confirmed that the "acceptance criteria" program element satisfies the
 
criterion defined in SRP-LR Section A.1.2.3.6. The staff finds this program element
 
acceptable.
 
  (10) Operating Experience - The "operating experience" program element criterion in SRP-LR Section A.1.2.3.10 is:
The operating experience should provide objective evidence to support 3-137 the conclusion that the effects of aging will be managed adequately so that the structure and component intended function(s) will be maintained
 
during the period of extended operation.
The applicant states in LRA Section B.3.1 that each of the following leakage events
 
described was detected prior to any significant effect on ACCW system pressure
 
and flow.
The Unit 2 letdown heat exchanger experienced several leakage events from 2001
 
through 2003, resulting in the replacement of this heat exchanger in 2004. The
 
letdown heat exchanger leaks initiated, predominantly in creviced areas of the internal baffles. All letdown heat exchanger leaks were detected prior to any loss of
 
component intended function. Leakage rates were typically in the drops-per-minute
 
range detected by investigation of room drain alarms.
In 2003, there was a leak in an 8-inch NPS butt weld in the return line from the
 
letdown heat exchanger. Metallurgical examination of this weld found evidence of
 
SCC initiated in the crevice formed by a weld backing ring.
The leakage rate was in the drops-per-minute range. Operator rounds in the auxiliary building detected the leaks.
Also in 2003, there were two leaks in socket welds in the ACCW return line from the
 
normal charging pump motor coolers. Both of these failures were linked to high
 
stresses from flange misalignment. One of the leaks was in a dead-ended line, the
 
other in the main flow line. One of the leaks issued a steady stream of water well
 
within the ACCW system makeup capacity. A walk-down of the ACCW system detected both of these leaks.
In 2004, there were two leaks in socket welds for heat exchanger drain lines for the Unit 2 ACCW heat exchangers, one leak on Train A and one on Train B, both in the
 
drops-per-minute range. Heat exchanger walk-downs detected them. The welds
 
were not sent offsite for metallurgical analysis, but system history suggests that
 
SCC presumably played a role in these failures.
 
During the audit and review, the staff reviewed the operating experience in the LRA and
 
operating experience reports and also interviewed the applicant's technical personnel and
 
confirmed that plant-specific operating experience did not reveal any degradation not
 
bounded by industry experience.
 
On the basis of its review of the above plant-specific operating experience and discussions
 
with the applicant's technical staff, the staff finds that the applicant's ACCW System Carbon
 
Steel Components Program will adequately manage the aging effects identified in the LRA
 
for which the AMP is credited.
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.10. The staff finds this program element acceptable.
 
UFSAR Supplement In LRA Section A.2.1, the applicant provided the UFSAR supplement for the ACCW System Carbon Steel Components Program. Also, in a letter dated June 27, 2007, the applicant provided Commitment No. 1 to implement the ACCW System Carbon 3-138 Steel Components Program prior to the period of extended operation. 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 ACCW System Carbon Steel Components Program, the staff concludes that the applicant has demonstrated that
 
effects of aging will be adequately managed so that the intended function(s) will be
 
maintained consistent with the CLB for the period of extended operation, upon
 
implementation through Commitment No. 1, 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), prior to the
 
period of extended operation.
 
3.0.3.3.2  Bolting Integrity Program 
 
Summary of Technical Information in the Application LRA Section B.3.2 describes the new Bolting Integrity Program as a plant-specific program. 
 
The applicant stated that the Bolting Integrity Program manages cracking, loss of material, and loss of preload in mechanical bolted closures. The program formalizes some activities
 
and adds new activities consolidated into an integrated program to address mechanical
 
bolting concerns.
 
The Bolting Integrity Program covers safety-related and nonsafety-related bolting for
 
pressure-retaining components within the scope of license renewal except for the reactor
 
vessel head studs, which are addressed by the Reactor Vessel Head Closure Stud
 
Program.
 
The applicant also stated that preventive aspects of the program include appropriate bolting
 
and torquing practices, control of thread lubricants, and periodic replacement of SG
 
manway and handhole bolting to manage cumulative fatigue damage for these fasteners.
 
The program's bolting and torquing practices are based on industry guidelines, vendor
 
recommendations, and plant-specific operating experience appropriate for the applications.
 
Consistent with NUREG-1339 recommendations, the program prohibits the use of
 
lubricants containing molybdenum disulfide, which has been specifically implicated in SCC
 
of bolting. 
 
The applicant further stated that the program also includes periodic inspection of closure
 
bolting assemblies to detect signs of leakage that may indicate loss of preload, loss of
 
material, or crack initiation. Periodic inspection of bolted closures in conjunction with the
 
Inservice Inspection (ISI) Program and External Surfaces Monitoring Program detects the effects of aging and joint leakage. Operator rounds and system walk-downs also detect
 
joint leakage. The Boric Acid Corrosion Control Program evaluated borated water leaks and
 
subsequent impact on bolted connections separately.
 
The Bolting Integrity Program does not control material selection and manufacturing. The
 
design process controls those activities. The Bolting Integrity 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.3.2 related to the applicant's demonstration of the Bolting Integrity 3-139 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 Bolting Integrity Program against the staff's recommended program
 
element criteria that are provided in SRP-LR Section A.1.2.3, and in SRP-LR Table A.1-1.
 
The staff focused its review on assessing how the plant-specific program elements for the
 
Bolting Integrity Program would ensure adequate aging management when compared to
 
the recommended program element criteria that are described in SRP-LR Section A.1.2.3.
 
Specifically, the staff reviewed the following seven (7) program elements of the applicant's
 
program against their corresponding program elem ent criteria that are provided in the subsections to SRP-LR Section A.1.2.3: (1)"scope of the program," (2) "preventive actions,"
 
(3) "parameters monitored or inspected," (4) "detection of aging effects," (5) "monitoring and
 
trending," (6) "acceptance criteria," and (10) "operating experience."
 
The applicant indicated that program elements (7) "corrective actions,"(8) "confirmation
 
process," and (9) "administrative controls" are parts of the site-controlled QA program. The
 
staff evaluated the Inservice Inspection Program's "confirmatory process" and
 
"administrative controls" program elements as part of the staff's evaluation of the applicant's Quality Assurance Program. The staff's evaluation of the applicant's Quality
 
Assurance Program is described in SER Section 3.0.4. The staff's evaluation of the
 
remaining program elements are described in the paragraphs that follow:
 
(1) Scope of the Program - The "scope of the program" program element criterion in SRP-LR Section A.1.2.3.1 requires that the program scope include the specific
 
structures and components addressed with this program
.
The applicant states in LRA Section B.3.2 that the program scope includes all mechanical discipline pressure boundary bolted connections within the scope of
 
license renewal, except for the reactor vessel head studs which is managed by the
 
Reactor Vessel Closure Head Stud Program. Consistent with NUREG-1339, the
 
program considers fasteners determined to have actual yield strength values equal
 
to or greater than 150 ksi (and which are loaded in tension) susceptible to SCC.
During the audit and review, the staff reviewed the applicant's program basis
 
documents for this program that adequately identified all the components within the
 
scope of this AMP. Further, the staff compared attributes of this AMP to those of GALL AMP XI.M18, "Bolting Integrity" to determine whether the plant-specific Vogtle
 
AMP for Bolting Integrity would be effective in managing the effects of aging. The staff noted that the program descriptions for GALL AMP XI.M18 and the Vogtle
 
Bolting Integrity AMP as augmented by the Inservice Inspection Program are
 
equivalent because they both address the same components without exception. The
 
staff concludes that the component supports and associated bolting, including high
 
strength NSSS component support bolting, is within the scope of the VEGP
 
Inservice Inspection Program. The staff finds the "scope of the program" acceptable
 
since it specifically identifies the components within the scope of the Bolting Integrity
 
Program and that the components are equivalent to those identified in GALL AMP XI.M18.
 
The staff concludes that the specific components for which the program manages
 
aging effects are identified, which satisfies the criterion defined in SRP-LR Section 3-140 A.1.2.3.1. On this basis, the staff finds the applicant's scope of the program acceptable.
(2) Preventive Actions - The "preventive acti ons" program element criterion in SRP-LR Section A.1.2.3.2 is that condition moni toring programs do not rely on preventive actions, and thus, preventive actions need not be provided.
The applicant states in LRA Section B.3.2 that bolting and torquing practices and related guidance will be based on industry guidelines like the EPRI bolting
 
guidelines, vendor recommendations, and plant-specific operating experience. Over
 
the years EPRI has published various guides to design, installation, and
 
maintenance of bolted closures: EPRI NP-5067, "Good Bolting Practices: A
 
Reference Manual for Nuclear Power Plant Maintenance Personnel," EPRI TR-
 
104213, "Bolted Joint Maintenance and Applications Guide," and other, more
 
specific guidelines. At times, these guidelines are contradictory. The applicant
 
stated that it will use guidance appropriate for VEGP applications. Control of bolt
 
preload by good bolted-joint practices effectively minimizes the potential for SCC.
 
Application of lubricants will be controlled to specify approved, stable lubricants.
 
Approved lubricants lists will be updated based on new industry operating
 
experience and research data. Consistent with NUREG-1339 recommendations, the
 
program will prohibit the use of Molybdenum Disulfide, which has been specifically
 
implicated in SCC of bolting. The applicant noted that detection of significant
 
leakage during operator rounds minimizes the effects of aggressive environments.
 
Timely detection and correction of leakage minimizes the degradation of bolted
 
connections. 
 
The applicant also stated that periodic replacement of SG secondary side manway
 
and handhole bolts manages cumulative fatigue damage (LRA Section 4.3.5). 
 
This approach ensures a conservative number of transient cycles in current fatigue
 
analyses. The current replacement schedule of 30 years of service life may be
 
adjusted by updated analyses initiated by the program. The Steam Generator Program strategic plan tracks replacement activity.
During the audit and review, the staff reviewed the applicant's program basis
 
documents for this program which descri bed the preventive and mitigative actions that are focused on prevention of bolted joint failure through control of bolt preload
 
and the application of good bolted joint practices to minimize the occurrence of
 
SCC. In addition, the staff noted that only approved lubricants will be used, and that
 
early leak detection through operator rounds will minimize the potential for bolting
 
degradation by limiting the formation of aggressive environments. The staff noted that GALL AMP XI.M18, and the Vogtle Bolting Integrity Program both address
 
equivalent preventive actions. Additionally, the staff noted that the Vogtle Bolting
 
Integrity Program will direct the periodic replacement of the steam generator
 
secondary manway and handhold bolts to manage cumulative fatigue damage and
 
that the frequency of bolt replacement of 30 years can be modified through updated
 
analyses. On this basis, the staff finds the "preventive actions" acceptable since
 
they would be effective in preventing bolted joint failure.
The staff confirmed that the "preventive actions" program element satisfies the 3-141 criterion defined in SRP-LR Section A.1.2.3.2. The staff finds this program element acceptable.
(3) Parameters Monitored or Inspected - The "parameters monitored or inspected" program element criterion in SRP-LR Section A.1.2.3.3 are:
The parameters to be monitored or inspected should be identified and linked to
 
the degradation of the particular structure and component intended function(s).
 
The parameters monitored or inspected should detect the presence and extent
 
of aging effects.
The applicant states in LRA Section B.3.2 that joint installation and maintenance activities monitor parameters for proper bolt torque and joint alignment. Operator
 
rounds and visual and non-visual examinations specified by the Inservice Inspection (ISI) Program and External Surfaces Monitoring Program detect loss of preload
 
evidenced by leakage, loss of material, and cracking.
During the audit and review, the staff reviewed the applicant's program basis
 
documents for this program which described the parameters monitored that include
 
leak detection and include proper joint alignment during maintenance and operation
 
activities. The staff finds the "parameters monitored or inspected" acceptable since
 
it identifies the performance of inspections equivalent to those identified in GALL AMP XI.M18.
 
The staff concludes that this program element satisfies the criteria defined in SRP-
 
LR Section A.1.2.3.3. The staff finds it acceptable on the basis that the applicant
 
inspects bolted connections within scope for evidence of leakage, corrosion, and
 
loss of preload. 
 
In addition, this program element specifies both visual and non-visual inspection
 
techniques in accordance with the Inservice Inspection Program and External
 
Surfaces Monitoring Program.
The staff confirmed that the "parameters m onitored or inspected" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff finds this
 
program element acceptable.
(4) Detection of Aging Effects - The "detection of aging effects" program element criteria in SRP-LR Section A.1.2.3.4 are:
 
Detection of aging effects should occur before there is a loss of the
 
structure and component intended function(s). The parameters to be
 
monitored or inspected should be appropriate to ensure that the structure
 
and component intended function(s) will be adequately maintained for
 
license renewal under all CLB design conditions. Provide information that
 
links the parameters to be monitored or inspected to the aging effects
 
being managed.
 
Describe "when," "where," and "how" program data are collected (i.e., all
 
aspects of activities to collect data as part of the program).
 
3-142 The method or technique and frequency may be linked to plant-specific or industry-wide operating experience. Provide justification, including
 
codes and standards referenced, that the technique and frequency are
 
adequate to detect the aging effects before a loss of SC intended
 
function. A program based solely on detecting SC failures is not considered an effective aging management program.
 
When sampling is used to inspect a group of SCs, provide the
 
basis for the inspection population and sample size. The
 
inspection population should be based on such aspects of the
 
SCs as a similarity of materials of construction, fabrication, procurement, design, installation, operating environment, or
 
aging effects. The sample size should be based on such
 
aspects of the SCs as the specific aging effect, location, existing technical information, system and structure design, materials of construction, service environment, or previous
 
failure history. The samples should be biased toward
 
locations most susceptible to the specific aging effect of
 
concern in the period of extended operation. Provisions
 
should also be included on expanding the sample size when
 
degradation is detected in the initial sample.
The applicant states in LRA Section B.3.2 that periodic inspections in conjunction with the following activities detect the effects of aging and joint leakage. Operator
 
rounds periodically monitor bolted connections for signs of leakage due to loss of
 
preload. Visual inspections detect loss of preload resulting in joint leakage and
 
fastener degradation due to cracking or loss of material. The Inservice Inspection (ISI) Program inspects safety-related fasteners using inspection techniques specified in ASME Code Section XI, Subsections IWB, IWC, and IWD. The External
 
Surfaces Monitoring Program inspects carbon steel, alloy steel, and copper alloy
 
fasteners subject to loss of material using general visual examination techniques to
 
detect leakage and corrosion of bolted closures. Inspections to detect joint leakage
 
will focus on bolted connections in high-temperature or high-pressure service where
 
leakage is most likely.
During the audit and review, the staff reviewed the applicant's program basis
 
documents for this program which adequately described that detection of aging
 
effects include periodic inspections and that the safety-related bolted fasteners are
 
subject to the appropriate inspections techniques as specified in ASME Code Section XI. The staff finds the "detection of aging effects" acceptable since it
 
identifies the performance of inspections equivalent to those identified in GALL AMP XI.M18.
 
This program element satisfies the SRP-LR Section A.1.2.3.4 because it specifies
 
that visual and non-visual inspections are performed which can detect the aging
 
effects and that the frequency of inspection ensures that the aging effects will be
 
detected prior to the loss of component function. Also, the applicant's Bolting
 
Integrity Program does not utilize sampling as all bolted connections are subject to
 
inspection. 
 
3-143 The staff confirmed that the "detection of aging effects" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.4. The staff finds this program
 
element acceptable.
(5) Monitoring and Trending - The "monitoring and trending" program element criteria in SRP-LR Section A.1.2.3.5 are:
Monitoring and trending activities should be described, and they should
 
provide predictability of the extent of degradation and thus effect timely
 
corrective or mitigative actions. Plant-specific and/or industry-wide
 
operating experience may be considered in evaluating the
 
appropriateness of the technique and frequency.
 
This program element should describe "how" the data collected are
 
evaluated and may also include trending for a forward look. This includes
 
an evaluation of the results against the acceptance criteria and a
 
prediction regarding the rate of degradation in order to confirm that
 
timing of the next scheduled inspection will occur before a loss of SC
 
intended function. The parameter or indicator trended should be
 
described. The methodology for analyzing the inspection or test results
 
against the acceptance criteria should be described.
 
The applicant states in LRA Section B.3.2 that operations department personnel periodically conduct rounds of accessible areas. The engineering staff also
 
conducts system walk-downs periodically. ISI program inspection frequencies are established consistent with ASME Code Section XI as specified by
 
10 CFR 50.55a(g)(4)(ii). The applicant also stated that the Inservice Inspection (ISI)
 
Program is based on ASME Code Inservice Inspection Program B (IWA-2432).
 
Owner activity reports record ISI results for the staff after each operating cycle. 
 
The External Surfaces Monitoring Program conducts general visual inspections periodically of both normally accessible and normally inaccessible areas. Inspection
 
intervals will be consistent with those specified by the External Surfaces Monitoring
 
Program.
During the audit and review, the staff reviewed the applicant's program basis
 
documents for this program which adequately described that monitoring and
 
trending activities include periodic inspections through conducting rounds of
 
accessible areas and that engineering staff conducts system walk-downs on a
 
periodic basis. 
 
The staff concludes that this program element satisfies the criteria defined in the
 
SRP-LR Section A.1.2.3.5 on the basis that the program describes the specific
 
inspection activities, the frequency of performance, and the method of their
 
documentation. Additionally, the program describes the actions taken to evaluate
 
the acceptability of inspection results.
The staff confirmed that the "monitoring and trending" program element satisfies the
 
criterion defined in SRP-LR Section A.1.2.3.5. The staff finds this program element
 
acceptable.
 
3-144 (6) Acceptance Criteria - The "acceptance criteria" program element criteria in SRP-LR Section A.1.2.3.6 are:
The acceptance criteria of the program and its basis should be
 
described. The acceptance criteria, against which the need for corrective
 
actions will be evaluated, should ensure that the SC intended function(s)
 
are maintained under all CLB design conditions during the period of
 
extended operation.
 
The applicant states in LRA Section B.3.2 that any significant joint leakage detected during operator rounds or system walkdowns is unacceptable and it is entered into
 
the corrective actions process. For inspection of safety-related fasteners under the
 
Inservice Inspection (ISI) Program, acceptance standards will be consistent with those as defined in ASME Code Section XI Articles IWA-3000, IWB-3000, IWC-
 
3000, and IWD-3000. For unacceptable conditions identified during general visual
 
inspections conducted by the External Surface Monitoring Program, indications of
 
joint leakage, cracking, or significant corrosion of fasteners or joint mating surfaces
 
are entered into the corrective action process. 
 
During the audit and review, the staff reviewed the applicant's program basis documents for this program which adequately described that the acceptance criteria included those specified in ASME Code Section XI for safety-related fasteners and
 
equivalent criteria for nonsafety-related fasteners.
 
The staff concludes that this program element satisfies the criteria in SRP-LR
 
Section A.1.2.3.6. The staff finds this program element acceptable on the basis that the acceptance criteria are consistent with ASME Section XI articles IWA-3000, IWB-3000, IWC-3000, and IWD-3000. 
 
Further, any evidence of joint leakage, cracking, or significant corrosion is reported
 
and documented in the VEGP corrective actions process.
The staff confirmed that the "acceptance criteria" program element satisfies the
 
criterion defined in SRP-LR Section A.1.2.3.6. The staff finds this program element
 
acceptable.
 
(10) Operating Experience - The "operating ex perience" program element criterion in SRP-LR Section A.1.2.3.10 is:
The operating experience should provide objective evidence to
 
support the conclusion that the effects of aging will be managed
 
adequately so that the structure and component intended
 
function(s) will be maintained during the period of extended
 
operation.
The applicant states in LRA Section B.3.2 that industry operating experience shows that bolted connections typically do not fail catastrophically but are more likely to
 
leak. Additionally, complete joint failure is unlikely due to the redundancy of multiple
 
fasteners. The applicant stated that degradation of bolted connections in the
 
industry has been related primarily to boric acid corrosion (addressed by the Boric
 
Acid Corrosion Control Program), out-of-specification fasteners, and recurring 3-145 leakage events. Recent plant-specific operating experience with fasteners includes leakage due to loss of preload, corrosion of fasteners in environments with wetting
 
or condensation effects, loose or improperly torqued fasteners, and missing
 
fasteners and locking pins. Some carbon steel and alloy steel bolting has been
 
replaced with corrosion-resistant material. Maintenance to correct leaks also has
 
detected minor scratching and corrosion of flange surfaces. The applicant also
 
stated that these results indicate that the redundancy of bolted connections with
 
Inservice Inspection (ISI) Program in spections and system walkdowns have detected degradation effectively prior to the loss of any intended function. There
 
have been no reports of bolt cracking due to SCC in recent experience.
The applicant further stated that the Bolting Integrity Program is based on industry practices and vendor recommendations for bolted connection installation and
 
maintenance. Program updates will incorporate new guidance applicable to VEGP.
During the audit and review, the staff reviewed the operating experience provided in the LRA and operating experience evaluation reports, and also interviewed the
 
applicant's technical personnel and confirmed that plant-specific operating
 
experience did not reveal any degradati on not bounded by industry experience. The staff concludes that these operating experience events provide objective evidence
 
that the Bolting Integrity Program will provide timely detection of aging degradation
 
and corrective action.
 
On the basis of its review of the operating experience and discussions with the
 
applicant's technical staff, the staff concludes that the applicant's Bolting Integrity
 
Program will adequately manage the aging effects identified in the LRA for which
 
this AMP is credited.
 
The staff confirmed that the "operating ex perience" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.10. The staff finds this program element
 
acceptable.
 
UFSAR Supplement In LRA Section A.2.2, the applicant provided the UFSAR supplement for the Bolting Integrity Program. Also, in a letter dated June 27, 2007, the applicant
 
provided Commitment No. 2 to implement the Bolting Integrity Program prior to the period
 
of extended operation. The staff reviewed the UFSAR Supplement section and finds the
 
UFSAR supplement information provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
 
Conclusion On the basis of its review of the applicant's Bolting Integrity Program, the staff concludes that the applicant has demonstrated that effects of aging will be adequately
 
managed so that the intended function(s) will be maintained consistent with the CLB for the
 
period of extended operation, upon implementation through Commitment No. 2, as required
 
by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
determined that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
 
3.0.3.3.3  Diesel Fuel Oil Program 
 
Summary of Technical Information in the Application LRA Section B.3.7 describes the existing Diesel Fuel Oil Program as a plant-specific program. 
 
3-146 The applicant stated that the Diesel Fuel Oil Program manages loss of material in the diesel fuel oil systems for the emergency diesel generators (EDGs) and diesel engine-driven fire water pumps by monitoring and maintenance of diesel fuel oil quality. The program is
 
based on VEGP Technical Specifications and supplemental requirements. Draining, cleaning, and internal condition inspections of diesel fuel oil components under other AMPs
 
are as follows:
 
The Periodic Surveillance and Preventiv e Maintenance Program periodically cleans and inspects the EDG system diesel fuel oil storage tank interiors. The Fire Protection Program visually inspects diesel engine-driven fire water pump fuel supply lines for leakage during diesel operation as a part of
 
surveillance testing. The One-Time Inspection Program verifies the effectiveness of the Diesel Fuel Oil Program at preventing loss of diesel fuel oil component material by
 
sampling inspections focused on locations like tank bottoms where
 
contaminants may accumulate. The inspections measure storage tank
 
bottom surface thickness to confirm that significant degradation has not
 
occurred.
Staff Evaluation In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.3.7 on the applicant's demonstration of the Diesel Fuel Oil 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 Diesel Fuel Oil Program against the staff's recommended program
 
element criteria that are provided in SRP-LR Section A.1.2.3, and in SRP-LR Table A.1-1.
 
The staff focused its review on assessing how the plant-specific program elements for the
 
Diesel Fuel Oil Program would ensure adequate aging management when compared to the recommended program element criteria that are described in SRP-LR Section A.1.2.3.
 
Specifically, the staff reviewed the following seven (7) program elements of the applicant's
 
program against their corresponding program elem ent criteria that are provided in the subsections to SRP-LR Section A.1.2.3: (1) "scope of the program," (2) "preventive
 
actions," (3) "parameters monitored or inspected," (4) "detection of aging effects," (5)
 
"monitoring and trending," (6) "acceptance criteria," and (10) "operating experience."
 
The applicant indicated that program elements (7) "corrective actions," (8) "confirmation
 
process," and (9) "administrative controls" are parts of the site-controlled QA program. The
 
staff evaluated the Diesel Fuel Oil Program's "corrective actions," "confirmation process"
 
and "administrative controls" program elements as part of the staff's evaluation of the applicant's Quality Assurance Program. The staff's evaluation of the applicant's Quality
 
Assurance Program is described in SER Section 3.0.4. The staff's evaluation of the
 
remaining program elements are described in the paragraphs that follow:
 
(1) Scope of the Program - The "scope of the program" program element criterion in SRP-LR Section A.1.2.3.1 requires that the program scope include the specific structures and components addressed with this program.
 
The applicant states in LRA Section B.3.7 that the Diesel Fuel Oil Program is 3-147 credited for license renewal to manage loss of material due to corrosion on surfaces exposed to diesel fuel oil in the following systems:
EDG system  Fire protection system (diesel engine-driven fire water pumps)
The applicant also stated that the program monitors and maintains diesel fuel oil
 
quality in the diesel fuel oil systems for the EDGs and diesel engine-driven fire water
 
pumps. For license renewal, the program focus is to manage conditions that can
 
cause loss of material in system components by monitoring and maintaining diesel
 
fuel oil quality in the storage tanks. Fuel oil monitoring activities that minimize the
 
potential for degradation of the coating system on the interior of EDG system diesel
 
fuel oil storage tanks are within the scope of the program.
 
The staff concludes that the specific components (EDGs and diesel engine-driven
 
fire water pumps) for which the program manages aging effects are identified. The
 
staff finds that this satisfies the criterion defined in SRP-LR Section A.1.2.3.1. On
 
this basis, the staff finds the applicant's scope of the program acceptable.
 
The staff confirmed that the "scope of t he program" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.1. The staff finds this program element
 
acceptable.
(2) Preventive Actions - The "preventive acti ons" program element criterion in SRP-LR Section A.1.2.3.2 states that the activities for prevention and mitigation programs
 
should be described and that these actions should mitigate or prevent aging
 
degradation.
 
The applicant states in LRA Section B.3.7 that, when necessary based on the results of microbe and stability analyses, biocides and fuel oil stabilizers are added.
 
In addition, the staff noted during the audit and review that the program periodically
 
monitors the presence of water in the bottom of the EDG diesel fuel oil tanks and, if
 
present, drains the water from the bottom of the tank to minimize the potential for
 
corrosion of the tank.
The staff finds this acceptable because the program is primarily a condition
 
monitoring program which has provisions fo r preventive measures (addition of fuel additives and draining of the accumulated water), if the results of periodic testing
 
indicate that it is warranted.
The staff confirmed that the "preventive actions" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.2. The staff finds this program element
 
acceptable.
(3) Parameters Monitored or Inspected - The "parameters monitored or inspected" program element criterion in SRP-LR Section A.1.2.3.3 are:
The parameters to be monitored or inspected should be identified and
 
linked to the degradation of the particular structure and component
 
intended function(s). The parameters monitored or inspected should
 
detect the presence and extent of aging effects.
3-148  The applicant states in LRA Section B.3.7 that prior to offloading to the EDG diesel fuel oil storage tanks, fuel oil in tanker cars is bottom-sampled. When the tanker has
 
multiple compartments, the program uses a composite sample of proportionate
 
volumes from each compartment. Bottom sampling of new fuel oil conservatively
 
measures fuel oil contaminants like water and sedimentation.
Before the addition of fuel oil to the EDG diesel fuel oil storage tanks, the applicant
 
stated that the program analyzes oil for the following parameters for aging
 
management:
Clear and bright appearance in accordance with ASTM Test Method D4176,  Mercaptan sulfur content in accordance with ASTM Test Methods D3227 or D484; and  Neutralization number in accordance with ASTM Test Method D664.
Before addition to the diesel fuel oil tanks for the diesel engine-driven fire water pumps, or within 72 hours after fuel addition, the program tests the fuel oil for a
 
clear and bright appearance in accordance with ASTM Test Method D4176.
In accordance with VEGP Technical Specifications, the applicant also stated that
 
the program analyzes samples collected prior to offload to the EDG diesel fuel oil
 
storage tanks for the parameters specified in Table 1 of ASTM D975 (1981) within
 
31 days after addition of the sampled fuel oil to the tanks. For aging management, the program credits the following parameters from this analysis to manage the
 
effects of aging:
 
Water and sediment content consistent with ASTM Test Method D1796 or D2709. Copper Strip Corrosion analyzed consistent with ASTM Test Method D130.
The applicant further stated that the program monitors fuel oil stored in the EDG fuel
 
oil storage tanks for the following parameters for aging management:
Check for and remove accumulated water,  Using a recirculated tank sample, total particulate content consistent with ASTM Test Method D6217 (this method uses a 0.8 micron filter),  Using a recirculated tank sample, mercaptan sulfur content consistent with ASTM Test Method D3227 or D484,  Using a recirculated tank sample, neutralization number in accordance with ASTM Test Method D664, and; 3-149  Using a recirculated tank sample, microbe and stability analyses are performed.
Fuel oil mercaptan sulfur and neutralization number testing address the potential for
 
aggressive conditions that could affect the coating applied to the internal surfaces of
 
the EDG diesel fuel oil storage tanks.
 
The program analyzes the stored fuel oil in the diesel fuel oil tanks for the diesel
 
engine-driven fire water pumps for a clear and bright appearance using a composite
 
sample from the storage tank. 
 
The staff finds this program element acceptable because the program monitors the
 
quality of the fuel oil to detect the presence of contaminants in water and sediments
 
that could cause the identified aging effects. In addition, the program provides for
 
testing the fuel oil for the presence of Mercaptan sulfur and neutralization number
 
which could affect the coating applied to the internal surfaces of the EDG fuel oil
 
storage tanks. Finally, the program monitors the particulate level in the fuel oil which
 
is an indicator of the effectiveness of the program in managing the degradation of
 
the surfaces exposed to diesel fuel oil. On this basis, the staff finds the applicant's
 
parameters monitored or inspected program element acceptable.
The staff confirmed that the "parameters m onitored or inspected" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff finds this
 
program element acceptable.
(4) Detection of Aging Effects - The "detection of aging effects" program element criteria in SRP-LR Section A.1.2.3.4 are:
 
Detection of aging effects should occur before there is a loss of the
 
structure and component intended function(s). The parameters to be
 
monitored or inspected should be appropriate to ensure that the structure
 
and component intended function(s) will be adequately maintained for
 
license renewal under all CLB design conditions. Provide information that
 
links the parameters to be monitored or inspected to the aging effects
 
being managed.
 
Describe "when," "where," and "how" program data are
 
collected (i.e., all aspects of activities to collect data as part of
 
the program).
The method or technique and frequency may be linked to plant-specific
 
or industry-wide operating experience. Provide justification, including
 
codes and standards referenced, that the technique and frequency are
 
adequate to detect the aging effects before a loss of SC intended
 
function. A program based solely on detecting SC failures is not
 
considered an effective aging management program.
 
When sampling is used to inspect a group of SCs, provide the basis for
 
the inspection population and sample size. The inspection population 3-150 should be based on such aspects of the SCs as a similarity of materials of construction, fabrication, procurement, design, installation, operating
 
environment, or aging effects.
 
The applicant states in LRA Section B.3.7 that degradation of fuel oil system components cannot occur without fuel oil contaminants like water, sediment, or
 
microbiological organisms. The program minimizes degradation of the EDG fuel oil
 
storage tank interior coating system by monitoring Mercaptan sulfur and
 
neutralization number as indicators of fuel oil condition. Periodic sampling, analysis, and appropriate corrective actions assure that fuel oil contaminants have not
 
impacted fuel oil syst em components adversely.
The applicant also stated that detection of loss of material in internal surfaces of fuel
 
oil system components is through activities and inspections under other AMPs.
 
These inspection activities include the following visual and volumetric examination
 
techniques:
For the EDG diesel fuel oil storage tanks, visual inspection of the internal tank surfaces for degradation of the applied coating and corrosion of the
 
tank base metal is under the Periodic Surveillance and Preventive
 
Maintenance Activities Program. Visual monitoring of the fuel supply lines for the diesel engine-driven fire water pumps for leakage indicative of component degradation during diesel
 
operation is part of the surveillance testing under the Fire Protection
 
Program. The One-Time Inspection Program monitors the effectiveness of the Diesel Fuel Oil Program at preventing loss of material in the diesel fuel oil
 
components by sampling inspections focused on locations like tank bottoms
 
where contaminants may accumulate. The inspections measure storage tank
 
bottom surface thickness to confirm that significant degradation has not
 
occurred.
The staff finds this program element acceptable on the basis that the program
 
monitors the presence of fuel oil contaminants that could result in the degradation of
 
the fuel oil system components. The program also monitors the Mercaptan sulfur and neutralization number as an indicator of the aggressiveness of the fuel oil which
 
minimizes the potential for degradation of the coating on the surface of the EDG fuel
 
oil storage tanks.
The staff confirmed that the "detection of aging effects" program element satisfies
 
the criterion defined in SRP-LR Section A.1.2.3.4. The staff finds this program
 
element acceptable.
(5) Monitoring and Trending - The "monitoring and trending" program element criteria in SRP-LR Section A.1.2.3.5 are:
Monitoring and trending activities should be described, and they should 3-151 provide predictability of the extent of degradation and thus effect timely corrective or mitigative actions.
 
This program element should describe how the data collected are
 
evaluated and may also include trending for a forward look. The
 
parameter or indicator trended should be described.
 
The applicant states in LRA Section B.3.7 that the program monitors EDG system stored fuel oil periodically as follows:
Consistent with VEGP Technical Specifications, the program checks for and removes accumulated water every 31 days. Consistent with VEGP Technical Specifications, the program monitors total particulate every 31 days. Mercaptan sulfur and neutralization number are monitored quarterly. The program analyzes diesel engine-driven fire water pump stored diesel fuel oil for a clear and bright appearance quarterly.
The staff finds this program element acceptable on the basis that the program
 
monitors the presence of fuel oil contaminants on a frequency which is consistent
 
with the VEGP Technical Specifications and less than on a quarterly basis as recommended in GALL AMP XI.M30, "Fuel Oil Chemistry." The program also monitors the Mercaptan sulfur and neutralization number on a quarterly basis, which is consistent with GALL AMP XI.M30 and acceptable.
 
The staff confirmed that the "monitoring and trending" program element satisfies the
 
criterion defined in SRP-LR Section A.1.2.3.5. The staff finds this program element
 
acceptable.
(6) Acceptance Criteria - The "acceptance criteria" program element criteria in SRP-LR Section A.1.2.3.6 are:
The acceptance criteria of the program and its basis should be
 
described. The acceptance criteria, against which the need for corrective
 
actions will be evaluated, should ensure that the SC intended function(s)
 
are maintained under all CLB design conditions during the period of
 
extended operation.
The applicant states in LRA Section B.3.7 that the EDG system new fuel oil acceptance criteria are as follows:
New fuel oil must have a clear and bright appearance in accordance with ASTM Test Method D4176. Mercaptan sulfur content must be less than 0.01 percent if stored oil Mercaptan content is greater than 0.007 percent or the offload exceeds 3-152 15,000 gallons added to the storage tank since the last Mercaptan analysis where Mercaptan content was less than 0.007 percent. Neutralization number must be less than 0.2. Water and sediment content analyzed in accordance with ASTM Test Method D1796 or D2709 must be less than 0.05 percent. Copper strip corrosion analyzed in accordance with ASTM Test Method D130 must be No. 3 or less. Before addition to the diesel fuel oil storage tank for the diesel engine-driven fire water pumps, or within 72 hours after fuel oil addition, the program tests
 
the fuel oil for a clear and bright appearance in accordance with ASTM Test
 
Method D4176 EDG system stored fuel oil acceptance criteria are as follows:
Any indication of accumulated water is unacceptable. Total particulate must be less than 10 mg/liter. Mercaptan sulfur content must be less than 0.01 percent. Neutralization number must be less than 0.2. Microbe analyses must not indicate significant presence. Stability analyses must not indicate any significant breakdown of the fuel.
Stored fuel oil for the diesel engine-driven fire water pumps must have a clear and
 
bright appearance.
 
The staff finds this program element acceptable on the basis that the program identifies specific acceptance criteria for the parameters against which the need for
 
corrective actions are evaluated. 
 
On this basis, the staff finds the applicant's acceptance criteria program element
 
acceptable.
The staff confirmed that the "acceptance criteria" program element satisfies the
 
criterion defined in SRP-LR Section A.1.2.3.6. The staff finds this program element
 
acceptable.
 
(10) Operating Experience - The "operating ex perience" program element criterion in SRP-LR Section A.1.2.3.10 is:
The operating experience should provide objective evidence to support
 
the conclusion that the effects of aging will be managed adequately so
 
that the structure and component intended function(s) will be maintained
 
during the period of extended operation.
The applicant states in LRA Section B.3.7 that the Diesel Fuel Oil Program is in
 
accordance with general requirements for environmental and engineering programs.
 
Periodic program reviews ensure compliance with regulatory, process, and 3-153 procedural requirements. There has been no significant degradation of EDG fuel oil system or fire pump diesel fuel oil sy stem components. A recent 10-year cleaning and inspection of the EDG Fuel Oil Storage Tanks observed only minimal amounts
 
of sludge and no damage to the inorganic zinc coating or the underlying tank base
 
metal. Recent plant-specific operating experience shows no significant or recurring
 
problems in diesel fuel oil test results and only two minor test failures. In 2002 a
 
check for accumulated water detected and removed a small quantity of water from
 
the 1A Emergency Diesel Fuel Oil Storage Tank. In 2003, a clear and bright test
 
detected high solids in the No. 5 Fire Pump Diesel Fuel Oil Storage Tank. After
 
circulation through a portable filtration system the tank contents passed a follow-up
 
clear and bright test.
The applicant further stated that the condition of the fuel oil storage tanks and other
 
components and the early detection of fuel oil quality issues by fuel oil sampling
 
demonstrate that the program effectively manages degradation of surfaces exposed
 
to diesel fuel oil.
 
During the audit, the staff confirmed in discussions with the applicant's technical staff and
 
review of VEGP operating experience report evaluation that no significant aging
 
degradation in the EDG fuel oil system or fire pump diesel fuel oil system components has been identified to date. In addition, the staff confirmed that, during the last 10-year tank
 
cleaning and inspection of the EDG fuel oil storage tanks, no damage to the inorganic zinc
 
coating or the underlying tank base metal was observed. On this basis, the staff finds that
 
the applicant's operating experience acceptable.
 
The staff confirmed that the "operating ex perience" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.10. The staff finds this program element
 
acceptable.
 
UFSAR Supplement In LRA Section A.2.7, the applicant provided the UFSAR supplement for the Diesel Fuel Oil Program. The staff reviewed this section and finds the UFSAR
 
supplement information an adequate summary descr iption of the program, as required by 10 CFR 54.21(d).
 
Conclusion On the basis of its technical review of the applicant's Diesel Fuel Oil Program, the staff concludes that the applicant has demonstrated that effects of aging will be
 
adequately managed so that the intended function(s) will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and determined that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.3.4  Inservice Inspection Program 
 
Summary of Technical Information in the Application LRA Section B.3.13 describes the existing Inservice Inspection Program as a plant-specific program. 
 
The applicant stated that the Inservice Inspection (ISI) Program mandates examinations, testing, and inspections of components and systems to detect deterioration and manage
 
aging effects. The program uses periodic visual, surface, and volumetric examination and
 
leakage tests of Classes 1, 2, and 3 pressure-retaining components, their attachments, and
 
their supports to detect and characterize flaws.
3-154  The applicant also stated that the program is in accordance with 10 CFR 50.55(a), which ISI requirements of ASME Code Section XI for Classes 1, 2, and 3 pressure-retaining
 
components, their integral attachments, and their supports. Inspection, repair, and replacement of these components are covered in Section XI Subsections IWB, IWC, IWD
 
and IWF, respectively.
 
In accordance with 10 CFR 50.55a(g)(4)(ii) and as based on ASME ISI Program B (IWA-
 
2432), the ISI Program is updated at the end of each 120-month inspection interval to the
 
latest code edition and addenda specified in 10 CFR 50.55a twelve months before the start
 
of the inspection interval. The ISI Program second inspection interval ended in May 2007.
The third ISI interval requirements are based on ASME Code Section XI, 2001 Edition and
 
2002 and 2003 Addenda. 
 
Staff Evaluation In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.3.13 on the applicant's demonstration of the ISI 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 Inservice Inspection Program against the staff's recommended
 
program element criteria that are provided in SRP-LR Section A.1.2.3, and in SRP-LR Table A.1-1. The staff focused its review on assessing how the plant-specific program
 
elements for the Inservice Inspection Program would ensure adequate aging management when compared to the recommended program elem ent criteria that are described in SRP-LR Section A.1.2.3. Specifically, the staff reviewed the following eight (8) program elements
 
of the applicant's program against their corresponding program element criteria that are
 
provided in the subsections to SRP-LR Section A.1.2.3: (1)"scope of the program,"
 
(2) "preventive actions," (3) "parameters monitored or inspected," (4) "detection of aging
 
effects," (5) "monitoring and trending," (6) "acceptance criteria," (7) "corrective actions," and
 
(10) "operating experience."
 
The applicant indicated that program elements (8) "confirmation process," and
 
(9) "administrative controls" are parts of t he site-controlled QA program. The staff evaluates the Inservice Inspection Program's "confirmato ry process" and "administrative controls" program elements as part of the staff's eval uation of the applicant's Quality Assurance Program. The staff's evaluation of the applicant
's Quality Assurance Program is described in SER Section 3.0.4. The staff's evaluation of the remaining program elements are
 
described in the paragraphs that follow:
 
(1) Scope of the Program - LRA Section B.3.13 states that the following ASME Code Section XI inspection categories are credited for license renewal:
All applicable Subsection IWB examination categories except B-N-1 and B-N-2. The Reactor Internals Program manages aging of the reactor internals. Subsection IWC examination categories applicable to the Model F SGs  Subsection IWC and IWD visual examinations credited as parts of the ACCW System Carbon Steel Components Program, Bolting Integrity
 
Program, Boric Acid Corrosion Control Program, and External Surfaces 3-155 Monitoring Program  All applicable Subsection IWF examination categories for component supports and bolting, including high-strength nuclear steam supply system
 
component support bolting SRP-LR Section A.1.2.3.1, "scope of program," provides the following
 
recommendation for AMP "scope of program" program elements:
 
The specific program necessary for license renewal should be identified. The scope of the progr am should include the specific structures and components of which the program manages the
 
aging. The staff reviewed the license renewal basis evaluation document, SNC-corporate and VEGP-specific implementation procedures and 10-Year ISI Plan for the VEGP
 
units as part of its review of the ISI Program to determine how the "scope of
 
program" program element for the ISI Program compared with the staff's recommendations in SRP-LR Section A.1.2.3.1. From its review of these
 
documents, the staff concludes that the IS I Program is implemented to comply with the requirements of Section &sect;50.55a of Title 10, Code of Federal Regulations.
 
The GALL Report, Revision 1, Volume 2 recommends that a plant's ISI program be
 
credited for aging management under 10 CFR Part 54 only for specific ASME Code
 
Class 1 and 2 components that are identified in the specific AMR items in the report.
 
The staff noted that the scope of the ISI Program credited for aging management in
 
accordance with the requirements of 10 CFR Part 54 did not include all of the ASME
 
Code Class 2 and 3 systems, components, and supports that the program that is implemented for compliance with the requirements of 10 CFR 50.55a. The staff
 
sought further clarification on this matter and asked the applicant to:
 
clarify whether the scope of the Reactor Internals Program covers all ASME inspection item requirements in the ASME Code Section XI, Table IWB-
 
2500-1 for Examination Categories B-N-1 and B-N-2. provide its basis why the "scope of program" program element does not credit ASME Code Section XI, Subsection IWC for remaining ASME Class 2
 
systems at VEGP (i.e., for those VEGP Cl ass 2 systems that are not part of the VEGP Model F steam generators)  clarify which of the ASME Section XI Examination Categories and Inspection Items are within the scopes of the ACCW System Carbon Steel Components
 
Program (Appendix B.3.1), Bolting Integrity Program (Appendix B.3.2), Boric
 
Acid Corrosion Control Program (Appendix B.3.3), and External Surfaces
 
Monitoring Program (Appendix B.3.8). Clarify whether the collective scope of
 
these AMPs includes all visual examination-based inspection items in ASME Section XI Table IWC-2500-1 for VEGP Class 2 components and in ASME Section XI Table IWD-2500-1 for VEGP Class 3 components.
 
3-156 The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that the scope of ISI Program
 
is broader than the set of inspections explicitly credited for license renewal and that
 
SNC will replace the ISI Program scope description in Section B.3.13 of the VEGP
 
LRA with the following:
The ISI program scope is defined by ASME Section XI Subsections IWB-
 
1000, IWC-1000, IWD-1000, and IWF-1000 for Class 1, 2, and 3
 
components and supports, and includes all pressure-retaining components
 
and their integral attachments.
 
The applicant stated that the program description would be amended to reflect this
 
clarification in a future LRA amendment. The staff confirmed that the applicant
 
amended the LRA in a letter dated March 20, 2008.
 
The applicant also provided specific clarifications on the ASME Code Section XI
 
Examination Categories that are credited for aging management activities of the
 
ASME Code Class 1, 2, and 3 components and components supports at VEGP and on the ASME Code Section XI Examination Categories that are implemented for
 
aging management purposes as part of the program element criteria for the
 
following LRA AMPs:
 
AMP B.3.1, ACCW System Carbon Steel Components Program  AMP B.3.2, Bolting Integrity Program  AMP B.3.3, Boric Acid Corrosion Control Program  AMP B.3.24, Reactor Internals Program
 
The applicant also stated that the program description and the program elements for
 
the ISI program contained two errors:
 
  (1) AMP B.3.8, External Surfaces Monitoring Program, was inadvertently listed as an AMP that credits ASME Code Section XI 
 
Examination categories requirements as part of its program element criteria. 
 
  (2)  The "scope of program" program element for the ISI program inadvertently listed the ASME Code Section XI Examinations
 
Categories for the AMP B.3.24 to be Examination Categories B-N-1
 
and B-N-2 and that instead it should have credited Examination
 
Category B-N-3. 
 
The applicant stated these errors in the application would be corrected and that the
 
corrections would be reflected in a future LRA amendment. The staff confirmed that
 
the applicant amended the LRA in a letter dated March 20, 2008.
 
The applicant provided additional details on the ASME Code Section XI Examination
 
Categories that are used for aging management in a supplemental response in the
 
letter dated February 8, 2008. In this response, the applicant stated that Section 2 of
 
the VEGP LRA provides a listing of VEGP systems within the scope of license
 
renewal, and that the system within the scope of license renewal for meeting the
 
scoping criteria of 10 CFR 54.4(a)(1) include all systems and components that are 3-157 categorized as ASME Safety Class 1, 2, or 3, and that all of these systems and components fall under the scope of the VEGP ISI Program as implemented for
 
compliance with the requirements of 10 CFR 50.55a.
 
The staff also noted that the LR basis evaluation document stated that the program
 
updates the code of record to the latest one endorsed in 10 CFR 50.55a one year
 
prior to entering the next 120 month ISI interval for the facility and that the VEGP
 
units just entered their 3rd 10-year ISI intervals starting in May 31, 2007. The LR
 
basis evaluation document also stated that the code of record for the 3 rd 10-Year ISI Interval is the 2001 edition of Section XI inclusive of the 2003 addenda. The staff
 
concludes that this is the same as the recommended edition of the ASME Code Section XI referenced in GALL XI.M1 and is acceptable.
 
The staff finds this program element acceptable because the applicant has provided clarification that: (1) which ASME Code Class systems and ASME Code Section XI
 
Examinations Categories are within scope of the ISI Program for the purpose of
 
complying with the requirements of 10 CFR 50.55a, (2) which of the ASME Code
 
Class systems and ASME Code Section XI Examination Categories are implemented for compliance with 10 CFR 50.55a and which systems and ASME Code Section XI Examination Categories are within the scope of the applicant's ISI
 
Program, credited for aging management in accordance with the requirements of 10 CFR Part 54, and (3) which edition of the ASME Code Section XI is currently in
 
effect for VEGP Units 1 and 2. The staff's questions on the "scope of program"
 
program element are resolved. Based on this evaluation, the staff confirmed that the "scope of the program" program element satisfies the criterion defined in the SRP-
 
LR Section A.1.2.3.1. 
(2) Preventive Actions - LRA Section B.3.13 states that the condition-monitoring ISI Program does not include preventive actions.
SRP-LR Section A.1.2.3.2, "preventive actions" provides, in part, the following NRC
 
guideline recommendations for AMP "prev entative actions" program elements in plant-specific LRAs:
 
The activities for prevention and mitigation programs should be
 
described. These actions should mitigate or prevent aging degradation.
For condition or performance monitori ng programs, they do not rely on preventive actions and thus, this information need not be provided. More
 
than one type of aging management program may be implemented to
 
ensure that aging effects are managed.
The ISI Program is defined as a condition monitoring program for the VEGP LRA
 
and the program does not include specific criteria to mitigate or prevent aging
 
effects from occurring in ASME Code Class systems because required ISI inspection criteria, flaw evaluation acceptance criteria, and corrective action and repair/replacement criteria in the ASME Code Section XI do not include specific
 
criteria for mitigation or prevention of aging effects in ASME Code Class systems.
 
Based on this assessment, the staff agrees that the ISI Program does not need to
 
include preventive actions that corresponds to applicable "preventive actions"
 
program element defined in SRP-LR Section A.1.2.3.2 because the AMP is a 3-158 condition monitoring program and does not include activities to preclude or mitigate aging effects from occurring.
The staff confirmed that the ISI Program does not need to include a program
 
element that satisfies the "preventive ac tions" program element the criterion defined in the in SRP-LR Section A.1.2.3.2. The staff finds this program element acceptable.
 
(3) Parameters Monitored or Inspected - LRA Section B.3.13 states that the ISI Program detects degradation in components crediting the program by inspection techniques specified in ASME Code Section XI, Subsections IWB, IWC, IWD, and
 
IWF. SRP-LR Section A.1.2.3.3, "parameters monitored or inspected" provides the
 
following recommendation for "parameters monitored or inspected" program
 
elements for condition monitoring-based AMPs:
For a condition monitoring program, the parameter monitored or inspected should detect the presence and extent of aging effects. Some examples
 
are measurements of wall thickness and detection and sizing of cracks.
The staff reviewed the license renewal basis evaluation document, SNC-corporate and VEGP-specific implementation procedures and 10-Year ISI Plan for the VEGP
 
units as part of its review of the ISI Program to determine how the "parameters
 
monitored or inspected" program element for the ISI Program compared with the staff's recommendations in SRP-LR Section A.1.2.3.3. From its review of these
 
documents, the staff concludes that the "parameters monitored or inspected"
 
program element discussion in the LR basis evaluation document stated that the ISI Program is a condition monitoring program and that this AMP monitors for aging
 
effects that can be induced by age-related degradation mechanisms, including
 
those mechanical and chemical mechanisms that can induce cracking and loss of
 
material in ASME Code Class components, and loss of preload in ASME Code
 
Class mechanical connections (i.e., bolted connection assemblies or mechanical
 
assemblies using keys or other fasteners). The staff concludes that aging effects
 
are consistent with those identified in the "parameters monitored" program element in GALL AMP XI.M1, "ASME Code Section XI, Subsections IWB, IWC, IWD, and
 
IWF." 
 
This is acceptable because it conforms to the aging effects that GALL AMP XI.M1
 
recommends for monitoring.
 
The staff also noted that the program manages loss (reduction) of fracture
 
toughness in those ASME Code Class pump casings and valve bodies that are
 
made from cast austenitic stainless steel (CASS) and operate at temperatures
 
greater than or equal to 482
&#xfb;F. The applicant's program element discussion stated that, for these components, the visual examinations proposed under the ASME Code Section XI are adequate for these flaw-tolerant components. The staff concludes that this is consistent with both the guidance in GALL AMP XI.M1, "ASME Code Section XI, Subsections IWB, IWC, IWD, and IWF," and in the NRC's
 
guidelines on thermal aging of CASS components, which are described in the
 
Christopher Grimes letter dated May 19, 2000, "License Renewal Issue 98-0030,
'Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Components'".
3-159  This is acceptable because it conforms to the NRC's recommended guidelines for
 
managing loss of material due to thermal aging in CASS pump casings and valve
 
bodies. Based on this evaluation, the staff concludes that the "parameters monitored or
 
inspected" program element is acceptable because the aging effects that the program monitors for are consistent with either those identified in AMP XI.M1 of the
 
GALL Report or in NRC-issued LR guidance documents (i.e. in the Chris Grimes
 
letter of May 19, 2000).
The staff confirmed that the "parameters m onitored or inspected" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff finds this
 
program element acceptable.
(4) Detection of Aging Effects - LRA Section B.3.13 states that the ISI Program uses nondestructive examination techniques as specified in ASME Code Section XI, Subsections IWB, IWC, IWD, and IWF, to detect and characterize component flaws.
 
Volumetric (e.g., radiographic, ultrasonic, or eddy current) examinations detect and characterize surface and subsurface flaws. Examinations comply with the performance demonstration initiative based on ASME Code Section XI Appendix
 
VIII, 2001 Edition, as mandated by 10 CFR 50.55a. Surface examinations (e.g., magnetic particle or dye penetrant testing) detect surface flaws. There are three
 
specified levels of visual examination. VT-1 visual examination detects cracks and
 
symptoms of wear, corrosion, erosion, or physical damage on the surface of the
 
component; VT-1 can use either direct visual or remote examination by various
 
optical and video devices. VT-2 visual examination locates evidence of leakage
 
from pressure-retaining components. VT-3 visual examination determines general
 
mechanical and structural condition of components and supports and detects
 
discontinuities and imperfections. 
 
SRP-LR Section A.1.2.3.4, "detection of aging effects" provides the following
 
recommendation for "detection of aging effects" program elements for condition
 
monitoring-based AMPs:
Detection of aging effects should occur before there is a loss of the structure and component intended function(s). The parameters to be
 
monitored or inspected should be appropriate to ensure that the structure
 
and component intended function(s) will be adequately maintained for
 
license renewal under all CLB design conditions. This includes aspects
 
such as method or technique (e.g., visual, volumetric, surface inspection),
frequency, sample size, data collection and timing of new/one-time inspections to ensure timely detection of aging effects. Provide information
 
that links the parameters to be monitored or inspected to the aging effects
 
being managed.
 
The staff reviewed the license renewal basis evaluation document, SNC-corporate
 
and VEGP-specific implementation procedures and 10-Year ISI Plan for the VEGP
 
units as part of its review of the ISI Program to determine how the "detection of
 
aging effects" program element for the ISI Program compared with the staff's
 
recommendations in SRP-LR Section A.1.2.3.4.
3-160  From its review of these documents, the staff concludes that the "detection of aging
 
effects" program element discussion in the LR basis evaluation document stated that the ISI Program implements the non-des tructive examination (NDE) techniques of the ASME Code Section XI and that these techniques include volumetric
 
examination methods, including ultrasonic testing (UT), radiography testing (RT) or
 
eddy current testing (ET), and surface examination methods, including magnetic
 
particle testing (MT), dye-penetrant testing (PT) and eddy current testing (ET). The
 
staff noted that the LR basis evaluation document stated that UT, RT, and ET
 
volumetric examination techniques mentioned in the previous sentence are capable
 
of detecting and characterizing both surface-breaking flaws and subsurface flaws, and that the PT and MT surface examination techniques are capable of detecting
 
surface flaws. The staff also noted that the applicant's "detection of aging effects"
 
program element includes a sufficient clarification on the aging effects that the UT, RT, ET, PT, and MT non-visual examination techniques are capable of detecting.
 
This provides the relevant information lin king the parameters being monitored for to the aging effects being managed, as recommended in SRP-LR Section A.1.2.3.4. 
 
The staff also determined, from its review of the LR basis evaluation document, it
 
stated that the ISI Program includes visual examination techniques as follows:
 
(1) VT-1 visual examination methods are capable of detecting discontinuities and
 
imperfections in the surfaces of the components, including evidence of cracks, corrosion, erosion, or wear, (2) VT-2 visual examination methods are conducted
 
during system pressure tests or system leakage tests, with or without the use of
 
leakage collection systems, to detect ev idence of leakage from ASME Code Class pressure retaining components, and (3) VT-3 visual examination methods are
 
conducted to determine the general mechanical or structural condition of
 
components and their supports, to verify design parameters such as clearances, settings, to monitor for physical displa cements of ASME Code Class components, and to detect discontinuities and imperfections, such as loss of integrity at bolted
 
connections, loose or missing parts, debris, corrosion, erosion, or wear. 
 
The staff noted that the visual VT-1, VT-2, and VT-3 NDE methods referenced in the
 
LRA and the LR basis evaluation document are equivalent to those referenced in
 
Article IWA-2000 of the ASME Code Section and are consistent with those recommended in "detection of aging effects" program element of GALL AMP XI.M1, ASME Code Section XI, Subsections IWB, IWC, IWD, and IWF," and that the
 
applicant's "detection of aging effects" program element includes a sufficient
 
clarification on those aging effects that the specific visual VT-1, VT-2, and VT-3
 
examination techniques are capable of detecting. This provides the relevant information linking the parameters being monitored for to the aging effects being
 
managed, as recommended in SRP-LR Section A.1.2.3.4.
 
The basis document states that the inspection techniques are prescribed by the ASME Code Section XI or are as specified in 50.55a and that the inspection
 
techniques have been developed in accordance with industry consensus process.
The staff has evaluated the ability of the ASME Code Section XI inspection
 
techniques to detect relevant aging in the evaluation of the "detection of aging
 
effects" program element for this AMP. The basis document clarifies that in some
 
cases the techniques are qualified in accordance with the performance
 
demonstration initiative (PDI) project. The NRC's PDI requirements in 10 CFR 3-161 50.55a are mandated to ensure that ultrasonic testing techniques are appropriately qualified to be capable of monitoring for, detecting and sizing relevant flaw
 
indications. 
 
The staff concludes that using the PDI is acceptable to qualify the UT examination
 
techniques for their ability to monitor for, detect, and size relevant surface-breaking
 
and subsurface flaw indications because the applicant's PDI qualifications are
 
performed in accordance with the applicable PDI requirements of 10 CFR 50.55a, which the NRC has established as acceptable qualification requirements for
 
volumetric examination technique monitoring, detection and sizing capabilities.
 
Based on this review, the staff concludes that the both the non-visual and visual
 
examination techniques for the ISI Program are acceptable because they are
 
consistent with the non-visual and visual examinations techniques recommended for implementation in GALL AMP XI.M1, ASME Code Section XI, Subsections IWB, IWC, IWD, and IWF," and because the applicant has clarified how the volumetric
 
inspection techniques for the ISI Program are qualified for use in accordance with
 
the applicant's PDI process and the PDI initiative requirements in 10 CFR 50.55a.
 
The staff also determined that the applicant's discussion of both the non-visual and
 
visual examination techniques in the "detection of aging effects" program element
 
for the ISI Program conforms to recommended criteria in the SRP-LR Section
 
A.1.2.3.4, because it provides the relevant information linking the examination
 
techniques used for monitoring to the parameters and aging effects being monitored
 
for by these techniques.
 
Based on this evaluation, the staff confirmed that the "detection of aging effects"
 
program element satisfies the criterion defined in SRP-LR Section A.1.2.3.4. The
 
staff finds this program element acceptable.
(5) Monitoring and Trending - LRA Section B.3.13 states that ISI Program inspection frequencies for each inspection interval are consistent with ASME Code Section XI
 
as specified in 10 CFR 50.55a(g)(4)(ii). The program, based on ASME Code ISI
 
Program B (IWA-2432), compares results to baseline data and other previous test results and evaluates indications in accordance with ASME Code Section XI. If the
 
component qualifies by analytical evaluation as acceptable for continued service, subsequent inspections reexamine the area of the indication. Indications that
 
exceed acceptance standards are extended to additional examinations in accordance with ASME Code Section XI. Owner activity reports record ISI Program
 
results for the staff after each refueling outage.
 
SRP-LR Section A.1.2.3.5, "monitoring and trending" provides the following
 
recommendation for the "monitoring and trending" program elements for
 
preventative/mitigative-based, condition monitoring-based, and performance-
 
monitoring-based AMPs:
 
Monitoring and trending activities should be described, and they should
 
provide predictability of the extent of degradation and thus effect timely
 
corrective or mitigative actions. 
 
3-162 Plant specific and/or industry-wide operating experience may be considered in evaluating the appropriateness of the technique and
 
frequency.
 
This program element describes "how" the data collected are evaluated
 
and may also include trending for a forward look. This includes an
 
evaluation of the results against the acceptance criteria and a prediction
 
regarding the rate of degradation in order to confirm that timing of the next
 
scheduled inspection will occur before a loss of SC intended function.
 
Although aging indicators may be quantitative or qualitative, indicators
 
should be quantified, to the extent possible, to allow trending. The
 
parameter or indicator trended should be described. The methodology for
 
analyzing the inspection or test results against the acceptance criteria
 
should be described. Trending is a comparison of the current monitoring
 
results with previous monitoring results in order to make predictions for the
 
future.
The staff reviewed the license renewal basis evaluation document, SNC-corporate
 
and VEGP-specific implementation procedures and 10-Year ISI Plan for the VEGP
 
units as part of its review of the ISI Program to determine how the "monitoring and
 
trending" program element for the ISI Program compared with the staff's
 
recommendations in SRP-LR Section A.1.2.3.5. 
 
The staff noted, from its review of the LR basis evaluation document, that the
 
applicant establishes its inspection frequencies and sample sizes for the ASME Code Section XI inspections that are implemented under this program in
 
accordance with the frequency and sample size criteria of the inspection items that are defined in the applicable ASME Code Section XI Examination Categories. The
 
staff also noted that, in its response letter dated February 8, 2008 the applicant
 
stated and defined which ASME Code Examination Categories are credited for
 
aging management in the applicant's response to the staff's question on scoping of
 
systems and Examinations Categories for th is AMP. The staff provided its basis for accepting those ASME Code Section XI Examination Categories credited for aging
 
management in its evaluation of the "scope of program" program element for this AMP. Based on this evaluation, the staff concludes that the applicant has
 
established acceptable inspection frequencies and sample sizes for those ASME Code Section XI inspection items that are credited for aging management because
 
they are defined in the applicable ASME Code Section Examination Categories that
 
have been credited for aging management and approved in the staff's evaluation of
 
the "scope of program" program element for this AMP.
 
The LR basis evaluation document also indicated that the program calls for the
 
results of the examinations to be recorded and compared to baseline data and data
 
from other previous inspection results. The LR basis evaluation document also
 
indicated that, if the results indicate the presence of relevant flaw indications in an
 
ASME Code Class components and the flaw size is within the acceptable flaw size limit of the applicable ASME Code Section XI flaw acceptance standard, the
 
component is re-examined during subsequent refueling outages. The staff
 
concludes that this is acceptable because: (1) it is in compliance with applicable evaluation and trending requirements in the ASME Code Section XI Articles IWB-
 
3000, IWC-3000, and IWD-3000 for ASME Code Class 1, 2, and 3 components, 3-163 (2) the followup examinations during the subsequent refueling outages will provide for further assessment of the flaw indications to determine whether unacceptable
 
flaw growth is occurring in the impacted component, and because these trending activities are in conformance with the NRC's recommendation in GALL AMP XI.M1
 
that the inspection results for ASME Code Class components be evaluated and trended in accordance the applicable ASME Section XI requirements.
The staff also determined that the applicant's "monitoring and trending" program
 
element for the ISI Program conforms to recommended criteria in the SRP-LR
 
Section A.1.2.3.5, because it provides a sufficient clarification on how the
 
frequencies and sample sizes for the non-visual and visual examinations are
 
established and how the program collects and trends that data from these
 
examinations and evaluates them against applicable acceptance criteria for these examination methods, as established in the ASME Code Section XI.
Based on this evaluation, the staff confirmed that the "monitoring and trending"
 
program element satisfies the criterion defined in SRP-LR Section A.1.2.3.5. The
 
staff finds this program element acceptable.
(6) Acceptance Criteria - LRA Section B.3.13 states that a pre-service, or baseline, inspection of program components prior to startup assured both an absence of
 
defects greater than code-allowable and a basis for evaluation of subsequent ISI
 
results compared, as appropriate, to baseline data, other previous test results, and ASME Code Section XI acceptance standards. ISI program acceptance standards are defined in ASME Code Section XI Articles IWA-3000, IWB-3000, IWC-3000, IWD-3000, and IWF-3000.
SRP-LR Section A.1.2.3.6, "monitoring" provides the following recommendation for
 
the "acceptance criteria" program elem ents for preventative/mitigative-based, condition monitoring-based, and performance-monitoring-based AMPs:
 
The acceptance criteria of the program and its basis should be described.
 
The acceptance criteria, against which the need for corrective actions will
 
be evaluated, should ensure that the structure and component intended
 
function(s) are maintained under all CLB design conditions during the
 
period of extended operation. The program should include a methodology
 
for analyzing the results against applicable acceptance criteria, and insure
 
corrective action is taken, such as piping replacement, before reaching this
 
acceptance criterion. This acceptance criterion should provide for timely
 
corrective action before loss of intended function under these CLB design
 
loads.
 
Acceptance criteria could be specific numerical values, or could consist of
 
a discussion of the process for calculating specific numerical values of
 
conditional acceptance criteria to ensure that the structure and component
 
intended function(s) will be maintained under all CLB design conditions.
 
Information from available references may be cited. It is not necessary to
 
justify any acceptance criteria taken directly from the design basis
 
information that is included in the UFSAR because that is a part of the
 
CLB. Also, it is not necessary to discuss CLB design loads if the
 
acceptance criteria do not permit degradation because a structure and 3-164 component without degradation should continue to function as originally designed. Acceptance criteria, which do permit degradation, are based on
 
maintaining the intended function under all CLB design loads.
 
The staff reviewed the license renewal basis evaluation document, SNC-corporate
 
and VEGP-specific implementation procedures and 10-Year ISI Plan for the VEGP
 
units as part of its review of the ISI Program to determine how the "acceptance
 
criteria" program element for the ISI Program compared with the staff's
 
recommendations in SRP-LR Section A.1.2.3.6. 
 
Based on its review of license renewal basis evaluation document for the ISI
 
Program, the staff concludes that the applicant credits the applicable acceptance standards in the ASME Code Section XI, Articles IWA-3000, IWB-3000, IWC-3000, IWD-3000, or IWF-3000 as the applicable acceptance criteria for the ISI Program, and that the applicant performs additional evaluations in accordance with the
 
analytical procedures in IWB-3600, IWC-3600, or IWD-3600, if the applicant
 
determines that recordable flaw indications are greater than the applicable ASME Code Section XI acceptance standard limits. 
 
The staff asked the applicant to clarify the ASME Code Section options that could be used for the evaluation of flaws that are in excess of the ASME Code Section XI
 
acceptance standards. The applicant provided its response to the staff's question in
 
a letter dated February 8, 2008. In its response, the applicant stated that the
 
corrective actions taken in response to indications identified during ISI Program
 
inspections are consistent with the requirements of 10 CFR 50.55a and ASME Section XI Articles IWA-3000, IWB-3000, IWC-3000, IWD-3000, and IWF-3000 and
 
may include acceptance by supplemental exam ination, by analytical evaluation, or by repair / replacement. The applicant also stated that any unacceptable flaw
 
indication or condition identified during ISI Program activities results in initiation of a
 
condition report and subsequent evaluation of the condition by the corrective actions
 
program. The applicant stated that the SNC Quality Assurance Program performs
 
periodic audits of the ISI Program to ensure that the corrective actions are consistent with 10 CFR 50.55a and ASME Section XI requirements. The staff finds
 
the applicant's response to this question to be acceptable because: (1) the applicant
 
has  stated that the applicant is using the appropriate flaw evaluation and corrective action criteria in the ASME Code Section XI to assess and, if necessary, correct
 
flaw indications or conditions that are detected as part of the applicant's ASME Code Section XI ISI Program, and (2) the applicant has stated that it applies its 10
 
CFR Part 50, Appendix B, Quality Assurance Program to ensure that its ISI is being
 
implemented in accordance with the requirements of 10 CFR 50.55a and the ASME Code Section XI. The staff's question on this matter is resolved. 
 
Based on this review, the staff finds the "acceptance criteria" program element to be
 
acceptable because the applicant has clarified that it uses the applicable acceptance criteria in the ASME Code Section XI as its basis for evaluating relevant
 
flaw indications in ASME Code Class components, and because the ASME Code Section XI establishes NRC required acceptance criteria (as required in accordance
 
with the requirements in 10 CFR 50.55a) for evaluating recordable flaw indications
 
that are detected as part of the non-destructive testing examinations that are
 
implemented in accordance with the AMP. 
 
3-165 The staff finds that the "acceptance criteria" program element for ISI Program conforms to the "acceptance criteria" program element recommended in SRP-LR
 
Section A.1.2.3.6 because the applicant has provided clarification to identify which
 
acceptance criteria in the CLB, as defined by the applicable acceptance criteria of the ASME Code Section XI, are used as the acceptance criteria for the ISI Program, and because the applicant has clarified those corrective action options that are
 
available for implementation if these acceptance criteria are exceeded.
(10) Operating Experience - LRA Section B.3.13 states that, because the ASME Code is a consensus document widely used over a long period, it has been generally
 
effective in managing aging effects in Classes 1, 2, and 3 components and their
 
attachments. The GALL Report includes some specific examples of industry
 
operating experience with component degradation. The ISI Program is in
 
accordance with general requirements for engineering programs. Periodic program
 
reviews ensure compliance with regulatory, process, and procedural requirements.
 
The applicant stated that review of recent ISI Program performance results show
 
that the program has found and corrected degradation attributable to aging effects
 
effectively. The ISI Program has detected leakage at mechanical connections and
 
surface corrosion, minor conditions either corrected or found acceptable for
 
continued service. Previously the program detected wall loss in the Unit 2 stainless steel chemical volume and control system letdown piping between the flow orifices
 
and their isolation valves and determined the pipe thinning mechanism to be
 
cavitation-induced erosion. Piping replacement and design modifications corrected
 
the problem. The ISI Program monitors these locations for this effect.
SRP-LR Section A.1.2.3.10, "operating experience" provides the following
 
recommendation for the "operating experience" program elements for
 
preventative/mitigative-based, condition monitoring-based, and performance-
 
monitoring-based AMPs:
 
Operating experience with existing programs should be discussed. The
 
operating experience of aging management programs, including past
 
corrective actions resulting in program enhancements or additional
 
programs, should be considered. A past failure would not necessarily
 
invalidate an aging management program because the feedback from
 
operating experience should have resulted in appropriate program
 
enhancements or new programs. This information can show where an
 
existing program has succeeded and where it has failed (if at all) in
 
intercepting aging degradation in a timely manner. This information should
 
provide objective evidence to support the conclusion that the effects of
 
aging will be managed adequately so that the structure and component
 
intended function(s) will be maintained during the period of extended
 
operation.
The staff reviewed the license renewal basis evaluation document and the operating
 
experience document for the ISI Program to determine how the "acceptance criteria"
 
program element for the ISI Program com pared with the staff's recommendations in SRP-LR Section A.1.2.3.10. The staff focused its review on operating experience
 
related to generic operational experience related to augmented inspections of U.S.
 
PWR upper reactor vessel closure head (RVCH) penetration nozzles and VEGP-
 
specific experience with the augmented inspections that have been performed on 3-166 the upper RVCH penetration nozzles for the VEGP units. The staff also focused on relevant VEGP-specific operating experience related to augmented inspections of
 
the VEGP chemical and volume control syst ems (CVCS). In this manner, the staff focused its review on those generic and plant-specific operational experience that
 
were determined to be risk-significant by the license and had resulted in the
 
applicant's augmentation of its ISI program.
 
The staff concludes that the applicant has performed and will continue to perform
 
augmented inservice inspections of the VEGP ASME Code Class 1 upper reactor
 
vessel closure head (RVCH) penetration nozzles in accordance with the NRC's first
 
revised order EA-03-009. The staff also determined that the augmented inspections
 
include ultrasonic testing (UT) and eddy current testing (ET) of the penetration
 
nozzles and their associated nickel alloy partial penetration J-groove welds, and
 
bare metal visual (BMV) examinations of the adjacent low alloy steel base metal in
 
the upper RVCH. The staff noted that recent augmented inspections of the upper
 
RVCH penetration nozzles at VEGP Unit 1 in refueling outage (1R13) did not
 
indicate any indication of cracking in the nickel alloy j-groove welds. The applicant
 
implements these augmented ISI examinati ons as part of its "Nickel Alloy management program for reactor vessel closure head penetrations." The staff has
 
evaluated the applicant's Nickel Alloy Management Program for Reactor Vessel
 
Closure Head Penetrations and its evaluation is further evaluated and documented
 
in Section 3.0.3.1.1 of this SER. Based on this assessment, the staff concludes that
 
the applicant's ISI program includes an assessment of relevant generic operating
 
experience events and a process and actions to augment its ISI Program based on
 
this experience.
From its review of the operating experience document for this AMP, the staff also
 
determined that the applicant currently implements augmented inspections of the
 
chemical and volume control system (CVCS) let down piping between the flow
 
orifices and their respective isolation valves in accordance in accordance with the
 
VEGP risk-informed ISI (RI-ISI) program. The applicant indicated that VEGP-
 
specific augmented UT examinations of this piping had indicated that wall thinning
 
had occurred in this CVCS piping. The applicant indicated that it had performed a
 
root cause analysis of thinning in this CVCS piping and that the root cause analysis
 
attributed the wall loss to thinning by cavitation. The applicant stated that the root
 
cause analysis eliminated flow-accelerated corrosion (FAC) as the relevant wall
 
thinning mechanism as the component piping is fabricated from stainless steel, which is not susceptible to FAC-induced erosion. 
 
As part of its review of the LRA, the staff noted that the applicant's Flow-Accelerated
 
Corrosion Program (LRA AMP B.3.10) is also credited to manage both loss of
 
material resulting from flow-accelerated corrosion and loss of material by cavitation. 
 
The staff asked the applicant to clarify whether the augmented inspections of the
 
CVCS piping for loss of material by cavitation would be implemented as part of the
 
applicant's augmented UT inspection activities under is ISI Program or as part of the
 
applicant's UT inspection activities that are implemented under its Flow-Accelerated
 
Corrosion Program. 
 
The applicant provided its response to the staff's question in a letter dated February
 
8, 2008. In its response, the applicant stated that the augmented UT inspection 3-167 activities for the CVCS piping would be implemented as part of the applicant's augmented inspection activities for the ISI Program. The staff's finds the applicant's
 
response to be acceptable because the response clarifies that the augmented UT
 
inspections of the CVCS piping will be implemented as part of the applicant's
 
augmented inspection activities that are within the scope of the ISI Program. The
 
staff's question is resolved. Based on this assessment, the staff concludes that the
 
applicant's ISI program includes an assessment of relevant VEGP-specific
 
operating experience events and a process and actions to augment its ISI Program based on this experience.
 
Based on this evaluation, the staff confirmed that the "operating experience"
 
program element satisfies the criterion defined in the GALL Report and in SRP-LR
 
Section A.1.2.3.10 and that the program incorporates relevant generic and VEGP-
 
specific operating experience. Based on this review, the staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Section A.2.13, 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 descr iption 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 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 determined that it provides an
 
adequate summary description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.3.5  Nickel Alloy Management Program for Non-Reactor Vessel Closure Head
 
Penetration Locations
 
Summary of Technical Information in the Application
: LRA Section B.3.14 describes the Nickel Alloy Management Program for Non-Reactor Vessel Closure Head Penetration
 
Locations as a plant-specific program. 
 
The applicant stated that the plant-specific Nickel Alloy Management Program for Non-
 
Reactor Vessel Closure Head Penetration Locations manage cracking due to primary water
 
stress corrosion cracking (PWSCC) for non-reactor vessel head nickel alloy component
 
locations. The overall goal of the program is to maintain plant safety and minimize the
 
impact of PWSCC on plant availability through assessment, inspection, mitigation, and
 
repair or replacement of susceptible co mponents. Program development is based on MRP-126, "Generic Guidance for Alloy 600 Management."  MRP-126 is not intended to address
 
Alloy 600 in steam generator tubing; the industry has a separate program for this issue, EPRI's Steam Generator Management Program, which the applicant discusses in Appendix B.3.26 of the LRA.
 
The applicant also stated that the non-reactor vessel closure head penetration locations in
 
PWR reactor coolant systems, PWSCC of Alloy 600 base material and Alloy 82 / 182 weld
 
materials is a currently emerging materials degradation issue. The VEGP Nickel Alloy
 
Management Program for Non-Reactor Vessel Closure Head Penetration Locations is
 
being developed to address concerns regarding the potential for PWSCC in nickel alloy 3-168 components exposed to a high temperature reac tor coolant environment. While elements of this program exist, implementation details are still under development by the industry.
Consequently, this program has been categoriz ed as a new program for license renewal.
 
The applicant further stated that the program is based on the following set of
 
implementation commitments:
: 1) SNC will continue to participate in industry initiatives directed at resolving PWSCC issues, such as owners group programs and the EPRI Materials
 
Reliability Program. 2) SNC will comply with applicable NRC Orders. 3) SNC will submit a program inspection plan for VEGP that includes implementation of applicable NRC Bulletins, Generic Letters, and staff
 
accepted industry guidance. The inspection plan will be submitted to the
 
staff for review and approval not less than 24 months prior to entering the
 
period of extended operation for VEGP Units 1 and 2. The program
 
implementation commitments are consistent with the aging management
 
program commitments listed in NUREG-1801, Rev. 1, Vol. 2, Section IV for
 
managing PWSCC for non-reactor vessel head nickel alloy components.
Staff Evaluation In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.3.14 on the applicant's demonstration of the Nickel Alloy Management
 
Program for Non-Reactor Vessel Closure Head Penetration Locations 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 Generic Aging Lessons Learned (GALL) report, NUREG-1801, Vol. 2, Rev. 1, contains
 
the staff's generic evaluation of the existi ng 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 repor t indicate that many of the existing programs are adequate to manage the aging effects for particular structures or components
 
for license renewal without change. The GALL report also contains recommendations on
 
specific areas for which existing programs should be augmented for license renewal.
 
Guidance for the aging management of nickel-alloy material components is provided in the
 
aging management review line items of Chapter IV, "Reactor Vessel, Internals, and Reactor
 
Coolant System," in the GALL report. The items applicable to nickel-alloy material
 
components in Westinghouse reactors are found within sections A2, "Reactor Vessel (Pressurized Water Reactor)," B2 "Reactor Vessel Internals (PWR) - Westinghouse," C2, "Reactor Coolant System and Connected Lines (Pressurized Water Reactor)", and D1, "Steam Generator (Recirculating)."
 
The aging management programs specified in the GALL report for nickel-alloy non-reactor
 
vessel closure head penetration locations consist of the following:
: 1) Chapter XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," for Class 1 components 3-169 2) Chapter XI.M2, "Water Chemistry," for PWR primary water 3) Fatigue is a time-limited aging analysis (TLAA) to be performed for the period of extended operation, and, for Class 1 components, environmental
 
effects on fatigue are to be addressed. See the Standard Review Plan, Section 4.3 "Metal Fatigue," for acceptable methods for meeting the
 
requirements of 10 CFR 54.21(c)(1). 4) Commit in the FSAR supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2)
 
evaluate and implement the results of the industry programs as applicable to
 
the reactor internals; and (3) upon completion of these programs, but not
 
less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and
 
approval. 5) Comply with applicable NRC Orders and provide a commitment in the FSAR supplement to implement applicable (1) Bulletins and Generic Letters and (2)
 
staff-accepted industry guidelines.
The ASME Section XI Inservice Inspection program is addressed in Appendix B.3.13 of the
 
LRA and Final Safety Analysis Report (FSAR) supplement Appendix A.2.13. The Water
 
Chemistry program is addressed in Appendix B.3.28 of the LRA and FSAR supplement
 
Appendix A.2.28. The fatigue TLAA is addressed in section 4.3, "Metal Fatigue," of the LRA
 
and FSAR supplement Appendix A.3.2. FSAR supplement A.2.14, "Nickel Alloy
 
Management Program for Non-Reactor Vessel Closure Head Penetration Locations"
 
contains commitments that 1) SNC will continue to participate in industry initiatives directed
 
at resolving PWSCC issues, such as owners group programs and the EPRI Materials
 
Reliability Program, 2) SNC will comply with applicable NRC Orders, and 3) SNC will
 
submit a program inspection plan for VEGP that includes implementation of applicable NRC
 
Bulletins, Generic Letters, and staff accepted industry guidance. The inspection plan will be
 
submitted to the staff for review and approval not less than 24 months prior to entering the
 
period of extended operation for VEGP Units 1 and 2. In addition, FSAR supplement
 
Appendix A.2.24, "Reactor Vessel Internals Program," contains a commitment to submit an
 
inspection plan for the VEGP reactor vessel internals to the NRC for review and approval
 
not less than 24 months before entering the period of extended operation for VEGP Units 1
 
and 2.
 
The applicant indicates that currently, management of PWSCC in nickel alloys is a rapidly
 
evolving area and as a result, program attributes have not yet been finalized. Further, where industry guidance has been developed, there are ongoing efforts to reach
 
acceptable resolution of NRC staff concerns which may alter program requirements.
 
Therefore, the applicant has not included assessments for each of the ten aging
 
management program elements for this program. The applicant has committed (Commitment No. 12) to revise the program to insure compliance with NRC regulations and
 
submit an inspection plan prior to the period of extended operation. 
 
The staff reviewed the Nickel Alloy Management Program for Non-Reactor Vessel Closure
 
Head Penetration Locations against the AMP elements found in the GALL Report based on
 
the applicant's submittal. However, on submittal to the NRC of the licensee's inspection
 
plan, a further review of the following sections in SRP-LR Section A.1.2.3, and in SRP-LR 3-170 Table A.1-1, should be performed:
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  Operating experience (1) Scope of the Program - LRA Section B.3.14 states that the Nickel Alloy Management Program for Non-Reactor Vessel Closure Head Penetration Locations
 
will manage cracking due to PWSCC for the following nickel alloy component
 
locations:
Butt welds within the primary system including: -  Reactor Vessel Inlet and Outlet Nozzle Dissimilar Metal Welds
-  Pressurizer Surge, Spray, Safety, and Relief Nozzle Dissimilar Metal Welds  Reactor Vessel Bottom Mounted Instrument Nozzles  Reactor Vessel Flange Leakage Monitor Tube  Steam Generator Primary Channel Head Drain Connection Tube &
Dissimilar Metal Welds The staff noted that nickel alloy materials are managed under several other
 
programs such as the Reactor Vessel Internals Program, the Nickel Alloy
 
Management Program for Reactor Vessel Closure Head Penetrations, the Steam
 
Generator Tube Inspection Program, and the Steam Generator Program for Upper Internals. Components addressed in these programs are, appropriately, not
 
included in the program scope of the Nickel Alloy Management Program for Non-
 
Reactor Vessel Closure Head Penetration Locations.
The staff confirmed that the "scope of t he program" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1. The staff
 
finds this program element acceptable.
(2) Preventive Actions - A description of this program element was not included in LRA Section B.3.14. However, the applicant noted use of the ASME Code Section XI
 
inspection requirements for ISI and committed to submit a program inspection plan
 
for VEGP that includes implementation of applicable NRC Bulletins, Generic Letters, and staff accepted industry guidance.
3-171  The staff finds that the preventive actions usable under the Nickel Alloy Inspection
 
Program are inspection and mitigation. Inspection uses nondestructive and visual
 
examination methods to monitor the aging of the nickel alloy components as
 
required by the ISI program and as augmented by the recommendations of
 
applicable bulletins, generic letters and NRC approved industry guidance. In this
 
manner, it is a condition or performance monitoring program and in accordance with
 
SRP LR Section A.1.2.3.2 no additional review is required. Some mitigation
 
techniques are currently available for use to address nickel alloy components, however numerous more options are being explored to address the mitigation of
 
active degradation mechanisms for these components as noted in Commitment
 
No. 12.
The staff notes the applicant committed to submit a program inspection plan for VEGP that
 
includes implementation of applicable NRC Bulletins, Generic Letters, and staff accepted
 
industry guidance. Also, in a letter dated June 27, 2007, the applicant provided
 
Commitment No.12 to implement the Program prior to the period of extended operation.
 
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).
 
These programs will address the available authorized mitigation techniques and
 
their application. The inspection plan will be submitted to the staff for review and
 
approval not less than 24 months prior to entering the period of extended operation
 
for VEGP Units 1 and 2. The staff will review the inspection plan under the
 
"preventive actions" program element criterion as defined in the GALL Report and in
 
SRP-LR Section A.1.2.3.2.
 
Based on this review and the applicant's commitments, the staff confirms that the
 
"preventive actions" program element satisf ies the recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.2. The staff finds this program element
 
acceptable.
 
(3) Parameters Monitored or Inspected - LRA Section B.3.14 the Nickel Alloy Inspection Program detects degradation by using the examination and inspection requirements of ASME Section XI, augmented as appropriate by examinations in response to NRC Orders, Bulletins and Generic Letters, or to accepted industry
 
guidelines. The parameters monitored are the presence and extent of cracking."
 
For condition monitoring programs, SRP-LR Section A.1.2.3.3 states:
 
The parameters to be monitored or inspected should be identified and linked to the
 
degradation of the particular structure and component intended function(s)," and
 
"[f]or a condition monitoring program, the parameter monitored or inspected should
 
detect the presence and extent of aging effects. Some examples are
 
measurements of wall thickness and detection and sizing of cracks.
 
The staff notes that the Nickel Alloy Inspection Program uses the appropriate
 
volumetric, surface and visual NDE techniques for detection of degradation of the
 
components identified in the scope of the program as required by ASME Code and
 
recommended by the applicable bulletins, generic letters and industry guidance.
 
3-172 The applicant committed (Commitment No. 12) to submit a program inspection plan for VEGP that includes implementation of applicable NRC Bulletins, Generic Letters, and staff accepted industry guidance. The inspection plan will be submitted to the
 
staff for review and approval not less than 24 months prior to entering the period of
 
extended operation for VEGP Units 1 and 2. The staff will review the "parameters
 
monitored or inspected" program element criterion as defined in the GALL Report
 
and in SRP-LR Section A.1.2.3.3 during the review of the program inspection plan.
 
Based on this review and the applicant's commitments, the staff confirms that the
 
"parameters monitored or inspected" program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.3. The staff finds this program
 
element acceptable.
 
(4) Detection of Aging Effects - A description of this program element was not included in LRA Section B.3.14. However, the applicant noted use of the ASME Code Section XI inspection requirements for ISI and committed to submit a program
 
inspection plan for VEGP that includes implementation of applicable NRC Bulletins, Generic Letters, and staff accepted industry guidance. 
 
The NRC has approved, in accordance with 10 CFR 50.55a, the specific techniques
 
and frequencies for monitoring nickel alloy components are prescribed by ASME Code Section XI for those components examined in accordance with the ISI
 
program. For other items included in the scope of the Nickel Alloy Inspection
 
program, the methods and frequencies of examination are recommended in the
 
applicable bulletins, generic letters and industry guidance. Each of these programs
 
for the detection of aging effects would have been written by or analyzed by the
 
NRC to provide adequate detection capability. The applicant has a commitment (Commitment No. 12) to submit an inspection plan detailing these programs to the
 
staff for review and approval not less than 24 months prior to entering the period of
 
extended operation for VEGP Units 1 and 2. The staff will review the "detection of
 
aging effects" program element criterion as defined in the GALL Report and in SRP-
 
LR Section A.1.2.3.4 during the review of the program inspection plan.
 
Based on this review and the applicant's commitments, the staff confirms that the
 
applicant's commitment in the "detection of aging effects" program element satisfies the
 
recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.4. The
 
staff finds this program element acceptable.
 
(5) Monitoring and Trending - A description of this program element was not included in LRA Section B.3.14. However, the applicant noted use of the ASME Code Section XI inspection requirements for ISI and committed to submit a program inspection
 
plan for VEGP that includes implementation of applicable NRC Bulletins, Generic
 
Letters, and staff accepted industry guidance. 
 
In general, the tools for monitoring and trending of nickel alloy component
 
inspection programs are based on the scope and reporting requirements
 
established by the ASME Code as required by 10 CFR 50.55a. The staff notes that ASME Section XI requires, "recording of examination and test results that provide a
 
basis for evaluation and facilitate comparison with the results of subsequent examinations."  ASME Section XI also requires, "retention of all inspection, examination, test, and repair /replacement activity records and flaw evaluation 3-173 calculations for the service lifetime of the component or system."  ASME Section XI additionally provides rules for "additional examinations" (i.e., sample expansion), when flaws or relevant conditions are found that exceed the applicable acceptance
 
criteria, to assist in determination of an extent of condition and causal analysis.
 
Specific monitoring or trending requirements may be created under NRC Bulletins, Generic Letters and staff accepted industry guidance. As these programs change
 
due to the evolving development of long term inspection requirements in this area, the review for monitoring and trending of these programs is based on the
 
commitment (Commitment No. 12) of the applicant to provide an inspection plan to
 
the staff for review and approval not less than 24 months prior to entering the period
 
of extended operation for VEGP Units 1 and 2. The staff will review the "monitoring
 
and trending" program element criterion as defined in the GALL Report and in SRP-
 
LR Section A.1.2.3.5 during the review of the program inspection plan.
 
Based on this review and the applicant's commitments, the staff confirms that the
 
"monitoring and trending" program element satisfies the recommendations in the GALL
 
Report and the guidance in SRP-LR Section A.1.2.3.5. The staff finds this program element
 
acceptable.
 
(6) Acceptance Criteria - A description of this program element was not included in LRA Section B.3.14. However, the applicant noted use of the ASME Code Section XI
 
inspection requirements for ISI and committed (Commitment No. 12) to submit a
 
program inspection plan for VEGP that includes implementation of applicable NRC
 
Bulletins, Generic Letters, and staff accepted industry guidance. The inspection plan
 
will be submitted to the staff for review and approval not less than 24 months prior
 
to entering the period of extended operation for VEGP Units 1 and 2.
 
In general, the acceptance criteria of nickel alloy component inspection programs
 
are based on the scope and reporting requirements established by the ASME Code as required by 10 CFR 50.55a. The staff notes that ASME Section XI, IWB-3000
 
contains acceptance criteria appropriate for the reactor coolant pressure boundary components examined in accordance with Section XI. Also, ASME Section XI, IWA-
 
5250 was verified to contain acceptable steps for evaluation and corrective
 
measures for sources of leakage identified by visual examinations for leakage.
 
These requirements ensure that nickel alloy components in the reactor coolant
 
pressure boundary maintain their designed function under all required design
 
conditions.
 
Specific acceptance criteria may be created under NRC Bulletins, Generic Letters
 
and staff accepted industry guidance. As these programs change due to the
 
evolving development of long term inspection requirements in this area, the
 
acceptance criteria review of these programs is based on the commitment (Commitment No. 12) of the applicant to provide an inspection plan to the staff for
 
review and approval not less than 24 months prior to entering the period of
 
extended operation for VEGP Units 1 and 2. 
 
The staff will review the "acceptance criteria" program element criterion as defined
 
in the GALL Report and in SRP-LR Section A.1.2.3.6 during the review of the
 
program inspection plan.
 
3-174 Based on this review and the applicant's commitments, the staff confirms that the "acceptance criteria" program element satisfies the recommendations in the GALL Report
 
and the guidance in SRP-LR Section A.1.2.3.6. The staff finds this program element
 
acceptable.
 
(7) Corrective Actions - A description of this program element was not included in LRA Section B.3.14. However, the applicant noted use of the ASME Code Section XI
 
inspection requirements for ISI and committed (Commitment No. 12) to submit a
 
program inspection plan for VEGP that includes implementation of applicable NRC
 
Bulletins, Generic Letters, and staff accepted industry guidance. The inspection plan
 
will be submitted to the staff for review and approval not less than 24 months prior
 
to entering the period of extended operation for VEGP Units 1 and 2.
 
The staff will review the "corrective actions" program element criterion as defined in
 
the GALL Report and in SRP-LR Section A.1.2.3.7 during the review of the program
 
inspection plan.
 
Based on this review and the applicant's commitments, the staff confirms that the
 
"corrective actions" program element satisfies the recommendations in the GALL Report
 
and the guidance in SRP-LR Section A.1.2.3.7. The staff finds this program element
 
acceptable.
 
(8) Confirmation Process - A description of this program element was not included in LRA Section B.3.14. However, the applicant committed (Commitment No. 12) to
 
submit a program inspection plan for VEGP that includes implementation of
 
applicable NRC Bulletins, Generic Letters, and staff accepted industry guidance.
 
The inspection plan will be submitted to the staff for review and approval not less
 
than 24 months prior to entering the period of extended operation for VEGP Units 1
 
and 2.
 
The staff will review the "confirmation process" program element criterion as defined
 
in the GALL Report and in SRP-LR Section A.1.2.3.8 during the review of the
 
program inspection plan.
 
Based on this review and the applicant's commitments, the staff confirms that the
 
"confirmation process" program element satisfies the recommendations in the GALL Report
 
and the guidance in SRP-LR Section A.1.2.3.8. The staff finds this program element
 
acceptable.
 
(9) Administrative Controls - A description of this program element was not included in LRA Section B.3.14. However, the applicant committed (Commitment No. 12) to
 
submit a program inspection plan for VEGP that includes implementation of
 
applicable NRC Bulletins, Generic Letters, and staff accepted industry guidance.
 
The inspection plan will be submitted to the staff for review and approval not less
 
than 24 months prior to entering the period of extended operation for VEGP Units 1
 
and 2.
 
The staff will review the "administrative controls" program element criterion as defined in the GALL Report and in SRP-LR Section A.1.2.3.9 during the review of
 
the program inspection plan.
 
3-175 (10) Operating Experience - LRA Section B.3.14 states that within the industry, Alloy 600/82/182 locations experiencing PWSCC include vessel head CRDM
 
penetrations, bottom mounted instrument penetrations, butt weld locations, steam
 
generator drain connections, and pressurizer penetrations. The most recent industry
 
experience relates to detection of indications in pressurizer nozzle butt welds at a
 
number of PWRs. At VEGP, PWSCC has not been detected at any Alloy
 
600/82/182 location to date. However, there is no reason to conclude that VEGP
 
Alloy 600/82/182 locations will not experience PWSCC based on similarities with
 
other units where PWSCC has been detected. Recent inspection history for VEGP
 
Units 1 and 2 is summarized below.
 
VEGP Pressurizer Butt Welds
 
For the VEGP Unit 1 pressurizer butt weld locations, only the spray nozzle Alloy 82 butt
 
weld has been volumetrically examined with a performance demonstration initiative
 
qualified ultrasonic inspection technique. This examination was performed during the
 
Spring 2005 refueling outage, with no recordable indications identified. Bare metal visual
 
examinations have been performed on all Unit 1 Alloy 82 butt welds during both the Spring
 
2005 and Fall 2006 refueling outages, with acceptable results. Mitigation of the Unit 1 Alloy
 
82 butt welds by application of full structural weld overlays using Alloy 52/152 materials was
 
performed during the Spring 2008 refueling outage. Due to geometric limitations on
 
inspection coverage and heightened concerns regarding the potential for PWSCC at
 
pressurizer nozzle butt weld locations, all VEGP Unit 2 pressurizer butt weld locations were
 
mitigated in the Spring 2007 refueling outage by application of full structural weld overlays
 
using Alloy 52/152 weld material. Due to the structural replacement of the original Alloy
 
82/182 welds, prior inspection results are no longer meaningful.
 
VEGP Reactor Vessel Nozzle Butt Welds
 
During the Fall 2006 refueling outage for Unit 1 and the Spring 2007 refueling outage for
 
Unit 2, all eight reactor vessel nozzle butt welds were volumetrically examined using a
 
performance demonstration initiative qualified ultrasonic inspection technique, with no
 
recordable indications identified. Additionally, bare metal visual examination did not identify
 
any indication of leakage.
 
Reactor Vessel Bottom Mounted Instrumentation Penetrations
 
Bare metal visual examination of the bottom head area was performed for Unit 1 during the
 
Fall 2006 refueling outage and for Unit 2 during the Spring 2007 refueling outage with no
 
indications of leakage identified. As a supplemental measure VEGP conducted volumetric
 
examinations of Unit 1 and Unit 2 bottom mounted instrument penetrations during the Fall
 
2006 Unit 1 refueling outage and the Spring 2007 Unit 2 refueling outage. The inspection
 
used ultrasonic and eddy current methods capable of detecting cracking of base material.
 
Fifty-seven of fifty-eight Unit 1 penetrations were successfully examined and forty-six of fifty-eight Unit 2 penetrations were successfully examined. There were no recordable
 
indications identified for any bottom mounted instrument penetration.
 
Steam Generator Primary Channel Head Drain Connection Tube & Dissimilar Metal Weld
 
For the steam generator primary channel head drains, a select number of plants having a
 
design similar to that used in the VEGP M odel F steam generators have experienced leaks 3-176 due to PWSCC. The leaks were detected through visual identification of boric acid crystals around the drain line coupling. Detailed analysis indicated that the cracks initiated at the
 
backside of the partial penetration weld, which is exposed to reactor coolant. To date, bare
 
metal visual and VT-2 examination of the VEGP drain locations has not identified any
 
cracking. Bare metal visual examination and VT-2 examination will be performed at each refueling outage until the location is mitigated.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
 
UFSAR Supplement In LRA Sections A.2.14, the applicant provided the UFSAR supplement for the Nickel Alloy Management Program for Non-Reactor Vessel Closure
 
Head Penetration Locations. The staff reviewed this section and finds the UFSAR
 
supplement information an adequate summary descr iption of the program, as required by 10 CFR 54.21(d).
 
Conclusion The staff has reviewed LRA Appendix section B.3.14, which describes the Nickel Alloy Management Program for Non-Reactor Vessel Closure Head Penetration
 
Locations as a plant-specific program and finds that the program in conjunction with the
 
commitments made by the applicant meet the guidance as established in the GALL report, NUREG-1801, Vol. 2, Rev. 1, for structures and/or components made of nickel alloy
 
material.
 
On the basis of its technical review of the applicant's Nickel Alloy Management Program for
 
Non-Reactor Vessel Closure Head Penetration Locations and applicant's Commitment No.
 
12, the staff concludes that the applicant has demonstrated that effects of aging will be
 
adequately managed so that the intended function(s) will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and determined that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.3.6  Periodic Surveillance and Preventive Maintenance Activities 
 
Summary of Technical Information in the Application LRA Section B.3.21 describes the existing Periodic Surveillance and Preventive Ma intenance Activities as a plant-specific program. 
 
The applicant stated that the Periodic Surveillance and Preventive Maintenance Activities
 
includes existing and new periodic inspections and tests relied on for license renewal to
 
manage aging effects for the components included in the program. Implementation of the Periodic Surveillance and Preventive Maintenance Activities is generally through repetitive tasks and surveillances. The program activities credited for license renewal are described
 
under the heading "Detection of Aging Effects." Enhancements to the Periodic Surveillance
 
and Preventive Maintenance Activities 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.3.21 on the applicant's demonstration of the Periodic Surveillance and
 
Preventive Maintenance Activities to ensure that the effects of aging, as discussed above, 3-177 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 Activities against
 
the staff's recommended program element cr iteria that are provided in SRP-LR Section A.1.2.3, and in SRP-LR Table A.1-1. The staff focused its review on assessing how
 
the plant-specific program elements for the Periodic Surveillance and Preventive Maintenance Activities would ensure adequate aging management when compared to the
 
recommended program element criteria that are described in SRP-LR Section A.1.2.3.
 
Specifically, the staff reviewed the following seven (7) program elements of the applicant's
 
program against their corresponding program elem ent criteria that are provided in the subsections to SRP-LR Section A.1.2.3: (1)"scope of the program," (2) "preventive actions,"
 
(3) "parameters monitored or inspected," (4) "detection of aging effects," (5) "monitoring and
 
trending," (6) "acceptance criteria," and (10) "operating experience."
 
The applicant indicated that program elements (7) "corrective actions,"(8) "confirmation
 
process," and (9) "administrative controls" are parts of the site-controlled QA program. The
 
staff evaluated the Inservice Inspection Program's "confirmatory process" and
 
"administrative controls" program elements as part of the staff's evaluation of the applicant's Quality Assurance Program. The staff's evaluation of the applicant's Quality
 
Assurance Program is described in SER Section 3.0.4. The staff's evaluation of the
 
remaining program elements are described in the paragraphs that follow:
 
(1) Scope of the Program - The "scope of the program" program element criterion in SRP-LR Section A.1.2.3.1 requires that the program scope include the specific
 
structures and components addressed with this program. The applicant states in LRA Section B.3.21 that the Periodic Surveillance and Preventive Maintenance Activities for license renewal are credited with managing
 
the aging effects described in the AMRs. These activities are described under the
 
heading "Detection of Aging Effects."
 
During the audit and review, the staff reviewed the applicant's program basis
 
document for this program and noted that it contains a list of specific components
 
within the scope of this program. The list identifies that those preventive
 
maintenance (PM) and surveillance testing activities credited with managing aging
 
effects apply to:  Control Building Control Room Filter Unit seals  Emergency Diesel Generator Diesel Fuel Oil Storage Tanks (interior surfaces)  Steam Generator Blowdown Trim Heat Exchangers' shells (interior Surfaces)  Secondary Steam Generator Blowdown Sample Baths' shells (interior surfaces)  Steam Generator Blowdown Corrosion Product Monitor coolers' shells and heads (interior surfaces) 3-178  Nuclear Service Cooling Water Cooling Tower Fill and Drift Eliminators  Potable Water System water heater housings (A2417S4001E01 and E02 only)  Boric Acid Storage Tank (BAST) diaphragms  Condensate Storage Tank (CST) diaphragms  Reactor Make-up Water Storage Tank (RMWST) diaphragms The staff also noted that the Periodic Surveillance and Preventive Maintenance
 
Activities will be enhanced by the addition of PM activities to manage the secondary
 
steam generator blowdown sample baths' shells, steam generator blowdown
 
corrosion product monitor cooler's shells and heads, and the within scope potable
 
water system water heater housings. The staff reviewed the surveillance and PM
 
activities that will be performed and found that it contains acceptance criteria which
 
will be used to determine if the component's condition is acceptable. Further, the
 
staff noted that the surveillance and PM activities and enhancements will include
 
periodic visual inspections of interior surfaces and that these inspections are
 
performed as part of routine surveillances tests or maintenance. The staff finds the
 
use of the Periodic Surveillance and Preventive Maintenance Activities acceptable
 
since it includes activities to manage the aging effects being addressed.
 
The staff concludes that the specific components for which the program manages
 
aging effects are identified, which satisfies the criterion defined in SRP-LR 
 
Section A.1.2.3.1. On this basis, the staff finds the applicant's scope of the program
 
acceptable.
(2) Preventive Actions - The "preventive acti ons" program element criterion in SRP-LR Section A.1.2.3.2 is that condition moni toring programs do not rely on preventive actions, and thus, preventive actions need not be provided.
The applicant states in LRA Section B.3.21 that the Periodic Surveillance and Preventive Maintenance Activities is a condition monitoring program.
 
The inspections and testing activities detect but do not prevent aging effects;
 
however, the activities prevent component failures that might be caused by
 
aging effects.
During the audit and review, the staff reviewed the applicant's program basis
 
document for this program which identifies it as a condition monitoring program and
 
that its inspection and testing activities used to identify component aging effects do
 
not prevent aging effects. The program document also stated that the periodic
 
surveillance and PM activities perform condition monitoring and is therefore
 
consistent with the SRP-LR. The staff concludes that these activities will provide for
 
the timely detection of aging degradation and are acceptable.
 
The staff confirmed that the "preventive actions" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.2. The staff finds this program element
 
acceptable.
3-179  (3) Parameters Monitored or Inspected - The "parameters monitored or inspected" program element criterion in SRP-LR Section A.1.2.3.3 are:
The parameters to be monitored or inspected should be
 
identified and linked to the degradation of the particular
 
structure and component intended function(s). The
 
parameters monitored or inspected should detect the
 
presence and extent of aging effects.
The applicant states in LRA Section B.3.21 that for each inspection or test activity instructions on the parameters monitored or inspected permit early detection of
 
degradation prior to loss of component intended function. Parameters monitored or
 
inspected vary with the component(s) and aging effects managed. Inspection and
 
testing activities monitor various parameters (e.g., surface condition, loss of
 
material, presence of corrosion products or fluid leakage, signs of cracking, or
 
reduction of wall thickness).
During the audit and review, the staff reviewed the applicant's program basis
 
document for this program which identifi ed the types of parameters monitored in order to permit early detection of degradation prior to loss of component intended
 
function. Specifically, the parameters monitored or inspected, which are based on
 
the components(s) and the aging effect(s) being managed, include surface
 
condition, loss of material, presence of corrosion products or fluid leakage, signs of
 
cracking, or reduction of wall thickness. The staff finds that the parameters
 
monitored will provide effective indications of aging degradation for the aging effects
 
being addressed and are acceptable. 
 
This program element satisfies the criteria defined in SRP-LR Section A.1.2.3.3.
 
The staff finds it acceptable on the basis that the applicant specifically identifies
 
each component within the scope of the program, provides a description of the 
 
aging management activity along with the aging effect(s) being managed, and the
 
related plant implementing procedure.
The staff confirmed that the "parameters m onitored or inspected" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff finds this
 
program element acceptable.
(4) Detection of Aging Effects - The "detection of aging effects" program element criteria in SRP-LR Section A.1.2.3.4 are:
 
Detection of aging effects should occur before there is a loss of the
 
structure and component intended function(s). The parameters to be
 
monitored or inspected should be appropriate to ensure that the structure
 
and component intended function(s) will be adequately maintained for
 
license renewal under all CLB design conditions. Provide information that
 
links the parameters to be monitored or inspected to the aging effects
 
being managed. Describe "when," "where," and "how" program data are
 
collected. 
 
3-180 The method or technique and frequency may be linked to plant-specific or industry-wide operating experience. Provide justification, including
 
codes and standards referenced, that the technique and frequency are
 
adequate to detect the aging effects before a loss of SC intended
 
function. A program based solely on detecting SC failures is not
 
considered an effective aging management program.
 
When sampling is used to inspect a group of SCs, provide the basis for
 
the inspection population and sample size. The inspection population
 
should be based on such aspects of the SCs as a similarity of materials
 
of construction, fabrication, procurement, design, installation, operating
 
environment, or aging effects. The sample size should be based on such
 
aspects of the SCs as the specific aging effect, location, existing
 
technical information, system and structure design, materials of
 
construction, service environment, or previous failure history. The
 
samples should be biased toward locations most susceptible to the
 
specific aging effect of concern in the period of extended operation.
 
Provisions should also be included on expanding the sample size when
 
degradation is detected in the initial sample.
 
The applicant states in LRA Section B.3.21 that the Periodic Surveillance and
 
Preventive Maintenance Activities periodically inspect and test components to
 
detect aging effects. Established inspection and testing intervals for timely detection
 
of degradation vary with the component, material, and environment, and consider
 
industry and plant-specific operating experience and manufacturer
 
recommendations. The extent and schedule of inspections and testing assure
 
detection of component degradation prior to loss of intended functions. The program
 
uses established techniques like visual inspections.
The applicant stated that a visual inspection of the control building control room filter
 
unit seals is part of the control room emergency filtration system filter testing
 
required by the VEGP Technical Specifications. Cleaning and inspection of the EDG
 
diesel fuel oil storage tanks are preventive maintenance tasks. Visual inspection of
 
the tanks detects degradation of the applied inorganic zinc coating or the underlying
 
base material. VEGP Technical Specifications require these cleaning and visual
 
inspection tasks every ten years. Note: The One-Time Inspection Program will
 
measure wall thickness of the EDG diesel fuel oil storage tank bottoms. Visual
 
inspection of the SG blowdown trim heat exchanger is a preventive maintenance task. Inspection by visual or other nondestructive examination technique of the
 
secondary steam generator blowdown sample bath and the SG blowdown corrosion
 
product monitor cooler are new prevent ive maintenance tasks that manage loss of material from the interior of these heat exchanger shells. 
 
These heat exchangers are cooled by well or river water but not by NSCW;
 
therefore, they are not in the scope of the GL 89-13 Program. 
 
The applicant further stated that visual inspection of the NSCW cooling towers is a
 
preventive maintenance task that collects sample specimens of the tower fill and
 
drift eliminators. Failure load testing of the specimens evaluates deterioration of the
 
tower fill and drift eliminators. Visual inspection of the potable water system water
 
heater housings within the scope of license renewal is a new preventive 3-181 maintenance task that will manage loss of material by inspecting for evidence of leakage and loss of material on the housing. Visual inspections of the boric acid
 
storage tank, condensate storage tank, and reactor make-up water storage tank
 
diaphragms are preventive maintenance tasks that manage change in material
 
properties (including cracking) and loss of material on the internal elastomer
 
diaphragms in these tanks. 
 
During the audit and review, the staff reviewed the applicant's program basis
 
document for this program which identified the detection of aging effects activities.
 
These address each type of inspection appropriate to the components' intended
 
functions in order that they will be adequately maintained for the period of extended
 
operation. The staff noted that the applicant's program includes a list and
 
description of each component and the corresponding activities associated with this
 
AMP and their plant-specific task identifiers. 
 
In Enclosure 2 of letter dated, June 27, 2007 the applicant made a commitment (Commitment No. 18) to enhance the Periodic Surveillance and Preventive
 
Maintenance Activities by preparing the plant-specific task identifiers and
 
procedures, for the secondary steam generator blowdown sample baths' shells, steam generator blowdown corrosion product monitor coolers' shells and heads, and the potable water system water heater housings. The staff finds that the
 
activities for the detection of aging effects are identified and are acceptable.
 
The staff concludes that this program element satisfies the criteria defined in SRP-
 
LR Section A.1.2.3.4. The staff finds it acceptable on the basis that the applicant
 
specifically identifies each component within the scope of the program, provides a
 
description of the aging management activity along with the aging effect(s) being
 
managed, and the related plant implementing procedure. Further, the applicant
 
identifies the frequency that the periodic surveillance and preventive maintenance
 
activity will be performed.
 
The staff confirmed that the "detection of aging effects" program element satisfies the
 
criterion defined in SRP-LR Section A.1.2.3.4. The staff finds this program element
 
acceptable.
 
(5) Monitoring and Trending - The "monitoring and trending" program element criteria in SRP-LR Section A.1.2.3.5 are:
Monitoring and trending activities should be described, and they should
 
provide predictability of the extent of degradation and thus effect timely
 
corrective or mitigative actions. 
 
Plant-specific and/or industry-wide operating experience may be
 
considered in evaluating the appropriateness of the technique and
 
frequency.
 
This program element should describe "how" the data collected are
 
evaluated and may also include trending for a forward look. This includes
 
an evaluation of the results against the acceptance criteria and a
 
prediction regarding the rate of degradation in order to confirm that
 
timing of the next scheduled inspection will occur before a loss of SC 3-182 intended function. The parameter or indicator trended should be described. The methodology for analyzing the inspection or test results
 
against the acceptance criteria should be described.
 
The applicant states in LRA Section B.3.21 that preventive maintenance and surveillance testing activities monitor and trend age-related degradation. Inspection
 
and testing intervals for timely detection of component degradation vary with the
 
component, material, and environment and consider industry and plant-specific
 
operating experience and manufacturer recommendations. The frequency of
 
inspection or other activities is subject to change for plant-specific environments or
 
observed degradation. Such observations may dictate that an increased or
 
decreased task frequency would be appropriate for a particular activity. 
 
During the audit and review, the staff reviewed the applicant's program basis
 
document for this program which includes a list and description of each component
 
and their corresponding activities associated with this AMP, and their plant-specific
 
task identifiers. The staff noted that for each inspection or testing activity described, the results are compared to acceptance criteria appropriate for that component and
 
inspection or test, as provided in the identified procedures. Additionally, the staff
 
noted that for the NSCW cooling tower fill and drift eliminators, the failure load
 
values are plotted and trended to estimate the remaining life of these components.
 
Further, the staff noted that although for those inspection and testing activities which
 
are visual inspections that do not record quantitative data and therefore no
 
prediction is made for rate of degradation, failures to meet the acceptance criteria
 
are trended by the corrective action process. 
 
The staff finds that the monitoring and trending activities included will provide timely
 
detection of aging degradation for the aging effects being addressed and are
 
acceptable.
 
The staff concludes that this program element satisfies the criteria defined in the
 
SRP-LR Section A.1.2.3.5 on the basis that the program describes each inspection
 
or testing activity and that their acceptance criteria would identify age related
 
degradation in a timely manner.
 
The staff confirmed that the "monitoring and trending" program element satisfies the
 
criterion defined in SRP-LR Section A.1.2.3.5. The staff finds this program element
 
acceptable.
 
(6) Acceptance Criteria - The "acceptance criteria" program element criteria in SRP-LR Section A.1.2.3.6 are:
 
The acceptance criteria of the program and its basis should be described. The
 
acceptance criteria, against which the need for corrective actions will be evaluated, should ensure that the SC intended function(s) are maintained under all CLB design
 
conditions during the period of extended operation.
The applicant states in LRA Section B.3.21 that acceptance criteria for the Periodic Surveillance and Preventive Maintenance Activities will be defined in specific
 
inspection and testing procedures. The acceptance criteria confirm component
 
integrity by verifying the absence of aging effect(s) or by comparing parameters to 3-183 limits based on intended function(s) established by the plant design basis.
Acceptance criteria correlating directly to the AERMs will be based on codes, standards, specifications, vendor recommendations, industry guidance, engineering
 
judgment, and plant-specific operating experience. Unacceptable degradations will
 
have condition reports resolved under the corrective action process.
 
During the audit and review, the staff reviewed the applicant's program basis
 
document for this program which identified the acceptance criteria for each type of
 
inspection appropriate to the component's AERM. The staff noted that the
 
applicant's program includes a list and description of each component and their
 
corresponding activities associated with this AMP and their plant-specific task
 
identifiers. Further the documents state that acceptance criteria are provided within
 
each procedure associated with the plant-specific task.
 
In Enclosure 2 of letter dated, June 27, 2007 the applicant made a commitment (Commitment No. 18) to enhance the Periodic Surveillance and Preventive
 
Maintenance Activities by preparing the plant-specific task identifiers and
 
procedures which include their acceptance criteria, for the secondary steam
 
generator blowdown sample baths' shells, steam generator blowdown corrosion
 
product monitor coolers' shells and heads, and the potable water system water
 
heater housings. The staff finds the acceptance criteria appropriate for the aging
 
effects being addressed.
 
The staff concludes that this program element satisfies the criteria in SRP-LR
 
Section A.1.2.3.6. The staff finds this program element acceptable on the basis that
 
the acceptance criteria are provided within each procedure associated with the
 
plant-specific task. Further, all conditions not meeting the acceptance criteria are
 
reported and documented in the VEGP corrective action process.
The staff confirmed that the "acceptance criteria" program element satisfies the
 
criterion defined in SRP-LR Section A.1.2.3.6. The staff finds this program element
 
acceptable.
 
  (10) Operating Experience - The "operating experience" program element criterion in SRP-LR Section A.1.2.3.10 is:
The operating experience should provide objective evidence to support
 
the conclusion that the effects of aging will be managed adequately so
 
that the structure and component intended function(s) will be maintained
 
during the period of extended operation.
The applicant states in LRA Section B.3.21 that periodic visual inspections have
 
detected degradation of the filter unit door seals, indicating that the program to
 
monitor these seals is effective. As noted in the report of Diesel Fuel Oil Program
 
operating experience, recent 10-year cleaning and visual inspection of the EDG fuel
 
oil storage tanks detected no degradation of the inorganic zinc coating or tank base
 
metal. Periodic inspections of the SG blowdown trim heat exchangers for fouling, corrosion, and other adverse conditions have detected fouling of the heat
 
exchangers but not corrosion. With no current repetitive tasks, no inspection history
 
is available for the secondary SG blowdown sample baths or the SG blowdown
 
corrosion product monitor coolers. The applicant also stated that the maintenance 3-184 history of these heat exchangers shows no corrosion. These heat exchangers are only within the 10 CFR 54.4(a)(2) scope of license renewal for pressure boundary
 
concerns so the shell needs management for loss of material only. Reduction of
 
heat transfer is not an AERM for these heat exchangers. In failure load testing of the
 
tower fill and drift eliminators since 1988 through the latest report in 2003, no
 
specimens have failed to meet the acceptanc e criteria, and the projected lifetime of the tower fill and drift eliminators indicates that the material deteriorates slowly in
 
the tower environment. The potable water system water heater housings currently
 
have no scheduled inspection repetitive tasks, so no history for planned tasks is
 
available. The maintenance history of these heat exchangers shows no leakage due
 
to corrosion. The applicant further stated that the original boric acid storage tank, condensate storage tank, and reactor make-up water storage tank diaphragms have
 
been replaced with diaphragms constructed of an improved elastomer material.
 
Since these replacements, periodic bladder inspections have detected several
 
instances of tears in the diaphragms. The diaphragm vendor attributed the tears to
 
improper operation, not aging, as the tanks were not maintained with a nitrogen
 
blanket between the diaphragm and the water. Without nitrogen blankets the
 
diaphragms can "stick" to the tank wall, creating sufficient force to tear them during
 
level changes. Procedures are in place to correct the operational deficiency with no
 
aging-related failures observed since the diaphragms were replaced.
 
During the audit and review, the staff reviewed the operating experience in the LRA
 
and the operating experience evaluation reports and also interviewed the applicant's
 
technical personnel and confirmed that did not reveal any degradation not bounded
 
by industry experience. The staff concludes that these operating experience events
 
provide objective evidence that the Periodic Surveillance and Preventive
 
Maintenance Activities will provide timely detection of aging degradation and
 
corrective action.
 
On the basis of its review of the operating experience and discussions with the
 
applicant's technical staff, the staff concludes that the applicant's Periodic Surveillance and Preventive Maintenance Activities will adequately manage the aging effects identified in the LRA for which this AMP is credited.
The staff confirmed that the "operating ex perience" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.10. The staff finds this program element
 
acceptable.
 
UFSAR Supplement In LRA Section A.2.21, the applicant provided the UFSAR supplement for the Periodic Surveillance and Preventive Maintenance Activities. The staff reviewed the
 
applicant's license renewal commitment letter (NL-07-1261, dated June 27, 2007) and
 
confirmed that this program is identified as Commitment No. 18 to be implemented before
 
the period of extended operation. The staff reviewed this section and finds the UFSAR
 
supplement information an adequate summary descr iption 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 Activities, the staff concludes that the applicant has demonstrated
 
that effects of aging will be adequately managed so that the intended function(s) will be
 
maintained consistent with the CLB for the period of extended operation, upon
 
implementation of Commitment No. 18, as required by 10 CFR 54.21(a)(3). The staff also 3-185 reviewed the UFSAR supplement for this AMP and determined that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.3.7  Reactor Vessel Internals Program 
 
Summary of Technical Information in the Application LRA Section B.3.24 describes the new Reactor Vessel Internals Program as a plant-specific program. 
 
The applicant stated that the Reactor Vessel Internals Program manages material
 
degradation for the reactor vessel internals. The program will be based on the following set
 
of implementation commitments:
 
The applicant will participate in the industry program for investigating and managing aging effects on reactor vessel internals. The applicant will evaluate and implement the results of industry programs like the EPRI Materials Reliability Project (MRP) as applicable to the VEGP reactor vessel internals. The applicant will submit a reactor vessel internals inspection plan to the staff for review and approval at least 24 months before the period of
 
extended operation for Units 1 and 2.
The applicant also stated that the Reactor Vessel Internals Program will be implemented
 
prior to the period of extended operation. As program attributes are not yet fully developed, assessments for each of the ten aging managem ent program elements are not included; assessments for each of the ten elements will be included in the inspection plan submitted
 
for review and approval. The program implementat ion commitments are consistent with the AMP commitments listed in GALL Report Section IV.B2 for managing PWR reactor vessel
 
internals. The scope of components to be included in the program includes all of the
 
components and aging effects described in GALL Report Revision 1, Section IV.B2, with
 
the following differences:
 
(1) The Reactor Vessel Internals Program will manage wear of reactor vessel internals components. Section IV.B2 credits Inservice Inspection Program visual inspections
 
to manage such wear. Reactor vessel internals inspection and evaluation guidance
 
currently in development by the EPRI MRP Reactor Internals Focus Group will consider potential wear of reactor vessel internals components. The ensuing inspection requirements may not align with those of ASME Code Section XI. (2) The Reactor Vessel Internals Program will manage embrittlement of the bottom-mounted instrumentation column cruciforms, the only CASS reactor vessel internals
 
components. These cruciforms are ASME SA-351 Grade CF8 castings. GALL
 
Report Section IV.B2 credits the program described in GALL Report Section XI.M13, "Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless
 
Steel (CASS)," to manage embrittlement of cast austenitic stainless steel reactor
 
vessel internals due to thermal aging and irradiation embrittlement.
Reactor vessel internals inspection and evaluation guidance currently in development by the EPRI Reactor Internals Focus Group will consider the potential
 
embrittlement of CASS reactor vessel internals. The applicant will apply the 3-186 inspection and evaluation requirements from this industry effort to the bottom-mounted instrumentation column cruciforms in the Reactor Vessel Internals
 
Program. (3) The Reactor Vessel Internals Program will manage cracking of the reactor vessel core support lugs, pads, and their attachment welds. GALL Report Section IV.A2
 
does not credit the Reactor Vessel Internals Program for this component and aging
 
effect combination. (4) The Reactor Vessel Internals Program will manage wear of the reactor vessel closure head thermal sleeves. GALL Report Sections IV.A2 and IV.B2 do not
 
address reactor vessel head thermal sleeves.
 
Staff Evaluation In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.3.24 , Reactor Vessel Internals Program, and the applicant's license renewal (LR) basis evaluation document for this AMP 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 Reactor Vessel Internals Program against the staff's recommended
 
program element criteria that are provided in SRP-LR Section A.1.2.3, and in SRP-LR Table A.1-1. The staff focused its review on assessing how the plant-specific program
 
elements for the Reactor Vessel Internals Program would ensure adequate aging
 
management when compared to the recommended program element criteria that are described in SRP-LR Section A.1.2.3. Specifically, the staff reviewed seven (7) of the
 
applicant's program elements of a total of 10 against their corresponding program element
 
criteria that are provided in the subsections to SRP-LR Section A.1.2.3: (1)"scope of the
 
program," (2) "preventive actions," (3) "param eters monitored or inspected," (4) "detection of aging effects," (5) "monitoring and trending," (6) "acceptance criteria," and (10) "operating
 
experience."
 
The applicant indicated that program elements (7) "corrective actions,"(8) "confirmation
 
process," and (9) "administrative controls" are parts of the site-controlled QA program. The
 
staff evaluated the Inservice Inspection Program's "confirmatory process" and
 
"administrative controls" program elements as part of the staff's evaluation of the applicant's Quality Assurance Program. The staff's evaluation of the applicant's Quality
 
Assurance Program is described in SER Section 3.0.4. The staff's evaluation of the
 
remaining program elements are described in the paragraphs that follow:
 
(1) Scope of the Program - LRA Section B.3.24 states that the scope of components to be included in the program includes all of the components and aging effects
 
described in NUREG-1801, Rev. 1, Section IV.B2, with the following differences:
  "The VEGP Reactor Vessel Internals Program will manage wear of reactor vessel internals components. NUREG-1801, Section
 
IV.B2, credits Inservice Inspection Program visual inspections to
 
manage wear of the reactor vessel internals. Reactor vessel
 
internals inspection and evaluation guidance currently in
 
development by the EPRI MRP Reactor Internals Focus Group (MRP) will consider the potential for wear of reactor vessel
 
internals components. The resulting inspection requirements may 3-187  or may not align with existing ASME Section XI inspection requirements."
    "The VEGP Reactor Vessel Internals Program will manage embrittlement of the VEGP Bottom Mounted Instrumentation
 
Column Cruciforms, which are the only VEGP cast austenitic
 
stainless steel (CASS) reactor vessel internals components.
 
These Cruciforms are ASME SA-351 Grade CF8 castings.
 
NUREG-1801, Section IV.B2,credits the program described in NUREG-1801, Section XI.M13, "Thermal Aging and Neutron
 
Embrittlement of Cast Austenitic Stainless Steel (CASS)" to
 
manage embrittlement of cast austenitic stainless steel reactor
 
vessel internals due to thermal aging and irradiation
 
embrittlement."
  "Reactor vessel internals inspection and evaluation guidance currently in development by the MRP will consider the potential
 
embrittlement of cast austenitic stainless steel reactor vessel
 
internals. SNC will include the inspection and evaluation
 
requirements resulting from this industry effort, applicable to the
 
VEGP Bottom Mounted Instrumentation Column Cruciforms, in
 
the Reactor Vessel Internals Program."
  "The Reactor Vessel Internals Program will manage cracking of the reactor vessel core support lugs, pads, and associated
 
attachment welds. NUREG-1801, Section IV.A2, does not credit
 
the Reactor Vessel Internals Program for this component and
 
aging effect combination."
  "The Reactor Vessel Internals Program will manage wear of the reactor vessel closure head thermal sleeves. NUREG-1801, Sections IV.A2 and IV.B2, do not address reactor vessel head
 
thermal sleeves."
SRP-LR Section A.1.2.3.1, "scope of program," provides the following
 
recommendation for AMP "scope of program" program elements:
 
The specific program necessary for license renewal should be identified. The scope of the progr am should include the specific structures and components of which the program manages the
 
aging. The GALL Report, as invoked by the SRP-LR, does not currently include a recommended AMP for PWR reactor vessel internal components because the
 
industry is currently in progress of developing its augmented inspection program for
 
PWR RV internals and submitting this program to the NRC for review and approval.
 
Instead, the AMR items in the GALL Report which invoke augmented inspection
 
activities for PWR RV internals call for the applicants to provide the following
 
commitment in the UFSAR supplements for their applications:
3-188  participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and
 
implement the results of the industry programs as applicable
 
to the reactor internals; and (3) upon completion of these
 
programs, but not less than 24 months before entering the
 
period of extended operation, submit an inspection plan for
 
reactor internals to the NRC for review and approval.
 
The MRP, in conjunction with the Electric Power Research Institute (EPRI)
 
and the Nuclear Energy Institute (NEI), are currently responsible for
 
developing a set of industry-wide augmented inspection and flaw evaluation
 
program guidelines for PWR RV internals and for getting these guidelines
 
reviewed and approved by the NRC, with the intent to develop a consistent
 
concerted set of augmented recommended guidelines that would be
 
acceptable to both the industry and the NRC. Thus, the GALL report was
 
updated in September 2005 to encourage PWR applicants to commit to the
 
EPRI MRP Reactor Internal's Focus Group augmented inspection and flaw evaluation guidelines for their RV internal components.
 
The staff reviewed the license renewal (LR) basis evaluation document as part of its
 
review of the Reactor Vessel Internals Program to determine how the "scope of
 
program" program element for the AMP co mpared with the staff's recommendations in SRP-LR Section A.1.2.3.2. The staff also reviewed the LR basis evaluation
 
document to determine whether the program elements for the Reactor Vessel
 
Internals Program would ensure adequate aging management of the RV internals
 
components during the period of extended operation. From its review of this
 
document, the staff concludes that the "scope of program" program element for the
 
Reactor Vessel Internals Program includes Commitment No. 20 on implementation
 
of this AMP. The staff noted that Commitment No. 20 provided in the Applicant's
 
letter NL-07-1261, dated June 27, 20071), required the applicant to commit to the
 
following actions with respect to implementation of the Reactor Vessel Internals
 
Program:
commit to the MRP's activities on RV internals, (2) commit to use the results from the MRP studies on RV internals and
 
inspection and flaw evaluation (I&FE) guidelines as the basis
 
for scheduling and implementing the inspections for the
 
VEGP RV internals, and (3) commit to submitting an
 
inspection plan for these components to the NRC for review
 
and approval at least 2 years prior to entering the period of
 
extended operation. 
 
The staff noted that the provisions of Commitment No. 20 are consistent with the
 
wording specified in the particular GALL Report AMR items that invoke the industry-
 
wide activities for PWR RV internals. However, the staff also noted that the
 
applicant is also relying on the Reactor Vessel Internals Program to manage loss of
 
material and cracking in the Control Rod Drive (CRD) penetration nozzle thermal
 
sleeves and in the RV attachments welds, lugs, and supports and that the applicant
 
had indicated that these components are not within the scope of the MRP's
 
augmented aging studies for PWR. In this case, the staff concludes that the 3-189 commitment as provided in the applicant's letter dated June 27, 2007, did not indicate that the scope of the inspection plan for the VEGP RV internals would
 
include the CRD penetration nozzle thermal sleeves and the RV attachment weld, lugs, and support pads. 
 
The staff informed the applicant that, since the scope of the MRP's augmented
 
aging studies did not cover CRD penetration nozzle thermal sleeves and the RV
 
attachment weld, support lugs, and support pads, Commitment No. 20 would need
 
to be supplemented to specifically indicate that the scope of the inspection plan
 
would include augmented inspection activities for the CRD for these components.
 
The staff asked the applicant to supplement the wording of Commitment No. 20
 
accordingly and to docket the revised version of the commitment.
The applicant provided its response to the staff's question in a letter dated February
 
8, 2008. In its response, the applicant provided the text that will be added to the
 
third part of the commitment. The staff confirmed that the applicant amended the
 
LRA in a letter dated March 20, 2008 and incorporated the changes into
 
Commitment No. 20, and is as follows:
 
Implement the Reactor Vessel Internals Program as described in LRA
 
Section B.3.24
 
The program will be based on the following commitments:
 
SNC will participate in the industry program for investigating and managing aging effects on reactor internals. This is an
 
ongoing commitment.
SNC will evaluate and implement the results of the industry programs, such the Electric Power Research Institute Material
 
Reliability Program, as applicable to the VEGP reactor internals. This
 
commitment will be fully the implemented prior to the period of
 
extended operation.
SNC will submit an inspection plan for the VEGP reactor internals to the NRC for review and approval not less than 24 months before
 
entering the period of extended operation for VEGP Units 1 and 2.
 
This inspection plan will address the bases, inspection methods, and
 
acceptance criteria associated with aging management of the reactor 
 
vessel thermal sleeves and the core support lugs (along with the
 
associated support pads and attachment welds).
 
Based on the information reviewed in LRA Section B.3.24, Reactor Vessel Internals
 
Program, the LR basis evaluation document for this AMP, and Commitment No. 20, the staff concludes that the "scope of program" program element is acceptable
 
because:
the scope of the program includes both those RV internals in which the AMR items for the component commodity groups in
 
the LRA credit augmented inspection activities of the MRP 3-190 Reactor Internal Focus Group, and the CRD penetration nozzle thermal sleeves and the RV core support attachment
 
welds, lugs, and pads the applicant has to committed to participate in the MRP's industry initiative studies for PWR RV internals, to use the
 
results of these studies and the MRP's recommended
 
inspection and flaw evaluation (I&FE) guidelines as the basis
 
for scheduling and implementing the inspections the VEGP
 
RV internals, and to submit an inspection plan for the RV
 
internals to the NRC for review and approval at least two (2)
 
years prior to entering the period of extended operation the inspection plan for the RV internals will include augmented inspection activities for the control rod drive (CRD) penetration nozzle thermal sleeves and the RV core
 
support attachments welds, lugs, and pads (which are not
 
within the scope of MRP's industry initiatives for PWR RV
 
internals).
the applicant's inspection plan for the RV internals will be submitted to the NRC for review and approval at least two
 
years prior to entering the period of extended operation
 
Based on this review, the staff concludes that the "scope of program" program
 
element is acceptable and conforms to the staff's recommendations in SRP-LR
 
Section A.1.2.3.4 because: (1) the SRP-LR invokes the staff's recommendation in
 
the GALL Report, and (2) the applicant has, in Commitment No. 20, included an
 
acceptable commitment to manage aging of the VEGP RV internals that is
 
consistent with the staff's recommendations for PWR RV internals in the GALL
 
Report. The staff confirmed that the "scope of the program" program element
 
satisfies the criterion defined in SRP-LR Section A.1.2.3.1. The staff finds this
 
program element acceptable.
  (2) Preventive Actions - LRA Section B.3.4 did not provide any "preventive actions" program element description for the Reactor Vessel Internals Program. The
 
applicant provided this information in the LR basis evaluation document for the
 
Reactor Vessel Internals Program.
SRP-LR Section A.1.2.3.2, "preventive actions" provides, in part, the following NRC
 
guideline recommendations for AMP "prev entative actions" program elements in plant-specific LRAs:
 
The activities for prevention and mitigation programs should be described.
 
These actions should mitigate or prevent aging degradation.
 
For condition or performance monitori ng programs, they do not rely on preventive actions and thus, this information need not be provided. More
 
than one type of aging management program may be implemented to
 
ensure that aging effects are managed.
3-191  The staff reviewed the license renewal basis evaluation document as part of its
 
review of the Reactor Vessel Internals Program to determine how the "preventive
 
actions" program element for the AMP compared with the staff's recommendations
 
in SRP-LR Section A.1.2.3.2. From its review of this document, the staff concludes
 
that the "preventive actions" program elem ent description in the LR basis document for the Reactor Vessel Internal Program indicated that the program does not rely on
 
preventive actions to preclude aging effects from initiating or on mitigative activities
 
to minimize the probability that aging effects will initiate in the RV internal
 
components. The staff concurs that the Reactor Vessel Internals Program is a
 
condition monitoring program that will implement the augmented inspections and flaw evaluation criteria defined and recommended by the MRP Reactor Internal
 
Focus Group for PWR RV internals, and those VEGP-specific augmented inspection
 
criteria for the Control Rod Drive (CRD) penetration nozzle thermal sleeves and the
 
RV core support attachments welds, lugs, and pads. As such, the staff concludes
 
that the Reactor Vessel Internals Program does not include specific preventive or
 
mitigative activities. 
 
The applicant's Water Chemistry Control Program (LRA Section B.3.28) is designed to mitigate the probability that aging effects induced by chemical or corrosive aging
 
mechanisms, such loss of material induced by pitting or crevice corrosion or
 
cracking induced by stress corrosion cracking (SCC, including irradiation-assisted stress corrosion cracking [IASCC] or primary water stress corrosion cracking
 
[PWSCC]), will initiate in the plant systems exposed to aqueous environments. The staff evaluated the ability of the Water Chemistry Control Program to mitigate the
 
aging effects that may potentially be induced by chemical or corrosive aging
 
mechanisms in SER Section 3.0.3.1.4.
Based on this assessment, the staff confirm ed that the "preventive actions" program element does not need to satisfy the "preventive actions" program element criterion
 
defined in SRP-LR Section A.1.2.3.2. The staff finds this program element
 
acceptable.
(3) Parameters Monitored or Inspected - LRA Section B.3.4 did not provide any "parameters monitored or inspected" pr ogram element description for the Reactor Vessel Internals Program. The applicant provided this information in the LR basis
 
evaluation document for the Reactor Vessel Internals Program.
SRP-LR Section A.1.2.3.3, "parameters monitored or inspected" provides the
 
following recommendation for "parameters monitored or inspected" program
 
elements for condition monitoring-based AMPs:
For a condition monitoring program, the parameter monitored or inspected should detect the presence and extent of aging effects. Some examples
 
are measurements of wall thickness and detection and sizing of cracks.
The staff reviewed the LR basis evaluation document as part of its review of the
 
Reactor Vessel Internals Program to determine how the "parameters monitored or
 
inspected" program element for the AMP compared with the staff's
 
recommendations in SRP-LR Section A.1.2.3.3. From its review of this document, the staff concludes that the "parameters monitored or inspected" program element 3-192 in the LR basis document indicated that the parameters monitored will be based on the results of industry initiatives on internals and that inspection techniques will be
 
selected on the ability to detect evidence of age-related degradation, including
 
cracking due to SCC, IASCC, PWSCC, or cyclical loading, loss of material due to
 
mechanisms such as wear, and changes in dimension due to void swelling. The
 
"parameters monitored or inspected" program element also indicated that the
 
program will indirectly be used to manage potential loss (reduction) of fracture
 
toughness that may be induced by either neutron irradiation embrittlement, void
 
swelling, or thermal aging in components made from CASS or martensitic materials
 
by using inspection techniques that are capable of detecting cracks in the
 
component materials. The aging effects are consistent with the aging effects
 
identified in the specific AMR items in GALL Report Table IV.B2 that recommend
 
using the MRP Reactor Vessel Internal Focus Group industry initiatives for aging
 
management of Westinghouse PWR RV internals.
 
The staff has verified that Reactor Vessel Internals Program is based on
 
implementation of Commitment No. 20, which was docketed in the applicant's letter dated March 20, 2008. In this letter, the applicant committed to participate in and to
 
implement the inspections that are recommended by the MRP Reactor Vessel
 
Internal Focus Group to manage these aging effects prior to a loss of component
 
intended function. This is acceptable because the AMRs in the GALL Report permit
 
applicant's to use the industry initiatives of the MRP Reactor Vessel Internal Focus
 
Group for aging management if their LRAs are docketed to include a commitment in
 
the UFSAR Supplement to:
 
(1) participate in the industry programs for investigating and managing aging
 
effects on reactor internals; (2) evaluate and implement the results of the
 
industry programs as applicable to the reactor internals; and (3) upon
 
completion of these programs, but not less than 24 months before entering the
 
period of extended operation, submit an inspection plan for reactor internals to
 
the NRC for review and approval. This inspection plan will address the bases, inspection methods, and acceptance criteria associated with aging management
 
of the reactor vessel thermal sleeves and the core support lugs (along with the
 
associated support pads and attachment welds.
 
The staff has verified that LRA Commitment No. 20 includes these elements, and
 
that the commitment states that the inspection plan for the RV internals will include
 
VEGP-specific inspection criteria for manage wear in the VEGP control rod drive (CRD) penetration nozzle thermal sleeves and cracking of the RV core support
 
attachments welds, lugs, and pads.
Based on this review, the staff concludes that the "parameters monitored or
 
inspected" program element is acceptable and conforms to the staff's
 
recommendations in SRP-LR Section A.1.2.3.3 because: (1) the SRP-LR invokes the staff's recommendation in the GALL Report, and (2) the applicant has, in
 
Commitment No. 20, included an acceptable commitment to manage aging of the
 
VEGP RV internals that is consistent with the staff's recommendations for PWR RV
 
internals in the GALL Report. The staff confirmed that the "parameters monitored or
 
inspected" program element satisfies the criterion defined in the in SRP-LR
 
Section A.1.2.3.3. The staff finds this program element acceptable.
 
3-193 (4) Detection of Aging Effects - LRA Section B.3.4 did not provide any "parameters monitored or inspected" program element description for the Reactor Vessel
 
Internals Program. The applicant provided this information in the LR basis
 
evaluation document for the Reactor Vessel Internals Program.
SRP-LR Section A.1.2.3.4, "detection of aging effects" provides the following
 
recommendation for "detection of aging effects" program elements for condition
 
monitoring-based AMPs:
Detection of aging effects should occur before there is a loss of the structure and component intended function(s). The parameters
 
to be monitored or inspected should be appropriate to ensure that
 
the structure and component intended function(s) will be
 
adequately maintained for license renewal under all CLB design
 
conditions. This includes aspects such as method or technique (e.g., visual, volumetric, surface inspection), frequency, sample
 
size, data collection and timing of new/one-time inspections to
 
ensure timely detection of aging effects. Provide information that
 
links the parameters to be monitored or inspected to the aging
 
effects being managed.
The staff reviewed the LR basis evaluation document as part of its review of the
 
Reactor Vessel Internals Program to determine how the "detection of aging effects"
 
program element for the AMP compared with the staff's recommendations in SRP-
 
LR Section A.1.2.3.4. From its review of this document, the staff concludes that the
 
"detection of aging effects" program element description in the LR basis evaluation
 
identifies that the inspection techniques for the RV internals include those inspection
 
techniques described in MRP-153, and that these techniques include visual
 
examination techniques (VT-1 and EVT-1) and volumetric examination techniques
 
such as radiography (RT), ultrasonic testing (UT), and eddy current testing (ET).
 
The program element clarifies that these inspection techniques will be selected, based on the Material Reliability Project Reactor Vessel Internal Focus Group
 
recommendations, to detect component degradation before critical flaw sizes, wall
 
thicknesses, or dimensions are exceeded. This is acceptable because the AMRs in
 
Section IV.B2 of the GALL Report permit Westinghouse-design applicants to use
 
the industry initiatives of the MRP Reactor Vessel Internal Focus Group for aging
 
management if their LRAs are docketed to include a commitment in the UFSAR
 
Supplement to:
 
(1) participate in the industry programs for investigating and managing aging
 
effects on reactor internals; (2) evaluate and implement the results of the
 
industry programs as applicable to the reactor internals; and (3) upon
 
completion of these programs, but not less than 24 months before entering the
 
period of extended operation, submit an inspection plan for reactor internals to
 
the NRC for review and approval.
 
The staff has verified that LRA Commitment No. 20 includes these elements.
 
The staff concludes that the "detection of aging effects" program element
 
description in the LR basis evaluation document also stated that loss of fracture
 
toughness cannot be managed by direct monitoring, and that if required by the MRP 3-194 component functionality evaluation, the examination techniques specified to manage loss of fracture toughness will focus on detection of cracking before a crack
 
grows beyond the critical flaw size that was calculated in the limiting fracture
 
toughness study. 
 
The staff concludes that this is acceptable because: (1) the AMRs in Section IV.B2
 
of the GALL Report establish the NRC's position that Westinghouse-design
 
applicants may use the industry initiatives and recommendations of the MRP
 
Reactor Vessel Internal Focus Group as an option to manage the aging effects that
 
are applicable to their PWR RV internals, if committed to in the UFSAR
 
Supplements of their LRAs, (2) the MRP Reactor Vessel Internal Focus Group
 
industry initiatives include recommended inspection techniques to detect cracking
 
prior to a loss of component intended function, (3) the industry initiatives include
 
studies to account for the impact that neutron irradiation embrittlement, void
 
swelling, and thermal aging (for CASS components) could have on the fracture
 
toughness and hence critical crack size of the materials used to fabricate the RV
 
internals, (4) the applicant has, in Commitment No. 20, committed to participate in
 
the MRP's industry initiatives and studies on PWR RV internals and to apply and
 
implement the MRP recommendations for PWR RV internals to the specific internals
 
at VEGP, (5) the applicant has, in Commitment No. 20, committed to submit an
 
inspection plan for its RV internals to the NRC for review and approval at least two
 
years prior to entering the period of extended operation and (6) the inspection plan
 
to be submitted to the NRC for review and approval will include specific VEGP-
 
proposed inspection methods for detecting loss of material due wear in the VEGP
 
control rod drive (CRD) penetration nozzle thermal sleeves and cracking of the RV
 
core support attachments welds, lugs, and pads. 
 
Based on this review, the staff concludes that the "detection of aging effects"
 
program element is acceptable and conforms to the staff's recommendations in
 
SRP-LR Section A.1.2.3.4 because: (1) the SRP-LR invokes the staff's
 
recommendation in the GALL Report, and (2) the applicant has, in Commitment No.
 
20, included an acceptable commitment to manage aging of the VEGP RV internals
 
that is consistent with the staff's recommendations for PWR RV internals in the
 
GALL Report.
The staff confirmed that the "detection of aging effects" program element satisfies the criterion defined in the GALL Report and in SRP-LR
 
Section A.1.2.3.4. The staff finds this program element acceptable.
(5) Monitoring and Trending - LRA Section B.3.4 did not provide any "monitoring and trending" program element description for the Reactor Vessel Internals Program.
 
The applicant provided this information in the LR basis evaluation document for the
 
Reactor Vessel Internals Program.
SRP-LR Section A.1.2.3.5, "monitoring and trending" provides the following
 
recommendation for the "monitoring and trending" program elements for
 
preventative/mitigative-based, condition monitoring-based, and performance-
 
monitoring-based AMPs:
 
Monitoring and trending activities should be described, and they should
 
provide predictability of the extent of degradation and thus effect timely
 
corrective or mitigative actions. Plant specific and/or industry-wide 3-195 operating experience may be considered in evaluating the appropriateness of the technique and frequency.
This program element describes "how" the data collected are evaluated
 
and may also include trending for a forward look. This includes an
 
evaluation of the results against the acceptance criteria and a prediction
 
regarding the rate of degradation in order to confirm that timing of the
 
next scheduled inspection will occur before a loss of SC intended
 
function. Although aging indicators may be quantitative or qualitative, aging indicators should be quantified, to the extent possible, to allow
 
trending. The parameter or indicator trended should be described. The
 
methodology for analyzing the inspection or test results against the
 
acceptance criteria should be described. Trending is a comparison of
 
the current monitoring results with previous monitoring results in order to
 
make predictions for the future.
The staff reviewed the LR basis evaluation document as part of its review of the
 
Reactor Vessel Internals Program to determine how the "monitoring and trending"
 
program element for the AMP compared with the staff's recommendations in SRP-
 
LR Section A.1.2.3.5. From its review of this document, the staff concludes that the
 
"monitoring and trending" program element description in the LR basis evaluation
 
states that the applicant will implement industry developed I&FE guidelines (as
 
applicable to the VEGP RV internal designs) to ensure adequate monitoring and
 
trending so that a loss of component intended function does not occur prior to the
 
end of the period of extended operation. The staff concludes that the program
 
element description also states: (1) that MRP-152 provides preliminary industry
 
guidance related to inspection intervals, with the inspections for most components
 
most likely to conform to a schedule that conforms to that in the ASME Code Section XI, Paragraph IWB-2430, and (2) that components with detected flaws or
 
postulated high crack growth rates may result in more frequent inspections frequencies.
The staff also determined that the program element description states that, for those
 
components not subject to the MRP program, SNC will address the inspection
 
frequencies based on industry experience, VEGP specific data, and vendor
 
evaluations and recommendations. 
 
Based on this review, The staff finds the applicant's bases for its "monitoring and
 
trending" program element to be acceptable because the applicant has, in
 
Commitment No. 20, committed to: (1) participate in the MRP's activities on RV
 
internals, (2) use the results MRP studies on RV internals and inspection and flaw
 
evaluation (I&FE) guidelines as the basis for establishing and frequency for, scheduling and implementing its inspections the VEGP RV internals, and (3) submit
 
an inspection plan for these components to the NRC for review and approval at
 
least 2 years prior to entering the period of extended operation, including specific
 
inspection plans for managing loss of material due wear in the VEGP control rod
 
drive (CRD) penetration nozzle thermal sleeves and cracking of the RV core support attachments welds, lugs, and pads. This is LRA Commitment No. 20.
 
Based on this review, the staff concludes that the "monitoring and trending" program
 
element is acceptable and conforms to the staff's recommendations in SRP-LR 3-196 Section A.1.2.3.5 because: (1) the SRP-LR invokes the staff's recommendation in the GALL Report, and (2) the applicant has, in Commitment No. 20, included an
 
acceptable commitment to manage aging of the VEGP RV internals that is
 
consistent with the staff's recommendations for PWR RV internals in the GALL
 
Report. The staff confirmed that the "monitoring and trending" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.5.
 
The staff finds this program element acceptable.
(6) Acceptance Criteria - LRA Section B.3.4 did not provide any "acceptance criteria" program element description for the Reactor Vessel Internals Program. The
 
applicant provided this information in the LR basis evaluation document for the
 
Reactor Vessel Internals Program.
 
SRP-LR Section A.1.2.3.6, "acceptance criteria" provides the following
 
recommendation for the "acceptance criteria" program elements for
 
preventative/mitigative-based, condition monitoring-based, and performance-
 
monitoring-based AMPs:
 
The acceptance criteria of the program and its basis should be described.
 
The acceptance criteria, against which the need for corrective actions will
 
be evaluated, should ensure that the structure and component intended
 
function(s) are maintained under all CLB design conditions during the
 
period of extended operation. The program should include a methodology
 
for analyzing the results against applicable acceptance criteria. Corrective
 
action is taken, such as piping replacement, before reaching this
 
acceptance criterion. This acceptance criterion should provide for timely
 
corrective action before loss of intended function under these CLB design
 
loads.
 
Acceptance criteria could be specific numerical values, or could consist of
 
a discussion of the process for calculating specific numerical values of
 
conditional acceptance criteria to ensure that the structure and component
 
intended function(s) will be maintained under all CLB design conditions.
 
Information from available references may be cited . . . . It is not necessary
 
to justify any acceptance criteria taken directly from the design basis
 
information that is included in the UFSAR because that is a part of the
 
CLB. Also, it is not necessary to discuss CLB design loads if the
 
acceptance criteria do not permit degradation because a structure and
 
component without degradation should continue to function as originally
 
designed. 
 
Acceptance criteria, which do permit degradation, are based on
 
maintaining the intended function under all CLB design loads.
 
The staff reviewed the LR basis evaluation document as part of its review of the
 
Reactor Vessel Internals Program to determine how the "acceptance criteria"
 
program element for the AMP compared with the staff's recommendations in SRP-
 
LR Section A.1.2.3.6. From its review of this document, the staff concludes that the
 
"acceptance criteria" program element description states the program will be based
 
on the results of the MRP studies on PWR RV internals and will implement the
 
MRP's recommended acceptance criteria for RV internals. The staff also determined 3-197 that the program element states that: (1) when the MRP program is completed, the program will include applicable acceptance criteria recommendations for critical
 
component flaw sizes, wall thicknesses, and critical dimensions, with adequate
 
margins to address detection limitations, flaw sizing uncertainties, conservatively
 
postulated crack growth rates, and other uncertainties, and (2) when examinations
 
result in the detection of flaws, MRP-153 provides the MRP's preliminary industry
 
guidance regarding flaw tolerance evaluations for PWR RV internals. The staff finds
 
these bases to be acceptable because: (1) the applicant's bases are consistent with
 
the AMR line items for RV internals that invokes this industry-wide integrated
 
approach to RV internal components, and (2) the applicant has, in Commitment No.
 
20, committed to participation in the MRP's industry studies and activities on PWR
 
RV internals, to use and implement the results and recommendations of the MRP's
 
inspection and flaw evaluation (I&FE) guidelines as the basis for evaluating any
 
relevant indications in the VEGP RV internals. The staff verified that the applicant
 
has included this commitment in LRA Commitment No. 20.
The staff also determined that the program element states that: (1) for inspections of
 
the RV core support lugs, pads, and attachment welds, any relevant flaw indications will be compared to applicable flaw acceptance criteria in the ASME Section XI for
 
category B-N-2 component inspection items or in accordance with more restrictive
 
guidance, (2) the acceptance criteria for these components will be included in the
 
inspection plan that will be submitted to the NRC for review and approval, and (3)
 
for the RV closure head thermal sleeves, the limits on acceptable wall loss (as a
 
result of wear) will be compared to minimum values established by the program and
 
based on VEGP specific data and wear rate trending. This is acceptable because
 
the applicant has, in Commitment 20, committed to submitting the bases, inspection
 
methods, and acceptance criteria for the control rod drive penetration nozzle
 
thermal sleeves, and the RV core support lugs, pads, and attachments as part of
 
the RV internal inspection plan that will be submitted to the NRC for review and
 
approval. The staff verified that the applicant has included this commitment in LRA
 
Commitment No. 20.
 
Based on this review, the staff concludes that the "acceptance criteria" program
 
element is acceptable and conforms to the staff's recommendations in SRP-LR
 
Section A.1.2.3.6 because: (1) the SRP-LR invokes the staff's recommendation in
 
the GALL Report, and (2) the applicant has, in Commitment No. 20, included an
 
acceptable commitment to manage aging of the VEGP RV internals that is
 
consistent with the staff's recommendations for PWR RV internals in the GALL
 
Report. The staff confirmed that the "acceptance criteria" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.6. The staff
 
finds this program element acceptable.
 
(10) Operating Experience - LRA Section B.3.24 states that the new Reactor Vessel Internals Program has no programmatic history. The program will be based upon
 
industry operating experience, research data, and vendor evaluations.
Development of the program will rely upon the consensus opinion of the EPRI MRP
 
Reactor Internals Focus Group, which includes utility representatives, research
 
scientists, and vendors. For the reactor vessel thermal sleeves, program
 
development will be based on plant-specific data and on vendor recommendations. 
 
3-198 The applicant stated that the Unit 2 Spring 2007 refueling outage found a number of reactor vessel head thermal sleeves to have experienced wear up to 360 &deg; around
 
the thermal sleeve where it exits the bottom end of the control rod drive mechanism
 
penetration tube. Wear was more severe at unrodded than at rodded locations.
 
Initial evaluation attributes the wear to contact with the penetration tubes due to
 
flow-induced oscillations. The wear was of varying magnitudes, significant at nine
 
locations and minimal at twenty-three locations. Because of these wear indications;
 
lower sections of the four thermal sleev es experiencing the most extensive wear were removed up to points well above the vessel penetration weld.
All four of the removed sleeves were in unrodded penetration locations. The
 
remaining thermal sleeves will be re-inspected at the next scheduled refueling
 
outage, at which time; assessments will determine additional monitoring
 
requirements and corrective actions. Earlier in plant life, VEGP preemptively replaced the original Units 1 and 2 Alloy X-750 control rod guide tube support pins
 
with strain-hardened Type 316 stainless steel support pins based on industry experience with PWSCC in Alloy X-750 support pins.
SRP-LR Section A.1.2.3.10, "operating experience" provides the following
 
recommendation for the "operating experience" program elements for
 
preventative/mitigative-based, condition monitoring-based, and performance-
 
monitoring-based AMPs:
 
Operating experience with existing programs should be discussed. The
 
operating experience of aging management programs, including past
 
corrective actions resulting in program enhancements or additional
 
programs, should be considered. A past failure would not necessarily
 
invalidate an aging management program because the feedback from
 
operating experience should have resulted in appropriate program
 
enhancements or new programs. This information can show where an
 
existing program has succeeded and where it has failed (if at all) in
 
intercepting aging degradation in a timely manner. This information should
 
provide objective evidence to support the conclusion that the effects of
 
aging will be managed adequately so that the structure and component
 
intended function(s) will be maintained during the period of extended
 
operation.
 
The staff reviewed the applicant's program documents and the operating
 
experience document for the Inservice Inspection Program to determine how
 
the "operating experience" program element for the Reactor Vessel Internals
 
Program compared with the staff's recommendations in SRP-LR Section
 
A.1.2.3.10 and to determine whether the applicant's program was capable of
 
addressing relevant operating experience for PWR RV internals, including both
 
existing and potential operating experience, and both generic and VEGP-
 
specific operating experience with PWR RV internals. The staff verified
 
applicant's operating experience program element does address both existing
 
and potential, and VEGP-specific and generic  operating experience on aging of
 
PWR RV internals that the industry is concerned about and is currently studying
 
through the industry studies and initiatives of the MRP. These initiatives include
 
studies on PWR former and baffle bolts, stainless steel and inconel (Alloys 600
 
and 690 base metal materials, and Alloy 82, 182, 52, or 152 weld filler metal 3-199 materials) RV internals, and RV internals made from martensitic, precipition-hardened, and strain hardened steel, all of which may be potentially susceptible
 
to stress-corrosion induced cracking (including potential irradiation-assisted
 
stress corrosion cracking); loss of fracture due to neutron irradiation
 
embrittlement, potential void swelling or, for cast austenitic stainless steels (CASS) due to thermal aging; changes in dimensions due to void swelling; and
 
for bolted, keyed, or pinned RV internal connections loss of preload due to
 
stress relaxation (including irradiation-assisted stress relaxation). 
 
The staff has verified that, to address existing and potential VEGP-specific and
 
generic operating experience that is applicable to the VEGP RV internals, the
 
applicant has, in Commitment No. 20, committed to: (1) participating in the
 
MRP industry-wide studies and initiatives for PWR RV internals, (2)
 
implementing the bases, inspection criteria and recommendations, and flaw
 
evaluation criteria and recommendations that are developed by the MRP for
 
PWR RV internals to the inspection, monitoring and trending, and evaluation of
 
the RV internals for the VEGP units, and (3) for these components, to submit an
 
inspection for these components to the NRC for review and approval at least
 
two years prior to entering the period of extended operation. The staff's has
 
included its bases for accepting the AMP based on the provisions of the
 
Commitment, as assessed by the staff in its evaluations for the previous
 
program elements for this AMP. Based on this assessment, the staff concludes
 
that the applicant, through its commitment to the MRP activities, has provided
 
an acceptable basis for addressing both existing and potential, and VEGP-
 
specific and generic operating experience for the VEGP RV internals that are
 
within the scope of the MRP's industry initiatives and studies for PWR RV
 
internals.
 
The staff also verified that the "operating experience" program element for the
 
Reactor Vessel Internals Program did discuss and address VEGP-specific
 
experience with wear in the control rod drive penetration nozzle thermal sleeves
 
and potential operating experience with cracking of the VEGP RV core support
 
lugs, pads, and attachments. The staff noted that the "operating experience"
 
program element description for this AMP did identify that these components
 
are not within the scope of the MRP's industry initiatives and did an acceptable
 
job of discussing the causes and steps taken by the applicant to address the
 
experience. 
 
Based on this review, the staff concludes that the "operating experience" program
 
element is acceptable and conforms to the staff's recommendations in SRP-LR
 
Section A.1.2.3.10 because: (1) the SRP-LR contains the staff's recommendation in
 
the GALL Report, (2) the applicant has, in Commitment No. 20, included an
 
acceptable commitment to manage aging of the VEGP RV internals that is
 
consistent with the staff's recommendations for PWR RV internals in the GALL
 
Report, (3) Commitment No. 20 as proposed by the applicant and accepted by the
 
staff includes provisions to submit and inspection plan for the VEGP RV internals to
 
the staff for review and approval, and (4) the inspection, when submitted will include
 
appropriate inspection and flaw evaluation criteria for both the components
 
assessed by the MRP initiates on PWR RV internals and the control rod drive
 
penetration nozzle thermal sleeves and RV core support lugs, pads, and
 
attachments, which are not within the scope of the MRP's industry studies and 3-200 initiatives on PWR RV internals.
The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR
 
Section A.1.2.3.10. The staff finds this program element acceptable.
 
UFSAR Supplement In LRA Section A.2.24, the applicant provided the UFSAR supplement for the Reactor Vessel Internals Program. The staff verified that Commitment No. 20, when
 
implemented, is consistent with the staff's recommendations for managing aging in PWR
 
RV internals that are described in the specific AMRs for these components in the GALL
 
Report, and that Commitment No. 20 referenced that the commitment is applicable to
 
UFSAR Section A.2.2.4 and LRA Section B.3.4 for the Reactor Vessel Internals 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 Reactor Vessel Internals Program, the staff concludes that the applicant has demonstrated that effects of aging will
 
be adequately managed so that the intended function(s) will be maintained consistent with
 
the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff
 
also reviewed the UFSAR supplement for this AMP and determined that it provides an
 
adequate summary description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.3.8  Steam Generator Program for Upper Internals 
 
Summary of Technical Information in the Application LRA Section B.3.27 describes the existing Steam Generator Program for Upper Internals as a plant-specific program. 
 
The applicant stated that the Steam Generator Program for Upper Internals is an existing plant-specific subprogram of the Steam Generat or Program, which is an integrated program for managing the condition of the SGs. The Steam Generator Program conforms to the
 
program described in NEI 97-06, "Steam G enerator Program Guidelines." The Steam Generator Program for Upper Internals includes Steam Generator Program activities for aging management of the SG upper internals components within the scope of license
 
renewal.
 
Staff Evaluation In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.3.27 on the applicant's demonstration of the Steam Generator Program
 
for Upper Internals 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 Steam Generator Program for Upper Internals against the AMP
 
elements found in SRP-LR Section A.1.2.3, and in SRP-LR Table A.1-1. The staff focused
 
its review on assessing how the applicant's plant-specific program elements would ensure
 
adequate aging management when compared to the 10 recommended program elements described in SRP-LR Section A.1.2.3. Specifically, the staff reviewed the following seven
 
program elements of the applicant's program:
(1)"scope of the program," (2) "preventive actions," (3) "parameters monitored or inspected," (4) "detection of aging effects," (5)
 
"monitoring and trending," (6) "acceptance criteria," and (10) "operating experience."
 
The applicant indicated that program elements (7) "corrective actions," (8) "confirmation
 
process," and (9) "administrative controls" are parts of the site-controlled QA program. The 3-201 staff's evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven elements follows:
 
(1) Scope of the Program - LRA Section B.3.27 states that the program scope includes the following components:
Auxiliary Feedwater Spray Piping  Auxiliary Feedwater Nozzle Thermal Sleeve  Feedwater Distribution Assembly Piping and Fittings  Feedwater Inlet Nozzle  Feedwater Inlet Nozzle Thermal Sleeve  Feedwater J-Tubes  Moisture Separator Assembly - Primary  Moisture Separator Assembly - Secondary The staff reviewed the applicant's basis documents for the Steam Generator
 
Program for Upper Internals and determined that this program adequately identified
 
all the components within the scope of this AMP. The staff confirmed that the
 
specific components for which the program manages aging effects are identified, which satisfies the criterion defined in SRP-LR Section A.1.2.3.1. On this basis, the
 
staff finds the applicant's scope of the program acceptable
 
(2) Preventive Actions - LRA Section B.3.27 states that, consistent with NEI 97-06, the program relies upon water chemistry controls to prevent or mitigate degradation
 
mechanisms or to reduce degradation rates. 
 
These secondary-side chemistry controls are parts of the Water Chemistry Control
 
Program. The Water Chemistry Control Pr ogram is an existing program that mitigates loss of material, cracking, and reduction in heat transfer in system
 
components and structures through the control of water chemistry. The program
 
includes control of detrimental chemical species and the addition of chemical
 
agents. The staff confirmed that the "preventive actions" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.2. The staff
 
finds this program element acceptable.
 
(3) Parameters Monitored or Inspected - LRA Section B.3.27 states that the Steam Generator Program for Upper Internals includes inspection activities detect
 
degradation of secondary side internals needed to maintain tubing integrity and
 
accomplish SG intended functions. An assessment based upon SG design, potential degradation mechanisms; and related plant-specific and industry operating
 
experience establishes, for secondary side internal components, inspection
 
requirements that are incorporated into the SG inspection plans.
The staff confirmed that the "parameters m onitored or inspected" program element satisfies the criteria defined in the GALL Report and in SRP-LR Section A.1.2.3.3.
 
The staff finds this program element acceptable.
3-202 (4) Detection of Aging Effects - LRA Section B.3.27 states that the SG tubing eddy current testing data indicate some secondary-side conditions (e.g., evidence of loose parts); however, detection of aging effects in the SG secondary-side internals
 
is primarily accomplished through the use of visual inspections. The program
 
considers Industry and plant-specific operating experience from prior inspections
 
and cleaning activities (e.g., sludge lancing, sludge collector cleaning, etc.) in establishing secondary-side inspection requirements. Inspection of SG secondary-
 
side components is performed as needed to assess conditions or evaluate potential
 
degradation mechanisms. Visual inspections are adequate to detect loss of material
 
and cracking of SG internal support structures before any detrimental impact on
 
tube integrity. Various tools and techniques are available for visual inspection of
 
secondary side components; however, the choice of visual tools and techniques
 
varies with the points of interest for the inspection.
The staff confirmed that the "detection of aging effects" program element satisfies
 
the criteria defined in the GALL Report and in SRP-LR Section A.1.2.3.4. The staff
 
finds this program element acceptable.
 
(5) Monitoring and Trending - LRA Section B.3.27 states that consistent, with NEI 97-06, the program monitors secondary side SG components, the failure of which could
 
prevent the SG from fulfilling its intended safety-related function. NEI 97-06 states, "The monitoring shall include design reviews, an assessment of potential
 
degradation mechanisms, industry experience for applicability, and inspection, as
 
necessary, to ensure degradation of these components does not threaten tube
 
structural integrity and leakage integrity or the ability of the plant to achieve and
 
maintain safe shutdown." Inspection requirements are based upon the results of an
 
assessment of SG design, potential degradation mechanisms, and plant-specific
 
and industry operating experience. The program documents inspection results and, when appropriate, uses trends to alter requirements for subsequent inspections.
The staff confirmed that the "monitoring and trending" program element satisfies the
 
criteria defined in the GALL Report and in SRP-LR Section A.1.2.3.5. 
 
The staff finds this program element acceptable.
 
(6) Acceptance Criteria - LRA Section B.3.27 states that acceptance criteria for inspections of secondary side components are based on the inspection method and
 
engineering evaluation. Visual inspections typically use qualitative criteria for
 
detecting degradation sufficient to warrant further evaluation that may involve
 
additional inspection and engineering evaluation to quantify the extent of
 
degradation (e.g., ultrasonic testing to determine actual wall thickness and engineering evaluation to compare the results to the design requirements).
 
Corrective actions can include follow-up inspections to assess the rate of
 
degradation, the need for repair or replacement of the degraded component, or the
 
need for other appropriate action. Any rate of degradation that could cause a loss of
 
SG tube integrity or loss of intended function prior to the next scheduled inspection
 
is unacceptable. When inspection results do not satisfy established acceptance
 
criteria, the program initiates corrective actions The VEGP corrective actions
 
program is consistent with the corrective actions described in Branch Technical
 
Position RLSB-1 in SRP-LR Appendix A.1 and 10 CFR Part 50, Appendix B.
 
3-203 The staff confirmed that the "acceptance criteria" program element satisfies the criteria defined in the GALL Report and in SRP-LR Section A.1.2.3.6. The staff finds
 
this program element acceptable.
(10) Operating Experience - LRA Section B.3.27 states that the program incorporates new industry operating experience and research data for periodic program
 
improvement. EPRI SG guidelines forming the technical basis for the program and updated periodically by EPRI are results of a consensus process. The Steam
 
Generator Program is in accordance with general requirements for engineering
 
programs. Periodic program reviews and assessments ensure compliance with
 
regulatory, process, and procedural requirements. Recent Steam Generator
 
Program performance results show that the program effectively finds and corrects
 
degradation attributable to AERMs. The 2000 Unit 1 SG upper internals inspection
 
observed minor degradation on the feedwater distribution assembly and on one
 
primary moisture separator assembly. The 2002 Unit 2 SG upper internals
 
inspection observed minor degradation on the feedwater distribution assembly. In
 
2004, an extensive engineering review of the SG secondary side conditions and
 
related inspection requirements considered the 2000 and 2002 observations and
 
concluded that the degradation was minor and insignificant in industry experience.
The staff confirmed that the "operating ex perience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff
 
finds this program element acceptable.
 
UFSAR Supplement In LRA Section A.2.27, the applicant provided the UFSAR supplement for the Steam Generator Program for Upper Internals. 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 Steam Generator Program for Upper Internals, the staff concludes that the applicant has demonstrated that effects of
 
aging will be adequately managed so that the intended function(s) will be maintained
 
consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
determined that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
 
3.0.3.3.9  Inservice Inspection Program - IWE 
 
Summary of Technical Information in the Application LRA Section B.3.30 describes the existing Inservice Inspection Program - IWE as a plant-specific program.
 
The applicant stated that the Inservice Inspection (ISI) Program - IWE is in accordance with 10 CFR 50.55(a), which imposes the ISI requirements of ASME Code Section XI, Subsection IWE. The Inservice Inspection Program - IWE manages aging effects for the
 
containment liners and attachments including connecting penetrations and parts forming the leak-tight boundary. The primary inspection method for the ASME Section XI, Subsection IWE Program is periodic visual examination with limited volumetric
 
examinations utilizing ultrasonic thickness measurements as needed.
 
3-204 The applicant also stated that in accordance with 10 CFR 50.55a(g)(4)(ii) and as based on ASME Code Inservice Inspection Program B (I WA-2432), the Inservice Inspection Program - IWE updates at the end of each 120-month inspection interval to the latest code edition
 
and addenda specified in 10 CFR 50.55a twelve months before the start of the next
 
inspection interval. The program's second inspection interval ended in May 2007. The third ISI interval requirements are based on ASME Code Section XI, 2001 Edition including the
 
2002 and 2003 Addenda. 
 
Staff Evaluation In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.3.30 on the applicant's Inservice Inspection Program - IWE 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 Inservice Inspection Program - IWE against the staff's
 
recommended program element criteria that are provided in SRP-LR Section A.1.2.3, and
 
in SRP-LR Table A.1-1. The staff focused its review on assessing how the plant-specific
 
program elements for the Inservice Inspection Program - IWE would ensure adequate
 
aging management when compared to the recomm ended program element criteria that are described in SRP-LR Section A.1.2.3. Specifically, the staff reviewed the following seven
 
(7) program elements of the applicant's program against their corresponding program
 
element criteria that are provided in the subsections to SRP-LR Section A.1.2.3: (1)"scope
 
of the program," (2) "preventive actions," (3) "parameters monitored or inspected," (4)
"detection of aging effects," (5) "monitoring and trending," (6) "acceptance criteria," and (10)
 
"operating experience."
 
The applicant indicated that program elements (7) "corrective actions,"(8) "confirmation
 
process," and (9) "administrative controls" are parts of the site-controlled QA program. The
 
staff evaluated the Inservice Inspection Program's "confirmatory process" and
 
"administrative controls" program elements as part of the staff's evaluation of the applicant's Quality Assurance Program. The staff's evaluation of the applicant's Quality
 
Assurance Program is described in SER Section 3.0.4. The staff's evaluation of the
 
remaining program elements are described in the paragraphs that follow:
 
(1) Scope of the Program - The "scope of the program" program element criterion in SRP-LR Section A.1.2.3.1 requires that the program scope include the specific
 
structures and components addressed with this program.
 
The applicant states in LRA Section B.3.30 that the Inservice Inspection Program -
IWE is credited for managing aging effects for:
The metallic liners (including their integral attachments) for the concrete containments  The penetration sleeves including the personnel airlocks, emergency airlocks, and equipment hatches  The pressure-retaining bolted connections within the boundary of the concrete containment vessels  The seals, gaskets, and moisture barriers The staff concludes that the specific components (metallic liners and integral 3-205 attachments, penetration sleeves, pressure-retaining bolted connections, seals, gaskets, moisture barriers) for which the program manages aging effects are
 
identified, which satisfies the criterion defined in SRP-LR Section A.1.2.3.1. On this
 
basis, the staff finds the applicant's scope of the program acceptable. 
 
The staff confirmed that the "scope of t he program" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.1. The staff finds this program element
 
acceptable.
(2) Preventive Actions - The "preventive acti ons" program element criterion in SRP-LR Section A.1.2.3.2 is that condition moni toring programs do not rely on preventive actions, and thus, preventive actions need not be provided.
The applicant states in LRA Section B.3.30 that the condition-monitoring Inservice
 
Inspection Program - IWE includes no preventive actions.
 
The staff finds this program element acceptable because this is a condition
 
monitoring program and there is no need for preventive actions. On this basis, the
 
staff finds the applicant's preventive actions acceptable.
 
The staff confirmed that the "preventive actions" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.2.
 
(3) Parameters Monitored or Inspected - The "parameters monitored or inspected" program element criterion in SRP-LR Section A.1.2.3.3 are:
The parameter to be monitored or inspected should be
 
identified and linked to the degradation of the particular
 
structure and component intended function(s). The
 
parameters monitored or inspected should detect the
 
presence and extent of aging effects.
The applicant states in LRA Section B.3.30 that the program inspects the primary
 
containment and its attachments for evidence of cracks, wear, and corrosion. 
 
The program monitors loss of material of the containment liners and attachments by inspecting surfaces for visual evidence of flaking, blistering, peeling, discoloration, and other signs of distress.
 
During the audit and review, the staff asked the applicant to explain why the
 
Inservice Inspection Program - IWE progr am element "parameters monitored or inspected" does not appear to credit any inspection of non-coated primary
 
containment surfaces and also clarify whether or not this program credits the requirements of ASME Section XI, paragraph IWE-2310 to monitor for evidence of
 
discoloration, pitting, gouges, surface discontinuities, dents, and other signs of
 
surface irregularities in non-coated containment liner areas. 
 
In its response, the applicant stated that the Inservice Inspection Program - IWE is
 
credited for inspection of non-coated containment liner areas. The inspection of
 
non-coated areas examines for evidence of cracking, discoloration, wear, pitting, excessive corrosion, arc strikes, gouges, surface discontinuities, dents and other 3-206 signs of surface irregularities, which includes the requirements of ASME Section XI, paragraph IWE-2310.
 
The applicant also noted that the visible VEGP primary containment and
 
attachments steel surfaces are coated with a qualified coating. VEGP does not
 
credit coatings for aging management. The protective effects of coatings are not
 
credited when the aging effects requiring management are determined for the
 
underlying component materials. The Inservice Inspection Program - IWE
 
inspections of these coated containment liner surfaces, which examine for evidence
 
of flaking, blistering, peeling, discoloration, and other signs of distress, are credited
 
for license renewal for identify potential degradation of the underlying liner material.
 
The staff finds the program element acceptable on the basis that the applicant inspects the primary containment and its a ttachments for evidence of cracks, wear, and corrosion by monitoring coated surfaces for visual evidence of flaking, blistering, peeling, discoloration, and other signs of distress. The applicant also
 
examines non-coated areas for evidence of cracking, discoloration, wear, pitting, excessive corrosion, arc strikes, gouges, surface discontinuities, dents and other
 
signs of surface irregularities.
 
The staff confirmed that the "parameters m onitored or inspected" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff finds this
 
program element acceptable.
 
(4) Detection of Aging Effects - The "detection of aging effects" program element criteria in SRP-LR Section A.1.2.3.4 are:
 
Provide information that links the parameters to be monitored or
 
inspected to the aging effects being managed.
Describe when, where, and how program data are collected (i.e., all
 
aspects of activities to collect data as part of the program)
Link the method for the inspection population and sample size when
 
sampling is used to inspect a group of SCs. The inspection population
 
should be based on such aspects of the SCs as a similarity of materials
 
of construction, fabrication, procurement, design, installation, operating
 
environment, or aging effects.
The applicant states in LRA Section B.3.30 that the Inservice Inspection Program -
 
IWE manages loss of material and cracking for the primary containment and its
 
integral attachments. The primary inspection method is visual examination either
 
directly or remotely with sufficient illumination and suitable resolution for the
 
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 exam s to measure containment structure wall thickness.
 
The staff finds it acceptable on the basis that the applicant uses visual examination
 
either directly or remotely with sufficient illumination for the environment to detect
 
degraded conditions that may affect the containment structural integrity or leak 3-207 tightness. The applicant uses ultrasonic examinations to measure containment liner wall thickness.
The staff confirmed that the "detection of aging effects" program element satisfies
 
the criterion defined in SRP-LR Section A.1.2.3.4. The staff finds this program
 
element acceptable.
 
(5) Monitoring and Trending - The "monitoring and trending" program element criteria in SRP-LR Section A.1.2.3.5 are:
Monitoring and trending activities should be described, and they
 
should provide predictability of the extent of degradation and thus
 
effect timely corrective or mitigative actions.
This program element should describe how the data collected is
 
evaluated and may also include trending for a forward look. The
 
parameter or indicator trended should be described. 
 
The applicant states in LRA Section B.3.30 that the program establishes inspection frequencies for each inspection interval consistent with ASME Code Section XI as
 
specified in 10 CFR 50.55a(g)(4)(ii). Currently, the Inservice Inspection Program is
 
based on ASME Code Inservice Inspection Program B (IWA-2432). The program
 
compares results to baseline data and other previous test (inspection) results and evaluates indications in accordance with ASME Code Section XI. If the component
 
qualifies with the indication as acceptable for continued service, the program
 
reexamines the area of the indication during subsequent inspections. Examinations that
 
reveal indications that exceed acceptance standards are extended to include additional examinations in accordance with ASME Code Section XI.
 
The staff finds this acceptable on the basis that the program has established inspection
 
frequencies for each inspection interval and inspection results are compared to baseline
 
results and other previous test results for trending. For components with qualified
 
indications for continued service, the program reexamines the area of the indication in
 
later inspections. Component examinations are extended in areas where indications
 
exceed acceptance standards.
The staff confirmed that the "monitoring and trending" program element satisfies the
 
criterion defined in SRP-LR Section A.1.2.3.5. The staff finds this program element
 
acceptable.
(6) Acceptance Criteria - The "acceptance criteria" program element criteria in SRP-LR Section A.1.2.3.6 are:
The acceptance criteria of the program and its basis should be
 
described. The acceptance criteria, against which the need for corrective
 
actions will be evaluated, should ensure that the SC intended function(s)
 
are maintained under all CLB design conditions during the period of
 
extended operation.
 
3-208 The applicant states in LRA Section B.3.30 that a pre-service or baseline inspection of program components prior to startup a ssured freedom from defects greater than code-allowable. The program compares results of inservice inspections to baseline
 
data, other previous test (inspection) results, and acceptance criteria of the ASME Code Section XI standards. ASME Code Section XI, Article IWE-3000 defines
 
Inservice Inspection Program - IWE acceptance standards as applicable.
 
The staff concludes that this program element is acceptable on the basis that
 
acceptance criteria is based on a comparison of inservice inspections to baseline data, other previous test (inspection) results, and the acceptance criteria of the ASME Code Section XI, Subsection IWE.
The staff confirmed that the "acceptance criter ia" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.6. The staff finds this program element acceptable.
  (10) Operating Experience - The "operating experience" program element criterion in SRP-LR Section A.1.2.3.10 is:
The operating experience should provide objective evidence to support
 
the conclusion that the effects of aging will be managed adequately so
 
that the structure and component intended function(s) will be maintained
 
during the period of extended operation.
 
The applicant states in LRA Section B.3.30 that the Inservice Inspection Program - IWE
 
is in accordance with general requirements for engineering programs. Program reviews
 
ensure compliance with regulatory, process, and procedural requirements. ASME Boiler and Pressure Vessel Code Section XI is a consensus document periodically revised to
 
reflect updated guidance based in part on industry operating experience. Inservice
 
Inspection Program - IWE upgrades are based on industry and plant-specific operating
 
experience. Additionally, plant-specific operating experiences are shared among personnel of all three applicant plant sites and corporate offices.
The applicant stated that in 2004 during 2R10, an IWE inspection detected
 
corrosion on the containment liner plate at a few locations and entered it into the
 
Corrective Action Program, which repaired some corrosion locations and evaluated
 
most of the corrosion on the containment liner plate as cosmetic requiring no repair.
 
In 2006 during 1R13, IWE visual inspections detected surface rust anomalies on the
 
Unit 1 containment liner plate and entered them into the Corrective Action Program, which has recommended surface recoating and generated an action Item to track
 
the completion. The applicant further stated that industry and plant-specific
 
operating experience demonstrate that the program is effective in detection and
 
management of aging effects so components crediting this program can perform their intended function consistent with the CLB during the period of extended
 
operation.
 
During the audit and review, the staff noted that the detection of aging effects program element for GALL AMP XI.S1, ASME Section XI, Subsection IWE; states that ASME Section XI paragraph IWE-1240 requires augmented examinations of
 
containment surface areas that are subject to degradation. The staff asked the
 
applicant to explain historically what inspection findings under the VEGP Inservice 3-209 Inspection Program - IWE, have lead to the need for augmented inspections. The applicant was also asked to explain if any augmented inspections are currently
 
being performed on the containment surfaces, and if so, clarify the containment
 
locations within the scope of the augmented inspections and what the inspections
 
involve.
 
In its response, the applicant stated that IWE-1241 requires augmented
 
examinations of interior and exterior containment surface areas subjected to (a) accelerated corrosion with no or minimal corrosion allowance, and (b) excessive
 
wear from abrasion or erosion that causes a loss of protective coatings, deformation, or material loss. The VEGP IWE inspections have not identified any
 
areas which require augmented examination.
 
The applicant also stated that although not an augmented inspection, the liner plate
 
was examined following the removal of a portion the moisture seal. As identified in
 
the 1R9 NIS (Nuclear Inspection Service) Report, a small area of the moisture seal
 
was removed following the identification of surface rust at the mating surface
 
between the moisture seal and the containment liner plate. The liner plate was
 
examined following the removal of the moisture seal and no liner plate damage was
 
found. As a good practice since 1R9, VEGP performs a VT-3 of 100% of the
 
moisture barrier every period and UT measurements of liner plate thickness at
 
different locations.
 
The staff finds the applicant's response acceptable because it explains that the
 
VEGP IWE inspections have not identified any areas which require augmented
 
examination, indicating containment liner aging is being managed well by the
 
program.
 
During the audit and review, the staff reviewed a sample of the operating experience
 
referenced in the basis document for the Inservice Inspection Program - IWE and in
 
the LRA. The staff also reviewed a sample of condition reports. For example, in one
 
condition report reviewed by the staff, the condition report identified corrosion in
 
multiple locations around the Unit 2 moisture barrier between the base mat and liner
 
plate at elevation 171 foot. The corrosion was identified under the Inservice
 
Inspection Program - IWE. The condition was evaluated and determined to be
 
nonstructural with no effect on the structural integrity of the containment. The
 
condition was to be reexamined during the next inspection period in accordance
 
with the ASME code. No further condition reports were written on the original
 
finding. In another condition report, the applicant identified surface rust anomalies
 
on the Unit 1 containment liner plate during IWE visual inspections on level 2 and
 
level 3. The condition was determined to be acceptable until recoating of the surface
 
could be performed during the next refueling outage. 
 
The staff finds that the review of the operating experience documented in the basis
 
document for the Inservice Inspection Program - IWE did not reveal any unusual or
 
significant findings.
 
The staff confirmed that the "operating ex perience" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.10. The staff finds this program element
 
acceptable.
 
3-210 UFSAR Supplement In LRA Section A.2.30, the applicant provided the UFSAR supplement for the Inservice Inspection Program - IWE. 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 - IWE, the staff concludes that the applicant has demonstrated that effects of
 
aging will be adequately managed so that the intended function(s) will be maintained
 
consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
determined that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
 
3.0.3.3.10  Inservice Inspection Program - IWL 
 
Summary of Technical Information in the Application LRA Section B.3.31 describes the existing Inservice Inspection Program - IWL as a plant-specific program. 
 
The applicant stated that the Inservice Inspection Program - IWL is in accordance with 10 CFR 50.55(a), which imposes the ISI requirements of ASME Code Section XI, Subsection IWL, for Class CC components. 
 
The program manages the reinforced concrete and unbonded post-tensioning systems of
 
the containment structures.
 
The applicant also stated that in accordance with 10 CFR 50.55a(g)(4)(ii) and as based on
 
ASME Code Inservice Inspection Program B (I WA-2432), the Inservice Inspection Program - IWL is updated at the end of each 120-month inspection interval to the latest edition and
 
addenda of the Code specified in 10 CFR 50.55a twelve months before the start of the next
 
inspection interval. The program's second inspection interval ended in May 2007. The third ISI interval requirements are based on the ASME Code, Section XI, 2001 Edition including
 
the 2002 and 2003 Addenda. 
 
Staff Evaluation In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.3.31 on the applicant's Inservice Inspection Program - IWL 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 Inservice Inspection Program - IWL against the staff's recommended
 
program element criteria that are provided in SRP-LR Section A.1.2.3, and in SRP-LR Table A.1-1. The staff focused its review on assessing how the plant-specific program
 
elements for the Inservice Inspection Program - IWL would ensure adequate aging
 
management when compared to the recommended program element criteria that are described in SRP-LR Section A.1.2.3. Specifically, the staff reviewed the following seven
 
(7) program elements of the applicant's program against their corresponding program
 
element criteria that are provided in the subsections to SRP-LR Section A.1.2.3: (1)"scope
 
of the program," (2) "preventive actions," (3) "parameters monitored or inspected," (4)
"detection of aging effects," (5) "monitoring and trending," (6) "acceptance criteria," and (10)
 
"operating experience."
 
3-211 The applicant indicated that program elements (7) "corrective actions,"(8) "confirmation process," and (9) "administrative controls" are parts of the site-controlled QA program. The
 
staff evaluated the Inservice Inspection Program's "confirmatory process" and
 
"administrative controls" program elements as part of the staff's evaluation of the applicant's Quality Assurance Program. The staff's evaluation of the applicant's Quality
 
Assurance Program is described in SER Section 3.0.4. The staff's evaluation of the
 
remaining program elements are described in the paragraphs that follow:
 
(1) Scope of the Program - The "scope of the program" program element criterion in SRP-LR Section A.1.2.3.1 requires that the program scope include the specific
 
structures and components addressed with this program.
The applicant states in LRA Section B.3.31 that the Inservice Inspection Program -
IWL, under ASME Code Section XI, Subsection IWL, manages reinforced concrete
 
and unbonded post-tensioning systems of Class CC containments. The primary
 
containment is a prestressed concrete post-tensioned system. The containment
 
structure construction code is ASME Code Section III, 1977 Edition. The ASME Code Section XI inspection categories credited for license renewal are all applicable
 
IWL examination categories L-A and L-B.
 
The staff concludes that the specific components (reinforced concrete and
 
unbonded post-tensioning systems of Class CC containments) for which the
 
program manages aging effects are identified, which satisfies the criterion defined in
 
SRP-LR Section A.1.2.3.1. On this basis, the staff finds the applicant's "scope of the
 
program" element acceptable.
The staff confirmed that the "scope of t he program" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.1. The staff finds this program element
 
acceptable. (2) Preventive Actions - The "preventive actions
" program element criterion in SRP-LR Section A.1.2.3.2 is that condition moni toring programs do not rely on preventive actions, and thus, preventive actions need not be provided.
 
The applicant states in LRA Section B.3.31 that the condition-monitoring Inservice
 
Inspection Program - IWL includes no preventive actions.
 
The staff confirmed that the "preventive actions" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.2. The staff finds this program element
 
acceptable because this is a condition monitoring program and there is no need for
 
preventive actions. On this basis, the staff finds the applicant's preventive actions
 
acceptable.
(3) Parameters Monitored or Inspected - The "parameters monitored or inspected" program element criterion in SRP-LR Section A.1.2.3.3 are:
 
The parameter to be monitored or inspected should be identified and
 
linked to the degradation of the particular structure and component
 
intended function(s). The parameters monitored or inspected should
 
detect the presence and extent of aging effects.
 
3-212 The applicant states in LRA Section B.3.31 that the program examines primary containment concrete surfaces and concrete surfaces surrounding tendon
 
anchorages for evidence of damage or degradation like concrete cracks. Tendon
 
anchorages and wires are visually examined for cracks, corrosion, and mechanical
 
damage in addition to testing sample wires for yield strength, ultimate tensile
 
strength and elongation. The tendon corrosion protection medium is analyzed for
 
alkalinity, water content, and soluble ion concentration.
 
The staff concludes that this program element is acceptable on the basis that the
 
applicant inspects primary containment c oncrete surfaces and concrete surfaces surrounding tendon anchorages for evidence of damage or degradation. In addition, tendon anchorages and wires are visually examined for cracks, corrosion, and
 
mechanical damage in addition to testing sample wires for yield strength, ultimate
 
tensile strength and elongation. Finally, the tendon corrosion protection medium is
 
analyzed for alkalinity, water content, and soluble ion concentration.
 
The staff confirmed that the "parameters m onitored or inspected" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff finds this
 
program element acceptable.
 
(4) Detection of Aging Effects - The "detection of aging effects" program element criteria in SRP-LR Section A.1.2.3.4 are:
 
Provide information that links the parameters to be monitored or
 
inspected to the aging effects being managed.
 
Describe when, where, and how program data are collected (i.e., all aspects of activities to collect data as part of the
 
program)  Link the method for the inspection population and sample size when
 
sampling is used to inspect a group of SCs. The inspection population
 
should be based on such aspects of the SCs as a similarity of materials
 
of construction, fabrication, procurement, design, installation, operating
 
environment, or aging effects.
 
The applicant states in LRA Section B.3.31 that the program inspects containment
 
concrete, tendon end anchorage, and post-tensioning systems at five-year intervals as specified in ASME Code Section XI, Article IWL-2400. The program examines
 
the entire accessible concrete surface and all accessible tendon end anchorage
 
areas during each inspection. Detection methods for aging effects are visual VT-3
 
examination of all concrete surfaces and a more rigorous VT-1 or VT-1 examination
 
for selected areas (e.g., those indicating suspect conditions and areas surrounding
 
tendon anchorages). Detection of loss of tendon wire prestressing forces is by
 
tendon inspections and analyses in accordance with plant procedures and by
 
surveillance tests. For tendons, the program selects only random samples of each
 
tendon type for examination at each inspection. The minimum number of each type
 
tendon selected varies from 2 to 4 percent. The program measures prestressing
 
forces in sample tendons, detensions one sample tendon of each type, and
 
removes a single wire or strand from each detensioned tendon for examination and 3-213 testing. These visual examination methods with testing detect aging effects of accessible concrete components and prestressing systems in concrete
 
containments before design-basis requirements are compromised.
 
The staff concludes that this program element satisfies the criteria defined in SRP-
 
LR Section A.1.2.3.4. The staff finds it acceptable on the basis that the applicant
 
uses a visual VT-3C examination of all containment concrete surfaces and a more
 
rigorous VT-1 or VT-1C examination for selected areas to detect concrete and steel
 
aging effects at five year intervals. In addition, every five years the detection of loss
 
of tendon wire prestressing forces is by tendon inspections and analyses through
 
surveillance tests; with a minimum number of randomly selected tendons of each
 
type being tested. Sample wires are removed from each tendon type for
 
examination and testing also. 
 
The staff confirmed that the "detection of aging effects" program element satisfies
 
the criterion defined in SRP-LR Section A.1.2.3.4. The staff finds this program
 
element acceptable.
 
(5) Monitoring and Trending - The "monitoring and trending" program element criteria in SRP-LR Section A.1.2.3.5 are:
Monitoring and trending activities should be described, and they should
 
provide predictability of the extent of degradation and thus effect timely
 
corrective or mitigative actions.
 
This program element should describe how the data collected is
 
evaluated and may also include trending for a forward look. The
 
parameter or indicator trended should be described.
The applicant states in LRA Section B.3.31 that the program compares results to
 
baseline data and other previous test results and monitors, except in inaccessible
 
areas, all concrete surfaces regularly by virtue of examination requirements.
Trending of prestressing forces in tendons is in accordance with 10 CFR 50.55a and ASME Code Section XI, Subsection IWL. The program compares prestressing
 
forces in all inspection sample tendons measured by lift-off tests to acceptance
 
standards based on the predicted force for that type of tendon over its life.
 
The staff concludes that this program element satisfies the criteria defined in SRP-
 
LR Section A.1.2.3.5. The staff finds it acceptable on the basis that the program
 
compares inspection and test results to baseline data and other previous test results
 
and monitors concrete surfaces regularly. Monitoring and trending of prestressing
 
forces in tendons is performed every five years. The prestressing forces in all
 
inspection sample tendons are measured by lift-off tests and compared with
 
acceptance standards based on the predicted force for that type of tendon over its
 
life.
 
The staff confirmed that the "monitoring and trending" program element satisfies the
 
criterion defined in SRP-LR Section A.1.2.3.5. The staff finds this program element
 
acceptable.
(6) Acceptance Criteria - The "acceptance criteria" program element criteria in SRP-LR Section A.1.2.3.6 are:
3-214  The acceptance criteria of the program and its basis should be
 
described. The acceptance criteria, against which the need for corrective
 
actions will be evaluated, should ensure that the SC intended function(s)
 
are maintained under all CLB design conditions during the period of
 
extended operation.
The applicant states in LRA Section B.3.31 that the program compares results to
 
baseline data, other previous test results, and acceptance criteria of the ASME Code Section XI, Subsection IWL, for evaluation of any evidence of degradation.
 
The acceptance criteria are qualitative with guidance provided in Section IWL-2510
 
and references like American Concrete Institute (ACI) 201.1R and ACI 349.3R for
 
detection of concrete degradation. Predicted tendon forces are calculated in
 
accordance with Subsection IWL and Regulatory Guide 1.35.1, which provides an
 
acceptable methodology for use through the period of extended operation.
The staff concludes that this program element is acceptable on the basis that
 
acceptance criteria is based on a comparison of inservice inspections to baseline
 
data, other previous test (inspection) results, and the acceptance criteria of the ASME Code Section XI, Subsection IWL. Predicted tendon forces are calculated in
 
accordance with Regulatory Guide 1.35.1 for comparison with tendon liftoff force
 
test results.
 
The staff confirmed that the "acceptance criteria" program element satisfies the
 
criterion defined in SRP-LR Section A.1.2.3.6. The staff finds this program element
 
acceptable.
(10) Operating Experience - The "operating ex perience" program element criterion in SRP-LR Section A.1.2.3.10 is:
The operating experience should provide objective evidence to support
 
the conclusion that the effects of aging will be managed adequately so
 
that the structure and component intended function(s) will be maintained
 
during the period of extended operation.
The applicant states in LRA Section B.3.31 that the Inservice Inspection Program -
 
IWL is in accordance with general requirements for engineering programs. Program
 
reviews ensure compliance with regulatory, process, and procedural requirements.
The ASME Boiler and Pressure Vessel Code Section XI is a consensus document
 
periodically revised to reflect updated guidance based in part on industry operating
 
experience. Inservice Inspection Program - IWL upgrades are based upon industry
 
and plant-specific operating experience. Additionally, plant-specific operating
 
experiences are shared among the personnel of all three applicant plant sites and
 
corporate offices.
 
The applicant stated that the program has observed and documented for the
 
containment buildings many cracks which are typical in prestressed and reinforced
 
concrete structures. Some of the cracks are near or exceeding acceptable width
 
thresholds; however, the responsible engineer has determined that all are of no
 
structural significance. Indications of staining, cracking, exposed aggregate and
 
spalling have been identified on the containments and were characterized as minor.
3-215 No signs of corrosion in the cracks were noted. The spalling was acceptable because the condition had no effect on structural integrity. There was no active
 
degradation noted and the structural integrity of the containment structure was
 
unaffected. The applicant further stated that industry and plant-specific operating
 
experience demonstrate the effectiveness of the program at detecting and
 
managing aging effects so components crediting this program can perform their
 
intended functions consistent with the CLB during the period of extended operation.
 
During the audit and review, the staff noted that the tendon data for year 2005, as
 
provided in LRA Table 4.5-2, Concrete Containment Tendon Pre-stress, shows that
 
the predicted average tendon force is different for individual Unit 2 inverted U
 
vertical tendons. Also in LRA Table 4.5-4 for year 2005, the predicted average
 
tendon force is different for individual Unit 2 horizontal (shell) hoop tendons. This
 
phenomenon only appears in these two tables for the year 2005. The staff asked
 
the applicant to explain why the predicted average tendon force varies by individual
 
tendon in these two tables for year 2005. In its response, the applicant stated that
 
the predicted average tendon forces in LRA Table 4.5-2 for the individual Unit 2
 
inverted U vertical tendons are incorrect. The correct values should be 1463 Kips for
 
Tendon Numbers V20-92, V21-91 and V56-130. The predicted average tendon
 
forces in LRA Table 4.5-4 for the individual Unit 2 horizontal (shell) hoop tendons
 
are incorrect. The correct values should be 1427 Kips for Tendon Numbers H-66, H-99 and H-111. These changes do not affect the graphs described in the LRA. The
 
graphs are drawn based on actual data not the predicted data.
 
In its response, the applicant further stated that the LRA will be amended to correct
 
this discrepancy. The staff confirmed that the applicant revised the LRA in a letter
 
dated February 8, 2008.
 
The staff finds the applicant's response acceptable. The values shown in LRA
 
Table 4.5-2 for the individual Unit 2 inverted U vertical tendons and in LRA Table
 
4.5-4 for the individual Unit 2 horizontal hoop tendons are incorrect and will be
 
corrected by a license renewal application amendment. The correct values have
 
been provided which are more appropriate and agree with the graphs in the LRA.
During the audit and review, the staff reviewed a sample of the operating experience referenced in the basis document for the Inservice Inspection Program - IWL. The
 
staff also reviewed a sample of condition reports. For example, one condition report
 
identified the failure of two vertical tendon wires in one vertical tendon during
 
retensioning on the Unit 1 containment. The two broken wires were removed from
 
the tendon and the tendon was retensioned to an acceptable force based on the
 
reduced number of wires. No further action was identified and the final condition of
 
the tendon was determined to be acceptable. 
 
During audit and review discussions, the staff asked the applicant to discuss the
 
staining, spalling and cracks which were identified on the containment structures
 
and then determined by the responsible engineer to have no structural significance.
 
The applicant stated during the discussions that the staining was very minor and
 
from tendon sheathing grease leakage and not rebars corroding. The applicant
 
further stated that the spalling was not significant and did not threaten the minimum
 
specified concrete cover for rebar and tendon sheathes. The applicant also stated 3-216 that there were no signs of rebar corrosion at the surface cracks in the containment concrete.
 
The staff finds the applicant's review and evaluation of the inspection findings for
 
the VEGP containment structures acceptable because all the inspection findings
 
were determined to be minor without any structural significance and not out of the
 
ordinary for concrete structures. 
 
The staff finds that the discussions with the applicant about historic IWL inspection
 
results and review of the operating experience provided in the basis document for
 
the Inservice Inspection Program - IWL did not reveal any unusual or significant
 
findings.
 
The staff confirmed that the "operating ex perience" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.10. The staff finds this program element
 
acceptable.
 
UFSAR Supplement In LRA Section A.2.31, the applicant provided the UFSAR supplement for the Inservice Inspection Program - IWL. 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 - IWL, the staff concludes that the applicant has demonstrated that effects of
 
aging will be adequately managed so that the intended function(s) will be maintained
 
consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). 
 
The staff also reviewed the UFSAR supplement for this AMP and determined that it
 
provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
 
3.0.3.3.11  Non-EQ Cable Connections One-Time Inspection Program 
 
Summary of Technical Information in the Application LRA Section B.3.36 describes the new Non-EQ Cable Connections One-Time Inspecti on Program as a plant-specific program. 
 
The Non-EQ Cable Connections One-Time Ins pection Program uses one-time inspections on a sample of bolted connections within the scope of license renewal to confirm that
 
loosening of electrical connections is not an aging effect requiring additional aging
 
management during the period of extended operation. The program inspects for loosening
 
of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation.
 
The factors considered for sample selection are application (medium and low voltage
 
defined as <35kV), circuit loading (high loading), and location (high temperature, high
 
humidity, vibration, etc.). The technical basis for the sample selections will be documented.
 
Inspections may be by thermography, contact resistance testing, or other appropriate
 
methods including visual inspection based on plant configuration and industry guidance. 
 
3-217 The applicant identified Commitment No. 27 to be implemented prior to the period of extended operation. If there is an unacceptable condition or situation in the selected
 
sample, the Corrective Action Program will evaluate the condition and determine an
 
appropriate corrective action.
 
The Non-EQ Cable Connections One-Time Inspection Program adds assurance that
 
electrical cable connections will perform intended function for the period of extended
 
operation. This plant-specific AMP is an alternative to the program described in GALL Report Section XI.E6. The inspections will be within ten years immediately preceding 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.3.36 on the applicant's demonstration of the Non-EQ Cable Connections
 
One-Time 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 Non-EQ Cable Connections One-Time Inspection Program against
 
the staff's recommended program element cr iteria that are provided in SRP-LR Section A.1.2.3, and in SRP-LR Table A.1-1. The staff focused its review on assessing how
 
the plant-specific program elements for the Non-EQ Cable Connections One-Time Inspection Program would ensure adequate aging management when compared to the recommended program element criteria that are described in SRP-LR Section A.1.2.3.
 
Specifically, the staff reviewed the following seven (7) program elements of the applicant's
 
program against their corresponding program elem ent criteria that are provided in the subsections to SRP-LR Section A.1.2.3: (1)"scope of the program," (2) "preventive actions,"
 
(3) "parameters monitored or inspected," (4) "detection of aging effects," (5) "monitoring and
 
trending," (6) "acceptance criteria," and (10) "operating experience."
 
The applicant indicated that program elements (7) "corrective actions,"(8) "confirmation
 
process," and (9) "administrative controls" are parts of the site-controlled QA program. The
 
staff evaluated the Inservice Inspection Program's "confirmatory process" and
 
"administrative controls" program elements as part of the staff's evaluation of the applicant's Quality Assurance Program. The staff's evaluation of the applicant's Quality
 
Assurance Program is described in SER Section 3.0.4. The staff's evaluation of the
 
remaining program elements are described in the paragraphs that follow:
 
(1) Scope of the Program - The "scope of program" program element criterion in SRP-LR Appendix A.1.2.3.1 requires that the program scope include the specific
 
structures and components addressed with this program.
LRA Section B.3.36 states that the scope of this program is defined as the Non-EQ
 
connections for cables within the scope of license renewal. Cable connections
 
connect cable conductors to other cables or electrical devices. Cable connections within the scope of license renewal are in the sample set for this program. Most
 
connections have insulating material and metallic parts. This AMP for electrical
 
cable connections (metallic parts) manages loosening of bolted connections due to
 
thermal cycling, ohmic heating, electrical transients, vibration, chemical
 
contamination, corrosion, and oxidation. Circuits exposed to appreciable ohmic or
 
ambient heating during operation may experience loosening from repeat cycling of
 
connected loads or cycling of the ambient temperature. Cable connections may 3-218 loosen if subjected to significant thermally-induced cyclic stress. The design of these connections accounts for the stresses of ohmic heating and thermal cycling;
 
therefore, these stressors should not be a significant aging issue but confirmation of
 
the lack of aging effects is warranted.
The staff interviewed the applicant's technical personnel and reviewed the Non-EQ
 
Cable Connections One-Time Inspection Program bases documents.
The staff concludes that the specific commodity groups for which the program manages aging
 
effects are identified (Non-EQ bolted cable connections associated with cables
 
within the scope of license renewal), which satisfies the criterion defined in SRP-LR
 
Appendix A.1.2.3.1. The staff also determined that the exclusion of high-voltage
 
(>35 kV) switchyard connections, connections covered under EQ program and the
 
existing PM program, acceptable. 
 
Switchyard connections are addressed in SER Section 3.6.2.2. EQ cable
 
connections are covered under 10 CFR 50.49. Cable connections under PM
 
program are periodically inspected. On this basis, the staff finds that the applicant's
 
scope of program acceptable.
In LRA AMP B.3.36, "Non-EQ Cable Connections One-time Inspection Program,"
under "Program Description," "and Detection of Aging Effects," Sections, the applicant states that the inspections will be performed within a window of five years
 
immediately preceding the period of extended operation for the first unit (Unit 1) and
 
in the following paragraph, the applicant states that the inspections will be
 
performed within a window of ten years immediately preceding the period of
 
extended operation. During the audit and review, the staff asked the applicant to
 
clarify when this one-time inspection will be completed for each of the VEGP Units.
 
In its response, the applicant stated that the LRA will be amended to state that the
 
inspections for both units will be performed within a window of five years
 
immediately proceeding the period of extended operation. In its letter dated March
 
20, 2008, the applicant amended the LRA to correct this discrepancy.
The staff confirmed that the "scope of t he program" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1. The staff
 
finds this program element acceptable.
(2) Preventive Actions - The "preventive acti ons" program element criterion in SRP-LR Appendix A.1.2.3.2 is that condition moni toring programs do not rely on preventive actions, and thus, preventive actions need not be provided.
LRA Section B.3.36 states that the condition-monitoring Non-EQ Cable Connections
 
One-Time Inspection Program takes no actions to prevent or mitigate aging
 
degradation.
The staff concludes that the preventive actions program element satisfies the criterion 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 applicant's preventive actions acceptable.
 
3-219 The staff confirmed that the "preventive actions" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.2. The staff
 
finds this program element acceptable.
(3) Parameters Monitored or Inspected - The "parameter monitored or inspected" program element criterion in SRP-LR Appendix A.1.2.3.3 are:
The parameter to be monitored or inspected should be identified and linked to the
 
degradation of the particular structure and component intended function(s). The
 
parameter monitored or inspected should detect the presence and extent of aging
 
effects. LRA Section B.3.36 states that this program will focus on the metallic parts of cable
 
connections. The one-time inspection verifies that loosening of bolted connections
 
due to thermal cycling, ohmic heating, electrical transients, vibration, chemical
 
contamination, corrosion, and oxidation is not an aging effect requiring a periodic
 
AMP. Parameters inspected vary with the detection method.
The staff concludes that the parameters monitored/inspected program element
 
satisfies the criterion 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 applicant's parameters monitored or inspected acceptable.
The staff confirmed that the "parameters m onitored or inspected" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.3.
 
The staff finds this program element acceptable.
 
(4) Detection of Aging Effects - The "detection of aging effects" program element criteria in SRP-LR Appendix A.1.2.3.4 are:
 
Provide information that links the parameters to be monitored or inspected to
 
the aging effects being managed.
 
Describe when, where, and how program data are collected (i.e., all aspects
 
of activities to collect data as part of the program)
 
Link the method for the inspection population and sample size when sampling is
 
used to inspect a group of structures and components (SCs). The inspection
 
population should be based on such aspects of the SCs as a similarity of materials
 
of construction, fabrication, procurement, design, installation, operating
 
environment, or aging effects.
 
LRA Section B.3.36 states that the program will inspect or test a representative
 
sample of electrical connections within the scope of license renewal and subject to
 
an AMR within five years immediately preceding the period of extended operation of
 
the first unit (VEGP Unit 1) to confirm there are no AERMs during the period of
 
extended operation. The factors considered for sample selection will be application 3-220 (medium and low voltage), circuit loading (high-loading), and location (high temperature, high humidity, vibration, etc.). The technical basis for the sample
 
selection will be documented. Inspections may be by thermography, contact
 
resistance testing, or other appropriate methods including visual inspection based
 
on plant configuration and industry guidance. The one-time inspection adds
 
confirmation to support industry operating experience showing that electrical
 
connections have not experienced a high degree of failures and that existing
 
installation and maintenance practices are effective. 
 
During the audit and review, the staff asked the applicant to explain how it would be
 
able to provide an indication of the integrity of the cable connections by visual
 
inspection. In its response, the applicant stated that LRA, Appendix B, Section
 
B.3.36, "detection of aging effects," to delete visual inspection from the inspection
 
method to verify the integrity of the cable connections. 
 
In its letter dated March 20, 2008, the applicant amended the LRA, Appendix B, Section B.3.36 to state that inspection may include thermography, contact
 
resistance testing, or other appropriate methods.
The staff concludes that this program element satisfies the criteria defined in SRP-
 
LR Appendix A.1.2.3.4. Thermography is used to detect loose connections by
 
monitoring higher than normal temperature 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. The staff also determined 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 the applicant's detection of aging effects acceptable.
The staff confirmed that the "detection of aging effects" program element satisfies
 
the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.4. The staff
 
finds this program element acceptable.
(5) Monitoring and Trending - The "monitoring and trending" program element criteria in SRP-LR Appendix A Section A.1.2.3.5 are:
Monitoring and trending activities should be described, and they should
 
provide predictability of the extent of degradation and thus effect timely
 
corrective or mitigative actions.
This program element should describe how the data collected are evaluated
 
and may also include trending for a forward look. The parameter or indicator
 
trended should be described.
LRA Section B.3.36 states that trending actions are not included as parts of this
 
one-time inspection program.
The staff concludes 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 3-221 available data. Furthermore, the staff did not see a need for such activities. On this basis, the staff finds the applicant's monitoring and trending acceptable.
The staff confirmed that the "monitoring and trending" program element satisfies the
 
criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.5. The staff
 
finds this program element acceptable.
(6) Acceptance Criteria -  Acceptance Criteria - The "acceptance criteria" program element criteria in SRP-LR Appendix A.1.2.3.6 are:
The acceptance criteria of the program and its basis should be described.
 
The acceptance criteria, against which the need for corrective actions will be
 
evaluated, should ensure that the SC intended function(s) are maintained
 
under all CLB design conditions during the period of extended operation.
The program should include a methodology for analyzing the results against
 
applicable acceptance criteria.
 
Qualitative inspections should be performed to same predetermined criteria as
 
quantitative inspections by personnel in accordance with ASME Code and through
 
approved site-specific programs. LRA Section B.3.36 states that the acceptance
 
criteria for each inspection or surveillance are defined by the specific inspection or
 
test for the specific type of cable connection. Acceptance criteria selected will
 
indicate loose connection (e.g., higher than normal temperature at the connection, high resistance, observed looseness, etc.)
 
The staff concludes 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
 
current licensing basis.
 
The staff confirmed that the "acceptance criteria" program element satisfies the
 
criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.6. The staff
 
finds this program element acceptable.
 
(10) Operating Experience - The "operating ex perience" program element criterion in SRP-LR Appendix A.1.2.3.10 that operating experience should provide objective
 
evidence to support the conclusion that the effects of aging will be managed
 
adequately so that the structure and component intended function(s) will be
 
maintained during the period of extended operation.
LRA Section B.3.36 states that the new Non-EQ Cable Connections One-Time
 
Inspection Program has no programmatic history; however, as noted in GALL
 
Report, industry operating experience shows that loosening of connections and
 
corrosion of connections could be problems without proper installation and
 
maintenance. Industry operating experience supports this one-time inspection
 
program in lieu of periodic testing. This one-time inspection program will confirm the
 
effectiveness of installation and maintenance activities. Development of this 3-222 program considered plant-specific and industry operating experience. Industry operating experience that forms the basis for the program appears in the operating experience element of the GALL Report, Section XI.E6, program description. Plant-
 
specific operating experience is consistent with that program description.
In search of operating experience to respond to NEI's concerns about the lack of operating experience to support GALL AMP XI.E6 (NEI's White Paper on GALL AMP XI.E6, dated September 5, 2006), the staff confirmed that very little of the
 
operating experience that related to failed connections due to aging have been
 
identified and this operating experience can 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 PM program is effective such that a periodic inspection
 
program is not required.
The staff confirmed that the "operating ex perience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff
 
finds this program element acceptable.
 
UFSAR Supplement In LRA Section A.2.36, the applicant provided the UFSAR supplement for the Non-EQ Cable Connections One-Time Inspection Program. The staff reviewed the
 
applicant's license renewal commitment list in a letter dated February 08, 2008, and
 
confirmed that this new program is identif ied as Commitment No. 27 to be implemented for both units within a window of five years immediately proceeding the period of extended
 
operation. 
 
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 Non-EQ Cable Connections One-Time Inspection Program, the staff concludes that the applicant has
 
demonstrated that effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this
 
AMP and determined that it provides an adequate summary description of the program, as
 
required by 10 CFR 54.21(d).
 
3.0.4  Quality Assurance Program Attribut es Integral to Aging Management Programs 3.0.4.1 Summary of Technical Information in Application In Sections A.2.0, A Aging Management Programs,@ and B.1.3, A Aging Management Program Quality Control Attributes,@ of the license renewal application (LRA), the applicant described the elements of corrective action, confirmation process, and administrative controls that are applied to the aging management programs (AMPs) for both safety-related (SR) and nonsafety-related components. The VEGP quality assurance program (QAP) is
 
used which includes the elements of corrective action, confirmation process, and
 
administrative controls. Corrective actions, c onfirmation, and administrative controls are applied in accordance with the QAP regardless of the safety classification of the
 
components. Specifically, in Section A.2.0 and Section B.1.3, respectively, the applicant 3-223 stated that the QAP implements the requirements of 10 CFR 50, Appendix B, and is consistent with NUREG-1801, A Generic Aging Lessons Learned (GALL) Report.
@  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 structure and components (SCs) subject to an aging management review (AMR)
 
will be adequately managed so that their intended functions will be maintained consistent
 
with the current licensing basis (CLB) for the period of extended operation. The SRP-LR, Branch Technical Position RLSB-1, A 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 controls. Table
 
A.1-1, A Elements of an Aging Management Program for license Renewal,@ of Branch Technical Position RLSB-1 provides the following description of these quality attributes:
$ Attribute No. 7 - Corrective Actions, including root cause determination and prevention of recurrence, should be timely;
 
$ Attribute No. 8 - Confirmation Process, which should ensure that preventive actions are adequate and that appropriate corrective actions have been completed and are effective; and, 
$ Attribute No. 9 - Administrative Controls, which should provide a formal review and approval process.
The SRP-LR, Branch Technical Position IQMB-1 noted that those aspects of the AMP that
 
affect quality of safety-related structures, systems and components (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 10 CFR Part 50 QAP may
 
be used to address the elements of corrective action, confirmation process, and
 
administrative control. Branch Technical Position IQMB-1 provides the following guidance
 
with regard to the QA attributes of AMPs:
 
A 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 supplement
 
in accordance with 10 CFR 54.21(d).
@  The NRC staff reviewed the applicant
=s AMPs described in Appendix A, A Final Safety Analysis Report Supplement,@ and Appendix B, A Aging Management Programs and Activities,@ of the LRA, and the associated implementing documents. The purpose of this review was to ensure that the QA attributes (corrective action, confirmation process, and administrative controls) were consistent with the staff
=s guidance described in the SRP-LR, Section A.2, A Quality Assurance for Aging Management Programs (Branch Technical Position IQMB-1).
@  Based on the NRC staff
=s evaluation, the descriptions of the AMPs and their associated quality attributes provided in Appendix A, Section A.2.0, and Appendix B, 3-224 Section B.1.3, of the LRA are consistent with the staff
=s position regarding QA for aging management.
3.0.4.3 Conclusion On the basis of the NRC staff
=s evaluation, the descriptions and applicability of the plant-specific AMPs and their associated quality attributes provided in Appendix A, Section A.2.0, and Appendix B, Section B.1.3 of the LRA, were determined to be consistent with the
 
staff=s position regarding QA for aging management. The staff concludes that the QA attributes (corrective action, confirmation process, and administrative control) of the applicant's AMPs are consistent with 10 CFR 54.21(a)(3).
3.1  Aging Management of Reactor Vessel, Reactor Vessel Internals, and Reactor Coolant System This section of the SER documents the staff's review of the applicant's AMR results for the
 
reactor vessel, reactor vessel internals, and reactor coolant system components and
 
component groups of:
 
reactor vessel  reactor vessel internals  RCS and connected lines (includes the reactor coolant pumps)  pressurizer  SGs  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
 
RCS components and component groups. LRA Table 3.1.1, "Summary of Aging
 
Management Evaluations for Reactor Vessel, Reactor Vessel Internals, and Reactor
 
Coolant System in Chapter IV of NUREG-1801," is a summary comparison of the
 
applicant's AMRs with those evaluated in the GALL Report for the reactor vessel, reactor
 
vessel internals, and RCS components and component groups.
 
The applicant's AMRs evaluated and incorporated applicable plant-specific and industry
 
operating experience in the determination of AERMs. The plant-specific evaluation included
 
condition reports and discussions with appropriate site personnel to identify AERMs. The
 
applicant's review of industry operating experience included a review of the GALL Report
 
and operating experience issues identified since the issuance of the GALL Report.
 
3.1.2  Staff Evaluation The staff reviewed LRA Section 3.1 to determine whether the applicant provided sufficient
 
information to demonstrate that the effects of aging for the reactor vessel, reactor vessel
 
internals, and RCS components within the scope of license renewal and subject to an AMR, will be adequately managed so that the intended function(s) will be maintained consistent
 
with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
The staff conducted an audit of AMRs to ensure the applicant's claim that certain AMRs
 
were consistent with the GALL Report. The staff did not repeat its review of the matters 3-225 described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report
 
AMRs. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details
 
of the staff's audit evaluation are documented in SER Section 3.1.2.1.
 
In the audit, the staff also selected AMRs consistent with the GALL Report and for which
 
further evaluation is recommended. The staff confirmed that the applicant's further
 
evaluations were consistent with the SRP-LR Section 3.1.2.2 acceptance criteria. The
 
staff's audit evaluations are documented in SER Section 3.1.2.2.
 
The staff also conducted a technical review of the remaining AMRs not consistent with or
 
not addressed in the GALL Report. The technical review evaluated whether all plausible
 
aging effects have been identified and whether the aging effects listed were appropriate for
 
the material-environment combinations specified. The staff's 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 plant's operating experience to
 
verify the applicant's claims.
 
Table 3.1-1 summarizes the staff's evaluation of components, aging effects or mechanisms, and AMPs listed in LRA Section 3.1 and addressed in the GALL Report.
 
Table 3.1-1  Staff Evaluation for Reactor Vessel, Reactor Vessel Internals, and Reactor Coolant System Components in the GALL Report Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel pressure vessel support skirt
 
and attachment welds (3.1.1-1)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes Not applicable Fatigue is a TLAA (See
 
SER Section
 
3.1.2.2.1)
Steel; stainless steel; steel with nickel-alloy
 
or stainless steel cladding; nickel-alloy
 
reactor vessel
 
components: flanges;
 
nozzles; penetrations; safe
 
ends; thermal
 
sleeves; vessel
 
shells, heads and welds (3.1.1-2)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and
 
environmental effects
 
are to be addressed
 
for Class 1
 
components  Yes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.1.2.2.1) 3-226 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel; stainless steel; steel with nickel-alloy
 
or stainless steel cladding; nickel-alloy
 
reactor coolant pressure boundary
 
piping, piping
 
components, and
 
piping elements
 
exposed to reactor
 
coolant (3.1.1-3)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and
 
environmental effects
 
are to be addressed
 
for Class 1
 
components Yes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.1.2.2.1)
Steel pump and
 
valve closure bolting
 
(3.1.1-4)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c)
 
check Code limits for allowable cycles (less than 7000 cycles) of
 
thermal stress range Yes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.1.2.2.1)
Stainless steel and nickel alloy reactor
 
vessel internals
 
components
 
(3.1.1-5)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes TLAA Fatigue is a TLAA (See
 
SER Section
 
3.1.2.2.1) Nickel Alloy tubes
 
and sleeves in a
 
reactor coolant and secondary feedwater/steam
 
environment
 
(3.1.1-6)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes TLAA Fatigue is a TLAA (See
 
SER Section
 
3.1.2.2.1)
Steel and stainless
 
steel reactor coolant pressure boundary
 
closure bolting, head
 
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)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes TLAA Fatigue is a TLAA (See
 
SER Section
 
3.1.2.2.1) 3-227 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel; stainless steel; and nickel-alloy
 
reactor coolant pressure boundary
 
piping, piping
 
components, piping
 
elements; flanges;
 
nozzles and safe
 
ends; pressurizer
 
vessel shell heads and welds; heater
 
sheaths and sleeves;
 
penetrations; and
 
thermal sleeves
 
(3.1.1-8)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and
 
environmental effects
 
are to be addressed
 
for Class 1
 
components Yes TLAA Fatigue is a TLAA (See
 
SER Section
 
3.1.2.2.1)
Steel; stainless steel; steel with nickel-alloy
 
or stainless steel cladding; nickel-alloy
 
reactor vessel
 
components: flanges;
 
nozzles; penetrations;
 
pressure housings;
 
safe ends; thermal
 
sleeves; vessel
 
shells, heads and welds (3.1.1-9)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and
 
environmental effects
 
are to be addressed
 
for Class 1
 
components Yes TLAA Fatigue is a TLAA (See
 
SER Section
 
3.1.2.2.1)
Steel; stainless steel; steel with nickel-alloy
 
or stainless steel cladding; nickel-alloy
 
steam generator
 
components (flanges;
 
penetrations;
 
nozzles; safe ends, lower heads and welds)
(3.1.1-10)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and
 
environmental effects
 
are to be addressed
 
for Class 1
 
components Yes TLAA Fatigue is a TLAA (See
 
SER Section
 
3.1.2.2.1)
Steel top head enclosure (without
 
cladding) top head
 
nozzles (vent, top head spray or RCIC, and spare) exposed
 
to reactor coolant
 
(3.1.1-11)
Loss of material due to general, pitting and
 
crevice corrosion Water Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.1.2.2.2) 3-228 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel steam generator shell assembly exposed to secondary feedwater
 
and steam
 
(3.1.1-12)
Loss of material due to general, pitting and
 
crevice corrosion Water Chemistry and One-Time InspectionYes Not applicable Not applicable to VEGP.(See
 
SER Section
 
3.1.2.2.2)
Steel and stainless
 
steel isolation
 
condenser
 
components exposed
 
to reactor coolant
 
(3.1.1-13)
Loss of material due to general (steel only),
pitting and
 
crevice corrosion Water Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.1.2.2.2)
Stainless steel, nickel-alloy, and steel with nickel-alloy or
 
stainless steel
 
cladding reactor
 
vessel flanges,
: nozzles, penetrations, safe
 
ends, vessel shells, heads and welds
 
(3.1.1-14)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.1.2.2.2)
Stainless steel; steel with nickel-alloy or
 
stainless steel
 
cladding; and nickel-alloy reactor coolant pressure boundary
 
components exposed
 
to reactor coolant
 
(3.1.1-15)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.1.2.2.2)
Steel steam
 
generator upper and lower shell and
 
transition cone
 
exposed to secondary feedwater
 
and steam
 
(3.1.1-16)
Loss of material due to general, pitting and
 
crevice corrosion Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry
 
and, for Westinghouse
 
Model 44 and
 
51 S/G, if general
 
and pitting corrosion of the shell is known
 
to exist, additional
 
inspection
 
procedures are to be
 
developed. Yes Water Chemistry Control Program (B.3.28) and
 
Inservice
 
Inspection
 
Program (B.3.13) Inservice Inspection
 
Program is a
 
plant-specific
 
program (See
 
SER Section
 
3.1.2.2.2.4) 3-229 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel (with or without stainless steel
 
cladding) reactor
 
vessel beltline shell, nozzles, and welds
 
(3.1.1-17)
Loss of fracture toughness due
 
to neutron
 
irradiation
 
embrittlement TLAA, evaluated in accordance with 10 CFR 50, Appendix G, and RG 1.99. The applicant may
 
choose to
 
demonstrate that the
 
materials of the
 
nozzles are not
 
controlling for the TLAA evaluations. Yes TLAA Loss of fracture toughness is a TLAA (See
 
SER Section
 
3.1.2.2.3.1) Steel (with or without
 
stainless steel
 
cladding) reactor
 
vessel beltline shell, nozzles, and welds; safety injection
 
nozzles (3.1.1-18)
Loss of fracture toughness due
 
to neutron
 
irradiation
 
embrittlement Reactor Vessel Surveillance Yes Reactor Vessel Surveillance
 
Program (B.3.25) Consistent with the GALL Report with
 
exception (See
 
SER Section
 
3.1.2.2.3.2)
Stainless steel and nickel alloy top head
 
enclosure vessel
 
flange leak detection
 
line (3.1.1-19)
Cracking due to stress corrosion
 
cracking and
 
intergranular
 
stress corrosion
 
cracking A plant-specific aging management
 
program is to be
 
evaluated. Yes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.1.2.2.4)
Stainless steel
 
isolation condenser
 
components exposed
 
to reactor coolant
 
(3.1.1-20)
Cracking due to stress corrosion
 
cracking and
 
intergranular
 
stress corrosion
 
cracking Inservice Inspection (IWB, IWC, and IWD),
Water Chemistry, and plant-specific
 
verification program Yes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.1.2.2.4)
Reactor vessel shell
 
fabricated of SA508-
 
Cl 2 forgings clad with stainless steel
 
using a high-heat-input welding
 
process (3.1.1-21) Crack growth due to cyclic
 
loading TLAA Yes Not applicable Not applicable to VEGP.(See
 
SER Section
 
3.1.2.2.5) 3-230 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel and nickel alloy reactor
 
vessel internals
 
components exposed
 
to reactor coolant
 
and neutron flux
 
(3.1.1-22)
Loss of fracture toughness due
 
to neutron
 
irradiation
 
embrittlement, void swelling FSAR supplement commitment to
 
(1) participate in industry RVI aging
 
programs (2) implement
 
applicable results (3)
 
submit for NRC approval > 24
 
months before the
 
extended period an
 
RVI inspection plan based on industry
 
recommendation. Yes Reactor Vessel Internals
 
Program (B.3.24) Consistent with the GALL Report (See
 
SER Section
 
3.1.2.2.6)
Stainless steel
 
reactor vessel
 
closure head flange
 
leak detection line
 
and bottom-mounted
 
instrument guide
 
tubes (3.1.1-23)
Cracking due to stress corrosion
 
cracking A plant-specific aging management
 
program is to be
 
evaluated. Yes Water Chemistry Control Program (B.3.28) and
 
Inservice
 
Inspection
 
Program (B.3.13) Consistent with the GALL Report (See
 
SER Section
 
3.1.2.2.7.1)
Class 1 cast
 
austenitic stainless
 
steel piping, piping
 
components, and
 
piping elements
 
exposed to reactor
 
coolant (3.1.1-24)
Cracking due to stress corrosion
 
cracking Water Chemistry and, for CASS
 
components that do
 
not meet the
 
NUREG-0313
 
guidelines, a plant
 
specific AMP Yes Water Chemistry Control Program (B.3.28) and
 
Inservice
 
Inspection
 
Program (B.3.13) Consistent with the GALL Report (See
 
SER Section
 
3.1.2.2.7.2)
Stainless steel jet
 
pump sensing line
 
(3.1.1-25)
Cracking due to cyclic loading A plant-specific aging management
 
program is to be
 
evaluated. Yes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.1.2.2.8)
Steel and stainless
 
steel isolation
 
condenser
 
components exposed
 
to reactor coolant
 
(3.1.1-26)
Cracking due to cyclic loading Inservice Inspection (IWB, IWC, and IWD) and
 
plant-specific
 
verification program Yes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.1.2.2.8) 3-231 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel and nickel alloy reactor
 
vessel internals screws, bolts, tie rods, and hold-down
 
springs (3.1.1-27)
Loss of preload due to stress
 
relaxation FSAR supplement commitment to
 
(1) participate in industry RVI aging
 
programs (2) implement
 
applicable results (3)
 
submit for NRC approval > 24
 
months before the
 
extended period an
 
RVI inspection plan based on industry
 
recommendation. Yes Reactor Vessel Internals
 
Program (B.3.24) Consistent with the GALL Report (See
 
SER Section
 
3.1.2.2.9)
Steel steam generator feedwater
 
impingement plate
 
and support exposed to secondary feedwater
 
(3.1.1-28)
Loss of material due to erosion A plant-specific aging management
 
program is to be
 
evaluated. Yes Not applicable Not applicable to VEGP (See
 
SER Section
 
3.1.2.2.10)
Stainless steel steam dryers exposed to
 
reactor coolant
 
(3.1.1-29)
Cracking due to flow-induced
 
vibration A plant-specific aging management
 
program is to be
 
evaluated. Yes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.1.2.2.11)
Stainless steel
 
reactor vessel
 
internals components (e.g., Upper internals assembly, RCCA
 
guide tube
 
assemblies, Baffle/former assembly, Lower internal assembly, shroud assemblies, Plenum cover and plenum cylinder, Upper grid assembly, Control rod guide tube (CRGT) assembly, Core
 
support shield assembly, Core barrel assembly, Lower grid assembly, Flow distributor assembly, Thermal
: shield, Instrumentation
 
support structures)
 
(3.1.1-30)
Cracking due to stress corrosion
: cracking, irradiation-
 
assisted stress
 
corrosion
 
cracking Water Chemistry and UFSAR supplement
 
commitment to
 
(1) participate in industry RVI aging
 
programs (2) implement
 
applicable results
 
(3) submit for NRC approval > 24
 
months before the
 
extended period an
 
RVI inspection plan based on industry
 
recommendation. Yes Reactor Vessel Internals
 
Program (B.3.24) and Water Chemistry
 
Control Program (B.3.28) Consistent with the GALL Report (See
 
SER Section
 
3.1.2.2.12) 3-232 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Nickel alloy and steel with nickel-alloy
 
cladding piping, piping component, piping elements, penetrations, nozzles, safe ends, and welds (other
 
than reactor vessel
 
head); pressurizer
 
heater sheaths, sleeves, diaphragm plate, manways and
 
flanges; core support
 
pads/core guide lugs
 
(3.1.1-31)
Cracking due to primary water
 
stress corrosion
 
cracking Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry and UFSAR supplement
 
commitment to
 
implement applicable
 
plant commitments to
 
(1) NRC Orders, Bulletins, and
 
Generic Letters associated with nickel alloys and
 
(2) staff-accepted industry guidelines. Yes Water Chemistry Control Program (B.3.28),
Inservice
 
Inspection
 
Program (B.3.13), and Nickel Alloy
 
Management
 
Program for
 
Non-Reactor
 
Vessel Closure
 
Head Penetration
 
Locations (B.3.14) or
 
Reactor Vessel
 
Internals
 
Program (B.3.24) Partially Consistent with
 
the GALL Report (See
 
SER Section
 
3.1.2.2.13)
Steel steam generator feedwater
 
inlet ring and
 
supports (3.1.1-32) Wall thinning due to flow-
 
accelerated
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated.
Yes Steam Generator
 
Program for
 
Upper Internals (B.3.27) Consistent with the GALL Report (See
 
SER Section
 
3.1.2.2.14)
Stainless steel and nickel alloy reactor
 
vessel internals
 
components
 
(3.1.1-33)
Changes in dimensions due to void swelling FSAR supplement commitment to
 
(1) participate in industry RVI aging
 
programs (2) implement
 
applicable results
 
(3) submit for NRC approval > 24
 
months before the
 
extended period an
 
RVI inspection plan based on industry
 
recommendation. Yes Reactor Vessel Internals
 
Program (B.3.24) Consistent with the GALL Report (See
 
SER Section
 
3.1.2.2.15) 3-233 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel and nickel alloy reactor
 
control rod drive
 
head penetration
 
pressure housings
 
(3.1.1-34)
Cracking due to stress corrosion
 
cracking and primary water
 
stress corrosion
 
cracking Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry and for nickel alloy, comply with
 
applicable NRC
 
Orders and provide a
 
commitment in the UFSAR supplement
 
to implement
 
applicable
 
(1) Bulletins and
 
Generic Letters and
 
(2) staff-accepted industry guidelines. Yes Water Chemistry Control Program (B.3.28) and
 
Inservice
 
Inspection
 
Program (B.3.13) Partially Consistent with
 
the GALL Report (See
 
SER Section
 
3.1.2.2.16) Steel with stainless steel or nickel alloy cladding primary side
 
components; steam
 
generator upper and lower heads, tubesheets and tube-to-tube sheet welds
 
(3.1.1-35)
Cracking due to stress corrosion
 
cracking and primary water
 
stress corrosion
 
cracking Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry and for nickel alloy, comply with
 
applicable NRC
 
Orders and provide a
 
commitment in the UFSAR supplement
 
to implement
 
applicable
 
(1) Bulletins and
 
Generic Letters and
 
(2) staff-accepted industry guidelines. Yes Not applicable Not applicable to VEGP (See
 
SER Section
 
3.1.2.2.16) Nickel alloy, stainless
 
steel pressurizer spray head
 
(3.1.1-36)
Cracking due to stress corrosion
 
cracking and primary water
 
stress corrosion
 
cracking Water Chemistry and One-Time Inspection and, for nickel alloy welded spray heads, comply with
 
applicable NRC
 
Orders and provide a
 
commitment in the UFSAR supplement
 
to implement
 
applicable
 
(1) Bulletins and
 
Generic Letters and
 
(2) staff-accepted industry guidelines. Yes Not applicable Not applicable to VEGP (See
 
SER Section
 
3.1.2.2.16) 3-234 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel and nickel alloy reactor
 
vessel internals
 
components (e.g., Upper internals assembly, RCCA
 
guide tube assemblies, Lower internal assembly, CEA shroud
 
assemblies, Core shroud assembly, Core support shield assembly, Core barrel assembly, Lower grid assembly, Flow distributor assembly)
 
(3.1.1-37)
Cracking due to stress corrosion
: cracking, primary water
 
stress corrosion
: cracking, irradiation-
 
assisted stress
 
corrosion
 
cracking Water Chemistry and UFSAR supplement
 
commitment to
 
(1) participate in industry RVI aging
 
programs (2) implement
 
applicable results
 
(3) submit for NRC approval > 24
 
months before the
 
extended period an
 
RVI inspection plan based on industry
 
recommendation. Yes Water Chemistry Control Program (B.3.28) and
 
Reactor Vessel
 
Internals
 
Program (B.3.24) Consistent with the GALL Report (See
 
SER Section
 
3.1.2.2.17) Steel (with or without
 
stainless steel
 
cladding) control rod
 
drive return line
 
nozzles exposed to
 
reactor coolant
 
(3.1.1-38)
Cracking due to cyclic loading BWR Control Rod Drive Return Line
 
Nozzle No Not applicable Not applicable to PWRs Steel (with or without
 
stainless steel cladding) feedwater
 
nozzles exposed to
 
reactor coolant
 
(3.1.1-39)
Cracking due to cyclic loading BWR Feedwater Nozzle No Not applicable Not applicable to PWRs Stainless steel and nickel alloy
 
penetrations for
 
control rod drive stub
 
tubes instrumentation, jet
 
pump instrumentation, standby liquid
 
control, flux monitor, and drain line
 
exposed to reactor
 
coolant (3.1.1-40)
Cracking due to stress corrosion
: cracking, Intergranular
 
stress corrosion cracking, cyclic
 
loading BWR Penetrations and Water ChemistryNo Not applicable Not applicable to PWRs 3-235 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel and nickel alloy piping, piping components, and piping elements
 
greater than or equal
 
to 4 NPS; nozzle
 
safe ends and associated welds
 
(3.1.1-41)
Cracking due to stress corrosion
 
cracking and
 
intergranular
 
stress corrosion
 
cracking BWR Stress Corrosion Cracking and Water ChemistryNo Not applicable Not applicable to PWRs Stainless steel and nickel alloy vessel
 
shell attachment welds exposed to
 
reactor coolant
 
(3.1.1-42)
Cracking due to stress corrosion
 
cracking and
 
intergranular
 
stress corrosion
 
cracking BWR Vessel ID Attachment Welds and Water ChemistryNo Not applicable Not applicable to PWRs Stainless steel fuel
 
supports and control
 
rod drive assemblies
 
control rod drive
 
housing exposed to
 
reactor coolant
 
(3.1.1-43)
Cracking due to stress corrosion
 
cracking and
 
intergranular
 
stress corrosion
 
cracking BWR Vessel Internals and Water Chemistry No Not applicable Not applicable to PWRs Stainless steel and nickel alloy core
 
shroud, core plate, core plate bolts, support structure, top guide, core spray
 
lines, spargers, jet
 
pump assemblies, control rod drive
 
housing, nuclear
 
instrumentation
 
guide tubes
 
(3.1.1-44)
Cracking due to stress corrosion
: cracking, intergranular
 
stress corrosion
: cracking, irradiation-
 
assisted stress
 
corrosion
 
cracking BWR Vessel Internals and Water Chemistry No Not applicable Not applicable to PWRs Steel piping, piping
 
components, and
 
piping elements
 
exposed to reactor
 
coolant (3.1.1-45) Wall thinning due to flow-
 
accelerated
 
corrosion Flow-Accelerated Corrosion No Not applicable Not applicable to PWRs Nickel alloy core
 
shroud and core
 
plate access hole
 
cover (mechanical
 
covers)
(3.1.1-46)
Cracking due to stress corrosion
: cracking, intergranular
 
stress corrosion
: cracking, irradiation-
 
assisted stress
 
corrosion
 
cracking Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry No Not applicable Not applicable to PWRs 3-236 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel and nickel-alloy reactor
 
vessel internals
 
exposed to reactor
 
coolant (3.1.1-47)
Loss of material due to pitting
 
and crevice
 
corrosion Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry No Not applicable Not applicable to PWRs Steel and stainless
 
steel Class 1 piping, fittings and branch connections < NPS 4
 
exposed to reactor
 
coolant (3.1.1-48)
Cracking due to stress corrosion
: cracking, intergranular
 
stress corrosion
 
cracking (for
 
stainless steel only), and
 
thermal and
 
mechanical
 
loading Inservice Inspection (IWB, IWC, and IWD),
Water chemistry, and One-Time Inspection
 
of ASME Code
 
Class 1 Small-bore
 
Piping No Not applicable Not applicable to PWRs Nickel alloy core
 
shroud and core
 
plate access hole cover (welded
 
covers)
(3.1.1-49)
Cracking due to stress corrosion
: cracking, intergranular
 
stress corrosion
: cracking, irradiation-
 
assisted stress
 
corrosion
 
cracking Inservice Inspection (IWB, IWC, and IWD),
Water Chemistry, and, for BWRs with a
 
crevice in the access
 
hole covers, augmented inspection using UT
 
or other demonstrated
 
acceptable
 
inspection of the
 
access hole cover welds No Not applicable Not applicable to PWRs High-strength low alloy steel top head
 
closure studs and
 
nuts exposed to air with reactor coolant
 
leakage (3.1.1-50)
Cracking due to stress corrosion
 
cracking and
 
intergranular
 
stress corrosion
 
cracking Reactor Head Closure Studs No Not applicable Not applicable to PWRs Cast austenitic
 
stainless steel jet pump assembly
 
castings; orificed fuel
 
support (3.1.1-51)
Loss of fracture toughness due
 
to thermal aging
 
and neutron
 
irradiation
 
embrittlement Thermal Aging and Neutron Irradiation
 
Embrittlement of
 
CASS No Not applicable Not applicable to PWRs 3-237 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel and stainless steel reactor coolant pressure boundary (RCPB) pump and
 
valve closure bolting, manway and holding
 
bolting, flange
 
bolting, and closure
 
bolting in high-
 
pressure and high-temperature systems
 
(3.1.1-52)
Cracking due to stress corrosion
 
cracking, loss of
 
material due to wear, loss of
 
preload due to
 
thermal effects, gasket creep, and self-loosening Bolting Integrity No Bolting Integrity Program (B.3.2) The Bolting Integrity
 
Program is
 
plant-specific (See SER Section 3.1.2.1.2)
Steel piping, piping
 
components, and
 
piping elements
 
exposed to closed cycle cooling water
 
(3.1.1-53)
Loss of material due to general, pitting and
 
crevice corrosion Closed-Cycle Cooling Water System No Closed Cooling Water Program (B.3.6) Consistent with the GALL Report Copper alloy piping, piping components, and piping elements
 
exposed to closed cycle cooling water
 
(3.1.1-54)
Loss of material due to pitting, crevice, and
 
galvanic corrosion Closed-Cycle Cooling Water System No Not applicable Not applicable to VEGP (See
 
SER Section
 
3.1.2.1.1)
Cast austenitic
 
stainless steel
 
Class 1 pump
 
casings, and valve
 
bodies and bonnets
 
exposed to reactor coolant > 250&deg;C
(> 482&deg;F)
 
(3.1.1-55)
Loss of fracture toughness due
 
to thermal aging
 
embrittlement Inservice Inspection (IWB, IWC, and IWD).
Thermal aging susceptibility
 
screening is not necessary, inservice
 
inspection
 
requirements are
 
sufficient for
 
managing these
 
aging effects. ASME
 
Code Case N-481
 
also provides an
 
alternative for pump
 
casings. No Inservice Inspection
 
Program (B.3.13) Consistent with the GALL Report (See
 
SER Section
 
3.1.2.1.3) Copper alloy
> 15% Zn piping, piping components, and piping elements
 
exposed to closed cycle cooling water
 
(3.1.1-56)
Loss of material due to selective
 
leaching Selective Leaching of Materials No Not applicable Not applicable to VEGP (See
 
SER Section
 
3.1.2.1.1) 3-238 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Cast austenitic stainless steel
 
Class 1 piping, piping
 
component, and
 
piping elements and
 
control rod drive
 
pressure housings
 
exposed to reactor coolant > 250&deg;C
(> 482&deg;F)
 
(3.1.1-57)
Loss of fracture toughness due
 
to thermal aging
 
embrittlement Thermal Aging Embrittlement of
 
CASS No RCS CASS Fitting Evaluation
 
Program (B.3.5) Consistent with the GALL Report Steel reactor coolant pressure boundary
 
external surfaces exposed to air with borated water
 
leakage (3.1.1-58)
Loss of material due to boric acid
 
corrosion Boric Acid Corrosion No Boric Acid Corrosion
 
Control Program (B.3.3) Consistent with the GALL Report (See
 
SER Sections
 
3.1.2.1.1 and
 
3.1.2.1.4)
Steel steam
 
generator steam
 
nozzle and safe end, feedwater nozzle and safe end, AFW
 
nozzles and safe
 
ends exposed to secondary feedwater/steam
 
(3.1.1-59) Wall thinning due to flow-
 
accelerated
 
corrosion Flow-Accelerated Corrosion No Flow Accelerated
 
Corrosion
 
Program (B.3.10) Consistent with the GALL Report Stainless steel flux thimble tubes (with or without chrome
 
plating)
(3.1.1-60)
Loss of material due to wear Flux Thimble Tube Inspection No Flux Thimble Tube Inspection
 
Program (B.3.11) Consistent with the GALL Report Stainless steel, steel
 
pressurizer integral
 
support exposed to air with metal
 
temperature up to 288&deg;C (550&deg;F)
 
(3.1.1-61)
Cracking due to cyclic loading Inservice Inspection (IWB, IWC, and IWD) No Not applicable Not applicable to VEGP (See
 
SER Section
 
3.1.2.1.1)
Stainless steel, steel with stainless steel
 
cladding reactor coolant system cold
 
leg, hot leg, surge line, and spray line
 
piping and fittings
 
exposed to reactor
 
coolant (3.1.1-62)
Cracking due to cyclic loading Inservice Inspection (IWB, IWC, and IWD) No Fatigue and Cycle Monitoring
 
Program (B.3.38) and the
 
Inservice
 
Inspection
 
Program (B.3.13) Not consistent with the GALL
 
Report (See
 
SER Section
 
3.1.2.1.5) 3-239 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel reactor vessel flange, stainless steel and nickel 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)
Loss of material due to wear Inservice Inspection (IWB, IWC, and IWD) No Inservice Inspection
 
Program (B.3.13) or
 
Reactor Vessel
 
Internals
 
Program (B.3.24) Partially consistent with
 
the GALL Report (See
 
SER Section
 
3.1.2.1.6)
Stainless steel and steel with stainless steel or nickel alloy
 
cladding pressurizer
 
components
 
(3.1.1-64)
Cracking due to stress corrosion
: cracking, primary water
 
stress corrosion
 
cracking Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry No Water Chemistry Control Program (B.3.28) and
 
Inservice
 
Inspection
 
Program (B.3.13) Consistent with the GALL Report (See
 
SER Section
 
3.1.2.1.7) Nickel alloy reactor
 
vessel upper head
 
and control rod drive
 
penetration nozzles, instrument tubes, head vent pipe (top head), and welds
 
(3.1.1-65)
Cracking due to primary water
 
stress corrosion
 
cracking Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry and Nickel-Alloy
 
Penetration Nozzles Welded to the Upper
 
Reactor Vessel
 
Closure Heads of
 
Pressurized Water
 
Reactors No Water Chemistry Control Program (B.3.28),
Inservice
 
Inspection
 
Program (B.3.13), and Nickel Alloy
 
Management
 
Program for
 
Reactor Vessel
 
Closure Head
 
Penetrations (B.3.15) Consistent with the GALL Report (See
 
SER Section
 
3.1.2.1.8)
Steel steam generator secondary manways and
 
handholds (cover only) exposed to air with leaking secondary-side water
 
and/or steam
 
(3.1.1-66)
Loss of material due to erosion Inservice Inspection (IWB, IWC, and IWD) for
 
Class 2 components No Not applicable Not applicable to VEGP (See
 
SER Section
 
3.1.2.1.1) 3-240 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel with stainless steel or nickel alloy
 
cladding; or stainless
 
steel pressurizer
 
components exposed
 
to reactor coolant
 
(3.1.1-67)
Cracking due to cyclic loading Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry No Fatigue and Cycle Monitoring
 
Program (B.3.38) and
 
Inservice
 
Inspection
 
Program (B.3.13) Not consistent with the GALL
 
Report (See
 
SER Section
 
3.1.2.1.5)
Stainless steel, steel with stainless steel
 
cladding Class 1
 
piping, fittings, pump
 
casings, valve
 
bodies, nozzles, safe ends, manways, flanges, CRD
 
housing; pressurizer
 
heater sheaths, sleeves, diaphragm
 
plate; pressurizer
 
relief tank
 
components, reactor coolant system cold
 
leg, hot leg, surge line, and spray line
 
piping and fittings
 
(3.1.1-68)
Cracking due to stress corrosion
 
cracking Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry No Inservice Inspection
 
Program (B.3.13) and Water Chemistry
 
Control Program (B.3.28) Partially consistent with
 
the GALL Report (See
 
SER Section
 
3.1.2.1.7)
Stainless steel, nickel alloy safety
 
injection nozzles, safe ends, and associated welds and
 
buttering exposed to
 
reactor coolant
 
(3.1.1-69)
Cracking due to stress corrosion
: cracking, primary water
 
stress corrosion
 
cracking Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry No Inservice Inspection
 
Program (B.3.13) and Water Chemistry
 
Control Program (B.3.28) Partially consistent with
 
the GALL Report (See
 
SER Section
 
3.1.2.1.7)
Stainless steel; steel with stainless steel
 
cladding Class 1
 
piping, fittings and
 
branch connections
< NPS 4 exposed to
 
reactor coolant
 
(3.1.1-70)
Cracking due to stress corrosion
: cracking, thermal and
 
mechanical
 
loading Inservice Inspection (IWB, IWC, and IWD),
Water chemistry, and One-Time Inspection
 
of ASME Code
 
Class 1 Small-bore
 
Piping No Inservice Inspection
 
Program (B.3.13), Fatigue and Cycle
 
Monitoring
 
Program (B.3.38), and Water Chemistry
 
Control Program (B.3.28) Partially consistent with
 
the GALL Report (See
 
SER Section
 
3.1.2.1.9) High-strength low alloy steel closure head stud assembly exposed to air with
 
reactor coolant
 
leakage (3.1.1-71)
Cracking due to stress corrosion
 
cracking; loss of
 
material due to wear Reactor Head Closure Studs No Reactor Vessel Closure Stud
 
Program (B.3.23) Consistent with the GALL Report 3-241 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Nickel alloy steam generator tubes and
 
sleeves exposed to secondary feedwater/steam
 
(3.1.1-72)
Cracking due to OD stress
 
corrosion
 
cracking and
 
intergranular
 
attack, loss of
 
material due to fretting and wear Steam Generator Tube Integrity and Water Chemistry No Water Chemistry Control Program (B.3.28) and
 
Steam Generator Tubing Integrity
 
Program (B.3.26) Consistent with the GALL Report (See
 
SER Section
 
3.1.2.1.6) Nickel alloy steam
 
generator tubes, repair sleeves, and
 
tube plugs exposed
 
to reactor coolant
 
(3.1.1-73)
Cracking due to primary water
 
stress corrosion
 
cracking Steam Generator Tube Integrity and Water Chemistry No Water Chemistry Control Program (B.3.28) and
 
Steam Generator Tubing Integrity
 
Program (B.3.26). Consistent with the GALL Report Chrome plated steel, stainless steel, nickel alloy steam
 
generator anti-
 
vibration bars
 
exposed to secondary feedwater/steam
 
(3.1.1-74)
Cracking due to stress corrosion
 
cracking, loss of
 
material due to
 
crevice corrosion and
 
fretting Steam Generator Tube Integrity and Water Chemistry No Water Chemistry Control Program (B.3.28) and
 
Steam Generator Tubing Integrity
 
Program (B.3.26) Consistent with the GALL Report (See
 
SER Sections
 
3.1.2.1.6 and
 
3.1.2.1.7) Nickel alloy once-
 
through steam
 
generator tubes
 
exposed to secondary feedwater/steam
 
(3.1.1-75)
Denting due to corrosion of
 
carbon steel
 
tube support
 
plate Steam Generator Tube Integrity and Water Chemistry No Not applicable Not applicable to VEGP (See
 
SER Section
 
3.1.2.1.1)
Steel steam
 
generator tube
 
support plate, tube bundle wrapper
 
exposed to secondary feedwater/steam
 
(3.1.1-76)
Loss of material due to erosion, general, pitting, and crevice
 
corrosion, ligament cracking due to
 
corrosion Steam Generator Tube Integrity and Water Chemistry No Water Chemistry Control Program (B.3.28) and
 
Steam Generator Tubing Integrity
 
Program (B.3.26) Consistent with the GALL Report (See
 
SER Section
 
3.1.2.1.10) Nickel alloy steam
 
generator tubes and
 
sleeves exposed to phosphate chemistry in secondary feedwater/steam
 
(3.1.1-77)
Loss of material due to wastage
 
and pitting
 
corrosion Steam Generator Tube Integrity and Water Chemistry No Not applicable Not applicable to VEGP (See
 
SER Section
 
3.1.2.1.1) 3-242 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel steam generator tube
 
support lattice bars
 
exposed to secondary feedwater/steam
 
(3.1.1-78) Wall thinning due to flow-
 
accelerated
 
corrosion Steam Generator Tube Integrity and Water Chemistry No Not applicable Not applicable to VEGP (See
 
SER Section
 
3.1.2.1.1) Nickel alloy steam
 
generator tubes
 
exposed to secondary feedwater/steam
 
(3.1.1-79)
Denting due to corrosion of
 
steel tube
 
support plate Steam Generator Tube Integrity; Water Chemistry and, for
 
plants that could
 
experience denting
 
at the upper support
 
plates, evaluate potential for rapidly
 
propagating cracks
 
and then develop
 
and take corrective
 
actions consistent with NRC Bulletin 88-
: 02. No Not applicable Not applicable to VEGP (See
 
SER Section
 
3.1.2.1.1)
Cast austenitic
 
stainless steel
 
reactor vessel
 
internals (e.g., upper internals assembly, lower internal assembly, CEA
 
shroud assemblies, control rod guide tube assembly, core
 
support shield assembly, lower grid assembly)
 
(3.1.1-80)
Loss of fracture toughness due
 
to thermal aging
 
and neutron
 
irradiation
 
embrittlement Thermal Aging and Neutron Irradiation
 
Embrittlement of
 
CASS No Reactor Vessel Internals
 
Program (B.3.24) Not consistent with the GALL
 
Report (See
 
SER Section
 
3.1.2.1.3) Nickel alloy or nickel-alloy clad steam
 
generator divider
 
plate exposed to
 
reactor coolant
 
(3.1.1-81)
Cracking due to primary water
 
stress corrosion
 
cracking Water Chemistry No Water Chemistry Control Program (B.3.28) Consistent with the GALL Report Stainless steel steam generator primary
 
side divider plate
 
exposed to reactor
 
coolant (3.1.1-82)
Cracking due to stress corrosion
 
cracking Water Chemistry No Not applicable Not applicable to VEGP (See
 
SER Section
 
3.1.2.1.1) 3-243 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel; steel with nickel-alloy or
 
stainless steel
 
cladding; and nickel-alloy reactor vessel
 
internals and reactor
 
coolant pressure boundary components exposed
 
to reactor coolant
 
(3.1.1-83)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry No Water Chemistry Control Program (B.3.28) and
 
Steam Generator Tube Integrity
 
Program (B.3.26) Consistent with the GALL Report Nickel alloy steam
 
generator
 
components such as, secondary side
 
nozzles (vent, drain, and
 
instrumentation)
 
exposed to secondary feedwater/steam
 
(3.1.1-84)
Cracking due to stress corrosion
 
cracking Water Chemistry and One-Time Inspection
 
or Inservice Inspection (IWB, IWC, and IWD). No Not applicable Not applicable to VEGP (See
 
SER Section
 
3.1.2.1.1) Nickel alloy piping, piping components, and piping elements
 
exposed to air -
 
indoor uncontrolled (external)
 
(3.1.1-85) None None No None Consistent with the GALL Report Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to air -
 
indoor uncontrolled (External); air with borated water
 
leakage; concrete;
 
gas (3.1.1-86) None None No None Consistent with the GALL Report Steel piping, piping
 
components, and
 
piping elements in
 
concrete (3.1.1-87) None None No Not applicable Not applicable to VEGP (See
 
SER Section
 
3.1.2.1.1)
The staff's review of the reactor vessel, reactor vessel internals, and RCS 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 3-244 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 staff's review of AMPs credited to manage or monitor
 
aging effects of the reactor vessel, reactor vessel internals, and RCS components is
 
documented in SER Section 3.0.3.
3.1.2.1  AMR Results Consistent with the GALL Report 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
 
RCS components:
 
ACCW System Carbon Steel Components Program  Bolting Integrity Program  Boric Acid Corrosion Control Program  CASS RCS Fitting Evaluation Program  Closed Cooling Water Program  External Surfaces Monitoring Program  Flow-Accelerated Corrosion Program  Flux Thimble Tube Inspection Program  Inservice Inspection Program  Nickel Alloy Management Program for Non-Reactor Vessel Closure Head Penetration Locations  Nickel Alloy Management Program for Reactor Vessel Closure Head Penetrations  Oil Analysis Program  One-Time Inspection Program  One-Time Inspection Program for ASME Code Class 1 Small Bore Piping  Reactor Vessel Closure Head Stud Program  Reactor Vessel Internals Program  Reactor Vessel Surveillance Program  Steam Generator Tubing Integrity Program 3-245  Steam Generator Program for Upper Internals  Water Chemistry Control Program  Fatigue Monitoring Program LRA Tables 3.1.2-1 through 3.1.2-5 summarize AMRs for the reactor vessel, reactor vessel internals, and RCS 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
 
staff's audit and review determined whether the plant-specific components of these GALL
 
Report component groups were bounded by the GALL Report evaluation.
 
For each AMR line item the applicant noted 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
 
Report AMP. The staff audited these line items to verify consistency with the GALL Report
 
and validity of the AMR for the site-specific conditions.
 
Note B indicates that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the
 
GALL Report AMP. The staff audited these line items to verify consistency with the GALL
 
Report and verified that the identified exceptions to the GALL Report AMPs have been
 
reviewed and accepted. The staff also determined whether the applicant's AMP was
 
consistent with the GALL Report AMP and whether the AMR was valid for the site-specific
 
conditions.
 
Note C indicates that the component for the AMR line item, although different from, is
 
consistent with the GALL Report for material, environment, and aging effect. In addition, the
 
AMP is consistent with the GALL Report 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 determined
 
whether the AMR line item of the different component was applicable to the component
 
under review and whether the AMR was valid for the site-specific conditions.
 
Note D indicates that the component for the AMR line item, 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 Report AMP. The staff audited these line items to
 
verify consistency with the GALL Report. The staff verified whether the AMR line item of the
 
different component was applicable to the component under review and whether the
 
identified exceptions to the GALL Report AMPs have been reviewed and accepted. The
 
staff also determined whether the applicant's AMP was consistent with the GALL Report
 
AMP and whether the AMR was valid for the site-specific conditions.
3-246  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 or NUREG-1801 identifies a
 
plant specific aging management program. The staff audited these line items to verify
 
consistency with the GALL Report. The staff also determined whether the credited AMP
 
would manage the aging effect consistently with the GALL Report AMP and whether the
 
AMR was valid for the site-specific conditions.
 
The staff audited and reviewed the information in the LRA. The staff did not repeat its
 
review of the matters described in the GALL Report; however, the staff did verify that the
 
material presented in the LRA was applicable and that the applicant identified the
 
appropriate GALL Report AMRs. The staff's evaluation follows.
 
3.1.2.1.1 AMR Results Identified as Not Applicable
 
All or some of the AMR line items in the GALL Report Volume 2 that corresponds to GALL
 
Report Table 1, items 12, 35, 66, 75, 84 are not applicable to the recirculating steam
 
generators. The applicant stated in the LRA that the VEGP steam generators are a
 
Westinghouse Model F recirculating design. The GALL Report aging management item
 
associated with these line items is applicable only to once through steam generators. The
 
staff reviewed the documentation supporting the applicant's AMR evaluations and
 
confirmed the applicant's statement that VEGP does not have once-through steam
 
generators. On the basis that VEGP does not have once-through steam generators, the
 
staff agrees with the applicant's determination that the GALL Report AMR items associated
 
with the once-through steam generators are not applicable for VEGP.
 
The discussion in LRA Table 3.1.1 Item54 states that this item is not applicable, since
 
VEGP reactor coolant system boundary does not include any copper alloy components
 
exposed to closed-cycle cooling water. During the audit and review, the staff noted that the
 
GALL Report Item IV.C2-11, that rolls up to the GALL Report Table 1, Item 54, identifies
 
loss of material due to pitting, crevice, and galvanic corrosion as an aging effect for copper
 
alloy piping, piping components, and piping elements in closed cycle cooling water
 
environment. During the audit and review, the staff reviewed the applicant's license renewal
 
Program basis document for the steam generator component groups and verified that
 
VEGP does not have any copper alloy component exposed to closed-cycle cooling water in the reactor coolant system. On this basis, the staff agrees with the applicant's
 
determination that the corresponding AMR result line in the GALL Report is not applicable
 
for VEGP.
 
The discussion in LRA Table 3.1.1, Item 56 states that this item is not applicable, since
 
VEGP reactor coolant system boundary does not include any copper alloy components with
 
> 15% Zn. The staff noted that the GALL Report Item IV.C2-12, that rolls up to the GALL
 
Report Table 1, Item 56, identifies loss of material due selective leaching for copper alloy
 
piping components with >15% Zn. During the audit and review, the staff reviewed the
 
applicant's license renewal Program basis doc ument for the reactor coolant system and connected line component groups and verified that VEGP does not have any copper alloy
 
component exposed to closed-cycle cooling water in the reactor coolant system. On this basis, the staff agrees with the applicant's determination that the corresponding AMR result
 
line in the GALL Report is not applicable for VEGP.
 
3-247 The discussion in LRA Table 3.1.1, Item 61, states that the VEGP pressurizer support skirt and flange is not subject to cracking due to cyclic loading. The staff noted that the GALL
 
Report Item IV.C2-16, that rolls up to the GALL Report Table 1, Item 61, identifies cracking
 
due to cyclic loading for pressurizer integral support fabricated from steel or stainless steel
 
and exposed to air with metal temperature up to 288&deg;C (550&deg;F). During the audit and
 
review, the staff asked the applicant to provide technical justification for not identifying
 
cracking due to cyclic loading for VEGP pressurizer support skirt. 
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that UFSAR Section 3.9.N 1 describes the
 
design transients, loads, and analysis methods used to ensure the adequacy of the RCS
 
component supports, which include the pressurizer support skirt and flange. SNC's review
 
determined these analyses remain valid for the period of extended operation, but are not
 
TLAAs. The applicant further stated that for the pressurizer support loads are applied
 
gradually and remain constant and dynamic loads are too infrequent to initiate fatigue
 
cracking. Therefore, cracking due to thermal fatigue is not an aging effect requiring further
 
evaluation for these structural components. The staff reviewed the applicant's license
 
renewal Program basis document for the pressurizer component groups. The staff also
 
reviewed the VEGP UFSAR Section 3.9.N.1.4.4, "Primary Component Supports Models
 
and Methods" and Section 3.9.N.1.4.8, "Stress Criteria for Class 1 Components and
 
Component Supports." On the basis of these reviews, the staff agrees with the applicant's
 
determination that the corresponding AMR result line in the GALL Report is not applicable
 
for VEGP.
 
The discussion in LRA Table 3.1.1, Item 77, states that this item is not applicable. VEGP
 
does not use phosphate chemistry. On the basis that the staff verified that VEGP does not
 
use phosphate chemistry in its feedwater/steam environment, the staff agrees with the
 
applicant's determination that the corresponding AMR result line in the GALL Report is not
 
applicable for VEGP.
 
The discussion in LRA Table 3.1.1, Item 79, states that The VEGP steam generator tube
 
support plates are fabricated from type 405 ferritic stainless steel. The staff noted that the
 
GALL Report Item IV.D-19, that rolls up to the GALL Report Table 1, Item 79, identifies
 
denting/ corrosion of carbon steel tube support plate for nickel alloy steam generator tubes.
 
During the audit and review, the staff reviewed VEGP UFSAR Section 5.4.2.4.2, "Steam
 
Generator Design Effects on Materials," and verified that the tube support plates are made
 
of type 405 ferritic stainless steel. In addition this section of UFSAR states that the
 
peripheral supports provide stability to the plates so that tube fretting or wear due to flow induced plate vibrations at the tube support contac t regions is minimized. On this basis, the staff agrees with the applicant's determination that the corresponding AMR result line in the
 
GALL Report is not applicable for VEGP.
 
The discussion in LRA Table 3.1.1, Item 82, states that the VEGP steam generator divider
 
plates are fabricated from nickel alloys, not stainless steel. On the basis that VEGP does
 
not use stainless steel as a material of construction for its steam generator primary side
 
divider plate, the staff agrees with the applicant's determination that the corresponding
 
AMR result line in the GALL Report is not applicable for VEGP.
 
During the audit and review, the staff noted that GALL Report Table 1, Item 86, lists
 
stainless steel piping, piping components, and piping elements externally exposed to uncontrolled indoor air, air with borated water leakage, and concrete or gas. GALL Report 3-248 items IV.E-2, IV.E-3, IV.E-4, and IV.E-5 roll up to this table 1 Item 86. LRA Table 3.1.1, line-item 3.1.1-86, in the discussion column, states that this line-item is consistent with the
 
GALL Report. However, LRA Table 3.1.2-1 through Table 3.1-2-5 does not include
 
stainless components exposed to air with borated water leakage (IV.E-3), concrete (IV.E-4),
or gas (IV.E-5). During the audit and review, the staff asked the applicant to clarify whether
 
these line-items are not applicable to VEGP.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that exposure of stainless steel surfaces to
 
borated water leakage is applicable for VEGP and that VEGP LRA Tables 3.1.2-1, 3.1.2-2, 3.1.2-3, 3.1.2-4, and 3.1.2-5 do not include separate items for exposure to borated water
 
leakage. The applicant stated that, regardless of these facts, the VEGP AMR results are
 
consistent with the GALL Report Item IV.E-4 and conclude that there are no aging effects
 
requiring management for stainless steel component external surfaces, even when exposed to borated water leakage. The staff agreed with the applicant that, consistent with
 
the GALL Report Item IV.E-4, the external surfaces of the reactor coolant system
 
components that are fabricated from stainle ss steel do not have any aging effects that need to be managed during the period of extended operation. Therefore, the staff finds this
 
portion of the applicant's response acceptable.
 
In its response, the applicant also stated that the VEGP reactor coolant system and
 
connect lines interface with concrete at wall penetrations and that VEGP AMR methodology
 
does not generate separate AMR line items to address the concrete environment for piping
 
penetrations. The applicant stated that, for these cases, the environment associated with
 
pipe penetrations is considered to be a part of the indoor air environment, but regardless of
 
this fact, the VEGP AMR results are consistent with NUREG-1801 Item IV.E-4 and
 
conclude that there are no aging effects requiring management for stainless steel
 
components embedded in concrete. During the audit and review, the staff verified that the
 
VEGP reactor coolant system does not incl ude any stainless steel components that are embedded in concrete. Therefore, the staff finds this portion of the applicant's response
 
acceptable.
 
Regarding exposure to a dried gas, the applicant stated that VEGP does not include an
 
ASME Class 1 piping component associated with the reactor coolant system and connect
 
lines that are exposed to a dried gas. However this system includes non-ASME Class 1
 
piping component in a dried gas environmen
: t. For these components, the LRA AMR line items are linked to the GALL Report Item VII.J-19, which is associated with non-ASME
 
Class 1 mechanical auxiliary systems. The staff agreed with the applicant that this match
 
more appropriately describes the component type, since Section IV of the GALL Report is
 
focused on ASME Class 1 components. Therefore, the staff finds this portion of the
 
applicant's response acceptable.
 
The discussion in LRA Table 3.1.1, Item 87, states this line item is not applicable to VEGP.
 
VEGP has no in-scope reactor vessel, internals, and reactor coolant system components
 
embedded in concrete. On the basis that the staff verified that VEGP does not have any
 
reactor coolant system components embedded in concrete, the staff agrees with the
 
applicant's determination that the corresponding AMR result line in the GALL Report is not
 
applicable for VEGP.
 
3-249 3.1.2.1.2 Cracking Due to SCC, Loss of Material Due to Wear, and Loss of Preload
 
During the audit and review the staff noted that the discussion in LRA Table 3.1.1, Item 52, states that VEGP manages reactor coolant pressure boundary bolting cracking, loss of
 
material, and loss of preload with the plant-specific Bolting Integrity Program. LRA Tables
 
3.1.2-1, 3.1.2-3, 3.1.2-4, and 3.1.2-5 uses a standard Note E for the AMR line items that roll
 
up to the LRA Table 3.1.1, Item 52. Note E states (LRA Table 3.0-4) that the AMR line item
 
is consistent with the GALL Report for material, environment, and aging effect, but a
 
different aging management program is credited or the GALL Report identifies a plant-
 
specific aging management program. GALL Report Se ction IV lists reactor coolant system components, which roll up to GALL Report Table 1, Item 52, that identify cracking due
 
SCC, loss of material due wear, and loss of preload as aging effects for steel closure
 
bolting in air with reactor coolant leakage environment. The GALL Report recommends GALL AMP XI.M18, "Bolting Integrity" for managing these aging effects while the LRA uses
 
the Bolting Integrity Program, which is a plant specific program. The staff reviewed the
 
applicant's Bolting Integrity Program, and the staff's evaluation is documented in SER
 
Section 3.0.3.3.2. The staff's review of the Bolting Integrity Program includes the staff's
 
assessment of the AMP's program element s against the recommended program element criteria that are provided in Branch Position RLSB-1 in Appendix A of the SRP-LR (i.e.,
NUREG-1800, Revision 1). During the audit and review, the staff agreed with the
 
applicant's determination that these LRA line items are consistent with the GALL Report, except that the Bolting Integrity Program is identified as a plant specific AMP for the Vogtle
 
LRA. On the basis of the staff's evaluation of the AMP and the staff's determination that the
 
applicant's AMR results are consistent with the GALL Report, the staff finds the applicant's
 
AMR results to be acceptable. 
 
3.1.2.1.3 Loss of Fracture Toughness Due to Thermal Aging Embrittlement
 
During the audit and review, the staff noted that the discussion in LRA Table 3.1.1, Item 55, states that the VEGP Inservice Inspection Program manages loss of fracture toughness
 
due to thermal embrittlement of the VEGP reactor coolant pump casings and reactor
 
coolant system valve bodies. LRA Table 3.1.2-3 uses a standard Note E for the AMR line
 
items that roll up to the LRA Table 3.1.1, Item 55. Note E states (LRA Table 3.0-4) that the
 
AMR line item is consistent with the GALL Report for material, environment, and aging
 
effect, but a different aging management program is credited or GALL Report identifies a
 
plant-specific aging management program. GALL Report Item IV.C2-6, which rolls up to
 
GALL Report Table 1 Item 55, identifies loss of fracture toughness due to thermal aging
 
embrittlement as aging effects for CASS Class 1 pump casings, and valve bodies and bonnets in borated water. The GALL Report recommends GALL AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," for Class 1 components"
 
for managing this aging effect while the LRA uses the Inservice Inspection Program, which
 
is a plant specific program. The staff reviewed the applicant's Inservice Inspection Program, and the staff's evaluation is documented in SER Section 3.0.3.3.4. The staff agreed with
 
the applicant's determination that these LRA line items are consistent with the GALL
 
Report, except that the Inservice Inspection Pr ogram is identified as a plant specific AMP for the VEGP LRA. The staff's review of the Inservice Inspection Program includes the
 
staff's assessment of the AMP's program elements against the recommended program element criteria that are provided in Branch Position RLSB-1 in Appendix A of the SRP-LR (i.e., NUREG-1800, Revision 1). On the basis of the staff's evaluation of the AMP and the
 
staff's determination that the applicant's AMR results are consistent with the GALL Report, the staff finds the applicant's AMR results to be acceptable.
3-250  In LRA Table 3.1.1, line-Item 3.1.1-80, in the discussion column, the applicant of states that
 
the bottom mounted instrumentation column cruciforms are the only austenitic stainless
 
steel castings used in the VEGP reactor vessel internals. For these castings, VEGP will
 
manage loss of fracture toughness due to thermal aging and neutron irradiation
 
embrittlement with the LRA B.3.24 AMP, Reactor Vessel Internals Program (RVI). However, the staff noted that GALL Report Table 1, line-Item 80, recommends using Thermal Aging
 
Neutron Irradiation Embrittlement of CASS Program for managing loss of fracture
 
toughness due to thermal aging and neutron irradiation embrittlement. During the audit and
 
review, the staff asked the applicant to provide technical justification for using RVI in lieu of
 
the GALL Report recommended program and discuss in detail the MRP activities that refer
 
or include loss of fracture toughness due to thermal aging and neutron irradiation
 
embrittlement for the reactor internals.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that the VEGP Bottom Mounted Instrumentation
 
Column Cruciforms are CF8 cast austenitic stainless steel and are conservatively screened
 
in for thermal aging, since details of the ferrite and molybdenum content associated with
 
each casting are not known and that the cruciform castings are projected to exceed both
 
the 10 17 n/cm 2 (E > 1MeV) fluence threshold referenced in the GALL AMP XI.M13. The applicant stated that, as a result of this determination, the cruciform castings "screen in" for
 
irradiation embrittlement. The applicant stated that the aging management strategy relies
 
on the results of the ongoing EPRI Materials Reliability Program initiative to develop a
 
comprehensive aging management program for PWR reactor internals, and that as such, the VEGP Reactor Vessel Internals Program includes a commitment to submit an
 
inspection plan for staff review and approval not less than 24 months prior to entering the
 
period of extended operation for VEGP Units 1 and 2.
 
The staff reviewed the applicant's Reactor Vessel Internals Program, and the staff's
 
evaluation is documented in SER Section 3.0.3.3.7. During the audit and review, the staff
 
confirmed that the applicant's Commitment 20 in its letter dated August 11, 2008, stated
 
that it will implement the Reactor Vesse l Internals Program. The commitment has been added to Appendix A of this SER. The program is described in LRA Section A.2.24 and
 
Section B.3.24 and is based on the following commitments: (1) SNC will participate in the
 
industry program for investigating and managing of aging effects on reactor internals. This
 
is an ongoing commitment. (2) SNC will evaluate and implement the results of the industry
 
programs, such as the Electric Power Research Institute Material Reliability Program, applicable to the VEGP reactor internals. This commitment will be fully implemented prior to
 
the period of extended operation. (3) SNC will submit an inspection plan for the VEGP
 
reactor internals to the NRC for review and approval not less than 24 months before
 
entering the period of extended operation for VEGP Units 1 and 2. This inspection plan will
 
address the bases, inspection methods, and acceptance criteria associated with aging
 
management of the reactor vessel thermal sleeves and the core support lugs (along with
 
the associated support pads and attachment welds). On the basis of the staff's evaluation
 
of the AMP and the staff's determination that the applicant's AMR results are consistent
 
with the GALL Report, the staff finds the applicant's AMR results to be acceptable.
 
3.1.2.1.4 Loss of Material Due to Boric Acid Corrosion
 
During the audit and review, the staff noted that LRA Table 3.1.2-3, Item 20g, credits LRA
 
AMP B.3.8, External Surfaces Monitoring Program, for managing loss of material for carbon 3-251 steel valve bodies exposed to indoor air. LR A claims consistency with the GALL Report VII.I-8 and GALL Table 1, Item 3.1.1-58. However, GALL Report VII.I-8, and GALL Table 1, Item 3.1.1-58, are not consistent. Item VII.I-8 recommends using External Surfaces
 
Monitoring Program, but Item 3.1.1-58 recommends using Boric Acid Corrosion Program.
 
During the audit and review, the staff asked the applicant to clarify this discrepancy and to
 
provide technical justification for using the External Surfaces Monitoring Program. The
 
applicant provided its response to the staff's question in a letter dated February 8, 2008. In
 
its response, the applicant stated that LRA Table 3.1.2-3, Item 20g, should have been
 
linked with GALL Report Table 1, Item 3.3.1-58, instead of Item 3.1.1-58 and that GALL
 
Report Item 3.3.1-58 recommends using the External Surfaces Monitoring Program for
 
managing loss of material for steel external surfaces exposed to indoor air, which matches
 
the material, environment and program combination shown in LRA Table 3.1.2-3 (Item
 
20g). The applicant further stated that this is also consistent with GALL Report VII.I-8 and
 
that the External Surfaces Monitoring Program will visually identify loss of material due to
 
general corrosion, such as on the external surfaces of these carbon steel valves. The
 
applicant stated that the valve bodies addressed by Item 20g are not ASME Class 1
 
components but rather non-ASME Class 1 components associated with RCS support
 
systems (e.g. oil spill protection, cooling water). The staff finds the applicant response
 
acceptable since it stated that the applicant will revise the LRA to correct the above
 
typographical error. The staff confirmed that the applicant revised the LRA in a letter dated
 
March 20, 2008.
 
3.1.2.1.5 Cracking Due to Cyclic Loading
 
During the audit and review, the staff noted that LRA Table 3.1.2-3, Item 9a, credits Fatigue
 
Monitoring Program and Inservice Inspection Program for managing cracking due to cyclic loading for stainless steel Class 1 piping components NPS 4 that are exposed to borated water. LRA claims consistency with the GALL Report IV.C2-26 that rolls up to the GALL
 
Table 1 line 62. GALL Report Item IV.C2-26 recommends using Inservice Inspection
 
Program for managing cracking due to cyclic loading. LRA uses a standard Note E and a
 
plant special Note 105 for this line-item. Note E means that this line-Item is consistent with
 
GALL Report for material, environment, and aging effect, but a different aging management
 
program is credited. Note 105 states that the associated GALL Report Vol. 2 item does not
 
include all of the piping lines applicable for VEGP. Stress based fatigue monitoring to
 
manage thermal fatigue is performed by the Fatigue and Cycle Monitoring Program for a number of VEGP ASME Class 1 piping locations." During the audit and review, the staff
 
asked the applicant to clarify whether the aging effect "cracking due to cyclic loading" already postulates the initiation of a fatigue-induced crack in these piping components and
 
provide justification on how the Fatigue Moni toring Program manages cracking due to cyclic loading in these components when the program does not perform any inspections of the
 
components surfaces. The staff also asked the applicant to discuss the inspection methods
 
or techniques and frequency of these inspections that are being used to detect, monitor/trend cracking due cyclic loading.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that, as discussed in Section 3.1.2.2.1 of this
 
document, the applicant will revise LRA Table 3.1.2-3, Item 9a, to refer to the GALL Report
 
Item IV.C2-25 that rolls up to Table 1 line 8 instead of GALL Report Item IV.C2-26 which
 
rolls up to Table 1, line 62. Table 1, Item 62, will not be used by VEGP. The applicant also
 
stated that the revised LRA will be amended to replace "cracking due to cyclic loading" with
 
the term "Cracking - Thermal Fatigue," because SNC does not postulate the pre-existence 3-252 of a fatigue-induced crack. The applicant further stated that component inspections are not performed by the Fatigue Monitoring Program and that instead, the program tracks the CUF values for these components to manage cracking due to thermal fatigue. The staff finds the
 
applicant response acceptable since it provided clarification that VEGP does not postulate
 
a fatigue-induced crack for stainless steel Class 1 piping components  NPS 4 that are exposed to borated water. The staff confirmed that the applicant revised the LRA in a letter
 
dated March 20, 2008.
 
During the audit and review, the staff noted that LRA Table 3.1.2-4, items 2b, 3b, 4b, 6b, 7b, 9a, 10a, and 11a, credit Fatigue Monitoring Program and Inservice Inspection Program
 
for managing cracking due to cyclic loading for pressurizer components fabricated of
 
stainless steel, steel with stainless steel cladding, or nickel alloy materials that are exposed
 
to borated water. LRA uses a standard Note E which means that this line-item is consistent
 
with the GALL Report for material, environment, and aging effect, but a different aging
 
management program is credited. LRA claims consistency with the GALL Report line-Item IV.C2-18 that rolls up to the GALL Table 1, line 67. GALL Report Item IV.C2-18
 
recommends the Inservice Inspection Program and Water Chemistry Control Program for managing this aging effect. The applicant in the discussion column of LRA Table 3.1.1,line
 
Item 67, states that the Water Chemistry Control Program is not credited to mitigate
 
cracking due to cyclic loading. During the audit and review, the staff asked the applicant to
 
clarify whether the aging effect "cracking due to cyclic loading" already postulates the
 
initiation of a fatigue-induced crack in these pressurizer components and to justify how the
 
Fatigue Monitoring Program manages cracking due to cyclic loading in these components when the program does not credit any inspections of the components surfaces. The staff
 
also asked the applicant to discuss the inspection methods or techniques and frequency of
 
these inspections that are being used to detect, monitor/trend cracking due cyclic loading.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that, as discussed in Section 3.1.2.2.1 of this
 
document, the applicant will amend LRA Table 3.1.2-4, items 2b, 3b, 4b, 6b, 7b, 10a, and
 
11a to refer to the GALL Report Item IV.C2-25 that rolls up to Table 1 line 8 instead of
 
GALL Report Item IV.C2-18 which rolls up to Table 1 line 67 and to delete item 9a. The
 
applicant stated that Table 1, Item 67, will not be used by VEGP. The applicant also stated
 
that it will amend these AMRs to replace the term "cracking due to cyclic loading" with the
 
term "Cracking - Thermal Fatigue," because SNC does not postulate the pre-existence of a
 
fatigue-induced crack. The applicant also stated that component inspections are not
 
performed by the Fatigue Monitoring Program and that instead, the program tracks the CUF values for these components to manage cracking due to thermal fatigue. The staff
 
finds the applicant response acceptable since it provided clarification that VEGP does not
 
postulate the existence of a fatigue-induced crack for stainless steel Class 1 piping
 
components that are exposed to borated water. The staff confirmed that the applicant
 
amended the LRA appropriately in a letter dated March 20, 2008.
 
3.1.2.1.6 Loss of Material Due to Wear
 
During the audit and review, the staff noted that LRA Table 3.1.2-2 items 5e, 6e, 7e, 9c, 10c, 12e, 13e, 17e, 19e, and 20e identify loss of material due to wear for stainless steel
 
components in borated water environment. LRA us es Reactor Vessel Internals Program for managing this aging effect. It claims consistency with the GALL Report items IV.B2-26 and
 
IV.B2-34, which roll up to GALL Table 1, Item 63. It uses a standard Note E, which means
 
that this line item is consistent with the GALL Report for material, environment, and aging 3-253 effect, but a different aging management program is credited. GALL Report items IV.B2-26 and IV.B2-34 recommend ISI program for managing this aging effect. During the audit and
 
review, the staff asked the applicant to provide technical justification for using the RVI
 
program in lieu of the ISI program.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that wear of most reactor internals components
 
is expected to be adequately managed by ISI Program inspections but stated that
 
supplemental augmented inspections will be performed on these components if the EPRI
 
MRP inspection and flaw evaluation guidelines for PWR reactor internals conclude that
 
augmented inspections would be needed to manage wear in some of the reactor internals.
The applicant stated that SNC is not proposing alternatives to ASME Section XI
 
examination requirements for reactor internal s under the Reactor Vessel Internals Program.
Instead, the applicant stated that SNC is addressing the possibility of additional inspection
 
requirements for some component locations and that the VEGP reactor vessel internals
 
inspection plan will identify the inspection requirements for the reactor vessel internals
 
components. The applicant stated that the inspection plan will rely on ISI Program
 
inspections and identify any additional/augmented inspections to be performed. During the
 
audit and review, the staff concludes that the use of the Reactor Vessel Internals Program
 
in lieu of the Inservice Inspection Program is acceptable, because the Reactor Vessel Internals will perform those additional/ augmented inspections to the ASME Section XI
 
inspection requirements that are recommended through the industry initiatives of the EPRI
 
MRP, and because the applicant has addressed this in LRA Commitment No. 20, which
 
was submitted in the applicant's letter of March 20, 2008. On this basis, the staff finds the
 
applicant's response acceptable.
 
During the audit and review, the staff noted that the discussion in LRA Table 3.1.1, Item 63, states that VEGP manages wear of the reactor vessel flange and reactor vessel closure
 
head flange with the Inservice Inspection Program. LRA Tables 3.1.2-1 uses a standard
 
Note E for the AMR line items 4b and 25b that roll up to the LRA Table 3.1.1, Item 63. Note
 
E states (LRA Table 3.0-4) that the AMR line item is consistent with the GALL Report for
 
material, environment, and aging effect, but a different aging management program is
 
credited or the GALL Report identifies a plant-specific aging management program. GALL
 
Report Item IV.A2-25, which rolls up to GALL Report Table 1, Item 63, identifies loss of
 
material due to wear as an aging effect for steel vessel shell flange in reactor coolant
 
environment. The GALL Report recommends GALL AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, for Class 1 Components" for
 
managing this aging effect while the LRA uses the Inservice Inspection Program, which is a
 
plant specific program. The staff reviewed the applicant's Inservice Inspection Program, and the staff's evaluation is documented in SER Section 3.0.3.3.4. The staff agreed with
 
the applicant's determination that these LRA line items are consistent with the GALL
 
Report, except that the Inservice Inspection Pr ogram is identified as a plant specific AMP for the Vogtle LRA. The staff's review of the Inservice Inspection Program includes the
 
staff's assessment of the AMP's program elements against the recommended program element criteria that are provided in Branch Position RLSB-1 in Appendix A of the SRP-LR (i.e., NUREG-1800, Revision 1). On the basis of the staff's evaluation of the AMP and the
 
staff's determination that the applicant's AMR results are consistent with the GALL Report, the staff finds the applicant's AMR results to be acceptable.
 
During the audit and review, the staff noted that the LRA Table 3.1.2-5, Item 30e,credits
 
Steam Generator Tubing Integrity Program for managing loss of material due to wear for 3-254 nickel alloy steam generator tubes exposed to treated water. LRA shows consistency with GALL Report Item IV.D1-24, which is identified in GALL Report Table 1, Item 72. Similarly, LRA Table 3.1.2-5, Item 1c, credits Steam Generator Tubing Integrity Program for
 
managing loss of material due to wear for nickel alloy Anti-Vibration Bars in treated
 
water/steam environment. LRA shows consistency with GALL Report Item IV.D1-15, which
 
rolls up to GALL Report Table 1 Item 74. LRA uses the standard Note E, which means this
 
item is consistent with the GALL Report item for material, environment, and aging effect, but a different aging management program is credited. GALL Report items IV.D1-24 and IV.D1-15 recommend the Water Chemistry C ontrol Program and Steam Generator Tubing Integrity Program for managing this component, material, environment, and aging effect
 
combination. During the audit and review, the staff asked the applicant to provide bases for
 
using Steam Generator Tubing Integrity Program alone.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that wear of steam generators anti-vibration bars
 
and tubes is considered an aging effect due to relative motion between surfaces primarily
 
as a result of flow-induced vibration and that as such, control of water chemistry is not
 
effective to manage loss of material due to wear, however, water chemistry controls are
 
generally credited to manage corrosion of the anti-vibration bars and tubes. The applicant
 
stated that the Steam Generator Tubing Integrity Program detects wear of anti-vibration
 
bars and tubes through the use of eddy current testing, visual inspections, and leakage
 
monitoring. The staff agreed with the applicant that the Water Chemistry Control Program is
 
not effective in mitigating loss of material due to wear for the above steam generator
 
components because the program is designed to prevent or mitigate the occurrence of
 
those aging effects induced by corrosive aging mechanisms and not mechanical aging
 
mechanisms (such as wear). The staff reviewed the applicant's Steam Generator Tubing
 
Integrity Program. The staff's evaluation is documented in SER Section 3.0.3.2.16. On the
 
basis of these evaluations, the staff finds that the applicant's response to be acceptable
 
and that the applicant does not need to credit the Water Chemistry Control Program in
 
conjunction with the Steam Generator Tube Integrity Program because the Water
 
Chemistry Control Program is not effective in managing loss of material that is induced by wear (i.e., it is only a mitigative program) and because the inspections performed under the
 
Steam Generator Tube Integrity program provide for sufficient condition monitoring of these
 
components.
 
During the audit and review, the staff asked the applicant to discuss whether loss of
 
material due to erosion or wear is a plausible aging effect for the VEGP feedwater and
 
auxiliary feedwater nozzles, and the feedwater J-tubes.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that the design of the VEGP steam generators, including the use of thermal sleeves, essentially eliminates wear/erosion as an aging effect
 
for these components. With respect to the VEGP feedwater and auxiliary feedwater
 
nozzles, the applicant stated that loss of material due to erosion has been evaluated and
 
found to be insignificant. The applicant stated that these components are not susceptible to
 
wear because there are not any other com ponents within close enough proximity to cause surface contact due to relative motion and wear. The applicant also stated that wear
 
caused by impact of hard, abrasive particles is not plausible due to the high quality of the
 
feedwater and that, the VEGP feedwater J-tubes are fabricated from nickel alloy (Alloy 600)
 
which provides superior resistance to erosion or wear when compared to carbon steel
 
materials. The applicant stated that, although erosion is not considered to be an applicable 3-255 degradation mechanism for the feedwater J-tubes, the J-tubes have been included within the scope of the VEGP Steam Generator Program for Upper Internals as a conservative
 
measure. The staff finds this portion of the applicant's response acceptable, since it is
 
supported by industry operating experience and by WCAP-14757, Westinghouse Aging
 
Management Evaluation for Steam Generators, which indicates that erosion is not a
 
significant aging mechanism for these components and because in spite of this
 
determination, the applicant has conservatively include the feedwater J-tubes within the
 
scope of its Steam Generator Program for Upper Internals. 
 
3.1.2.1.7 Cracking Due to Stress Corrosion Cracking
 
During the audit and review, the staff noted that the discussion in LRA Table 3.1.1, Item 64, states that VEGP manages cracking due to SCC of the stainless steel pressurizer nozzle
 
safe ends (relief, safety, spray, and surge nozzles) and instrument penetrations with the
 
Water Chemistry Control Program and Inserv ice Inspection Program. LRA Table 3.1.2-1 uses a standard Note E for the AMR items 4a and 7a that roll up to the LRA Table 3.1.1, Item 64. Note E states (LRA Table 3.0-4) that the AMR line item is consistent with the GALL
 
Report for material, environment, and aging effect, but a different aging management
 
program is credited or the GALL Report identifies a plant-specific aging management
 
program. GALL Report Item IV.C2-19, which rolls up to GALL Report Table 1 Item 64, identifies cracking due to SCC as an aging effect for stainless steel pressurizer components
 
in reactor coolant environment. The GALL Report recommends GALL AMP XI.M2, "Water Chemistry," for PWR primary water and GALL AMP XI.M1, "ASME Section XI Inservice
 
Inspection, Subsections IWB, IWC, and IWD, for Class 1 Components" for managing this
 
aging effect while the LRA uses the Water Chemistry Control Program and Inservice
 
Inspection Program which is a plant specific program. The staff reviewed the applicant's
 
Water Chemistry Control Program and Inse rvice Inspection Program, and the staff's evaluations are documented in SER Sections 3.0.3.1.4 and 3.0.3.3.4, respectively. The
 
staff agreed with the applicant's determination that these LRA line items are consistent with
 
the GALL Report, except that the applicant's Inservice Inspection Program is identified as a
 
plant specific AMP for VEGP. The staff's review of the Inservice Inspection Program
 
includes the staff's assessment of the AM P's program elements against the recommended program element criteria that are provided in Branch Position RLSB-1 in Appendix A of the
 
SRP-LR (i.e., NUREG-1800, Revision 1). On the basis of the staff's evaluation of the AMP
 
and the staff's determination that the applicant's AMR results are consistent with the GALL
 
Report, the staff finds the applicant's AMR results to be acceptable.
 
During the audit and review, the staff noted that the discussion in LRA Table 3.1.1, Item 68, states that VEGP manages cracking due to SCC in stainless steel pressure boundary
 
components with the Water Chemistry Contro l Program and Inservice Inspection Program.
LRA Tables 3.1.2-3, 3.1.2-4, and 3.1.2-5 use a standard Note E for the AMR line items that
 
roll up to the LRA Table 3.1.1, Item 68. Note E states (LRA Table 3.0-4) that the AMR line
 
item is consistent with the GALL Report for material, environment, and aging effect, but a
 
different aging management program is credited or the GALL Report identifies a plant-
 
specific aging management program. GALL Report Section IV line items that roll up to GALL Report Table 1, Item 68, identify cracking due to SCC as an aging effect for stainless
 
steel or steel with stainless steel cladding reactor coolant system components in reactor
 
coolant environment. The GALL Report recommends GALL AMP XI.M2, "Water Chemistry," for PWR primary water and GALL AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, for Class 1 Components" for managing this aging effect
 
while the LRA uses the Water Chemistry Control Program and Inservice Inspection 3-256 Program which is a plant specific program. The staff reviewed the applicant's Water Chemistry Control Program and Inservice Ins pection Program, and the staff's evaluations are documented in SER Sections 3.0.3.1.4 and 3.0.3.3.4, respectively. The staff agreed
 
with the applicant's determination that these LRA line items are consistent with the GALL
 
Report, except that the applicant's Inservice Inspection Program is identified as a plant
 
specific AMP for the Vogtle LRA. The staff's review of the Inservice Inspection Program
 
includes the staff's assessment of the AM P's program elements against the recommended program element criteria that are provided in Branch Position RLSB-1 in Appendix A of the
 
SRP-LR (i.e., NUREG-1800, Revision 1). On the bases of the staff's evaluation of the AMP
 
and the staff's determination that the applicant's AMR results are consistent with the GALL
 
Report, the staff finds the applicant's AMR results to be acceptable.
 
During the audit and review, the staff noted that the discussion in LRA Table 3.1.1, Item 69, states that VEGP manages cracking due to SCC in the stainless steel reactor pressure
 
vessel (RPV) inlet and outlet nozzle safe ends with the Water Chemistry Control Program
 
and Inservice Inspection Program. It also states that VEGP manages cracking due to
 
PWSCC in the RPV inlet and outlet nozzle to safe end dissimilar metal welds with the
 
Water Chemistry Control Program, Inserv ice Inspection Program, and Nickel Alloy Management Program for Non-Reactor Vessel Closure Head Penetration Locations. LRA Table 3.1.2-1 uses a standard Note E for the AMR items 18a and 19a that roll up to the
 
LRA Table 3.1.1, Item 69. Note E states (LRA Table 3.0-4) that the AMR line item is
 
consistent with the GALL Report for material, environment, and aging effect, but a different
 
aging management program is credited or the GALL Report identifies a plant-specific aging
 
management program. GALL Report Item IV.A2-15, which rolls up to GALL Report Table 1
 
Item 69, identifies cracking due to SCC or PWSCC as an aging effect for stainless steel or
 
nickel alloy welds and/or buttering in reactor coolant environment. The GALL Report recommends GALL AMP XI.M2, "Water Chemistry," for PWR primary water and GALL AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, for Class
 
1 Components" for managing this aging effect. For the stainless steel welds, the LRA uses
 
the Water Chemistry Control Program and Inservice Inspection Program and the Water
 
Chemistry Control Program, Inservice Inspec tion Program, which is a plant specific program. For the nickel alloy welds, the LRA uses Nickel Alloy Management Program for
 
Non-Reactor Vessel Closure Head Penetration Locations in addition to the above
 
programs. The staff reviewed the applicant's Wa ter Chemistry Control Program, Inservice Inspection Program, and Nickel Alloy Management Program for Non-Reactor Vessel
 
Closure Head Penetration Locations. The staff's evaluations are documented in SER
 
Sections 3.0.3.1.4, 3.0.3.3.4, and 3.0.3.1.1, respectively. The staff agreed with the
 
applicant's determination that these LRA line items are consistent with the GALL Report, except that the applicant's Inservice In spection Program and Nickel Alloy Management Program for Non-Reactor Vessel Closure Head Penetrations are identified as plant specific
 
AMPs for the Vogtle LRA. The staff's reviews of the Inservice Inspection Program and the
 
Nickel Alloy Management program for Non-R eactor Vessel Closure Head Penetrations include the staff's assessments of the AM P program elements against the recommended program element criteria that are provided in Branch Position RLSB-1 in Appendix A of the
 
SRP-LR (i.e., NUREG-1800, Revision 1). On the basis of the staff's evaluations of the
 
AMPs and the staff's determination that the applicant's AMR results are consistent with the
 
GALL Report, the staff finds the applicant's AMR results to be acceptable.
 
During the audit and review, the staff noted that the LRA Table 3.1.2-5, Item 28a, credits
 
Water Chemistry Control Program and Steam Generator Tubing Integrity Program for
 
managing cracking due to stress corrosion cracking (SCC) for stainless steel steam 3-257 generator tube support plates and flow distribution baffles exposed to treated water. LRA shows consistency with GALL Report Item IV.D1-15, which rolls up to GALL Report Table 1
 
Item 74. However, GALL Report Item IV.D1-15 addresses loss of material due to crevice
 
corrosion and fretting aging effect, for steam generator structural and anti vibration bars.
 
Therefore, the LRA aging effect is different from the GALL Report for this item. Instead, it
 
appears that LRA Table 3.12.-5, Item 28a should have rolled up to GALL Item IV.D1-14 in
 
the GALL Report, Volume 2. During the audit and review, the staff asked the applicant to
 
explain why the LRA has considered LRA Table 3.1.2-5 Item 28a aging effect consistent
 
with the GALL Report Item IV.D1-15.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that LRA Table 3.1.2-5, Item 28a should have
 
been aligned to the GALL Report Item IV.D1-14 instead of IV.D1-15. Item 28a of LRA Table
 
3.1.2-5 will be revised to link to Item IV.D1-14. The staff confirmed that the applicant
 
revised the LRA in a letter dated March 20, 2008.
 
During the audit and review, the staff noted that LRA Table 3.1.2-5, Item 23a, credits the
 
Water Chemistry Control Program for managing cracking due to stress corrosion cracking (SCC) for nickel alloy steam outlet flow limit er exposed to steam. LRA shows consistency with GALL Report Item IV.D1-14, which rolls up to GALL Report Table 1 Item 74. LRA uses
 
the standard Note E, which means this item is consistent with the GALL Report item for
 
material, environment, and aging effect, but a different aging management program is
 
credited. However, GALL Report Item IV.D1-14 recommends the Water Chemistry Control
 
Program and the Steam Generator Tubing Int egrity Program for managing this component, material, environment, and aging effect combination. During the audit and review, the staff
 
asked the applicant to provide a basis for using the Water Chemistry Control Program
 
alone.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that the VEGP steam outlet flow limiter is
 
exposed to high purity secondary side steam which does not contain the impurities which
 
have been implicated in stress corrosion cracking of thermally treated Alloy 600 tubing. The
 
applicant also stated that the corrosion potentials for these components are significantly
 
different in the main steam environment, as compared with more aggressive areas of the
 
steam generator secondary side (e.g. top of tubesheet region), and also that the applicant
 
did not identify any VEGP or domestic PWR operating experience related to degradation of
 
a thermally treated Alloy 600 main steam flow limiters. The staff finds the applicant's
 
response acceptable based on the quality of high purity of steam and the lack of VEGP-
 
specific and industry-specific operating experience related to this aging effect for the Alloy
 
600 main steam flow limiter.
 
3.1.2.1.8 Cracking Due to Primary Water Stress Corrosion Cracking for Nickel Alloy
 
Components
 
During the audit and review, the staff noted that the discussion in LRA Table 3.1.1, Item 65, states that VEGP manages PWSCC of the reactor vessel closure head nickel alloy
 
penetrations with the Water Chemistry Control Program, the Inservice Inspection Program, and the Nickel Alloy Management Program for Reactor Vessel Closure Head Penetrations.
 
LRA Table 3.1.2-1 uses a standard Note E for the AMR items 10a and 13a that roll up to
 
the LRA Table 3.1.1, Item 65. Note E states (LRA Table 3.0-4) that the AMR line item is
 
consistent with the GALL Report for material, environment, and aging effect, but a different 3-258 aging management program is credited or the GALL Report identifies a plant-specific aging management program. GALL Report items IV.A 2-9 and IV-A2-18, which roll up to GALL Report Table 1. Item 65, identify cracking due to PWSCC as an aging effect for nickel alloy
 
components in reactor coolant environm ent. The GALL Report recommends GALL AMP XI.M2, "Water Chemistry," for PWR primary water, GALL AMP XI.M11-A, "Nickel-Alloy
 
Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads," and GALL AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, for Class
 
1 Components" for managing this aging effect while the LRA uses the Water Chemistry
 
Control Program, the Nickel Alloy Management Program for RVCH Penetrations, and the
 
Inservice Inspection Program which is a plant specific program. The staff reviewed the
 
applicant's Water Chemistry Control Program , Nickel Alloy Management Program for RVCH Penetrations, and Inservice Inspection Program, and the staff's evaluations are
 
documented in SER Sections 3.0.3.1.4, 3.0.3.1.1, and 3.0.3.3.4, respectively. The staff
 
agrees with the applicant's determination that these LRA line items are consistent with the
 
GALL Report, except that the applicant's Inservice Inspection Program is identified as a
 
plant specific AMP for VEGP. The staff's review of the Inservice Inspection Program
 
includes the staff's assessments of the AMP program elements against the recommended program element criteria that are provided in Branch Position RLSB-1 in Appendix A of the
 
SRP-LR (i.e., NUREG-1800, Revision 1). On the basis of the staff's evaluation of the AMPs
 
and the staff's determination that the applicant's AMR results are consistent with the GALL
 
Report, the staff finds the applicant's AMR results to be acceptable.
 
3.1.2.1.9 Cracking Due to Stress Corrosion Cracking or Thermal and Mechanical Loading
 
During the audit and review, the staff noted that the discussion in LRA Table 3.1.1, Item 70, states that VEGP manages cracking due to SCC with the Water Chemistry Control Program (Appendix B.3.28), Inservice Inspection Program, and the One-Time Inspection Program for
 
ASME Class 1 Small-Bore Piping. LRA Tables 3.1.2-3 uses a standard Note E for the AMR
 
items 8b that rolls up to the LRA Table 3.1.1, Item 70. Note E states (LRA Table 3.0-4) that
 
the AMR line item is consistent with the GALL Report for material, environment, and aging
 
effect, but a different aging management program is credited or the GALL Report identifies
 
a plant-specific aging management program. GALL Report Item IV.C2-9, which rolls up to
 
GALL Report Table 1 Item 70, identifies cracking due to SCC as an aging effect for
 
stainless steel Class 1 piping, fittings and branch connections < NPS 4 in reactor coolant
 
environment. The GALL Report recommends GALL AMP XI.M2, "Water Chemistry," for PWR primary water and GALL AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, for Class 1 Components" for managing this aging effect.
 
The LRA uses the Water Chemistry Control Program and Inservice Inspection Program which is a plant specific program. The staff reviewed the applicant's Water Chemistry
 
Control Program and Inservice Inspection Program, and the staff's evaluation is documented in SER Sections 3.0.3.1.4 and 3.0.3.3.4, respectively. The staff agrees with
 
the applicant's determination that these LRA line items are consistent with the GALL
 
Report, except using a plant specific AMP. On the basis of the staff's evaluation of the
 
AMPs and the staff's determination that the applicant's AMR results are consistent with the
 
GALL Report, the staff finds the applicant's AMR results to be acceptable.
 
During the audit and review, the staff noted that the discussion in LRA Table 3.1.1, Item 70
 
states that VEGP manages cracking due to cyclic loading with the Fatigue and Cycle
 
Monitoring Program, Inservice Inspection Pr ogram, and the One-Time Inspection Program for ASME Class 1 Small-Bore Piping. LRA Tables 3.1.2-3 uses a standard Note E for the
 
AMR items 8a that rolls up to the LRA Table 3.1.1, Item 70. Note E states (LRA Table 3.0-3-259 4) that the AMR line item is consistent with the GALL Report for material, environment, and aging effect, but a different aging management program is credited or the GALL Report
 
identifies a plant-specific aging management program. GALL Report Item IV.C2-9, which
 
rolls up to GALL Report Table 1 Item 70, identifies cracking due to thermal and mechanical
 
loading as an aging effect for stainless steel Class 1 piping, fittings and branch connections
 
< NPS 4 in reactor coolant environment. The GALL Report recommends GALL AMP XI.M2, "Water Chemistry," for PWR primary water and GALL AMP XI.M1, "ASME Section XI
 
Inservice Inspection, Subsections IWB, IWC, and IWD, for Class 1 Components," and GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-bore Piping" for
 
managing this aging effect. The LRA uses the One-Time Inspection for ASME Class 1
 
Small Bore Piping, Fatigue Monitoring Program , and Inservice Inspection Program which is a plant specific program. During the audit and review, the staff asked the applicant to clarify
 
whether the aging effect "cracking due to cyclic loading" already postulates the initiation of
 
a fatigue-induced crack in these piping components and justify how the Fatigue Monitoring
 
Program manages cracking due to cyclic l oading in these components when the program does not credit any inspections of the components surfaces. The staff also asked the
 
applicant to discuss the inspection methods or techniques and frequency of these
 
inspections that are being used to detect, monitor/trend cracking due cyclic loading
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that, as discussed in Section 3.1.2.2.1 of this
 
document, the applicant will revise LRA Table 3.1.2-3, Item 8a to refer to the GALL Report
 
Item IV.C2-25 that rolls up to Table 1 line 8 instead of GALL Report Item IV.C2-9 which
 
rolls up to Table 1 line 70. The applicant stated that Table 1 Item 70 will not be used by
 
VEGP for cracking due to cyclic loading and that it will amend the LRA to replace the term "cracking due to cyclic loading" with the term "Cracking - Thermal Fatigue," because SNC
 
does not postulate the pre-existence of a fatigue-induced crack. The applicant further
 
stated that component inspections are not performed by the Fatigue Monitoring Program and the program monitors the CUF values for these components to manage cracking due
 
to thermal fatigue. The staff finds the applicant response acceptable since it provided
 
clarification that VEGP does not postulate a fatigue-induced crack for small bore stainless
 
steel Class 1 piping components that are exposed to borated water. The staff confirmed
 
that the applicant made the appropriate amendments of the LRA in a letter dated March 20, 2008.
 
3.1.2.1.10 Loss of Material/ Erosion, General, Pitting, and Crevice Corrosion
 
During the audit and review, the staff noted that the discussion in LRA Table 3.1.1, Item 76, states that the VEGP steam generator moisture separator assemblies are aligned to this
 
item as a substitute. VEGP manages loss of material in the steam generator moisture
 
separator assemblies with the Water Chemistry Control Program and the Steam Generator
 
Program for Upper Internals. LRA Table 3.1.2-5 uses a standard Note E for the AMR items
 
11a and 12a that roll up to the LRA Table 3.1.1, Item 76. Note E states (LRA Table 3.0-4)
 
that the AMR line item is consistent with the GALL Report for material, environment, and
 
aging effect, but a different aging management program is credited or the GALL Report
 
identifies a plant-specific aging management program. GALL Report Item IV.D1-9, which
 
rolls up to GALL Report Table 1 Item 76, identifies loss of material/ erosion, general, pitting, and crevice corrosion steel steam generator tube bundle wrapper Secondary feedwater/
 
steam environment. The GALL Report recommends GALL AMP XI.M19, "Steam Generator Tubing Integrity" and GALL AMP XI.M2, "Water Chemistry," for PWR secondary water for
 
managing this aging effect. The LRA uses the Water Chemistry Control Program and 3-260 Steam Generator Program for Upper Internals, which is a plant specific program. For the nickel alloy welds, the LRA uses Nickel Alloy Management Program for Non- Reactor
 
Vessel Closure Head Penetration Locations in addition to the above programs. 
 
The staff reviewed the applicant's Water Chemistry Control Program and Steam Generator
 
Program for Upper Internals. The staff verified that the scope of the Steam Generator
 
Program for Upper Internals is credited to manage age related degradation (i.e. loss of
 
material or cracking) in secondary side SG internal components, which are located in the
 
upper regions of SG. The scope of the Water Chemistry Control Program is credited to
 
mitigate or prevent corrosion-induced aging effects (loss or material or cracking) in these
 
components. The staff's evaluations are documented in SER Sections 3.0.3.1.4, and
 
3.0.3.3.8 respectively. The staff agrees with the applicant's determination that these LRA
 
line items are consistent with the GALL Report, except the applicant is using the Steam
 
Generator Program for Upper Internals, instead of the Steam Generator Tubing Integrity
 
Program and that the applicant has identified its Steam Generator Program for Upper
 
Internals as a plant specific AMP for the Vogtle LRA. The staff's review of the Steam
 
Generator Program for Upper Internals in cludes the staff's assessments of the AMP program elements against the recommended program element criteria that are provided in Branch Position RLSB-1 in Appendix A of the SRP-LR (i.e., NUREG-1800, Revision 1) and
 
the ability of the AMP to manage loss of material and cracking in the SG upper internal
 
components. On the basis of the staff's evaluations of the AMPs and the staff's
 
determination that the applicant's AMR results are consistent with the GALL Report, the
 
staff finds the applicant's AMR results to be acceptable.
 
The staff evaluated the applicant's claim of consistency with the GALL Report. The staff
 
also reviewed information pertaining to the applicant's consideration of recent operating
 
experience and proposals for managing aging effects. On the basis of its review, the staff
 
concludes that the AMR results, which the applicant claimed to be consistent with the GALL
 
Report, are indeed consistent with 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 their intended function(s) will be maintained consistent with
 
the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation
 
is Recommended In LRA Section 3.1.2.2, the applicant further evaluated aging management, as
 
recommended by the GALL Report, for the reactor vessel, reactor vessel internals, and
 
RCS components and provides information c oncerning 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 (SCC) and intergranular stress corrosion cracking (IGSCC) 3-261  crack growth due to cyclic loading  loss of fracture toughness due to neutron irradiation embrittlement and void swelling  cracking due to SCC  cracking due to cyclic loading  loss of preload due to stress relaxation  loss of material due to erosion  cracking due to flow-induced vibration  cracking due to SCC and irradiation-assisted SCC  cracking due to primary water SCC  wall thinning due to flow-accelerated corrosion  changes in dimensions due to void swelling  cracking due to SCC and primary water SCC  cracking due to SCC, primary water SCC (PWSCC), and irradiation-assisted SCC (IASCC)
For component groups evaluated in the GALL Report, for which the applicant claimed
 
consistency with the report and for which the report recommends further evaluation, the
 
staff audited and reviewed the applicant's evaluation to determine whether it adequately
 
addressed the issues further evaluated. In addition, the staff reviewed the applicant's 
 
further evaluations against the criteria contained in SRP-LR Section 3.1.2.2. The staff's
 
review of the applicant's further evaluation follows.
 
3.1.2.2.1  Cumulative Fatigue Damage 
 
LRA Section 3.1.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants
 
must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents
 
the staff's review of the applicant's evaluation of this TLAA.
 
LRA Table 3.1.1, items 3.1.1-02, 3.1.1-03, and 3.1.1-04, indicate that the AMR result lines
 
are applicable to BWRs. The staff reviewed those AMR result lines in the SRP-LR and in
 
the GALL Report and agrees with the applicant's determination that the lines are not
 
applicable to VEGP which is a PWR.
 
In reviewing LRA AMR Tables 3.1.1, 3.2.1, 3.3.1, 3.4.1, 3.5.1, and 3.6.1 (Table 1s) the staff
 
noted that these tables include line-items that list TLAA, in the aging management program
 
column, for managing/evaluating identified aging effects, and address their corresponding
 
further evaluation subsections in Section 3 that refer to subsections of LRA Section 4, 3-262 "Time Limited Aging Analysis," for additional discussions for the LRA Table 1s line-items.
However, Section 4.0 does not provide details of the component/structure, material, environment, and aging effects combinations that are evaluated by the TLAA. In addition, the corresponding LRA Table 2s do not identify aging management programs that are
 
credited in accordance with 10 CFR 54.21(c)(1)(iii). During the audit and review, the staff
 
asked the applicant to provide details on the component/structure, material, environment, and aging effect combinations that are evaluated by TLAA, and clearly identify those line-
 
items that credit an aging management program in addition to/instead of a TLAA.
 
The applicant in its response stated that for those components in VEGP LRA Table 1s that
 
are associated with a TLAA, the further evaluation describes the TLAA and refers to section
 
4 of the LRA. As such, LRA Table 4.1.2-1 of Section 4 lists the TLAAs applicable to VEGP
 
and identifies the disposition method from 10 CFR 54.21(c)(1). The applicant further stated
 
that for TLAAs where the existing analysis remains valid, i.e. demonstration in accordance
 
with 10 CFR 54.21 (c)(1)(i), or TLAAs where analyses have been projected to the end of
 
the period of extended operation, i.e.10 CFR 54.21 (c)(1)(ii), there is not a resulting aging
 
effect requiring management for the period of extended operation. For these items, there
 
are not associated line items in the AMR results tables (Table 2s) in Section 3. For TLAAs
 
where disposition requires an AMR, i.e. 10 CFR 54.21(c)(1)(iii), an AMR is required and
 
there are associated line items included in the AMR results tables (Table 2s) in Section 3.
 
The applicant in its response stated that LRA Tables 3.1.2-3 3.1.2-5, 3.1.2-7, and 3.1.2-8
 
with their associated Table 3.1.1 items will be revised either to correct the existing AMR line
 
items or add AMR line items. Also, the applicant, in its response, stated that VEGP does
 
not have any Table 2 item associated with LRA Table 3.1.1, items 3.1.1-1, 5, 6, 9, 10, 17, and 21.
 
The applicant in its response stated that LRA Tables 3.1.2-3, 3.1.2-4, and 3.1.2-5 AMR line items as follows: 
 
For Table 3.1.2-3 item 9a and for Table 3.1.2-4 items 2b, 3b, 4b, 6b, 7b, 10a, 11a;
 
the aging effect requiring management will be changed from "Cracking - Cyclic
 
Loading" to "Cracking - Thermal Fatigue", the Fatigue Monitoring Program will be
 
included as the sole aging management program credited, and the GALL linkage
 
will be changed to GALL Item IV.C2-25. 
 
For Table 3.1.2-3 Item 8a the Aging Effect Requiring Management is changed from "Cracking - Cyclic Loading" to "Cracking - Thermal Loading" and the Fatigue
 
Monitoring Program is removed from t he Aging Management Programs. A new item, 8e, is added to Table 3.2.1-3 with the same Component type, intended function, material, and environment as Item 8a. The aging effect requiring management for
 
the new item is Cracking - Thermal Fatigue. The aging management program for the
 
new item is the Fatigue Monitoring Program. The NUREG-1801 Vol. 2 Item is IV.C2-
: 25. The Table 1 Item for the new item is 3.1.1-8 and the Note is E.
 
For Table 3.1.2-4 item 9a was included in error and will be deleted.
 
For Table 3.1.2-5 items 2a and 8a, the aging effect requiring management will be
 
changed from "Cracking - Cyclic Loading" to "Cracking - Thermal Fatigue", the
 
Fatigue Monitoring Program will be included as the sole aging management
 
program credited, and the GALL linkage is changed to GALL Item IV.D1-11.
3-263  For Table 3.1.2-5 Item 6a, the aging effect requiring management will be changed
 
from "Cracking - Cyclic Loading" to "Cracking - Thermal Fatigue." There is no
 
change to the AMP.
 
The staff confirmed that the applicant made the appropriate amendment of the LRA in a
 
letter dated March 20, 2008. Therefore, the staff finds the applicant's response acceptable.
 
In LRA Table 3.1.1, Item 3.1.1-1, under discussion column, the applicant states that this
 
item is not applicable to VEGP, because the VEGP reactor pressure vessels are a
 
Westinghouse design without a support skirt. Therefore, the applicable GALL Report Item
 
IV.A2-20 was not used. The staff noted that Section 5.4.14.2.1 of VEGP UFSAR states that
 
support for the reactor vessel are individual, air cooled, rectangular box structure beneath
 
the vessel nozzles bolted to the primary shield wall concrete. GALL Table 1, line-item 1
 
identifies cumulative fatigue damage as the aging effect and recommends TLAA evaluation
 
in accordance with 10 CFR 54.21(c). Although VEGP reactor vessels are not supported by
 
a support skirt, the staff finds cumulative fatigue damage aging effect, as identified in GALL
 
Table 1, line-item 1, applicable to the rectangular support structures (listed as Item 17 in
 
LRA Table 3.1.2-1). During the audit and review, the staff asked the applicant to explain
 
why cumulative fatigue damage aging effect is not considered for the VEGP reactor
 
supports.
 
The applicant in its response stated that cumulative fatigue damage is an applicable TLAA
 
for the VEGP reactor vessel supports. However, the existing TLAA for the VEGP reactor
 
vessel supports, discussed in LRA Section 4.3.4, is demonstrated to be valid for the
 
extended term of operation in accordance with 10 CFR 54.21(c)(1)(i). As such, there is no
 
aging effect requiring management for the period of extended operation based on the TLAA
 
disposition, and these TLAA items are not included in the Table 2s in Section 3. The
 
applicant in its response added that the discussion for Table 1 Item 3.1.1-1 will be revised
 
to clarify that fatigue of the VEGP RPV support pads is a TLAA and is discussed in Section
 
4.3 of the VEGP LRA.
 
The staff confirmed that the applicant made the appropriate amendment of the LRA in a
 
letter dated March 20, 2008. Therefore, the staff finds the applicant's response acceptable.
 
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 criteria in SRP-LR Section 3.1.2.2.2:
 
LRA Section 3.1.2.2.2 addresses loss of material in once-through SG shell and boiling-
 
water reactor (BWR) reactor vessel components exposed to feedwater and steam as not an
 
AERM because VEGP is a Westinghouse-design PWR with recirculating Model F SGs.
 
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 feedwater and steam. Loss of material due to general, pitting, and crevice corrosion also may occur in the steel top head enclosure (without
 
cladding) top head nozzles (vent, top head spray or reactor core isolation cooling (RCIC),
and spare) exposed to reactor coolant.
 
3-264 The staff reviewed the GALL Report Table 1, the SRP-LR items 11 and 12 and the comparable AMR result lines in the GALL Report (IV.A1-11 and IV.D2-8, respectively). The
 
staff confirmed that the GALL Report and SRP-LR for Item 11 apply to BWRs, and the
 
GALL Report and SRP-LR for Item 12 apply to once-through steam generators only. On the
 
basis that VEGP is not a BWR and the VEGP steam generators are Westinghouse
 
recirculating steam generator, the staff agrees with the applicant's determination that LRA
 
Table 3.1.1, items 11 and 12, are not applicable to VEGP.
 
LRA Section 3.1.2.2.2 addresses loss of material in BWR isolation condenser components
 
as an aging effect not applicable to VEGP, a PWR plant.
 
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 staff reviewed the GALL Report Table 1, Item 13, and the comparable AMR result lines
 
in the GALL Report (IV.C1-6) and in the SRP-LR. The staff confirmed that the GALL Report
 
Table 1, Item 13 applies only to BWRs. On the basis that VEGP is not a BWR, the staff
 
agrees with the applicant's determination that LRA Table 3.1.1, Item 13 is not applicable to
 
VEGP.
 
LRA Section 3.1.2.2.2 addresses loss of material in BWR reactor vessel and reactor
 
coolant pressure boundary components as an aging effect not applicable to VEGP, a PWR
 
plant.
 
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 staff reviewed the GALL Report Table 1, items 14 and 15, and the comparable AMR
 
result lines in the GALL Report (IV.A1-8 and IV.C1-14, respectively) and in the SRP-LR
 
Table 3.1.1, items 14 and 15. The staff confirmed that the GALL Report and SRP-LR
 
comparable line items apply only to BWRs. On the basis that VEGP is not a BWR, the staff
 
agrees with the applicant's determination that LRA Table 3.1.1, items 14 and 15 are not
 
applicable to VEGP.
 
LRA Section 3.1.2.2.2 addresses loss of material in SG upper and lower shells and
 
transition cones exposed to feedwater and steam and the ability to detect pitting and
 
crevice corrosion described in NRC Information Notice (IN) 90-04 if general and pitting
 
corrosion of the shell are present. For Westinghouse Models 44 and 51 SGs the SRP-LR
 
includes additional inspection requirements. 
 
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 feedwater and steam.
The existing program controls chemistry to mitigate corrosion and inservice inspection (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, according to
 
NRC Information Notice (IN) 90-04, the program may not be sufficient to detect pitting and 3-265 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.
 
In LRA Section 3.1.2.2.2, the applicant states that it credits its Water Chemistry Control
 
Program and its Inservice Inspection Program manage loss of material in the SG secondary
 
side pressure boundary components as a result of general, pitting or crevice corrosion.
 
Secondary side SG activities with feedback on secondary side conditions have not found
 
the conditions described in IN 90-04. Steam Generator Program periodic updates consider
 
new industry experience or research data. If information indicates that this issue is of
 
concern for Model F steam generators of similar vintage and operating history, the Steam
 
Generator Program will implement appropriate inspection activities. 
 
Since the VEGP reactors are designed Westinghouse Model F SGs, and since the
 
guidance in IN 90-04 is only applicable to Westinghouse Model 44 or Model 51 SGs, the
 
staff concludes that the further evaluation guidance and the additional inspections
 
recommended in the SRP-LR and the GALL Report are not applicable to the applicant's AMR assessments for the VEGP SGs.
 
During the audit and review, the staff noted that LRA Table 3.1.2-5, Item 29b, credits the
 
Water Chemistry Control Program, the In service Inspection Program, and the Steam Generator Tubing Integrity Program for managing loss of material aging effects for alloy
 
steel tube plates exposed to treated water. The AMR item in the LRA claims consistency
 
with the GALL Report Item IV.D1-12, which rolls up to GALL Table 1 Item 3.1.1-16. It also
 
uses a standard Note E, which means that this AMR item is consistent with the GALL
 
Report for material, environment, and aging effect, but a different aging management
 
program is credited. However, GALL Report Table 1, Item 16, and GALL Report Item
 
IV.D1-12 address loss of material due to general, pitting, and crevice corrosion for the
 
steam generator (SG) upper and lower shell, and transition cone fabricated from steel and
 
exposed to secondary feedwater/steam and it recommends Water chemistry and ISI
 
programs for managing this aging effect. In addition the GALL Report states that "As noted
 
in NRC IN 90-04, if general and pitting corrosion of the shell is known to exist, the AMP guidelines in Chapter XI.M1 may not be sufficient to detect general and pitting corrosion (and the resulting corrosion-fatigue cracking), and additional inspection procedures are to
 
be developed." During the audit and review, the staff asked the applicant to: a) explain how
 
LRA component type is consistent with the GA LL component type for this AMR line-item, b) explain whether the Steam Generator Tube Int egrity (SGTI) Program is used to augment the ISI Program, as noted in NRC IN 90-04, and discuss the additional inspections that are
 
performed to detect general and pitting corrosion (and the resulting corrosion-fatigue
 
cracking), and c) explain why the SGTI program is not used for other steam generator
 
components that are rolled up to Table 3.1.1, Item 3.1.1-16 (Table 3.1.2-5 items 2b, 8b, 20a, 21a, 24a, 25a, 29a, 31a, and 32a).
 
The applicant responded to the staff's question in a letter dated February 8, 2008. In this
 
response the applicant stated that LRA standard Note E does not refer to component type
 
consistency with the GALL Report and that as a result, the application of Note E in the
 
VEGP does not imply component type consistency. The applicant stated that for the SG
 
tubeplate, the VEGP ISI Program, which is implemented in accordance with the requirements of ASME XI, is capable of detecting significant loss of material due to
 
localized corrosion and that visual examinations of the secondary side of the tubeplates 3-266 performed under the ISI Program and the eddy curr ent examination/ultrasonic examinations performed in accordance with the Steam Generator Tubing Integrity Program will be
 
capable of monitoring for indications of localized corrosion associated with SG tube-to-
 
tubeplate interfaces. The applicant further stated that the LRA Table items listed in part c of
 
the above audit question, except Item 29a, relate to SG secondary side pressure boundary
 
components exposed to treated water and that, because aging management of these
 
ASME Code Safety Class 2 components is not addr essed by NEI 97-06, they are not within the scope of the VEGP Steam Generator Program; the applicant did clarify, however, that
 
these components are within the scope of the VEGP ISI Program. 
 
In regard to AMR Item 29a in LRA Table 3.1.2-5, which pertains to the management of loss
 
of material due to general, pitting, and crevice corrosion in the primary side Nickel-alloy
 
cladding in the SG tubeplates the applicant stated that it credits its Water Chemistry Control
 
Program alone to manage loss of material in the tubeplate surfaces that are exposed to the
 
borated water environment of the reactor coolant. The staff finds this to be acceptable
 
because the staff verified that the applicant's AMR is consistent the staff's AMR
 
recommendations in GALL AMR IV.C2-15.
 
The staff finds that the applicant's response to the staff's inquiry appropriately resolves the
 
issue raised in the question, because it clearly clarifies that the inspections performed
 
under the applicant's Steam Generator Tube Integrity Program will augment those
 
inspections that are implemented under the applicant's Inservice Inspection Program for
 
SG tube plates, and because the applicant's AMR to manage loss of material due to
 
general, pitting and crevice corrosion in the steel SG tube plates  is consistent with the
 
AMPs credited in GALL AMR IV.D1-12.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.1.2.2.2 criteria. For those line items that apply to LRA
 
Section 3.1.2.2.2, the staff concludes 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 criteria in SRP-LR Section
 
3.1.2.2.3:
 
LRA Section 3.1.2.2.3 states that neutron irradiation embrittlement 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 4.2 documents the staff's review of the applicant's evaluation of this TLAA.
 
In the applicant's response letter of February 8, 2008, the applicant stated that SNC will
 
amend the LRA to make the changes to its Type 2 AMR Tables and to provide clarifying
 
detail in the LRA Sections referenced in the Table 1s. Where a TLAA is dispositioned using
 
an aging management program, a note will be added to clarify which Table 2 items are
 
dispositioned by an aging management program. Where a TLAA is not dispositioned using
 
an aging management program, a note will be added to clarify that there are no associated
 
items in the Table 2s. The applicant in its response stated that there are no Table 2 items
 
related to Table 3.1.1, Item 3.1.1-17.
 
3-267 The staff confirmed that the applicant in its letter dated March 20, 2008) provided the above clarification for the AMR line items associated with the Table 3.1.1, Item 3.1.1-17.
 
LRA Section 3.1.2.2.3 addresses loss of fracture toughness due to neutron irradiation
 
embrittlement as an AERM that the Reacto r Vessel Surveillance Program, supported by TLAA evaluations, manages consistent with the SRP-LR. Reactor vessel components that
 
may reach a fluence equal to or greater than 1 x 10 17 n/cm 2 (E > 1.0 MeV) prior to the period of extended operation include the intermediate course shells, lower course shells, upper (nozzle) course shells, and the inlet nozzles. The last capsules examined for Units 1
 
and 2 were exposed to a fluence approximatel y equal to the expected 60-year operating fluence. Standby surveillance capsules remain in both Units 1 and 2 reactor vessels. 
 
SRP-LR Section 3.1.2.2.3 states that loss of fracture toughness due to neutron irradiation
 
embrittlement may occur in BWR and PWR reactor vessel beltline shell, nozzle, and welds
 
exposed to reactor coolant and neutron flux. A reactor vessel materials surveillance
 
program monitors neutron irradiation embrittlement of the reactor vessel. Reactor vessel
 
surveillance programs are plant-specific, depending on matters such as the composition of
 
limiting materials, availability of surveillance capsules, and projected fluence levels. In
 
accordance with 10 CFR Part 50, Appendix H, an applicant is required to submit its
 
proposed withdrawal schedule for approval prior to implementation. Untested capsules
 
placed in storage must be maintained for future insertion. Thus, further staff evaluation is
 
required for license renewal. Specific recommendations for an acceptable AMP are provided in GALL Report Chapter XI, Section M31.
 
The staff noted that LRA Table 3.1.2-1 items 14a (intermediate shell course), 16a (lower
 
shell course), and 23a (upper shell course) credit Reactor Vessel Surveillance Program for
 
managing loss of fracture toughness aging effect for these components in borated water
 
environment. However, 10 CFR 50.61 (a)(3) states that "Reactor Vessel Beltline means the
 
region of the reactor vessel (shell material including welds, heat affected zones and plates
 
or forgings) that directly surrounds the effective height of the active core and adjacent
 
regions of the reactor vessel that are predicted to experience sufficient neutron radiation
 
damage to be considered in the selection of the most limiting material with regard to
 
radiation damage." During the audit and review, the staff asked the applicant to clarify
 
whether welds are included in these line-items or provide technical justification for
 
excluding welds from the AMR tables.
 
The applicant responded to the staff's question in a letter dated February 8, 2008. In this
 
response, the applicant stated that weld material used in the reactor pressure vessel
 
component fabrication and the metallurgical effects of the welding techniques employed are
 
included with the base material evaluated in specific reviews of materials and associated
 
aging mechanisms. Therefore, the welds are included in the reactor components (upper, intermediate and lower shell courses) that are managed for loss of fracture toughness by
 
the Reactor Vessel Surveillance Program. The staff finds this response acceptable, because the staff concludes that loss of fracture toughness aging effect of the reactor
 
pressure vessel welds is managed by the Reactor Vessel Surveillance Program.
 
The staff concludes that the LRA correctly identifies VEGP components that are subject to
 
the aging effect of loss of fracture toughness due to neutron irradiation embrittlement and
 
that associated AMR results in LRA Table 3.1.1, items 3.1.1-18 and 3.1.2-1 are consistent
 
with the recommendations in the GALL Report. The staff reviewed the applicant's Reactor Vessel Surveillance Program, and the staff's evaluation is documented in SER Section 3-268 3.0.3.2.15. On the basis of the staff's evaluation of the AMP and the staff's determination that the applicant's AMR results are consistent with the GALL Report, the staff finds the
 
applicant's AMR results to be acceptable. The staff finds that this program includes
 
activities that are consistent with the recommendations in the GALL Report, and are
 
adequate to manage the aging effect of loss of fracture toughness due to neutron irradiation
 
embrittlement for alloy steel components clad with stainless steel exposed to reactor
 
coolant.
 
Based on the programs identified above, the staff concludes that the applicant's 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 concludes 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 criteria in SRP-LR Section
 
3.1.2.2.4:
 
LRA Section 3.1.2.2.4 addresses cracking of BWR top head enclosure
 
vessel flange leak detection lines as an aging effect not applicable to
 
VEGP, a PWR plant.
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 staff reviewed the GALL Report Table 1, SRP-LR line Item 19, and the comparable
 
AMR result lines in the GALL Report. The staff confirmed that the GALL Report and SRP-
 
LR line item apply only to BWRs. On the basis that VEGP is not a BWR, the staff agrees
 
with the applicant's determination that LRA Table 3.1.1, Item 19 is not applicable to VEGP.
 
LRA Section 3.1.2.2.4 addresses cracking of BWR isolation condenser components
 
exposed to reactor coolant as aging effect not applicable to VEGP, a PWR plant.
 
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 staff reviewed the GALL Report Table 1, SRP-LR Table 3.1.1, Item 20, and the
 
comparable AMR result lines in the GALL Report. The staff confirmed that the GALL Report
 
and SRP-LR line item apply only to BWRs. On the basis that VEGP is not a BWR, the staff
 
agrees with the applicant's determination that LRA Table 3.1.1, Item 20 is not applicable to
 
VEGP.
 
3.1.2.2.5  Crack Growth Due to Cyclic Loading 
 
LRA Section 3.1.2.2.5 states that growth of intergranular separations (underclad cracks) in
 
the heat affected zone under austenitic steel cladding is a TLAA, as defined in 3-269 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1).
SER Section 4.7 documents the staff's review of the applicant's evaluation of this TLAA.
 
In LRA Table 3.1.1, Item 3.1.1-21, under discussion column, the applicant states that this
 
item is not applicable to VEGP. Also, in LRA Section 3.1.2.2.5, "Crack Growth due to Cyclic
 
Loading," the applicant states that there are no analyses of underclad flaws in the VEGP
 
reactor vessels and therefore no TLAA exists for VEGP. It further added that there are SA-
 
508 Class 2 forgings clad using high heat input processes in the VEGP reactor pressure
 
vessel. However, weld processes used were subject to qualification and performance
 
testing as described in NRC Regulatory Guide 1.43 to ensure that underclad cracking
 
would not occur.
 
During the audit and review, the staff noted that SRP-LR Section 4.7.2.1 recommends that
 
the applicant should credit a TLAA to manage postulated crack growth in RPV components
 
fabricated from SA 508, Class 2 or 3 forgings or should demonstrate that the effects of
 
aging on the intended function will be adequately managed for the period of extended
 
function, if no TLAA exists. During the audit and review, the staff asked the applicant to: a)
 
Identify VEGP reactor pressure vessel components/portions that are made of SA-508 Class
 
2 steel forgings clad with stainless steel, b) provide additional justification for not using
 
TLAA for evaluation of underclad cracking in low-alloy steel safety related components clad
 
with stainless steel, and c) explain how crack growth due to cyclic loading is managed for
 
these components.
 
The applicant responded to the staff's question in a letter dated February 8, 2008. In this
 
response the applicant stated that the VEGP reactor pressure vessel components that are
 
fabricated from ASME SA-508 Cl. 2 forgings with internal stainless steel cladding material
 
include the closure head dome flanges (Table 3.1.2-1 Item 4), the primary inlet nozzles (Table 3.1.2-1 Item 17), the primary outlet nozzles (Table 3.1.2-1 Item 20), and the vessel
 
flanges (Table 3.1.2-1 Item 25). The applicant stated that it will amend the LRA to indicate
 
that the under-clad cracking analysis in Westinghouse WCAP-15338 is a TLAA for these
 
components, and that the underclad cracking analysis performed by Westinghouse in
 
WCAP-15338 demonstrates that analyzed growth of under-clad cracks in Westinghouse
 
reactor pressure vessel (RPV) components made from these is acceptable through 60-
 
years of license operation. As a result, the applicant stated that, based on the results of the
 
analysis in WCAP-15338, the TLAA on underclad cracking has been demonstrated to be
 
bounding in accordance with the criteria in accordance with 10 CFR 54.21(c)(1)(i). The staff
 
verified that the applicant made the applicable LRA amendment of LRA Sections 3.1 and
 
4.1, and supplemented the LRA to create LRA TLAA Section 4.7.5, "Underclad Cracking of
 
the Reactor Pressure Vessel," and UFSAR Section A.3.6.5, "Underclad Cracking of the
 
Reactor Pressure Vessel." 
 
The staff finds the applicant response, as supplemented by the applicant's amendments of
 
the LRA in the letter of March 20, 2008, to be acceptable because the applicant has
 
amended the LRA to indicate the TLAA on underclad cracking is credited to manage growth
 
postulated underclad cracks in those RPV components made from SA 508, Class 2
 
forgings and because this is in conformance with guidance in SRP-LR Section 3.1.2.2.5 .
 
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.
3-270  LRA Section 3.1.2.2.6 addresses loss of fracture toughness due to neutron irradiation
 
embrittlement and void swelling as an AERM that VEGP will manage, consistent with the
 
SRP-LR, by (1) participating in industry programs for investigating and managing aging
 
effects on reactor internals, (2) evaluating and implementing the results of the industry
 
programs applicable to the reactor internals, and (3) submitting an inspection plan for
 
reactor internals to the staff for review and approval not less than 24 months before the
 
period of extended operation. This commitment is included in the description of the Reactor
 
Vessel Internals Program and in the UFSAR Supplement description of the program.
 
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 UFSAR 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.
 
During the audit and review, the staff confirmed that the applicant in its letter dated August
 
11, 2008, in Commitment No. 20, stated that it will implement the Reactor Vessel Internals
 
Program, as described in LRA Section A.2.24 and Section B.3.24, based on the following
 
commitments: (1) SNC will participate in the industry program for investigating and
 
managing of aging effects on reactor internals. This is an ongoing commitment. (2) SNC will
 
evaluate and implement the results of the industry programs, such as the Electric Power
 
Research Institute Material Reliability Program, applicable to the VEGP reactor internals.
 
This commitment will be fully implemented prio r to the period of extended operation. (3)
SNC will submit an inspection plan for the VEGP reactor internals to the NRC for review
 
and approval not less than 24 months before entering the period of extended operation for
 
VEGP Units 1 and 2. This inspection plan will address the bases, inspection methods, and
 
acceptance criteria associated with aging management of the reactor vessel thermal
 
sleeves and the core support lugs (along with the associated support pads and attachment
 
welds).
 
Based on the programs identified above, the staff concludes that the applicant's 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 concludes 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 criteria in SRP-LR Section
 
3.1.2.2.7:
 
LRA Section 3.1.2.2.7 addresses cracking due to SCC in the stainless steel
 
reactor pressure vessel flange leakage-monitoring lines and the bottom-
 
mounted instrumentation guide tubes, stating that the Water Chemistry
 
Control Program and the Inservice Inspection Program manage cracking in 3-271 stainless steel portions of those. The leakage-monitoring lines serve no safety-related function and therefore need management only so leakage
 
has no adverse impact on other components inside containment. 
 
The Chemistry Control Program and the plant-specific Inservice Inspection
 
Program manage SCC in the bottom-mounted instrumentation guide tubes.
 
Cracking of the reactor vessel head thermal sleeves is aligned to this
 
summary item as a substitute.
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. The GALL
 
Report recommends that a plant-specific AMP be evaluated to ensure that
 
this aging effect is adequately managed.
 
LRA Table 3.1.2-1 items 2a and 22a credit the Water Chemistry Control Program
 
and Inservice Inspection Program for managing cracking due to SCC for bottom
 
mounted instrumentation guide tubes, and seal table and fittings that are fabricated
 
from stainless steel and exposed to borated water. During the audit and review, the
 
staff reviewed the applicant's license renewal program basis document for reactor
 
coolant pressure boundary systems and other supporting documents. The staff's
 
evaluation of the applicant's Water Chemistry Control Program is documented in
 
SER Section 3.0.3.1.4, and the staff's evaluation of the applicant's Inservice
 
Inspection Program is documented in SER Section 3.0.3.3.4. On the basis of its
 
review of these programs, the staff finds that the applicant's use of the Water
 
Chemistry Control Program and Inservice Inspection Program are adequate to
 
mitigate and manage cracking due to SCC for stainless steel components in borated
 
water environment.
 
The staff verified that the applicant credits its Water Chemistry Control Program, Inservice Inspection Program, and Nicke l-Alloy Management Program for Non-Reactor Vessel Head Closure Penetrations Program (refer to AMR 3a in LRA Table
 
3.1.2-1) to manage cracking due to primary water stress corrosion cracking in the
 
Nickel-alloy bottom mounted instrumentation penetrations. The staff verified that this
 
is in conformance with the guidelines in GALL AMR IV.A2-19. The staff finds this to
 
be acceptable because it is in conformance with the staff's recommendations in
 
GALL AMR IV.A2-19.
 
LRA Section 3.1.2.2.7 addresses cracking due to SCC that may occur in ASME Code Class
 
1 CASS piping components exposed to reactor coolant, stating that the reactor coolant loop
 
CASS elbows and laterals meet NUREG-0313 guidelines for ferrite content (greater than
 
7.5 percent) but not for carbon content (less than 0.035 percent). Consistent with the SRP-
 
LR, VEGP the Water Chemistry Control Program and the plant-specific Inservice Inspection Program manage cracking of these castings.
 
SRP-LR Section 3.1.2.2.7 states that cracking due to SCC may occur in Class 1 PWR
 
CASS reactor coolant system piping, pipi ng components, and piping elements exposed to reactor coolant. The existing program controls water chemistry to mitigate SCC; however SCC may occur in CASS components that do not meet the NUREG-0313 guidelines with
 
regard to ferrite and carbon content. The GALL Report recommends further evaluation of a 3-272 plant-specific program for these components to ensure this aging effect is adequately managed.
 
LRA Table 3.1.2-3, Item 10a, identifies cracking due to SCC for the reactor coolant loop
 
piping components that are fabricated of CASS and exposed to borated water and credits
 
the Water Chemistry Control Program and Inse rvice Inspection Program for managing this aging effect. During the audit and review, the staff reviewed the applicant's license renewal
 
Program basis document for reactor coolant pressure boundary systems and other
 
supporting documents. Based on its review and audit, the staff agrees with the applicant
 
that VEGP meets the guidelines in EPRI TR-105714 and NUREG-0313. The staff's
 
evaluation of the applicant's Water Chemistr y Control Program and Inservice Inspection Program is documented in SER Section 3.0.3.1.4 and 3.0.3.3.4, respectively. On the basis
 
of its review of these programs, the staff finds that the applicant's use of the Water Chemistry Control Program and Inservice Inspection Program are adequate to mitigate and
 
manage cracking due to SCC for CASS components in borated water environment.
 
Based on the programs identified above, the staff concludes that the applicant's 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 concludes 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 criteria in SRP-LR
 
Section 3.1.2.2.8:
 
LRA Section 3.1.2.2.8 addresses cracking of BWR jet pump sensing lines due to cyclic
 
loading as an aging effect not applicable to VEGP, a PWR plant.
 
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 staff reviewed the GALL Report Table 1, SRP-LR line Item 25, and the comparable
 
AMR result lines in the GALL Report. The staff confirmed that the GALL Report and the
 
SRP-LR item apply only to BWRs. On the basis that VEGP is not a BWR, the staff agrees
 
with the applicant's determination that LRA Table 3.1.1, Item 25 is not applicable to VEGP.
 
LRA Section 3.1.2.2.8 addresses cracking of BWR isolation condenser components due to
 
cyclic loading as an aging effect not applicable to VEGP, a PWR plant.
 
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 staff reviewed the GALL Report Table 1, SRP-LR line Item 26 and the comparable
 
AMR result lines in the GALL Report. The staff confirmed that the GALL Report and the
 
SRP-LR line item apply only to BWRs. On the basis that VEGP is not a BWR, the staff
 
agrees with the applicant's determination that LRA Table 3.1.1, Item 26 is not applicable to
 
VEGP.
 
3-273 3.1.2.2.9  Loss of Preload Due to Stress Relaxation 
 
The staff reviewed LRA Section 3.1.2.2.9 against the criteria in SRP-LR Section 3.1.2.2.9.
 
LRA Section 3.1.2.2.9 addresses loss of preload due to stress relaxation that may occur in
 
stainless steel and nickel alloy PWR reactor internals as an AERM that VEGP will manage, consistent with the SRP-LR, by (1) participating in industry programs for investigating and
 
managing aging effects on reactor internals, (2) evaluating and implementing the results of
 
the industry programs applicable to the reactor internals, and (3) submitting an inspection
 
plan for reactor internals to the staff for review and approval not less than 24 months before
 
the period of extended operation. This commitment is included in the description of the
 
Reactor Vessel Internals Program and in the UFSAR Supplement description of the
 
program.
 
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 UFSAR
 
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.
 
During the audit and review, the staff confirmed that, consistent with the GALL Report, the
 
applicant in Commitment No. 20 of Enclosure 2 to the applicant's letter of August 11,2008, committed to implementing its Reactor Vessel Internals Program, as described in LRA
 
Section A.2.24 and Section B.3.24, based on the following commitments: (1) SNC will
 
participate in the industry program for investigating and managing of aging effects on
 
reactor internals. This is an ongoing commitment. (2) SNC will evaluate and implement the
 
results of the industry programs, such as the Electric Power Research Institute Material
 
Reliability Program, applicable to the VEGP reactor internals. This commitment will be fully
 
implemented prior to the period of extended operation. (3) SNC will submit an inspection
 
plan for the VEGP reactor internals to the NRC for review and approval not less than 24
 
months before entering the period of extended operation for VEGP Units 1 and 2. This
 
inspection plan will address the bases, inspection methods, and acceptance criteria
 
associated with aging management of the reactor vessel thermal sleeves and the core
 
support lugs (along with the associated support pads and attachment welds). The staff finds
 
this to be acceptable because it is in conformance with the recommendations in SRP-LR
 
Section 3.1.2.2.9 and to the AMR items in GALL AMR Table IV.B2 that align to this SRP-LR
 
item.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.1.2.2.9 criteria. For those line items that apply to LRA
 
Section 3.1.2.2.9, the staff concludes 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).
 
3-274 3.1.2.2.10  Loss of Material Due to Erosion
 
The staff reviewed LRA Section 3.1.2.2.10 against the criteria in SRP-LR Section
 
3.1.2.2.10.
 
LRA Section 3.1.2.2.10 addresses erosion in SG impingement plates as an aging effect not
 
applicable because the SGs do not have impingement plates and instead use a
 
recirculating feed-ring design to distribute feedwater.
 
SRP-LR Section 3.1.2.2.10 states that loss of material due to erosion may occur in steel
 
steam generator feedwater impingement plates and supports exposed to secondary
 
feedwater.
 
During the audit and review, the staff noted that the VEGP UFSAR Section 5.4.2.2 states
 
that the water entering through the main feed nozzle is distributed circumferentially around
 
the steam generator by means of a feedwater ring and then flows through an annulus between the tube wrapper and shell. The feedwater enters the ring via a welded thermal
 
sleeve connection and leaves it through inverted J-tubes located at the flow holes which are
 
at the top of the ring. The J-tubes are arranged to distribute the bulk of the colder feedwater
 
to the hot leg side of the tube bundle. 
 
On the basis of this review, the staff confirmed that the VEGP steam generators do not
 
have impingement plates; therefore, LRA Table 3.1.1, Item 28, is not applicable to VEGP.
 
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 BWR stainless steel steam dryers exposed
 
to reactor coolant as an aging effect not applicable to VEGP, a PWR plant.
 
SRP-LR Section 3.1.2.2.11 states that cracking due to flow-induced vibration could occur
 
for the BWR stainless steel steam dryers exposed to reactor coolant.
 
The staff reviewed the GALL Report Table 1, SRP-LR line Item 29 and the comparable
 
AMR result lines in the GALL Report. The staff confirmed that the GALL Report and the
 
SRP-LR line Item apply only to BWRs. On the basis that VEGP is not a BWR, the staff
 
agrees with the applicant's determination that LRA Table 3.1.1, Item 29 is not applicable to
 
VEGP.
 
3.1.2.2.12  Cracking Due to Stress Corrosion Cracking and Irradiation-Assisted Stress
 
Corrosion Cracking 
 
The staff reviewed LRA Section 3.1.2.2.12 against the criteria in SRP-LR Section
 
3.1.2.2.12.
 
LRA Section 3.1.2.2.12 addresses cracking due to SCC and IASCC that may occur in
 
stainless steel PWR reactor internals exposed to reactor coolant as an AERM that VEGP
 
will manage, consistent with the SRP-LR, by the Water Chemistry Control Program and by (1) participating in industry programs for investigating and managing aging effects on 3-275 reactor internals, (2) evaluating and implementing the results of the industry programs applicable to the reactor internals, and (3) submitting an inspection plan for reactor internals
 
to the staff for review and approval not less than 24 months before the period of extended
 
operation. This commitment is included in the description of the Reactor Vessel Internals
 
Program and in the UFSAR Supplement description of the program.
 
SRP-LR Section 3.1.2.2.12 states that cracking due to SCC and irradiation-assisted stress
 
corrosion cracking (IASCC) may occur in PWR stainless steel reactor internals exposed to
 
reactor coolant. The existing program controls water chemistry to mitigate these aging
 
effects. The GALL Report recommends no further AMR if the applicant commits in the
 
UFSAR supplement (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.
 
LRA Table 3.1.2-2 credits the Water Chemistry Control and Reactor Vessel Internals
 
Programs for managing cracking due to SCC for the rector vessel internal components that
 
are fabricated from stainless steel (including CASS) and are exposed to borated water.
 
During the audit and review, the staff confirmed that, consistent with the GALL Report, the
 
applicant, in Commitment No. 20 of Enclosure 2 of the applicant's letter dated August
 
11,2008, committed to implementing its Reactor Vessel Internals Program, as described in
 
LRA Section A.2.24 and Section B.3.24, based on the following commitments: (1) SNC will
 
participate in the industry program for investigating and managing of aging effects on
 
reactor internals. This is an ongoing commitment. (2) SNC will evaluate and implement the
 
results of the industry programs, such as the Electric Power Research Institute Material
 
Reliability Program, applicable to the VEGP reactor internals. This commitment will be fully
 
implemented prior to the period of extended operation. (3) SNC will submit an inspection
 
plan for the VEGP reactor internals to the NRC for review and approval not less than 24
 
months before entering the period of extended operation for VEGP Units 1 and 2. This
 
inspection plan will address the bases, inspection methods, and acceptance criteria
 
associated with aging management of the reactor vessel thermal sleeves and the core
 
support lugs (along with the associated support pads and attachment welds). The staff finds
 
this to be acceptable because it is in conformance with the recommendations in SRP-LR 
 
Section 3.1.2.2.12 and to the AMR items in GALL AMR Table IV.B2 that align to this SRP-
 
LR item.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.1.2.2.12 criteria. For those line items that apply to LRA
 
Section 3.1.2.2.12, the staff concludes 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).
 
3.1.2.2.13  Cracking Due to Primary Water Stress Corrosion Cracking 
 
The staff reviewed LRA Section 3.1.2.2.13 against the criteria in SRP-LR Section
 
3.1.2.2.13.
 
LRA Section 3.1.2.2.13 addresses cracking due to PWSCC of nickel alloy components, 3-276 stating that the Water Chemistry Contro l Program, Inservice Inspection Program, and Nickel Alloy Management Program for Non-Reactor Vessel Closure Head Penetration
 
Locations manages PWSCC of RPV bottom-mounted instrument penetrations, SG drain
 
connections, and nickel alloy butt welds. The Nickel Alloy Management Program for Non-
 
Reactor Vessel Closure Head Penetration Locations includes a commitment to comply with
 
NRC orders and to implement bulletins, generic letters, and staff-accepted industry
 
guidelines. This commitment is included in the description of the Nickel Alloy Management
 
Program for Non-Reactor Vessel Closure Head Penetration Locations and in the UFSAR
 
Supplement description of the program. 
 
The applicant also stated that unlike the GALL Report AMP, the Water Chemistry Control
 
Program and the Reactor Vessel Internals Pr ogram VEGP will manage cracking of the core support lugs and pads. The Reactor Vessel Internals Program includes commitments to
 
evaluate and implement the results of industry programs applicable to the reactor internals
 
and to submit an inspection plan for reactor internals to the staff for review and approval
 
upon completion of these programs but at least 24 months before the period of extended
 
operation. The Reactor Vessel Internals Program inspection plan submitted to the staff will
 
implement requirements of any NRC orders, bulletins, or generic letters applicable to
 
cracking of the core support lugs and pads. LRA Table 3.3.2-27 aligns the sampling system
 
pressurizer and RCS sample cooler tubing to this summary item as a substitute. The Alloy
 
600 tubing extending past the shell of the cooler is within the 10 CFR 54.4(a)(2) scope of
 
license renewal. The Alloy 600 tubing is exposed to high temperature borated water and
 
welded to the stainless steel sampling system piping. Cracking of this tubing could occur
 
due to SCC at this welded location. The Water Chemistry Control Program and the One-
 
Time Inspection Program will manage cracking of these tubes.
 
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 reactor coolant pressure boundary 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 UFSAR supplement to implement applicable (1) bulletins and generic letters, and
 
(2) staff-accepted industry guidelines.
 
LRA Table 3.1.2-4 Item 6a and Table 3.1.2-5, Item 16a, credit the Water Chemistry Control
 
Program, Inservice Inspection Program, and the Nickel Alloy Management Program for Non-RVCH Penetration Locations for managing cracking due to SCC for nickel alloy nozzle
 
dissimilar metal welds, and primary channel head drain connection tube and dissimilar
 
metal weld, respectively. During the audit and review, the staff reviewed the applicant's
 
license renewal Program basis document for reactor coolant pressure boundary systems and other supporting documents. The staff's evaluation of the applicant's Water Chemistry
 
Control Program is documented in SER Section 3.0.3.1.4, and the staff's evaluation of the
 
Inservice Inspection Program is documented in SER Section 3.0.3.3.4. 
 
The staff also confirmed that, consistent with the GALL Report, in Commitment No. 12 of to the applicant's letter dated August 11, 2008, the applicant committed to
 
implementing its Nickel Alloy Management Progr am for Non-Reactor Vessel Closure Head Penetration Locations as described in VEGP LRA Section B.3.14 and Section A.2.24 and 3-277 based on the following commitments: (1) SNC will continue to participate in industry initiatives directed at resolving PWSCC issues, such as owners group programs and the
 
Electric Power Research Institute Materials Reliability Program, (2) SNC will comply with
 
applicable NRC Orders, and (3) SNC will submit a program inspection plan for VEGP that
 
includes implementation of applicable Bulletins, Generic Letters, and staff accepted
 
industry guidance. The inspection plan will be submitted to the staff for review and approval
 
not less than 24 months prior to entering the period of extended operation for VEGP Units 1
 
and 2. This inspection plan will address the bases, inspection methods, and acceptance
 
criteria associated with aging management of the reactor vessel thermal sleeves and the
 
core support lugs (along with the associated support pads and attachment welds). The staff
 
finds this to be acceptable because it is in conformance with the recommendations in SRP-
 
LR Section 3.1.2.2.12 and to the AMR items for Nickel-alloy reactor pressure vessel (RPV)
 
and Class 1 piping components in GALL AMR Tables IV.A2 and IV.C2 that align to this
 
SRP-LR item.
 
LRA Table 3.3.2-27, Item 5k, credits the Water Chemistry Control Program and the One-
 
Time Inspection Program for managing cracking for nickel alloy piping component exposed
 
to borated water  with T > 140&#xba;F. LRA claims consistency with the GALL Report IV.C2-13, which rolls up to GALL Table 1, line-item 31. LRA uses a standard Note E, which means
 
Consistent with GALL Report for material, environment, and aging effect, but a different
 
aging management program is credited. However, GALL Report Item IV.C2-13 recommends using Chapter XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" for Class 1 components, and Chapter XI.M2, "Water Chemistry" for
 
PWR primary water and comply with applicable NRC Orders and provide a commitment in
 
the UFSAR supplement to implement applicable (1) Bulletins and Generic Letters and
 
(2) staff-accepted industry guidelines. During the audit and review, the staff asked the
 
applicant to provide technical justification for using Water Chemistry Control Program and
 
One-Time Inspection Program in lieu of the GALL Report recommended programs.
 
The applicant provided its response to the staff's inquiry in a letter dated February 8, 2008.
 
In this response, the applicant stated that the above nickel alloy piping components are part
 
of the sample coolers of the NSSS sampling system and have attached Alloy 600 tubes for
 
sampling connections. The coolers are in the non-nuclear safety portion of the system and
 
are not within the scope of the ISI program. Therefore, the applicant credited the
 
combination of its Water Chemistry Control and a One-Time Inspection to manage cracking
 
due to SCC in these nickel alloy components in lieu of the combination of the Inservice
 
Inspection Program and the Water Chemistry C ontrol Program. The staff's evaluation of the applicant's Water Chemistry Control Program is documented in SER Section 3.0.3.1.4, and
 
the staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. 
 
The staff verified that these Nickel-alloy sampling system components are not reactor
 
coolant pressure boundary (RCPB) components and therefore, that these components are
 
not within the scope of the commitment criteria that the staff recommends in Table IV.C2 of
 
the GALL Report, Volume 2 for management of cracking/PWSCC in Nickel-alloy piping
 
components and elements in the RCPB. Based on this review, the staff finds that it is
 
acceptable to credit the water Chemistry Control Program to mitigate cracking due to
 
PWSCC in these non-safety related nickel alloy sampling piping components and to credit
 
the applicant's One-Time Inspection Program to verify the effectiveness of the Water
 
Chemistry Control Program to manage cracki ng in these components during the period of 3-278 extended operation. On the basis of these reviews, the staff finds the applicant's response acceptable.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.1.2.2.13 criteria. For those line items that apply to LRA
 
Section 3.1.2.2.13, the staff concludes 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).
 
3.1.2.2.14  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.
 
LRA Section 3.1.2.2.14 addresses wall thinning described in Information Notice 91-19
 
issued to inform licensees of wall thinning due to flow-accelerated corrosion in Combustion
 
Engineering-designed SG feedwater inlet rings and supports. VEGP is a Westinghouse-
 
design plant with Model F SGs so IN 91-12 issues do not apply directly; however, the
 
Steam Generator Upper Internals Program will manage possible wall thinning of the SG feedwater distribution assembly and its supports.
 
SRP-LR Section 3.1.2.2.14 states that wall thinning due to flow-accelerated corrosion may
 
occur in steel feedwater 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.
 
LRA Table 3.1.2-5, items 7b, 11b, and 12b, credit Steam Generator Program for Upper
 
internals for managing loss of material due flow accelerated corrosion (FAC) for feedwater
 
distribution assembly piping, fittings, and supports, and steam generator primary and
 
secondary moisture separators fabricated of carbon steel and exposed to treated
 
water/steam. LRA claims consistency with the GALL Report Item IV.D1-26, which rolls up to
 
GALL Table 1 Item 3.1.1-32. GALL Report Item IV.D1-26 and Table 1 Item 3.1.1-32 identify
 
wall thinning due to FAC for this component, material and environment combination, and
 
recommends a plant specific program to be evaluated with reference to NRC IN 91-19, "Steam Generator Feedwater Distribution Piping Damage." During the audit and review, the
 
staff asked the applicant to explain how LRA aging effect is consistent with the GALL
 
Report for this component, material, and environment and discuss the basis for crediting
 
Steam Generator Program for Upper internals. 
 
The applicant provided its response to the staff's inquiry in a letter dated February 8, 2008.
 
In this response the applicant stated that the steam generators (SGs) at VEGP are
 
Westinghouse Model F SGs and that these SGs are of a different design than those
 
addressed in IN 91-19 and do not distribute both feedwater and auxiliary feedwater flow via
 
a common nozzle. Instead, the applicant stated that the Model F SGs includes separate
 
nozzles for normal feedwater and auxiliary feedwater distribution and that operating
 
experience to date has not shown that Model F feedwater distribution assemblies are
 
susceptible to the thermal loadings for the Combustion Engineering SG designs addressed
 
in IN 91-19. The applicant stated that SNC conservatively postulates FAC degradation 3-279 mechanism for the feedwater ring assembly and moisture separators and credited its Steam Generator Program for Upper Internals to manage loss of material due to FAC in
 
these components. 
 
The applicant also stated that it has performed an assessment based upon SG design, potential degradation mechanisms, and related VEGP and industry operating experience to
 
establish inspection requirements for secondary side internals components and determined
 
that these activities are adequate to detect FAC of carbon steel steam generator internals
 
components prior to a loss of intended function. The staff verified that the Steam Generator
 
Program for Upper Internals includes acceptable criteria to manage loss of materials
 
mechanisms in these components. The staff's evaluation of the applicant's Steam
 
Generator Program for Upper Internals is documented in SER Section 3.0.3.3.8. On the
 
basis of this review, the staff finds that the applicant's use of the Steam Generator Program
 
for Upper Internals is adequate to manage FAC for carbon steel secondary side
 
components of the VEGP steam generator in borated water environment.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.1.2.2.14 criteria. 
 
For those line items that apply to LRA Section 3.1.2.2.14, the staff concludes 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).
 
3.1.2.2.15  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.
 
LRA Section 3.1.2.2.15 addresses changes in dimension due to void swelling that may
 
occur in stainless steel and nickel alloy PWR reactor internal components exposed to
 
reactor coolant as an AERM that VEGP will manage, consistent with the SRP-LR, by (1)
 
participating in industry programs for investigating and managing aging effects on reactor
 
internals, (2) evaluating and implementing the results of the industry programs applicable to
 
the reactor internals, and (3) submitting an inspection plan for reactor internals to the NRC
 
for review and approval not less than 24 months before the period of extended operation.
 
This commitment is included in the description of the Reactor Vessel Internals Program and
 
in the UFSAR Supplement description of the program.
 
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
 
UFSAR 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.
 
LRA Table 3.1.2-2 credits the Reactor Vessel Internals Programs for managing change in 3-280 dimension aging effect for the rector vessel internal components that are fabricated from stainless steel and exposed to borated water. During the audit and review, the staff
 
confirmed that, in Commitment No. 20 of Enclosure 2 to the applicant's letter dated August
 
11, 2008, the applicant commits to implementing its Reactor Vessel Internals Program, as
 
described in LRA Section A.2.24 and Section B.3.24, based on the following commitments:
 
(1) SNC will participate in the industry program for investigating and managing of aging
 
effects on reactor internals. This is an ongoing commitment. (2) SNC will evaluate and
 
implement the results of the industry programs, such as the Electric Power Research
 
Institute Material Reliability Program, applicable to the VEGP reactor internals. This
 
commitment will be fully implemented prior to the period of extended operation. (3) SNC will submit an inspection plan for the VEGP reactor internals to the NRC for review and
 
approval not less than 24 months before entering the period of extended operation for
 
VEGP Units 1 and 2.The staff finds this to be acceptable because it is in conformance with
 
the recommendations in SRP-LR Section 3.1.2.2.15 and to the AMR items in GALL AMR
 
Table IV.B2 that align to this SRP-LR item.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.1.2.2.15 criteria. For those line items that apply to LRA
 
Section 3.1.2.2.15, the staff concludes 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).
 
3.1.2.2.16  Cracking Due to Stress Corrosion Cracking and Primary Water Stress Corrosion
 
Cracking 
 
The staff reviewed LRA Section 3.1.2.2.16 against the following criteria in SRP-LR
 
Section 3.1.2.2.16:
 
  (1) LRA Section 3.1.2.2.16 addresses cracking of the reactor pressure vessel control rod drive mechanism pressure housings due to SCC, stating that the VEGP control
 
rod drive mechanism pressure housings (control rod drive mechanism adapter, latch
 
housing, and rod travel housing) are stainless steel requiring no evaluation of
 
commitments to nickel alloy management. The Water Chemistry Control Program
 
and the Inservice Inspection Program manage SCC in the control rod drive
 
mechanism adapters, latch housings, and rod travel housings. The stainless steel
 
conoseal assembly housings and core exit thermocouple nozzle assemblies also
 
are aligned to this item. The Water Chemistry Control Program and the Inservice
 
Inspection Program also manage SCC in these pressure housings. Finally, the
 
reactor vessel thermal sleeves are aligned to this item as a substitute with SCC
 
managed in these sleeves by only the Wa ter Chemistry Control Program. The SRP-LR aligns once-though SG components (LRA Table 3.1.1 Item 34) to this summary
 
item. VEGP has Westinghouse Model F-design recirculating SGs; therefore, once-
 
through SG items are not applicable.
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 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 lower heads, tubesheets, and tube-to-tube sheet welds made or clad with nickel alloy. The GALL Report recommends ASME Code Section XI ISI and control of water chemistry to 3-281 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
 
UFSAR supplement to implement applicable (1) bulletins and generic letters, and
 
(2) staff-accepted industry guidelines.
 
In the discussion section of LRA Table 3.1.1, Item 35, the applicant stated that the VEGP
 
steam generators (SGs) are Westinghouse Model F recirculating SGs and not once-
 
through SGs. In addition, the staff verified that, consistent with the information in LRA Table
 
3.1.2-5, the VEGP SG lower heads, tubesheets, and tube-to tube-sheet welds are made of
 
alloy steel materials without the presence of internal stainless steel or Nickel-alloy cladding. 
 
Based on this review, the staff finds that the recommendations on cracking due PWSCC in
 
SRP-LR Section 3.1.2.2.16, Item (1) and in GALL AMR IV.D2-4 are not applicable to the
 
VEGP LRA because the VEGP SGs are of a recirculating SG design and because the
 
design of the alloy steel lower heads, tubesheets, and tube-to tube-sheet welds in the SGs
 
does not include internal stainless steel or Nickel-alloy cladding.
 
During the audit, the staff verified that LRA Table 3.1.2-1 does include applicable AMRs on
 
management of cracking due to PWSCC in the stainless steel CRDM, housing adapters, latch housings and travel housings, and in the stainless steel conoseal assemblies (VEGP
 
Unit 1) and core exit thermocouple assemblies (VEGP Unit 2), and that in these AMRs, the
 
applicant credits its Water Chemistry Control Program and the Inservice Inspection
 
Program to manage cracking due to PWSCC of the components. The staff finds this to be
 
acceptable because it is in conformance with the staff's recommendations in SRP-LR
 
Section 3.1.2.2.16, Item (1) and in GALL AMR IV.A2-11.
 
During the audit and review, the staff noted that the applicant does include an additional
 
AMR item on cracking due to SCC (LRA Table 3.1.2-1 AMR Item 26a) in the stainless steel
 
vessel head thermal sleeves under exposure to borated water that has been aligned to
 
GALL AMR IV.A2-11 and in this AMR the applicant credited the Water Chemistry Control
 
Program alone to manage cracking due to SCC. in the reactor vessel head thermal
 
sleeves. During the audit, the staff asked the applicant to justify why the Water Chemistry
 
Program alone is sufficient to manage cracking due to SCC in these thermal sleeves
 
without crediting the Inservice Inspection Program.
 
The applicant provided its response to the staff's inquiry in a letter dated February 8, 2008.
 
In its response, the applicant stated that the thermal sleeve assemblies are shop fabricated
 
and heat treated and that, as such, there are no full penetration field welds associated with
 
this assembly. The applicant also stated that the component materials were tested for
 
corrosion susceptibility at the fabrication shop and that the thermal sleeves are not subject
 
to high tensile stresses, since one end of the thermal sleeve hangs freely into the vessel
 
upper head area, with no restraint. The applicant further stated that, even if cracking is
 
initiated in a region of higher stress, the material is not loaded in such a way as to maintain
 
stress loads and any postulated cracks would be expected to arrest once entering an area
 
of lower stress. The applicant stated that the reducing nature of the primary water chemistry
 
environment has been shown to be generally effective in mitigating stress corrosion
 
cracking and VEGP has no history of stress corrosion cracking at this location. 
 
The staff noted that the thermal sleeves in question are not reactor coolant pressure
 
boundary components and are only required to maintain physical integrity to prevent a
 
detrimental impact on safety related components. Three factors need to be present to 3-282 initiate stress corrosion cracking: (1) high stress field, (2) susceptible material, and (3) corrosive environment. Two of these factors are present for the design of these thermals
 
sleeves: (1) susceptible material (i.e., stainless steel) and (2) corrosive environment (i.e.,
borated water). However, these thermal sleeves are not loaded to the extent that the CRDM
 
housing and conoseal assemblies are because the thermal sleeves are free hanging and thus are free from restraint on their lower ends, 
 
Based on this review, the staff finds the applicant's response acceptable and that it is valid to credit the Water Chemistry Program alone for these thermal sleeves because the CRDM
 
thermal sleeves are not RCPB components and because the applicant has provided an
 
acceptable basis to establish that the stress loads on these sleeves will not be high enough
 
to stress corrosion cracking of the components. 
 
  (2) LRA Section 3.1.2.2.16 addresses cracking due to SCC of the pressurizer spray heads as an aging effect not applicable because VEGP pressurizer spray heads are
 
not within the scope of license renewal. LRA Table 3.1.1, line-item 3.1.1-36 states
 
that "This item is not applicable to VEGP. The VEGP Pressurizer Spray Heads do
 
not perform any license renewal intended function. Also see Section 3.1.2.2.16(2)."  SRP-LR Section 3.1.2.2.16 states that cracking due to SCC may occur on stainless
 
steel pressurizer spray heads. Cracking due to PWSCC may occur on nickel-alloy
 
pressurizer spray heads. The existing program controls water chemistry to mitigate
 
this aging effect.
 
The staff verified that pressurizer spray heads are not within the scope of license renewal at
 
VEGP. Based on this review, the staff finds that the technical issue raised in SRP-LR
 
Section 3.1.2.2.16, Item (2) is not applicable to the scope of the VEGP LRA. 
 
Based on the programs identified above, the staff concludes that the recommended criteria
 
in SRP-LR Section 3.1.2.2.16, Item (2) are not applicable to the scope of the VEGP LRA.
 
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.
 
LRA Section 3.1.2.2.17 addresses cracking due to SCC, PWSCC, and IASCC that may
 
occur in stainless steel and nickel alloy PWR reactor internal components exposed to
 
reactor coolant as AERMs that VEGP will manage, consistent with the SRP-LR, with the
 
Water Chemistry Control Program and by (1) participating in industry programs for
 
investigating and managing aging effects on reactor internals, (2) evaluating and
 
implementing the results of the industry programs applicable to the reactor internals, and
 
(3) submitting an inspection plan for reactor internals to the NRC for review and approval
 
not less than 24 months before the period of extended operation. This commitment is
 
included in the description of the Reactor Vessel Internals Program and in the UFSAR
 
Supplement description of the program.
 
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 3-283 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 UFSAR 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.
 
LRA Table 3.1.2-2 credits the Water Chemistry Control and Reactor Vessel Internals
 
Programs for managing cracking due to SCC for the rector vessel internal components that
 
are fabricated from stainless steel or nickel alloy and exposed to borated water. During the
 
audit and review, the staff confirmed that, in Commitment No. 20 of Enclosure 2 to the
 
applicant's letter of August 11, 2008, the applicant stated that it will implement the Reactor
 
Vessel Internals Program to manage cracking due to PWSCC in the reactor vessel internal
 
components, as described in LRA Section A.2.24 and Section B.3.24, based on the
 
following commitments: (1) SNC will participate in the industry program for investigating and
 
managing of aging effects on reactor internals. This is an ongoing commitment. (2) SNC will
 
evaluate and implement the results of the industry programs, such as the Electric Power
 
Research Institute Material Reliability Program, applicable to the VEGP reactor internals.
 
This commitment will be fully implemented prio r to the period of extended operation. (3)
SNC will submit an inspection plan for the VEGP reactor internals to the NRC for review
 
and approval not less than 24 months before entering the period of extended operation for
 
VEGP Units 1 and 2. This inspection plan will address the bases, inspection methods, and
 
acceptance criteria associated with aging management of the reactor vessel thermal
 
sleeves and the core support lugs (along with the associated support pads and attachment
 
welds). The staff finds this to be acceptable because it is in conformance with the
 
recommendations in SRP-LR Section 3.1.2.2.17 and to the AMR items in GALL AMR Table
 
IV.B2 that align to this SRP-LR item.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.1.2.2.17 criteria. For those line items that apply to LRA
 
Section 3.1.2.2.17, the staff concludes 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).
 
3.1.2.2.18  Quality Assurance for Aging Management of Nonsafety-Related Components 
 
SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.
 
3.1.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report In LRA Tables 3.1.2-1 through 3.1.2-5, 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 3.1.2-5, 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 3-284 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.
 
For component type, material, and environment combinations not evaluated in the GALL
 
Report, the staff reviewed the applicant's 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 staff's evaluation is documented in the following sections.
 
3.1.2.3.1 Reactor Vessel - Summary of Aging Management Review - 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 reviewing LRA, Table 3.1.2-1, the staff noted that the applicant credits Water Chemistry
 
Control Program, Inservice Inspection Progr am, and Nickel Alloy Management Program for non-reactor vessel closure head (Non-RVCH) penetration locations for managing cracking due to SCC for interior of the nickel alloy leakage monitoring tube assembly (Item 15a) in
 
the wetted indoor air environment. The LRA uses a standard Note F, which means that the
 
material is not in the GALL Report for this component. During the audit and review, the staff
 
asked the applicant to provide technical justification for the adequacy of these programs.
 
The applicant provided its response to the staff's inquiry in a letter dated February 8, 2008.
 
In its response, the applicant stated that the nickel alloy leakage monitoring tube assembly
 
is connected to the reactor vessel flange and provides a path to route any reactor coolant
 
leakage from the vessel flange to the reactor coolant drain tank. The applicant stated that
 
the leakage monitoring piping is normally dry unless leakage from the vessel flange exists;
 
thus, its internal environment is air-indoor and wetted due to reactor coolant leakage. The
 
applicant further stated that, since this tubing material is nickel alloy that is exposed to
 
reactor coolant environment, SCC is considered an applicable aging effect for this
 
component.
 
The applicant added that the VEGP Water Chemistry Control Program is an existing
 
program that mitigates loss of material, cracking, and reduction in heat transfer in system
 
components and structures through the control of detrimental chemical species and the
 
addition of chemical agents. The VEGP Water Chem istry Control Program currently is in conformance with Revision 5 of the EPRI PWR Primary Water Chemistry Guidelines, which recommend that the concentration of chlorides, fluorides, sulfates, lithium, and dissolved
 
oxygen and hydrogen are monitored and kept below the recommended levels to mitigate
 
SCC of austenitic stainless steel, Alloy 600, and Alloy 690 components and include
 
appropriate corrective actions to be taken when primary water chemistry parameters
 
exceed EPRI Action Levels. The applicant stated that inspection of the leakage monitor
 
tube is included in the VEGP Inservice Inspection Program and a VT-2 inspection is performed at each refueling outage in accordance with the ASME Section XI Code as
 
implemented by the VEGP Inservice Inspec tion Program. Regarding the Nickel Alloy Management Program for Non-RVCH Penetration Locations, the applicant stated that this 3-285 is a plant-specific program that will manage cracking due to PWSCC for the reactor vessel flange leakage monitor tube. The overall goal of the Nickel Alloy Management Program for
 
Non-RVCH Penetration Locations is to maintain plant safety and minimize the impact of PWSCC on plant availability through assessment, inspection, mitigation, and repair or
 
replacement of susceptible components. Further, the applicant stated that the inspection
 
plan will be submitted to the staff for review and approval not less than 24 months prior to
 
entering the period of extended operation for VEGP Units 1 and 2.
 
The staff's evaluations of the applicant's Wa ter Chemistry Control Program, Inservice Inspection Program, and Nickel Alloy Management Program for Non-RVCH Penetration
 
Locations are documented in SER Section 3.0.3.1.4, 3.0.3.3.4, and 3.0.3.3.5, respectively.
 
The staff finds the applicant's response acceptable because the applicant conservatively
 
treats this leakage monitoring line as a Nickel-alloy reactor coolant pressure boundary
 
component and because the applicant conservatively credits its Water Chemistry Control
 
Program, Inservice Inspection Program, and Nickel Alloy Management Program for Non-RVCH Penetration Locations to manage cracking due to SCC in these Nickel-alloy non
 
pressure boundary leakage lines (tubes). Based on this review, the staff also finds that is
 
acceptable to credit these program for aging management of cracking due to SCC in the
 
Nickel-alloy leakage monitoring tubes because the AMR proposed by the applicant credits
 
more conservative AMPs recommended for management of cracking/SCC in GALL AMR
 
IV.A2-5 and are consistent with the AMPs and commitments credited for aging
 
management of cracking due to SCC in Class 1 Nickel-alloy CRDM pressure housings, as
 
described in GALL AMR IV.A2-11. 
 
The staff noted that LRA Table 3.1.2-1, Item 15b, credits Water Chemistry Control and
 
Inservice Inspection Programs for managing loss of material aging effect for interior of the
 
nickel alloy leakage monitoring tube assembly (Item 15a) in the wetted indoor air
 
environment. The LRA uses a standard Note G, wh ich means that the environment is not in the GALL Report for this component and material. During the audit and review, the staff
 
asked the applicant to provide technical justification for the adequacy of these programs to
 
manage this aging effect (i.e., loss of material due to pitting and crevice corrosion).
 
The applicant provided its response to the staff' inquiry in a letter dated February 8, 2008.
 
In its response, the applicant stated that these leakage monitoring tubes are normally dry
 
and exposure to coolant only occurs in the event of a leak from the vessel inner o-ring. The
 
Water Chemistry Control Program controls ensure that coolant contacting the leakage
 
monitoring tube assembly is low in detrimental ionic species (e.g. chlorides, sulfates) and
 
as such significant corrosion is not promoted. The applicant further stated that the Inservice
 
Inspection Program includes visual examination of the flange surfaces and leak-off region
 
for indications of corrosion and that any indications of leakage or corrosion would result in
 
initiation of a Condition Report and implementation of appropriate corrective actions. The
 
applicant also stated that to-date, there has been no VEGP or domestic PWR experience
 
associated with degradation of this assembly.
 
The staff finds the applicant's response acceptable because the applicant conservatively
 
credits its Water Chemistry Control Program and Inservice Inspection Program to manage loss of material due to pitting and crevice corrosion in the Nickel-alloy RPV flange leakage
 
tubes and because this is more conservative than the recommendation in GALL AMR
 
IV.A2-14 that the Water Chemistry Program alone is sufficient alone to manage loss of
 
material due to pitting and crevice corrosion in Class 1 Nickel-alloy RPV components. The
 
staff's evaluations of the applicant's Water Chemistry Control and Inservice Inspection 3-286 Programs are documented in SER Section 3.0.3.1.4 and 3.0.3.3.4, respectively.
 
In reviewing LRA Table 3.1.2-1, the staff noted that LRA identifies loss of material due to
 
wear as an aging effect for stainless steel vessel head thermal sleeves (Item 26c) exposed
 
to borated water. LRA credits Reactor Vessel Internals Program, which is based on a set of
 
implementation commitments, for managing this aging effect. The LRA uses a standard
 
Note H, which means that the aging effect is not in GALL Report for this component, material, and environment combination. However, the GALL Report items IV.B2-26 and
 
IV.B2-34 recommend using ISI program for managing loss of material due to wear for Class
 
1 components fabricated from stainless steel and exposed to reactor coolant. During the
 
audit and review, the staff asked the applicant to explain how LRA Item 26c differs from the
 
GALL Report items IV.B2-26 and IV.B2-34, and why the ISI program is not used for
 
managing loss of material due to wear as an aging effect for stainless steel vessel head
 
thermal sleeves exposed to borated water.
 
The applicant responded to the staff's inquiry in a letter dated February 8, 2008. In its
 
response, the applicant stated that SNC does not believe that alignment to GALL Report
 
items IV.B2-26 or IV.B2-34 are appropriate because the loss of material due to wear is not
 
specifically identified as an applicable aging effect requiring management (AERM) In table
 
IV.A2 of the GALL Report, Volume 2, and because there is not any significant operating
 
experience to date that identifies loss of material due to wear as an aging issue for reactor
 
vessel head thermal. The applicant further stated that the nature of any postulated wear for
 
the components in the GALL Report is a slow developing condition and is not associated
 
with a high-cycle flow-induced mechanism and that the applicant's implementation of its
 
Inservice Inspection Program did not identify any indication of wear in these thermal
 
sleeves. The applicant stated that based on these determinations, SNC considers this issue
 
to be an emerging current term issue and that the applicant's implementation of its Reactor
 
Vessel Internals Program will be sufficient to address any wear-induced loss of material
 
issues in the vessel head thermal sleeves during the period of extended operation. The
 
staff finds this to be an acceptable aging management approach for postulated wear in the
 
thermal sleeves because the applicant has included these components in its Reactor
 
Vessel Internal Program and because the program includes Commitment No. 20 on the
 
LRA, which was provided in the applicant's letter of August 11, 2008. This commitment
 
includes the following commitment provisions:
 
(1) SNC will participate in the industry program for investigating and managing of aging effects on reactor internals. This is an ongoing commitment. 
 
(2) SNC will evaluate and implement the results of the industry programs, such as the Electric Power Research Institute Material Reliability Program, applicable to the
 
VEGP reactor internals. This commitment w ill be fully implemented prior to the period of extended operation. 
 
(3) SNC will submit an inspection plan for the VEGP reactor internals to the NRC for review and approval not less than 24 months before entering the period of extended
 
operation for VEGP Units 1 and 2. This inspection plan will address the bases, inspection methods, and acceptance criteria associated with aging management of
 
the reactor vessel thermal sleeves and the core support lugs (along with the
 
associated support pads and attachment welds).
 
3-287 Based on the applicant's response, the staff concludes that loss of material due to wear for the reactor vessel head thermal sleeve will be adequately managed by the Reactor Vessel
 
Internals Program. The staff's evaluation of the applicant's Reactor Vessel Internals
 
Programs is documented in SER Section 3.0.3.3.7.
 
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 Review -
 
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.
 
During the audit and review, the staff noted that LRA Table 3.1.2-2, Item 9d, addresses
 
stainless steel flux thimble tubes in "Air - Indoor (Interior)" environment. LRA uses a standard Note G, which means the environment is not in GALL Report for this component
 
and material. The LRA does not identify an aging effect for this component, material and
 
environment. Therefore, per the applicant, no aging management program is required.
During the audit, the staff asked the applicant to explain why this environment is not
 
considered as a "wetted" environment and to provide technical bases for identifying no
 
aging effect for the associated line-item
 
The applicant provided its response to the staff's inquiry in a letter dated February 8, 2008.
 
In this response, the applicant stated that the flux thimble tubes are movable tubes that are
 
inserted into the fixed flux thimble guide tubes from the seal table, through the flux thimble guide tubes, and into the instrumentation tubes of the fuel assemblies at the applicable core
 
locations. The applicant stated that the external surfaces of the flux thimble tubes are
 
exposed to borated water and the internal surfaces of the flux thimble tubes are dry, and
 
that as such, this environment is not considered to be "wetted" because there is no source
 
of water that could accumulate in the flux thimble tubes. The applicant added that the fact
 
that the flux thimble tubes have an internal indoor environment instead of the external indoor air environment has no affect on the conclusion regarding aging effects for this
 
material and environment combination. In addition, the applicant stated that two decades of
 
operating experience at PWRs throughout the industry confirm that the only significant
 
aging effect for flux thimble tubes is wear of the external surfaces, which is addressed in
 
LRA Table 3.1.2-2, Item 9c. During the audit, the staff found that the applicant's
 
determination that there are not any aging effects for the stainless steel flux thimble tube
 
surfaces that are exposed internally to an indoor air environment is acceptable because the
 
determination is based on extensive operating experience and because this determination
 
is consistent with GALL AMR IV.E-2.
 
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).
 
3-288 3.1.2.3.3  Reactor Coolant System and C onnected Lines - Summary of Aging Management Review - LRA Table 3.1.2-3 
 
The staff reviewed LRA Table 3.1.2-3, which summarizes the results of AMR evaluations
 
for the RCS and connected lines component groups.
 
In reviewing LRA Table 3.1.2-3, the staff noted that the applicant identified no aging effects
 
for the stainless steel capillary tubing for reactor vessel level indicator switch (RVLIS)
 
transmitters that are exposed to a silicone fluid environment. A standard Note G is used for
 
this AMR line, which indicates that the environment is not in the GALL Report for this
 
component and material. The staff concludes that silicone fluid is nearly chemically inert
 
and has no adverse effects on stainless steel materials in contact with it. On this basis, the
 
staff finds that stainless steel in a silicone fluid environment exhibits no aging effect, and
 
the component or structure will remain capable of performing intended functions consistent
 
with the CLB for the period of extended operation.
 
The staff noted that LRA Table 3.1.2-3, Item 5a, identifies cracking due to SCC as an aging
 
effect for the carbon steel reactor coolant pump (RCP) motor oil cooler channel heads
 
exposed to close-cycle cooling water and credi ts the Auxiliary Component Cooling Water (ACCW) System Carbon Steel Components Program, which is a new plant specific program, for managing this aging effect. The staff also noted that the applicant added this
 
combination of component, material, environment, and aging effect to the scope of this program, since this combination is not included in the GALL Report. 
 
During the audit and review, the staff asked the applicant to provide technical justification
 
for the adequacy of the ACCW System Carbon Steel Components Program. 
 
The applicant responded to the staff's inquiry in a letter dated February 8, 2008. In its
 
response, the applicant stated that the RCP lower lube oil coolers are exposed to auxiliary
 
closed cooling water on their tube sides and lube oil on their shell sides. The applicant also
 
stated that the VEGP-specific operating experience indicates that nitrite-induced SCC has
 
been an issue of concern only for the RCP motor oil cooler channel heads at VEGP Unit 2.
 
However, the applicant qualified this by clarifying that, as a conservative measure, nitrite-
 
induced SCC is identified as an applicable aging effect requiring management (AERM) for
 
the RCP motor oil cooler channel heads at both VEGP Unit 1 and VEGP Unit 2.The
 
applicant stated that the ACCW System Carbon Steel Components Program is credited to
 
manage SCC in these components and that the AMP is a new plant-specific program that
 
specifically manages cracking of carbon st eel components exposed to auxiliary component cooling water and that the AMP accomplishes this through a combination of leakage
 
detection monitoring, routine walkdown, and periodic visual examination techniques.
The staff verified that the applicant's ACCW System Carbon Steel Components Program is
 
developed and implemented to detect cracking that may occur in carbon steel auxiliary
 
component cooling water system components t hat are exposed to closed cycle cooling water. The staff's evaluation of the applicant's ACCW System Carbon Steel Components
 
Program is documented in SER Section 3.0.3.3.1. On the basis of this review, the staff
 
finds that the applicant's crediting of the ACCW System Carbon Steel Components
 
Program will provide assurance that cracki ng of ACCW System carbon steel components due to nitrite induced SCC will be adequately managed such that the components included
 
within the scope of this program will continue to perform their intended function during the
 
period of extended operation and that the applicant's response to the staff's inquiry is 3-289 acceptable because the program has been developed specifically to detect cracking that may occur in the ACCW system, including cracking due to nitrite-induced SCC, and the
 
applicant will continue to implement this AMP during the period of extended operation.
 
On the basis of its review, the staff finds that the applicant has appropriately evaluated the
 
AMR results of material, environment, AERM, and AMP combinations not 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).
 
3.1.2.3.4  Pressurizer - Summary of Aging Management Review - LRA Table 3.1.2-4 
 
The staff reviewed LRA Table 3.1.2-4, which summarizes the results of AMR evaluations
 
for the pressurizer component groups.
 
During the audit and review, the staff noted that LRA Table 3.1.2-4, Item 14a, identifies
 
cracking due to SCC as an aging effect for stainless steel for pressurizer surge nozzle and
 
spray nozzle thermal sleeves that are exposed to borated water and that the applicant
 
credits its Water Chemistry Control Program to manage this aging effect. The LRA uses a
 
standard Note J, which means neither the component nor the material and environment
 
combination is evaluated in GALL Report. However, GALL AMR IV.C2-19 recommends that
 
the Water Chemistry and ISI Programs be credited to manage cracking due to SCC in
 
stainless steel pressurizer components that are exposed to reactor coolant. During the
 
audit and review, the staff asked the applicant to explain why LRA Item 14a is not aligned
 
with the GALL Report Item IV.C2-19, and to explain how the effectiveness of Water
 
Chemistry Control Program is verified to ensure that cracking due to SCC is prevented or
 
mitigated in the pressurizer surge nozzle and spray nozzle thermal sleeves. The staff also
 
asked the applicant to provide justification for not crediting the Inservice Inspection
 
Program to manage cracking due to SCC in these thermal sleeves.
 
The applicant responded to the staff's inquiry in a letter dated February 8, 2008. In its
 
response, the applicant stated that the pressurizer stainless steel thermal sleeve
 
components do not serve a pressure retaining function, but rather function as a thermal
 
barrier to protect the structural alloy steel nozzle components from thermal cycling and
 
associated fatigue damage. The applicant explained that these thermal sleeves were rolled
 
into place and then welded to the surge and spray nozzle safe ends using an Alloy 82
 
dissimilar metal weld. The applicant stated that the other ends of the thermal sleeves are
 
not fixed and are free to expand or contract. The applicant stated that the Water Chemistry
 
Control Program minimizes oxygen and halide concentrations in the reactor coolant system
 
and hydrogen overpressure ensures the presence of low electrochemical corrosion
 
potentials and that under these conditions, SCC has not been a concern for the VEGP
 
stainless steel components. 
 
The applicant also stated that cracking in the weld or roll area is not likely to result in
 
movement of the thermal sleeves since they are tightly fit into the nozzle bore and the
 
rolling process results in improved resistanc e to IGSCC by placing the sleeve in a compressed state. 
 
The staff has verified that the dissimilar metal welds associated with these thermal sleeves
 
are addressed in AMR Item 6 of LRA Table 3.1.2-4 and are not aligned with the AMRs for
 
the thermal sleeves in LRA Table 3.1.2-4. The staff has evaluated the AMRs that are 3-290 credited to manage cracking due to SCC in the thermal sleeve dissimilar metal welds in SER Section 3.1.2.2.13. 
 
Based on this review, the staff finds the applicant's response to be acceptable because: (1)
 
the rolling process creates a compressive stress field for the regions of the thermal sleeves
 
that are rolled into position such that any growth of a postulated flaw would be mitigated, and (2) the applicant has addressed cracking due to SCC of the thermal sleeve dissimilar
 
metal welds in AMR Item 6 of LRA Table 3.1.2-4. 
 
The staff's evaluation of the applicant's Water Chemistry Control Program is documented in SER Section 3.0.3.1.4. On the basis of this review, the staff finds that the Water Chemistry
 
Control Program and continued monitoring of industry operating experience will be
 
adequate to manage cracking due to SCC for free standing regions of the pressurizer surge
 
nozzle and spray nozzle thermal sleeves during the period of extended operation. The staff
 
evaluated aging management programs credited to manage cracking due to SCC in the pressure spray nozzle and surge nozzle thermal sleeve dissimilar metal welds in SER
 
Section 3.1.2.2.13.
 
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).
 
3.1.2.3.5  Steam Generators - Summary of Aging Management Review -           
 
LRA Table 3.1.2-5
 
The staff reviewed LRA Table 3.1.2-5, which summarizes the results of AMR evaluations
 
for the steam generators component groups.
 
During the audit and review, the staff noted that LRA Table 3.1.2-3, items 2c, 8d, 20b, 24b, 25b, 31b, and 32b, address external surfaces of alloy steel steam generator components in
 
external indoor air environments with temperat ures in excess of 212 &#xba;F (T> 212 &#xba;F). LRA uses a standard Note G and a plant special Note 106. LRA Note G means that environment
 
for these AMRs is not addressed in the GALL Report for this component and material. LRA
 
Note 106 states that "Revision 1 of NUREG-1801[GALL Report] Vol. 2 does not include an
 
external surfaces environment with operati ng temperatures exceeding 212 &deg;F. External surfaces operating at temperatures above this threshold drive off moisture and preclude
 
corrosion of the component external surfaces. Additionally, borated water leakage is not a
 
concern for this location." 
 
During the audit and review, the staff asked the applicant to explain how external surfaces
 
of these components remain above 212&deg;F at all times (during reactor operation and
 
shutdown) and to provide technical bases for identifying no aging effect for the associated
 
line-items.
 
The applicant responded to the staff's question in a letter dated February 8, 2008. In this
 
response, the applicant stated that VEGP normally operates at full power with the external
 
steam generators surface temperature in excess of 212 &#xba;F (i.e.,
3-291 T > 212 &#xba;F) during the 18 month operating cycle. The applicant stated that during the three to four weeks that take place during scheduled refueling outages, the external surfaces of
 
the steam generators are at ambient temperatures. 
 
The applicant concluded that since the external surfaces of the steam generators are
 
exposed to ambient temperatures for relatively short periods of time, corrosion due to
 
atmospheric moisture is not expected to be significant.
 
Table IV.IX.D provides the following statement on air environments that can lead to
 
condensation or moisture on component surfaces:
 
The environment to which the internal or external surface of the component or
 
structure is exposed. Condensation on the su rfaces of systems with temperatures below the dew point is considered raw water, due to potential for surface
 
contamination. For the purposes of GALL'05, under certain circumstances, the
 
GALL'01 terms "moist air" or "warm moist air" are enveloped by condensation to
 
describe an environment where there is enough moisture for corrosion to occur.
 
The GALL environment discussed above indicates that the presence of both moisture and
 
cool or warm environmental conditions are necessary for condensation or moisture to occur
 
on component surfaces. A surface environment above 212 &#xba;F is hot enough to preclude
 
condensation that might induce corrosive type aging effects (loss of material due to
 
general, pitting or crevice corrosion or stress corrosion induced cracking). Based on this
 
review, the staff finds the applicant's response to be acceptable because the external alloy
 
steel SG component surfaces are not exposed to uncontrolled ambient air conditions for
 
any prolonged period of time and because, during power operations, the high temperature
 
air environment (i.e., T > 212 &#xba;F) for the alloy steel components will preclude condensation
 
or moisture from occurring on the component surfaces. Based on this review, the staff
 
concludes that the applicant has described an acceptable basis for concluding that there
 
are not any aging effects for the alloy steel SG components that are exposed to an external indoor air environment with temperatures above 212 &#xba;F.
 
The applicant also stated that loss of materials due to borated water leakage is the other
 
loss of material aging effect that could potentially require aging management for the
 
external surfaces of steel steam generator (SG) components. The staff verified that LRA
 
Table 3.1.2-5 does include AMR items to manage loss of material due to boric acid
 
corrosion in steel (i.e., carbon steel or alloy steel) SG components that have the potential to
 
be exposed to boric acid leakage of the primary coolant or other borated water sources and
 
that these AMRs have been aligned to and are consistent with the staff's recommendations
 
in AMR Item 58 in Table 1 of the GALL Report, Volume 1, and in GALL AMR IV.D1-3.
 
Based on this review, the staff has verified that the applicant has provided an acceptable
 
basis to manage loss of material in steel SG components that have the potential to be
 
exposed to leakage from borated water sources. The staff has evaluated these AMRs in
 
SER Section 3.1.2.1. 
 
The staff noted that LRA Table 3.1.2-5 credits the Fatigue Monitoring Program and
 
Inservice Inspection Program for managing cracking due to cyclic loading as an aging effect
 
for alloy steel auxiliary feedwater nozzle and feedwater inlet nozzle exposed to treated
 
water/ steam. LRA uses a standard Note H, which means that the aging effect is not in the
 
GALL Report for this component, material, and environment combination. During the audit
 
and review, the staff asked the applicant to clarify whether the aging effect "cracking due to 3-292 cyclic loading" already postulates the initiation of a fatigue-induced crack in these piping components and to justify how the Fatigue Monitoring Program manages cracking due to
 
cyclic loading in these components, when the program does not inspect for existing or
 
postulated fatigue-initiated cracks, but rather relies on cycle monitoring to assure that the
 
TLAAs on thermal fatigue will remain valid for the period of extended operation. The staff
 
also asked the applicant to discuss the inspection methods or techniques and frequency of
 
these inspections that are being used to detect, monitor/trend cracking due cyclic loading.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that SNC will amend LRA Table 3.1.2-5, to align
 
AMR items 2a and 8a to AMR Item 10 in Table 1 of the GALL Report, Volume 1 and to
 
GALL AMR IV.D1-8. The applicant also confirmed that SNC does not postulate the pre-
 
existence of a fatigue-induced crack and VEGP has no components with an aging effect
 
requiring management of "Cracking - cyclic loading. The applicant stated that the SNC
 
interpretation of "cracking due to cyclic loading" was different than the staff's and it now
 
understands the staff's intended use of the term "cracking due to cyclic loading" in GALL.
 
As a result, the applicant stated that SNC will amend the aging effect in those AMRs in the
 
LRA that refer to the term "Cracking - cyclic loading" to the aging effect term "Cracking -
 
Thermal Fatigue," the AMP credited in these AMRs to only the Fatigue Monitoring Program.
 
The applicant stated that the program monitors the CUF of those components that require
 
aging management to prevent cracking due to cumulative fatigue damage, component
 
inspections are not performed by the Fatigue Monitoring Program. 
 
The staff issued its question to ensure that the AMRs in the LRA corresponding to the
 
GALL AMRs on cumulative fatigue damage were differentiated from those AMRs in the
 
LRA that pertain to components with already known or postulated thermal fatigue-induced
 
cracks. The staff verified that the applicant made the applicable amendment of the LRA in a
 
letter dated March 20, 2008. The staff also verified that the applicant's Fatigue Monitoring
 
Program is the applicable program that is credited to manage "cracking due to thermal
 
fatigue" in these SG components. Based on this review, the staff concludes that the
 
applicant has provided an acceptable AMR basis for managing cracking due to thermal
 
fatigue in the SG components. The staff's evaluation of the applicant's Fatigue Monitoring
 
Program is documented in SER Section 3.0.3.2.19. On the basis of this review, the staff
 
finds the applicant's response to the staff's question on these AMRs on thermal fatigue to
 
be acceptable.
 
The staff noted that LRA Table 3.1.2-5, items 3b and 27d, credit Water Chemistry Control
 
Program for managing loss of material as an aging effect for nickel alloy auxiliary feedwater
 
nozzle thermal sleeve and SG tube plugs exposed to treated water or steam. During the
 
audit and review, the staff asked the applicant to provide technical justification for the
 
adequacy of this program for managing loss of material as an aging effect for these
 
components and to explain how effectiveness of the Water Chemistry Control Program for managing loss of material of auxiliary feedwater nozzle thermal sleeve and tube plugs is
 
verified.
 
The applicant provided it response to the staff's inquiry in a letter dated February 8, 2008.
 
In its response, the applicant stated that the VEGP Water Chemistry Control Program has
 
been shown to be adequate to prevent significant localized corrosion for the auxiliary
 
feedwater thermal sleeve and tube plugs, which are fabricated from thermally treated Alloy
 
600. The applicant stated that the VEGP Water Chemistry Control Program is implemented consistent with the EPRI water chemistry guidelines for PWR primary and secondary water 3-293 chemistry and that the program is consistent with the staff's guidelines in GALL AMP XI.M2.
The applicant stated that, at VEGP, the Wate r Chemistry Control Program implements action levels to limit chemistry excursions and t hat significant chemistry excursions result in the initiation of a condition report to document the off-normal chemistry conditions, evaluate
 
the consequences, and implement appropriate corrective actions. The applicant further
 
explained that consistent with the VEGP position, an extensive degradation study
 
sponsored by the NRC in NUREG/CR-6923 determined that loss of material due to
 
corrosion is not a significant concern for nickel alloy materials exposed to primary or
 
secondary water environments. 
 
During the audit and review, the staff reviewed the applicant's license renewal Program
 
basis document for the steam generators component groups and other supporting
 
documents. Also, the staff's evaluation of t he applicant's Water Chemistry Control Program is documented in SER Section 3.0.3.1.4. The staff concludes that the applicant adequately
 
demonstrated that, consistent with the industry guideline, loss of material due to localized
 
corrosion for the nickel alloy auxiliary feedwater thermal sleeve and tube plugs is
 
insignificant. Also, any excursion in the water chemistry that may initiate degradation will be
 
identified via implementation of the Water C hemistry Control Program corrective actions.
On the basis of these reviews, the staff finds the applicant response acceptable.
 
During the audit and review, the staff noted that LRA Table 3.1.2-5 credits Water Chemistry
 
Control Program and Steam Generator Tubing Integrity Program for managing loss of material aging effect for nickel alloy steam generator anti-vibration bars (1b) and stainless
 
steel tube support plates and flow distribution baffles (28b) exposed to treated water/steam.
 
Similarly, LRA Table 3.1.2-5 credits Water Chemistry Control Program and Steam
 
Generator Program for Upper Internals for managing loss of material aging effect for the
 
nickel alloy feedwater inlet nozzle thermal sleeve (9b) and J-tubes (10b) exposed to treated
 
water/ steam. During the audit and review, the staff asked the applicant to provide bases for
 
identifying this aging effect and using Water Chemistry Control Program and Steam
 
Generator Tubing Integrity Program or Steam Generator Program for Upper Internals for the associated AMR line-items.
 
The applicant provided its response to the staff's inquiry in a letter dated February 8, 2008.
 
In its response, the applicant stated that loss of material due to general corrosion is
 
typically only associated with carbon steels which do not develop tightly adherent oxidation layers in the SG coolant or borated water leakage environments. The applicant stated
 
however, that stainless steels and nickel base alloys are protected by passive oxidation
 
layers and that SNC has conservatively included loss of material as an aging effect for
 
nickel alloy and stainless internal components exposed to treated water/steam.
 
In regard to the AMPs that the applicant has credited to manage corrosion-based loss of
 
material effects in the nickel alloy steam generator anti-vibration bars (1b) and stainless
 
steel tube support plates and flow distribution baffles, the applicant stated that the VEGP
 
Water Chemistry Control Program is an existing program that prevents or mitigates loss of material, cracking, and reduction in heat transfer in system components and structures
 
through the control of detrimental chemical such as chlorides, fluorides, dissolved oxygen, and sulfate concentrations and the addition of chemical agents. The applicant stated that
 
the EPRI Primary Water Chemistry Guidelines and Secondary Water Chemistry Guidelines form the basis for the program. 
 
3-294 In the applicant's response letter of February 8, 2008, the applicant also stated that the VEGP Steam Generator Tubing Integrity Program is credited to provide reasonable
 
assurance that the steam generator tubes will perform their intended safety function(s)
 
during the period of extended operation. The applicant stated that monitoring of secondary
 
side components, such as the tube supports, is conducted as part of the Steam Generator
 
Secondary-Side Integrity Plan and that prior to each steam generator tubing inspection, a
 
degradation assessment (DA) is performed to determine and document inspection plans for
 
degradation mechanisms that could potentially occur. The applicant stated that the
 
degradation assessment establishes the inspection scope and NDE techniques for the
 
inspections to be performed and the tube structural limits and flaw growth rates for any flaw evaluations that need to be performed for flaw indications that are detected during the
 
inspection process.
 
During the audit and review, the applicant presented to the staff recent performance results
 
from the VEGP steam generator programs that show the programs have been effective in finding and correcting degradation attributable to aging effects requiring management. As a
 
result, the staff verified that the applicant's implementation of the Water Chemistry Control
 
Program, the Steam Generator Tubing Integrity Program, and the Steam Generator
 
Program for Upper Internals programs has been effective in managing loss of material in the Nickel-alloy steam generator anti-vibration bars, and the stainless steel tube support
 
plates and flow distribution baffles that are exposed to treated water or steam. Based on
 
this review, the staff finds that the applicant has provided an acceptable basis for crediting
 
the Water Chemistry Control Program and either the Steam Generator Tubing Integrity
 
Program or Steam Generator Program for U pper Internals for the associated AMR line-items that are provided in the LRA to manage loss of material in these steam generator
 
components and therefore, finds the applicant's response to be acceptable. The staff's
 
evaluations of the applicant's Water Chemis try Control Program, Steam Generator Tubing Integrity Program, and Steam Generator Progr am for Upper Internals are documented in SER Sections 3.0.3.1.4, 3.0.3.2.16, and 3.0.3.3.8, 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).
 
3.1.3  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 RCS
 
components within the scope of license renewal and subject to an AMR will be adequately
 
managed so that the intended function(s) will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.2  Aging Management of Engineered Safety Features System This section of the SER documents the staff's review of the applicant's AMR results for the
 
engineered safety features (ESF) syst em components and component groups of:
containment spray system  emergency core cooling system
 
3-295  3.2.1  Summary of Technical Information in the Application LRA Section 3.2 provides AMR results for the ESF system components and component groups. LRA Table 3.2.1, "Summary of Aging Management Evaluations for Engineered
 
Safety Features in Chapter V of NUREG-1801," is a summary comparison of the applicant's
 
AMRs with those evaluated in the GALL Report for the ESF system components and
 
component groups.
 
The applicant's AMRs evaluated and incorporated applicable plant-specific and industry
 
operating experience in the determination of AERMs. The plant-specific evaluation included
 
condition reports and discussions with appropriate site personnel to identify AERMs. The
 
applicant's review of industry operating experience included a review of the GALL Report
 
and operating experience issues identified since the issuance of the GALL Report.
 
3.2.2  Staff Evaluation The staff reviewed LRA Section 3.2 to determine whether the applicant provided sufficient
 
information to demonstrate that the effects of aging for the ESF 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 audit of AMRs to ensure the applicant's claim that certain AMRs
 
were consistent with the GALL Report. The staff did not repeat its review of the matters
 
described in the GALL Report; however, the staff did verify that the material presented in
 
the LRA was applicable and that the applicant identified the appropriate GALL Report
 
AMRs. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details
 
of the staff's audit evaluation are documented in SER Section 3.2.2.1.
 
During the audit, the staff also selected AMRs consistent with the GALL Report and for
 
which further evaluation is recommended. The staff confirmed that the applicant's further
 
evaluations were consistent with the SRP-LR Section 3.2.2.2 acceptance criteria. The
 
staff's audit evaluations are documented in SER Section 3.2.2.2.
 
The staff also conducted a technical review of the remaining AMRs not consistent with or
 
not addressed in the GALL Report. The technical review evaluated whether all plausible
 
aging effects have been identified and whether the aging effects listed were appropriate for
 
the material-environment combinations specified. The staff's 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 plant's operating experience to
 
verify the applicant's claims.
 
Table 3.2-1 summarizes the staff's evaluation of components, aging effects or mechanisms, and AMPs listed in LRA Section 3.2 and addressed in the GALL Report.
 
3-296 Table 3.2-1  Staff Evaluation for Engineered Safety Features System Components in the GALL Report Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendment s Staff Evaluation Steel and stainless steel piping, piping
 
components, and
 
piping elements in emergency core cooling system
 
(3.2.1-1)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes TLAA Consistent with the GALL Report, which recommends
 
further evaluation (See SER Section
 
3.2.2.2.1) Steel with stainless
 
steel cladding pump
 
casing exposed to treated borated water
 
(3.2.1-2)
Loss of material due to cladding
 
breach A plant-specific aging management
 
program is to be
 
evaluated.
 
Reference NRC
 
Information
 
Notice 94-63, "Boric Acid Corrosion
 
of Charging Pump Casings Caused by
 
Cladding Cracks" Yes Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.2.2)
Stainless steel
 
containment isolation
 
piping and
 
components internal
 
surfaces exposed to treated water
 
(3.2.1-3)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.2.3)
Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to soil
 
(3.2.1-4)
Loss of material due to pitting
 
and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated.
Yes Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.2.3)
Stainless steel and
 
aluminum piping, piping components, and piping elements
 
exposed to treated water (3.2.1-5)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (See SER
 
Section 3.2.2.2.3)
Stainless steel and copper alloy piping, piping components, and piping elements
 
exposed to
 
lubricating oil
 
(3.2.1-6)
Loss of material due to pitting
 
and crevice
 
corrosion Lubricating Oil Analysis and One-Time InspectionYes Oil Analysis Program (B.3.16) One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report, which recommends
 
further evaluation (See SER Section
 
3.2.2.2.3) 3-297 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendment s Staff Evaluation Partially encased stainless steel tanks with breached
 
moisture barrier exposed to raw water
 
(3.2.1-7)
Loss of material due to pitting
 
and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated for pitting
 
and crevice corrosion
 
of tank bottoms
 
because moisture and water can egress
 
under the tank due to
 
cracking of the
 
perimeter seal from weathering.
Yes Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.2.3)
Stainless steel
 
piping, piping
 
components, piping
 
elements, and tank
 
internal surfaces
 
exposed to
 
condensation (internal)
 
(3.2.1-8)
Loss of material due to pitting
 
and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated.
Yes Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.2.3)
Steel, stainless steel, and copper alloy heat
 
exchanger tubes
 
exposed to
 
lubricating oil
 
(3.2.1-9)
Reduction of heat transfer
 
due to fouling Lubricating Oil Analysis and One-Time InspectionYes Oil Analysis Program (B.3.16) One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report, which recommends
 
further evaluation (See SER Section
 
3.2.2.2.4)
Stainless steel heat
 
exchanger tubes
 
exposed to treated water (3.2.1-10)
Reduction of heat transfer
 
due to fouling Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.2.4)
Elastomer seals and
 
components in standby gas treatment system
 
exposed to air -
 
indoor uncontrolled
 
(3.2.1-11)
Hardening and loss of strength
 
due to elastomer
 
degradation A plant-specific aging management
 
program is to be
 
evaluated.
Yes Not applicable Not applicable to PWRs (See SER
 
Section 3.2.2.2.5)
Stainless steel high-pressure safety
 
injection (charging) pump miniflow orifice
 
exposed to treated borated water
 
(3.2.1-12)
Loss of material due to erosion A plant-specific aging management
 
program is to be
 
evaluated for erosion
 
of the orifice due to
 
extended use of the
 
centrifugal HPSI
 
pump for normal
 
charging.
Yes Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.2.6) 3-298 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendment s Staff Evaluation Steel drywell and suppression chamber spray system nozzle and flow orifice internal
 
surfaces exposed to
 
air - indoor
 
uncontrolled (internal)
 
(3.2.1-13)
Loss of material due to general
 
corrosion and
 
fouling A plant-specific aging management
 
program is to be
 
evaluated.
Yes Not applicable Not applicable to PWRs (See SER
 
Section 3.2.2.2.7)
Steel piping, piping
 
components, and
 
piping elements
 
exposed to treated water (3.2.1-14)
Loss of material due to general, pitting, and
 
crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (See SER
 
Section 3.2.2.2.8)
Steel containment
 
isolation piping, piping components, and piping elements
 
internal surfaces
 
exposed to treated water (3.2.1-15)
Loss of material due to general, pitting, and
 
crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.2.8)
Steel piping, piping
 
components, and
 
piping elements
 
exposed to
 
lubricating oil
 
(3.2.1-16)
Loss of material due to general, pitting, and
 
crevice corrosion Lubricating Oil Analysis and One-Time InspectionYes Oil Analysis Program (B.3.16) One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report, which recommends
 
further evaluation (See SER Section
 
3.2.2.2.8) Steel (with or without coating or wrapping)
 
piping, piping
 
components, and
 
piping elements
 
buried in soil
 
(3.2.1-17)
Loss of material due to general, pitting, crevice, and microbiologically
-influenced
 
corrosion Buried Piping and Tanks Surveillance
 
or
 
Buried Piping and Tanks Inspection Yes Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.2.9)
Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to treated water > 60&deg;C
(> 140&deg;F)
 
(3.2.1-18)
Cracking due to stress corrosion
 
cracking and
 
intergranular
 
stress corrosion
 
cracking BWR Stress Corrosion Cracking and Water ChemistryNo Not applicable Not applicable to PWRs 3-299 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendment s Staff Evaluation Steel piping, piping components, and
 
piping elements
 
exposed to steam or treated water
 
(3.2.1-19) Wall thinning due to flow-
 
accelerated
 
corrosion Flow-Accelerated Corrosion No Not applicable Not applicable to PWRs Cast austenitic
 
stainless steel piping, piping components, and piping elements
 
exposed to treated water (borated or unborated) > 250&deg;C
(> 482&deg;F)
 
(3.2.1-20)
Loss of fracture toughness due
 
to thermal aging
 
embrittlement Thermal Aging Embrittlement of
 
CASS No Not applicable Not applicable to PWRs High-strength steel
 
closure bolting exposed to air with steam or water
 
leakage (3.2.1-21)
Cracking due to cyclic loading, stress corrosion
 
cracking Bolting Integrity No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1)
Steel closure bolting exposed to air with steam or water
 
leakage (3.2.1-22)
Loss of material due to general
 
corrosion Bolting Integrity No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1)
Steel bolting and
 
closure bolting
 
exposed to air -
 
outdoor (external), or
 
air - indoor
 
uncontrolled (external)
 
(3.2.1-23)
Loss of material due to general, pitting, and
 
crevice corrosion Bolting Integrity No Bolting Integrity
 
Program (B.3.2) Consistent with the GALL Report (See
 
SER Section
 
3.2.2.1.2)
Steel closure bolting
 
exposed to air -
 
indoor uncontrolled (external)
 
(3.2.1-24)
Loss of preload due to thermal
 
effects, gasket
 
creep, and self-
 
loosening Bolting Integrity No Bolting Integrity
 
Program (B.3.2) Consistent with the GALL Report (See
 
SER Section
 
3.2.2.1.3)
Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to closed cycle cooling water
> 60&deg;C (> 140&deg;F)
 
(3.2.1-25)
Cracking due to stress corrosion
 
cracking Closed-Cycle Cooling Water System No Closed Cooling Water Program (B.3.6) Consistent with the GALL Report 3-300 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendment s Staff Evaluation Steel piping, piping components, and
 
piping elements
 
exposed to closed cycle cooling water
 
(3.2.1-26)
Loss of material due to general, pitting, and
 
crevice corrosion Closed-Cycle Cooling Water System No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1)
Steel heat exchanger
 
components exposed to closed cycle cooling water
 
(3.2.1-27)
Loss of material due to general, pitting, crevice, and galvanic
 
corrosion Closed-Cycle Cooling Water System No Closed Cooling Water Program (B.3.6) Consistent with the GALL Report Stainless steel
 
piping, piping
 
components, piping
 
elements, and heat
 
exchanger
 
components exposed to closed-cycle cooling water
 
(3.2.1-28)
Loss of material due to pitting
 
and crevice
 
corrosion Closed-Cycle Cooling Water System No Closed Cooling Water Program (B.3.6) Consistent with the GALL Report Copper alloy piping, piping components, piping elements, and
 
heat exchanger
 
components exposed to closed cycle cooling water
 
(3.2.1-29)
Loss of material due to pitting, crevice, and
 
galvanic corrosion Closed-Cycle Cooling Water System No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1)
Stainless steel and copper alloy heat
 
exchanger tubes
 
exposed to closed cycle cooling water
 
(3.2.1-30)
Reduction of heat transfer
 
due to fouling Closed-Cycle Cooling Water System No Closed Cooling Water Program (B.3.6) Consistent with the GALL Report External surfaces of
 
steel components
 
including ducting, piping, ducting
 
closure bolting, and
 
containment isolation
 
piping external
 
surfaces exposed to
 
air - indoor
 
uncontrolled (external);
 
condensation (external) and air -
 
outdoor (external)
 
(3.2.1-31)
Loss of material due to general
 
corrosion External Surfaces Monitoring No External Surfaces Monitoring
 
Program (B.3.8) Consistent with the GALL Report 3-301 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendment s Staff Evaluation Steel piping and ducting components
 
and internal surfaces
 
exposed to air -
 
indoor uncontrolled (Internal)
 
(3.2.1-32)
Loss of material due to general
 
corrosion Inspection of Internal Surfaces in
 
Miscellaneous Piping
 
and Ducting
 
Components No One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report (See
 
SER Section
 
3.2.2.1.4)
Steel encapsulation
 
components exposed
 
to air - indoor
 
uncontrolled (internal)
 
(3.2.1-33)
Loss of material due to general, pitting, and
 
crevice corrosion Inspection of Internal Surfaces in
 
Miscellaneous Piping
 
and Ducting
 
Components No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1)
Steel piping, piping
 
components, and
 
piping elements
 
exposed to
 
condensation (internal)
 
(3.2.1-34)
Loss of material due to general, pitting, and
 
crevice corrosion Inspection of Internal Surfaces in
 
Miscellaneous Piping
 
and Ducting
 
Components No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1)
Steel containment
 
isolation piping and
 
components internal
 
surfaces exposed to raw water
 
(3.2.1-35)
Loss of material due to general, pitting, crevice, and microbiologically
-influenced
 
corrosion, and
 
fouling Open-Cycle Cooling Water System No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1)
Steel heat exchanger
 
components exposed to raw water
 
(3.2.1-36)
Loss of material due to general, pitting, crevice, galvanic, and
 
microbiologically
-influenced
 
corrosion, and
 
fouling Open-Cycle Cooling Water System No Generic Letter 89-13
 
Program (B.3.12) Consistent with the GALL Report Stainless steel
 
piping, piping
 
components, and
 
piping elements exposed to raw water
 
(3.2.1-37)
Loss of material due to pitting, crevice, and
 
microbiologically
-influenced
 
corrosion Open-Cycle Cooling Water System No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1)
Stainless steel
 
containment isolation
 
piping and
 
components internal
 
surfaces exposed to raw water
 
(3.2.1-38)
Loss of material due to pitting, crevice, and
 
microbiologically
-influenced
 
corrosion, and
 
fouling Open-Cycle Cooling Water System No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1) 3-302 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendment s Staff Evaluation Stainless steel heat exchanger
 
components exposed to raw water
 
(3.2.1-39)
Loss of material due to pitting, crevice, and
 
microbiologically
-influenced
 
corrosion, and
 
fouling Open-Cycle Cooling Water System No Generic Letter 89-13
 
Program (B.3.12) Periodic Surveillance
 
and Preventive
 
Maintenance
 
Program (B.3.21) Consistent with the GALL Report (See
 
SER Section
 
3.2.2.1.5)
Steel and stainless
 
steel heat exchanger tubes (serviced by open-cycle cooling water) exposed to raw water
 
(3.2.1-40)
Reduction of heat transfer
 
due to fouling Open-Cycle Cooling Water System No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1) Copper alloy
> 15% Zn piping, piping components, piping elements, and
 
heat exchanger
 
components exposed to closed cycle cooling water
 
(3.2.1-41)
Loss of material due to selective
 
leaching Selective Leaching of Materials No One-Time Inspection
 
Program for
 
Selective
 
Leaching (B.3.19) Consistent with the GALL Report Gray cast iron piping, piping components, piping elements
 
exposed to closed-cycle cooling water
 
(3.2.1-42)
Loss of material due to selective
 
leaching Selective Leaching of Materials No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1) Gray cast iron piping, piping components, and piping elements
 
exposed to soil
 
(3.2.1-43)
Loss of material due to selective
 
leaching Selective Leaching of Materials No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1) Gray cast iron motor
 
cooler exposed to treated water 
 
(3.2.1-44)
Loss of material due to selective
 
leaching Selective Leaching of Materials No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1) 3-303 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendment s Staff Evaluation Aluminum, copper alloy > 15% Zn, and
 
steel external
 
surfaces, bolting, and
 
piping, piping
 
components, and
 
piping elements exposed to air with borated water
 
leakage (3.2.1-45)
Loss of material due to Boric acid
 
corrosion Boric Acid Corrosion No Boric Acid Corrosion
 
Control Program (B.3.3) Consistent with the GALL Report for
 
carbon steel and
 
cast iron Steel encapsulation
 
components exposed to air with borated water leakage (internal)
 
(3.2.1-46)
Loss of material due to general, pitting, crevice
 
and boric acid
 
corrosion Inspection of Internal Surfaces in
 
Miscellaneous Piping
 
and Ducting
 
Components No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1)
Cast austenitic
 
stainless steel piping, piping components, and piping elements
 
exposed to treated borated water
> 250&deg;C (> 482&deg;F)
 
(3.2.1-47)
Loss of fracture toughness due
 
to thermal aging
 
embrittlement Thermal Aging Embrittlement of
 
CASS No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1)
Stainless steel or
 
stainless-steel-clad
 
steel piping, piping
 
components, piping
 
elements, and tanks (including safety
 
injection
 
tanks/accumulators)
 
exposed to treated borated water > 60&deg;C
(> 140&deg;F)
 
(3.2.1-48)
Cracking due to stress corrosion
 
cracking Water Chemistry No Water Chemistry
 
Control Program (B.3.28) One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report with
 
an additional
 
one-time inspection not recommended by
 
the GALL Report Stainless steel
 
piping, piping
 
components, piping
 
elements, and tanks
 
exposed to treated borated water
 
(3.2.1-49)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry No Water Chemistry
 
Control Program (B.3.28) Consistent with the GALL Report Aluminum piping, piping components, and piping elements
 
exposed to air -
 
indoor uncontrolled (internal/external)
 
(3.2.1-50) None None No None Consistent with the GALL Report (See
 
SER Section
 
3.2.2.1.1) 3-304 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendment s Staff Evaluation Galvanized steel ducting exposed to
 
air - indoor controlled (external)
 
(3.2.1-51) None None No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1)
Glass piping
 
elements exposed to
 
air - indoor
 
uncontrolled (external), lubricating oil, raw water, treated water, or treated borated water
 
(3.2.1-52) None None No None Consistent with the GALL Report Stainless steel, copper alloy, and nickel alloy piping, piping components, and piping elements
 
exposed to air -
 
indoor uncontrolled (external)
 
(3.2.1-53) None None No None Consistent with the GALL Report Steel piping, piping
 
components, and
 
piping elements
 
exposed to air -
 
indoor controlled (external)
 
(3.2.1-54) None None No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1)
Steel and stainless
 
steel piping, piping
 
components, and
 
piping elements in
 
concrete (3.2.1-55) None None No None Consistent with the GALL Report Steel, stainless steel, and copper alloy
 
piping, piping
 
components, and
 
piping elements
 
exposed to gas
 
(3.2.1-56) None None No None Consistent with the GALL Report 3-305 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendment s Staff Evaluation Stainless steel and copper alloy
< 15% Zn piping, piping components, and piping elements exposed to air with borated water
 
leakage (3.2.1-57) None None No Not applicable Not applicable to VEGP (See SER
 
Section 3.2.2.1.1)
The staff's review of the ESF system 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 staff's review of AMPs
 
credited to manage or monitor aging effects of the ESF system components is documented in SER Section 3.0.3.
 
3.2.2.1  AMR Results Consistent with the GALL Report LRA Section 3.2.2.1 identifies the materials, environments, AERMs, and the following
 
programs that manage aging effects for the ESF system components:
 
Bolting Integrity Program Boric Acid Corrosion Control Program Closed Cooling Water Program External Surfaces Monitoring Program Generic Letter 89-13 Program Oil Analysis Program One-Time Inspection Program One-Time Inspection Program for Selective Leaching Piping and Duct Internal Inspection Program Water Chemistry Control Program LRA Tables 3.2.2-1 and 3.2.2-2 summarize AMRs for the ESF 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
 
staff's audit and review determined whether the plant-specific components of these GALL
 
Report component groups were bounded by the GALL Report evaluation.
 
The applicant noted for each AMR line item how the information in the tables aligns with the 3-306 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
 
Report AMP. The staff audited these line items to verify consistency with the GALL Report
 
and validity of the AMR for the site-specific conditions.
 
Note B indicates that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the
 
GALL Report AMP. The staff audited these line items to verify consistency with the GALL
 
Report and verified that the identified exceptions to the GALL Report AMPs have been
 
reviewed and accepted. The staff also determined whether the applicant's AMP was
 
consistent with the GALL Report AMP and whether the AMR was valid for the site-specific
 
conditions.
 
Note C indicates that the component for the AMR line item, although different from, is
 
consistent with the GALL Report for material, environment, and aging effect. In addition, the
 
AMP is consistent with the GALL Report 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 determined
 
whether the AMR line item of the different component was applicable to the component
 
under review and whether the AMR was valid for the site-specific conditions.
 
Note D indicates that the component for the AMR line item, 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 Report AMP. The staff audited these line items to
 
verify consistency with the GALL Report. The staff verified whether the AMR line item of the
 
different component was applicable to the component under review and whether the
 
identified exceptions to the GALL Report AMPs have been reviewed and accepted. The
 
staff also determined whether the applicant's AMP was consistent with the GALL Report
 
AMP and whether the AMR was valid for the site-specific conditions.
 
Note E indicates that the AMR line item is consistent with the GALL Report for material, environment, and aging effect, but credits a different AMP or NUREG-1801 identifies a
 
plant specific aging management program. The staff also determined whether the credited
 
AMP would manage the aging effect consistent ly with the GALL Report 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's evaluation follows.
 
3.2.2.1.1  AMR Results Identified as Not Applicable
 
In LRA Table 3.2.1, items 3.2.1-02, -03, -04, -05, -07, -08, -10, -11, -12, -13, -14, -15, -17,
-18, -19, -20, -21, -22, -26, -29, -33, -34, -35, -37, -38, -40, -42, -43, -44, -46, -47, -51, and -
 
54 are identified as "Not Applicable" since either the component, material, and environment 3-307 combination does not exist for VEGP engineered sa fety features systems, or they are applicable to BWR plants only, or the components are evaluated with their parent system in
 
other sections. For each of these items, the staff reviewed the LRA and the applicant's
 
supporting documents, and confirmed the applicant's claim that the component, material, and environment combination does not exist fo r VEGP engineered safety features systems.
On the basis that VEGP engineered safety f eatures systems do not have the component, material, and environment combination for these Table 1 items, the staff concurs with the
 
applicant's conclusion that these AMRs are not applicable to VEGP engineered safety
 
features systems.
 
During the audit and review, the staff noted that the discussion column of LRA Table 3.2.1, Item 3.2.1-50 indicated that this Table 3.2.1 item is not applicable to VEGP. However, AMR
 
result items in auxiliary systems referenc e this Table 3.2.1 item. The staff asked the applicant to clarify this position. The applicant provided its response to the staff's question
 
in a letter dated February 8, 2008. In its response, the applicant acknowledged this
 
oversight and stated that it will amend the LRA to address the auxiliary systems AMR result items in the discussion column of LRA Table 3.2.1, Item 3.2.1-50. The staff confirmed that
 
the applicant amended the LRA in a letter dated March 20, 2008. On the basis that the
 
applicant has appropriately corrected an error in the LRA, the staff finds this response
 
acceptable.
 
During the audit and review, the staff also noted that the discussion column of LRA Table
 
3.2.1, Item 3.2.1-57 indicated that this Table 3.2.1 item is consistent with the GALL Report.
 
However, there are no AMR result items that reference this Table 3.2.1 item. The staff
 
asked the applicant to clarify this position. The applicant provided its response to the staff's
 
question in a letter dated February 8, 2008. In its response, the applicant indicated that the
 
AMR process concluded that there are no aging effects for stainless steel and copper alloy (with less than 15 percent zinc) exposed to air with borated water leakage. The staff finds
 
this result is consistent with the GALL Report. The applicant further stated in its response
 
that VEGP did not list multiple lines with no aging effects for a particular component so this
 
Table 3.2.1 was not used as a reference in the AMR result items. The applicant will amend
 
the LRA to indicate in the discussion column of Table 3.2.1, Item 3.2.1-57 that this item was
 
not used. The staff confirmed that the applicant amended the LRA in a letter dated March
 
20, 2008. On the basis that the applicant has appropriately corrected an error in the LRA, the staff finds this response acceptable.
 
3.2.2.1.2  Loss of Material Due to General, Pitting and Crevice Corrosion LRA Table 3.2.1, Item 3.2.1-23 states that loss of material of steel bolting and closure bolting exposed to air environments when the co mponent temperature is less than or equal to 212 &deg;F is managed by the plant-specific Bolting Integrity Program. During the audit and
 
review, the staff noted that the AMR result items pointing to LRA Table 3.2.1, Item 3.3.1-23
 
refer to Note E.
 
The staff reviewed the AMR result items referring to Note E and determined that the
 
component type, material, environment, and aging effect are consistent with those of the
 
corresponding line of the GALL Report. The applicant developed a plant-specific AMP to
 
manage the effects of aging on steel closure bolting. Therefore, the applicant assigned a
 
Note E to these AMR result items. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The Bolting Integrity Program is a new plant-specific
 
program to manage cracking, loss of material, and loss of preload in mechanical bolted 3-308 closures. The staff's review of the Bolting Integrity Program includes the staff's assessment of the AMP's program elements against the recommended program element criteria that are provided in Branch Position RLSB-1 in Appendix A of the SRP-LR (i.e., NUREG-1800, Revision 1). The VEGP Bolting Integrity Program applies to safety-related and nonsafety-
 
related bolting for pressure-retaining components within the scope of license renewal, with
 
the exception of the reactor vessel head studs which are addressed by the Reactor Vessel
 
Head Closure Stud Program. Visual inspections are conducted to detect loss of preload
 
resulting in joint leakage and to detect fastener degradation due to cracking or loss of
 
material. On the basis of the periodic visual inspections of the closure bolting to detect loss
 
of material, the staff finds the applicant's use of the Bolting Integrity Program acceptable.
 
On the basis of its review of the AMR result items as described in the preceding paragraphs
 
and its comparison of the applicant's results to corresponding recommendations in the
 
GALL Report, the staff finds that the applicant addressed the aging effect or mechanism
 
appropriately as recommended by the GALL Report.
 
3.2.2.1.3  Loss of Preload Due to Thermal Effects, Gasket Creep, and Self-Loosening
 
LRA Table 3.2.1, Item 3.2.1-24, states that loss of preload of steel closure bolting externally
 
exposed to an uncontrolled indoor air environment is managed by the plant-specific Bolting Integrity Program. During the audit and review, the staff noted that the AMR result items
 
pointing to LRA Table 3.2.1, Item 3.2.1-24, refer to Note E.
 
The staff reviewed the AMR result items referring to Note E and determined that the
 
component type, material, environment, and aging effect are consistent with those of the
 
corresponding line of the GALL Report. The applicant developed a plant-specific AMP to
 
manage the effects of aging on steel closure bolting. Therefore, the applicant assigned a
 
Note E to these AMR result items. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The Bolting Integrity Program is a new plant-specific
 
program to manage cracking, loss of material, and loss of preload in mechanical bolted
 
closures. The staff's review of the Bolting Integrity Program includes the staff's assessment
 
of the AMP's program elements against the recommended program element criteria that are provided in Branch Position RLSB-1 in Appendix A of the SRP-LR (i.e., NUREG-1800, Revision 1). The VEGP Bolting Integrity Program applies to safety-related and nonsafety-
 
related bolting for pressure-retaining components within the scope of license renewal, with
 
the exception of the reactor vessel head studs which are addressed by the Reactor Vessel
 
Head Closure Stud Program. Visual inspections are conducted to detect loss of preload
 
resulting in joint leakage and to detect fastener degradation due to cracking or loss of
 
material. On the basis of the periodic visual inspections of the closure bolting to detect loss
 
of preload, the staff finds the applicant's use of the Bolting Integrity Program acceptable.
 
On the basis of its review of the AMR result items as described in the preceding paragraphs
 
and its comparison of the applicant's results to corresponding recommendations in the 
 
GALL Report, the staff finds that the applicant addressed the aging effect or mechanism
 
appropriately as recommended by the GALL Report.
 
3.2.2.1.4  Loss of Material Due to General Corrosion
 
LRA Table 3.2.1, Item 3.2.1-32, states that loss of material of steel piping and ducting
 
components and internal surfaces internally exposed to an uncontrolled indoor air
 
environment is managed by the One-Time Inspection Program. During the audit and 3-309 review, the staff noted that the AMR result items pointing to LRA Table 3.2.1, Item 3.2.1-32, refer to Note E.
 
The staff reviewed the AMR result items referring to Note E and determined that the
 
component type, material, environment, and aging effect are consistent with those of the
 
corresponding line of the GALL Report; however, where the GALL Report recommends the
 
Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, the applicant proposed to use the One-Time Inspection Program. Therefore, the applicant
 
assigned a Note E to these AMR result items.
 
During the audit and review, the staff asked the applicant to justify the use of the One-Time
 
Inspection Program in light of the GALL Report recommendation. The applicant provided its
 
response to the staff's question in a letter dated February 8, 2008. In its response, the
 
applicant stated that for the indoor air environment condensation or wetting is not expected.
 
Although, some loss of material due to corrosion is expected, the degree of corrosion for
 
this material and environment is expected to be minor and to progress slowly. The staff
 
finds that based on the lack of condensation or wetting, the aging effect will progress slowly
 
and the use of the One-Time Inspection Program is adequate to confirm this expectation.
 
On this basis, the staff finds the applicant's response acceptable.
 
The staff's evaluation of the applicant's One-Time Inspection Program is documented in
 
SER Section 3.0.3.1.2. The One-Time Inspection Program uses one-time inspections to
 
confirm that either an aging effect is not occurring, or is occurring so slowly as to not affect
 
the component's intended function(s) during the period of extended operation. The staff
 
confirmed that the inspections of internal surfaces of carbon steel and cast iron
 
components exposed to indoor air are included within the scope of the One-Time
 
Inspection Program. On the basis of the use of the one-time visual inspections to detect the loss of material, the staff finds the applicant's use of the One-Time Inspection Program
 
acceptable.
 
On the basis of its review of the AMR result items as described in the preceding paragraphs
 
and its comparison of the applicant's results to corresponding recommendations in the
 
GALL Report, the staff finds that the applicant addressed the aging effect or mechanism
 
appropriately as recommended by the GALL Report.
 
3.2.2.1.5  Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced
 
Corrosion, and Fouling
 
For most of the stainless steel heat exchanger components exposed to raw water within the
 
scope of license renewal, the applicant manages loss of material with its Generic Letter 89-
 
13 Program which is consistent with the GALL Report and acceptable. However, for the
 
shell side of the steam generator blowdown sample baths exposed to raw water (well
 
water); the applicant manages the loss of material with its Periodic Surveillance and
 
Preventive Maintenance Activities Program. This program is not consistent with the GALL
 
Report recommendation. Therefore, because t he component type, material, environment, and aging effect are consistent with those of the corresponding line of the GALL Report, the
 
applicant assigned a Note E to the AMR result item.
 
During the audit and review, the staff noted that the discussion entry in LRA Table 3.2.1, Item 3.2.1-39, did not recognize the application of the Periodic Surveillance and Preventive
 
Maintenance Activities Program to manage the loss of material for the steam generator 3-310 blowdown sample baths exposed to raw water. The staff asked the applicant to clarify use of this program for this material and environment combination. The applicant provided its
 
response to the staff's question in a letter dated February 8, 2008. In its response, the
 
applicant indicated that the steam generator blowdown sample baths are nonsafety-related
 
components which are within scope for 10 CFR 54.4(a)(2). Further, because of the well
 
water environment, the applicant stated in its response that new preventive maintenance
 
tasks are to be added to the Periodic Surveillance and Preventive Maintenance Activities
 
Program to conduct these inspections. In addition, the applicant stated that the frequency of
 
these inspections will be established based on the results of the initial inspections such that
 
assurance will be provided that these com ponents will continue to perform their intended function between inspections during the period of extended operation. On the basis of the
 
periodic visual inspections of these components under the Periodic Surveillance and
 
Preventive Maintenance Activities Program and the inspection frequency to be based on
 
the initial inspection results, the staff finds this response and the assignment of Note E to
 
this AMR result item acceptable.
 
The applicant also stated in its response that it intended to amend the LRA to include
 
information to the discussion column of LRA Table 3.2.1, Item 3.2.1-39, explaining its
 
position on managing the loss of material for the steam generator blowdown sample baths
 
exposed to raw water (well water). The staff confirmed that the applicant amended the LRA
 
in a letter dated March 20, 2008.
 
On the basis of its review of the AMR result items as described in the preceding paragraphs
 
and its comparison of the applicant's results to corresponding recommendations in the
 
GALL Report, the staff finds that the applicant addressed the aging effect or mechanism
 
appropriately as recommended by the GALL Report.
 
3.2.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended In LRA Section 3.2.2.2, the applicant further evaluated aging management, as
 
recommended by the GALL Report, for the ESF system components and provides information concerning how it will manage the following aging effects:
 
cumulative fatigue damage  loss of material due to cladding breach  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  local local 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 3-311  loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion  QA for aging management of nonsafety-related components For component groups evaluated in the GALL Report, for which the applicant claimed
 
consistency with the report and for which the report recommends further evaluation, the
 
staff audited and reviewed the applicant's evaluation to determine whether it adequately
 
addressed the issues further evaluated. In addition, the staff reviewed the applicant's
 
further evaluations against the criteria contained in SRP-LR Section 3.2.2.2.The staff's
 
review of the applicant's further evaluation follows.
 
3.2.2.2.1  Cumulative Fatigue Damage 
 
LRA Section 3.2.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants
 
must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents
 
the staff's review of the applicant's evaluation of this TLAA.
 
3.2.2.2.2  Loss of Material Due to Cladding Breach
 
The staff reviewed LRA Section 3.2.2.2.2 against the criteria in SRP-LR Section 3.2.2.2.2.
 
LRA Section 3.2.2.2.2 addresses loss of material due to cladding breach that may occur for
 
PWR pump casings with stainless steel cladding subjected to borated water as an aging
 
effect not applicable because the centrifugal charging pumps, safety injection pumps, and
 
RHR pumps use solid stainless steel casings. 
 
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.
 
Based on reviewing the LRA and the applicant's supporting documents, the staff confirmed
 
that the VEGP centrifugal charging pumps, safety injection pumps, and residual heat
 
removal pumps are fabricated from stainless steel and not from carbon steel with stainless
 
steel cladding. On this basis, the staff concludes that the AMR evaluation in SRP-LR
 
Section 3.2.2.2.2 and LRA Table 3.2.1, Item 3.2.1-02, do not apply to VEGP engineered
 
safety features systems because there are no steel pump casings with stainless steel cladding exposed to treated borated water in the engineered safety features systems.
 
3.2.2.2.3  Loss of Material Due to Pitting and Crevice Corrosion 
 
The staff reviewed LRA Section 3.2.2.2.3 against the following criteria in SRP-LR
 
Section 3.2.2.2.3:
 
  (1) LRA Section 3.2.2.2.3 addresses loss of material due to general, pitting, and crevice corrosion on the internal surfaces of stainless steel containment isolation piping
 
components exposed to treated water as an AERM predicted by the VEGP AMR
 
methodology but AMR results for ESF systems do not use this line item.
 
Containment isolation piping components ar e evaluated with their parent systems.
SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice 3-312 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 selected components at susceptible locations is an acceptable
 
method to determine whether an aging effect is occurring or is slowly progressing
 
such that the component's intended functions will be maintained during the period of
 
extended operation.
Based on reviewing the LRA and the applicant's supporting documents, the staff
 
confirmed that the containment isolation components are evaluated with the parent
 
system. On this basis, the staff finds it acceptable that the AMR result items do not
 
use Table 3.2.1, Item 3.2.1-03.
 
  (2) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion for stainless steel components exposed to soil, raw water, or internal
 
condensation as an aging effect not applicable. The VEGP AMR methodology
 
predicts loss of material for stainless steel piping components exposed to a soil
 
environment, but ESF system AMR result s do not include stainless steel piping components exposed to soil environments.
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.
Based on reviewing the LRA and the applicant's supporting documents, the staff
 
confirmed that the AMR result items for ESF systems do not include stainless steel piping components exposed to soil. On this basis, the staff finds it acceptable that
 
Table 3.2.1, Item 3.2.1-04, is not applicable to the ESF AMR result items.
 
  (3) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in stainless steel or aluminum piping components as an aging effect not
 
applicable to VEGP, a PWR plant.
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.
Based on reviewing the LRA and the applicant's supporting documents, the staff
 
finds acceptable the applicant's evaluation that this aging effect is not applicable to
 
VEGP, a PWR plant.
 
  (4) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in stainless steel and copper alloy components exposed to lubricating oil
 
as an AERM for which one-time inspection is recommended to verify the
 
effectiveness of lubricating oil controls in managing loss of material. Consistent with 3-313 the GALL Report AMP with exceptions, the Oil Analysis Program and the One-Time Inspection Program manage such loss of material in piping components.
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 the 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 staff reviewed the Oil Analysis Program and the One-Time Inspection Program
 
and determined that the aging effect of loss of material due to pitting and crevice
 
corrosion in stainless steel and copper alloy piping, piping components, and piping
 
elements exposed to lubricating oil will be effectively managed. The Oil Analysis Program maintains the quality of the lubricating oil within acceptable limits, thus
 
preserving an environment that is not conducive to deleterious aging effects. The
 
staff also confirmed that the One-Time Inspection Program will verify the
 
effectiveness of the Oil Analysis Program to manage loss of material due to pitting
 
and crevice corrosion for stainless steel and copper alloy components exposed to
 
lubricating oil. On the basis of its review, the staff finds that the applicant has met
 
the criteria of SRP-LR Section 3.2.2.2.3 by verifying the effectiveness of the Oil
 
Analysis Program by one-time inspections.
 
  (5) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in partially-encased stainless steel tanks exposed to raw water by
 
cracking of the perimeter seal by weathering as an aging effect not applicable
 
because the VEGP refueling water storage tank has a stainless steel liner encased
 
in concrete, not a moisture barrier exposed to raw water.
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.
Based on reviewing the LRA and the applicant's supporting documents, the staff
 
confirmed that the VEGP refueling water storage tank is encased in concrete and
 
will not be exposed to raw water. 
 
On this basis, the staff finds it acceptable that Table 3.2.1, Item 3.2.1-07, is not
 
applicable to the ESF AMR result items.
 
  (6) LRA Section 3.2.2.2.3 addresses loss of material due to crevice corrosion and pitting in stainless steel components exposed to internal condensation as an aging
 
effect not applicable because the VEGP ESF systems have no stainless steel piping
 
components or tanks exposed to internal condensation.
 
3-314 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.
Based on reviewing the LRA and the applicant's supporting documents, the staff
 
confirmed that the VEGP AMR result items do not include stainless steel piping
 
components or tank internal surfaces exposed to condensation. On this basis, the
 
staff finds it acceptable that Table 3.2.1, Item 3.2.1-08, is not applicable to the ESF
 
AMR result items.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.2.2.2.3 criteria where applicable. For those line items that apply to
 
LRA Section 3.2.2.2.3, the staff concludes 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).
 
3.2.2.2.4  Reduction of Heat Transfer Due to Fouling 
 
The staff reviewed LRA Section 3.2.2.2.4 against the following criteria in SRP-LR
 
Section 3.2.2.2.4:
 
  (1) LRA Section 3.2.2.2.4 addresses reduction of heat transfer due to fouling that may occur in steel, stainless steel, and copper alloy heat transfer tubes exposed to
 
lubricating oil as an AERM for which the aging management recommended is lube
 
oil chemistry control and a confirmatory one-time inspection. Consistent with the
 
GALL Report AMP with exceptions, the Oil Analysis Program and the One-Time
 
Inspection Program will manage reduction of heat transfer in lubricating oil heat
 
exchanger tubes.
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 selected components at
 
susceptible locations is an acceptable method to determine whether an aging effect
 
is occurring or is slowly progressing such that the component's intended functions
 
will be maintained during the period of extended operation.
The staff reviewed the Oil Analysis Program and the One-Time Inspection Program
 
and determined that the aging effect of reduction of heat transfer due to fouling in
 
steel, stainless steel and copper alloy heat exchanger tubes exposed to lubricating
 
oil will be effectively managed. The Oil Analysis Program maintains the quality of the
 
lubricating oil within acceptable limits, thus preserving an environment that mitigates
 
fouling as an aging mechanism to reduce heat transfer through the heat exchanger
 
tubes. The staff also confirmed that the One-Time Inspection Program will verify the
 
effectiveness of the Oil Analysis Program to manage the reduction of heat transfer
 
due to fouling for steel, stainless steel and copper alloy heat exchanger tubes 3-315 exposed to lubricating oil. On the basis of its review, the staff finds that the applicant has met the criteria of SRP-LR Section 3.2.2.2.4 by verifying the effectiveness of the
 
Oil Analysis Program by one-time inspections.
 
  (2) LRA Section 3.2.2.2.4 addresses reduction of heat transfer due to fouling that may occur in stainless steel heat exchanger tubes exposed to treated water as an aging
 
effect not applicable because AMR results for the ESF systems do not include heat
 
exchanger tubes exposed to treated, but nonborated water. For heat exchanger
 
tubes exposed to borated water, AMR results do not predict reduction in heat
 
transfer.
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.
Based on reviewing the LRA and the applicant's supporting documents, the staff
 
confirmed that the VEGP AMR result item s for ESF systems do not include stainless steel heat exchanger tubes exposed to treated water. In response to a clarifying
 
question from the staff, the applicant's response to the staff's question in a letter
 
dated February 8, 2008 stated that the stainless steel heat exchanger tubes at
 
VEGP are exposed to borated water which does not support an aging effect of
 
reduction of heat transfer due to fouling. The applicant further stated in its response
 
that fouling is not expected because borated water is filtered to remove particulates, de-ionized to remove contaminants and low in oxygen content. On this basis, the
 
staff finds it acceptable that Table 3.2.1, Item 3.2.1-10, is not applicable to the ESF
 
AMR result items.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.2.2.2.4 criteria where applicable. For those line items that apply to
 
LRA Section 3.2.2.2.4, the staff concludes 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 elastomer hardening and loss of strength in BWR standby
 
gas treatment system ductwork and filters as an aging effect not applicable to VEGP, a
 
PWR plant.
 
SRP-LR Section 3.2.2.2.5 states that hardening and loss of strength due to elastomer
 
degradation may occur in elastomer seals and components of the BWR standby gas
 
treatment system ductwork and filters exposed to air -  indoor uncontrolled.
3-316  Based on reviewing the LRA and the applicant's supporting documents, the staff finds
 
acceptable the applicant's evaluation that this aging effect is not applicable to VEGP, a
 
PWR plant.
 
3.2.2.2.6  Local Loss of Material Due to Erosion 
 
The staff reviewed LRA Section 3.2.2.2.6 against the criteria in SRP-LR Section 3.2.2.2.6.
 
LRA Section 3.2.2.2.6 addresses erosion of high-pressure safety-injection pump minimum
 
flow orifices exposed to borated water by extended use of this pump for normal charging as
 
an aging effect not applicable because VEGP does not use the safety-injection pumps for
 
normal charging so erosion of their minimum flow orifices is not plausible and the pertinent
 
GALL Report line item does not apply. 
 
SRP-LR Section 3.2.2.2.6 states that loss of material due to erosion may occur in the
 
stainless steel high-pressure safety injection (HPSI) pump miniflow recirculation orifice
 
exposed to treated borated water.
 
Based on reviewing the LRA and the applicant's supporting documents, the staff confirmed
 
that the VEGP high-pressure safety injection pumps are not used for normal charging flow.
 
On this basis, the staff finds it acceptable that Table 3.2.1, Item 3.2.1-12 is not applicable to
 
the ESF AMR result items.
 
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 loss of material due to general corrosion and fouling for
 
steel drywell and suppression chamber spray system nozzle and flow orifice for internal
 
surfaces exposed to an uncontrolled indoor air environment, as an aging effect.
 
Based on reviewing the LRA and the applicant's supporting documents, the staff finds
 
acceptable the applicant's evaluation that this aging effect is not applicable to VEGP, a
 
PWR plant.
 
3.2.2.2.8  Loss of Material Due to General, Pitting, and Crevice Corrosion 
 
The staff reviewed LRA Section 3.2.2.2.8 against the following criteria in SRP-LR
 
Section 3.2.2.2.8:
 
  (1) LRA Section 3.2.2.2.8 addresses loss of material due to general, pitting, and crevice corrosion that may occur in BWR steel piping components exposed to treated water
 
as an aging effect not applicable to VEGP, a PWR plant.
 
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.
 
3-317 Based on reviewing the LRA and the applicant's supporting documents, the staff finds acceptable the applicant's evaluation that this aging effect is not applicable to VEGP, a
 
PWR plant.
 
  (2) LRA Section 3.2.2.2.8 addresses loss of material due to general, pitting, and crevice corrosion that may occur on the internal surfaces of steel containment isolation
 
piping components exposed to treated water as an AERM predicted by the VEGP
 
AMR methodology but AMR results for ESF systems do not use this line item.
 
Containment isolation piping components ar e evaluated with their parent system. 
 
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 tr eated water. The existing AMP monitors and controls water chemistry to mitigate degradat ion. 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 selected components at susceptible locations is
 
an acceptable method to determine whether an aging effect is occurring or is slowly
 
progressing such that the component's intended functions will be maintained during the
 
period of extended operation.
 
Based on reviewing the LRA and the applicant's supporting documents, the staff confirmed
 
that the steel containment isolation components exposed to treated water are evaluated
 
with the parent system. On this basis, the staff finds it acceptable that the AMR result items
 
do not use Table 3.2.1, Item 3.2.1-15.
 
  (3) LRA Section 3.2.2.2.8 addresses loss of material due to general, pitting, and crevice corrosion that may occur in steel piping, piping components, and piping elements
 
exposed to lubricating oil as an AERM for which the aging management
 
recommended is oil analysis and a one-time inspection. Consistent with the GALL
 
Report AMP with exceptions, the Oil Anal ysis Program and the One-Time Inspection program will manage such loss of material in ESF system steel piping components.
 
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 lim its, 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 staff reviewed the Oil Analysis Program and the One-Time Inspection Program and
 
determined that the aging effect of loss of material due to general, pitting and crevice
 
corrosion in steel piping, piping components, and piping elements exposed to lubricating oil
 
will be effectively managed. The Oil Analysis Program maintains the quality of the 3-318 lubricating oil within acceptable limits, thus preserving an environment that is not conducive to deleterious aging effects. The staff also confirmed that the One-Time Inspection Program
 
will verify the effectiveness of the Oil Analys is Program to manage loss of material due to general, pitting and crevice corrosion for steel piping components exposed to lubricating oil.
 
On the basis of its review, the staff finds that the applicant has met the criteria of SRP-LR
 
Section 3.2.2.2.8 by verifying the effectivene ss of the Oil Analysis Program by one-time inspections.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.2.2.2.8 criteria where applicable. For those line items that apply to
 
LRA Section 3.2.2.2.8, the staff concludes 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).
 
3.2.2.2.9  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 in steel piping elements exposed to soil
 
environments as an AERM (loss of material for buried steel components) predicted by the
 
VEGP AMR methodology, noting that the only related GALL Report AMP is for BWR
 
standby gas treatment system and material for buried steel components and that AMR results for ESF systems do not include any steel piping components exposed to a soil environment. 
 
SRP-LR Section 3.2.2.2.9 states that loss of material due to general, pitting, crevice, and
 
microbiologically-influenced corrosion (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 applicant's inspection frequency and
 
operating experience with buried components to ensure that loss of material does not
 
occur.
 
Based on reviewing the LRA and the applicant's supporting documents, the staff confirmed
 
that the AMR result items for ESF system s do not include steel piping components exposed to soil. On this basis, the staff finds it acceptable that Table 3.2.1, Item 3.2.1-17 is not
 
applicable to the ESF AMR result items.
 
3.2.2.2.10  Quality Assurance for Aging Management of Nonsafety-Related Components 
 
SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.
 
3.2.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report 
 
In LRA Tables 3.2.2-1 and 3.2.2-2, 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.
3-319  In LRA Tables 3.2.2-1 and 3.2.2-2, 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 stated that 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 com ponent 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.
 
For component type, material, and environment combinations not evaluated in the GALL
 
Report, the staff reviewed the applicant's 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 staff's evaluation is documented in the following sections.
 
3.2.2.3.1  Containment Spray System - Summary of Aging Management Review -
 
LRA Table 3.2.2-1 
 
The staff reviewed LRA Table 3.2.2-1, which summarizes the results of AMR evaluations
 
for the containment spray system component groups.
 
In LRA Table 3.2.2-1, the applicant stated that stainless steel capillary tubing (sealed) for
 
Containment (CTMT) pressure sensors expos ed to a silicone interior environment does not exhibit any aging effects requiring management. During the audit and review, the staff
 
confirmed that the silicone material used in these components at VEGP is non-corrosive
 
Dow Corning 702 and that the components are sealed at the factory. Sealing of the sensors
 
at the factory keeps contaminates out of the component interior. The staff also confirmed
 
that site-specific operating experience has shown that no aging effects for these materials
 
have occurred at VEGP. On this basis, the staff finds the applicant's assertion that there is
 
no aging effect requiring management for stainless steel capillary tubing (sealed) for CTMT
 
pressure sensors exposed to a silicone interior environment acceptable.
 
In LRA Table 3.2.2-1, the applicant stated that stainless steel encapsulation vessels, piping
 
components, spray nozzles, tank - spray additive tank (Unit 2 only), and valve bodies
 
exposed to an interior air-indoor environment does not exhibit any aging effects requiring management. The GALL Report does not indicate any aging effects requiring management for stainless steel exposed to an external uncontrolled air-indoor environment. The staff
 
does not consider there to be any significant difference in the aging effects for stainless
 
steel components exposed internally or externa lly to an indoor-air environment. Also, during the audit and review, the staff confirmed that site-specific operating experience has shown
 
that no aging effects for these materials have occurred at VEGP. On this basis, the staff
 
finds the applicant's assertion that there is no aging effect requiring management for
 
stainless steel encapsulation vessels, piping components, spray nozzles, tank - spray
 
additive tank (Unit 2 only), and valve bodies exposed to an interior air-indoor environment
 
acceptable.
 
3-320 In LRA Table 3.2.2-1, the applicant proposed to manage the loss of material for carbon steel CTMT spray pumps motor coolers shells exposed to an interior air-ventilation
 
environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. During the
 
audit and review, the staff confirmed that the surfaces exposed to ventilation air are mostly
 
dry although some condensation could be present to support corrosion. Based on the lack
 
of moisture, the staff expects that any loss of material would progress slowly if at all. On
 
this basis, the staff finds the application of the One-Time Inspection Program acceptable to
 
manage the loss of material for carbon steel CTMT spray pumps motor cooler shells.
 
Furthermore, the staff confirmed that the applicant has included the internal surfaces of
 
carbon steel components exposed to ventilation air within the scope of the One-Time
 
Inspection Program to confirm that the aging effect of loss of material in an interior air-
 
ventilation environment is either not present or is proceeding very slowly. On the basis of its review, the staff finds that the aging effect of loss of material for carbon steel CTMT spray
 
pumps motor cooler shells exposed to an interior air-ventilation environment will be effectively managed by the One-Time Inspection Program.
 
In LRA Table 3.2.2-1, the applicant proposed to manage loss of preload for stainless steel
 
closure bolting exposed to an air-indoor external environment using the Bolting Integrity
 
Program.
 
The staff's evaluation of the Bolting Integrity Program is documented in SER Section
 
3.0.3.3.2. The Bolting Integrity Program description states that bolting and closure
 
inspections will be performed for signs of leakage due to loss of bolt preload. This program
 
is a plant-specific program. The staff's review of the Bolting Integrity Program includes the
 
staff's assessment of the AMP's program elements against the recommended program element criteria that are provided in Branch Position RLSB-1 in Appendix A of the SRP-LR (i.e., NUREG-1800, Revision 1). 
 
On the basis of its review, the staff finds that, because these components will be inspected
 
periodically, the aging effect of loss of preload of stainless steel closure bolting exposed to
 
an air-indoor external environment will be effe ctively managed by the Bolting Integrity 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).
 
3.2.2.3.2  Emergency Core Cooling System - Summary of Aging Management Review -
LRA Table 3.2.2-2 
 
The staff reviewed LRA Table 3.2.2-2, which summarizes the results of AMR evaluations
 
for the emergency core cooling system component groups.
 
In LRA Table 3.2.2-2, the applicant stated that stainless steel encapsulation vessels and
 
piping components exposed to an interior ai r-indoor environment do not exhibit any aging 3-321 effects requiring management. The GALL Report does not indicate any aging effects requiring management for stainless steel exposed to an external uncontrolled air-indoor
 
environment. The staff does not consider there to be any significant difference in the aging
 
effects for stainless steel components exposed in ternally or externally to an indoor-air environment. Also, during the audit and review, the staff confirmed that site-specific
 
operating experience has shown that no aging effects for these materials have occurred at
 
VEGP. The staff also notes that stainless steel is highly resistant to corrosion in dry
 
atmospheres in the absence of corrosive species. On this basis, the staff finds the
 
applicant's assertion that there is no aging effect requiring management for stainless steel
 
encapsulation vessels and piping components exposed to an interior air-indoor
 
environment acceptable.
 
In LRA Table 3.2.2-2, the applicant stated that glass sight glasses exposed to an interior
 
air-indoor environment do not exhibit any agi ng effects requiring management. There is no corresponding GALL Report Table 1 line item or GALL Report Volume 2 Chapter V line
 
item for this material/environment combination. However, GALL Report Volume 2 does
 
contain line item EP-15 (V.F-6) for engineered safety features systems which apply to glass
 
piping elements in an external indoor unc ontrolled air environment. This GALL Report Volume 2 line item documents that there are no aging effects for this material/environment
 
combination. Furthermore, the staff finds that there is no difference in the aging degradation
 
conclusion for this material/environment combination if the component is exposed
 
internally. In addition, the environment for th is AMR line item is air-indoor, which is a controlled environment. Therefore, the staff concludes that glass sight glasses exposed to
 
an interior air-indoor environment do not exhibit aging effects requiring management.
 
In LRA Table 3.2.2-2, the applicant stated that stainless steel refueling water storage tank (RWST) liners exposed to an interior air-outdoor environment do not exhibit any aging effects requiring management. The staff finds this acceptable because the GALL Report
 
indicates that there are no aging effects for stainless steel exposed to uncontrolled indoor
 
air. Furthermore, there is no expectation of age-related degradation for stainless steel in an
 
air-outdoor external environment in the absence of an aggressive environment such as salt air or being in an industrial location. Stainless steel is highly resistant to corrosion in dry
 
atmospheres in the absence of corrosive species, as cited in the Metals Handbook, Volume
 
3 (p. 65) and Volume 13 (p. 555) (Ninth Edition, American Society for Metals International, 1980 and 1987). During the audit, the staff confirmed that VEGP is not located near the sea
 
or in an industrial location. Therefore, the staff concludes that stainless steel RWST liners
 
exposed to an interior air-outdoor environment do not exhibit aging effects requiring
 
management.
 
In LRA Table 3.2.2-2, the applicant proposed to manage the loss of material for carbon
 
steel motor cooler shells for the centrifugal charging pumps, residual heat removal (RHR)
 
pumps, and safety injection (SI) pumps expos ed to an interior air-ventilation environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. During the
 
audit and review, the staff confirmed that surfaces exposed to ventilation air are mostly dry, although some condensation could be present to support corrosion. Based on the lack of
 
moisture, the staff expects that any loss of material would progress slowly, if at all. On this
 
basis, the staff finds the application of the One-Time Inspection Program acceptable to 3-322 manage the loss of material for carbon steel motor cooler shells for the centrifugal charging pumps, RHR pumps, and SI pumps. Furthermore, the staff confirmed that the applicant has
 
included the internal surfaces of carbon steel components exposed to ventilation air within
 
the scope of the One-Time Inspection Program to confirm that the aging effect of loss of
 
material in an interior air-ventilation environment is either not present or is proceeding very
 
slowly. On the basis of its review, the staff finds that the aging effect of loss of material for
 
carbon steel motor cooler shells for the centrifugal charging pumps, RHR pumps, and SI
 
pumps exposed to an interior air-ventilation environment will be effectively managed by the One-Time Inspection Program.
 
In LRA Table 3.2.2-2, the applicant stated that copper alloy motor cooler shells for the RHR
 
pumps exposed to an interior air-ventilation environment do not exhibit any aging effects requiring management. There is no corresponding GALL Report Table 1 line item or GALL
 
Report Volume 2 Chapter V (V.F-3) line item for this material/environment combination.
 
However, GALL Report Volume 2 does contain line item EP-10 for engineered safety
 
features systems which applies to copper alloy piping, piping components, and piping
 
elements in an external indoor uncontrolled air environment. This GALL Report Volume 2
 
line item documents that there are no aging effects for this material/environment
 
combination. During the audit and review, the staff confirmed that the surfaces of
 
components exposed to ventilation air are mostly dry which is similar to the surfaces
 
exposed to an air-indoor environment. Because the GALL Report does not identify any
 
aging effects requiring management for copper alloy piping, piping components, and piping
 
elements exposed to indoor uncontrolled air which is a similar environment to the air-
 
ventilation environment for this copper alloy line item, the staff finds it acceptable that there
 
are no aging effects. Therefore, the staff concludes that copper alloy motor cooler shells for
 
the RHR pumps exposed to an interior air-v entilation environment do not exhibit aging effects requiring management.
 
In LRA Table 3.2.2-2, the applicant stated that stainless steel electric heater housings, flow
 
orifice/elements, piping components, pipe spools for startup strainers, sludge mixing pump
 
casings, and valve bodies exposed to an air-out door external environment do not exhibit any aging effects requiring management. Based on industry experience, the staff finds that
 
there is no expectation of age-related degradation for stainless steel exposed to outdoor air
 
in the absence of an aggressive environment such as salt air or being in an industrial
 
location. Stainless steel is highly resistant to corrosion in dry atmospheres in the absence
 
of corrosive species, as cited in the Metals Handbook, Volume 3 (p. 65) and Volume 13 (p.
 
555) (Ninth Edition, American Society for Metals International, 1980 and 1987). During the
 
audit and review, the staff confirmed that VEGP is not located near the sea or in an
 
industrial location. Therefore, stainless steel electric heater housings, flow orifice/elements, piping components, pipe spools for startup strainers, sludge mixing pump casings, and
 
valve bodies exposed to an air-outdoor exte rnal environment exhibit no aging effects requiring management, and the component or structure will remain capable of performing
 
intended functions consistent with the CLB for the period of extended operation.
 
In LRA Table 3.2.2-2, the applicant proposed to manage loss of preload for stainless steel
 
closure bolting exposed to an air-outdoor or air-indoor external environment and carbon steel closure bolting exposed to an air-outdoor external environment using the Bolting
 
Integrity Program.
 
The staff's evaluation of the Bolting Integrity Program is documented in SER Section
 
3.0.3.3.2. The Bolting Integrity Program description states that bolting and closure 3-323 inspections will be performed for signs of leakage due to loss of bolt preload. This program is a plant-specific program. The staff's review of the Bolting Integrity Program includes the
 
staff's assessment of the AMP's program elements against the recommended program element criteria that are provided in Branch Position RLSB-1 in Appendix A of the SRP-LR (i.e., NUREG-1800, Revision 1). On the basis of its review, the staff finds that, because
 
these components will be inspected periodically, the aging effect of loss of preload of
 
stainless steel closure bolting exposed to an air-outdoor or air-indoor external environment and carbon steel closure bolting exposed to an air-outdoor external environment will be effectively managed by the Bolting Integrity Program.
 
In LRA Table 3.2.2-2, the applicant proposed to manage loss of material due to selective
 
leaching for gray cast iron filter housings ex posed to an internal environment of lubricating oil using the One-Time Inspection Program for Selective Leaching.
 
The staff's evaluation of the One-Time Inspection Program for Selective Leaching is
 
documented in SER Section 3.0.3.2.12. The One-Time Inspection Program for Selective
 
Leaching description states that the program will be a one-time inspection program to
 
assess selective leaching in susceptible cast iron and copper alloy components. The
 
program includes a one-time examination of a sample population of components most likely
 
to exhibit selective leaching. The new VEGP progr am is to provide objective evidence that the aging effect is not occurring, or that the aging effect is occurring slowly enough not to
 
affect the SSCs intended function during the period of extended operation, and thus not
 
require additional aging management. The inspections will be performed within a window of
 
ten years immediately preceding the period of extended operation. If degradation due to
 
selective leaching is identified, additional exam inations will be performed. This program is a new program consistent with GALL AMP XI.M33, "Selective Leaching of Materials" with an
 
exception that the program may use other detection techniques instead of, or in addition to, visual examination and hardness measurement. For some component locations, visual
 
examination and hardness measurement ma y not be feasible due to geometry and configuration issues. Other examination methods which are equally effective in detecting
 
and assessing the extent of selective leaching may be used. Examination techniques may
 
include hardness measurement (where feasible based on form and configuration), visual
 
examination, metallurgical evaluation, or other proven techniques determined to be
 
effective in identifying and assessing the extent of selective leaching. If any conditions are
 
observed which do not meet the acceptance criteria, appropriate actions will be taken to
 
prevent the component from being returned to service until the required corrective actions have been completed. On the basis of its review, the staff finds that the aging effect of loss
 
of material due to selective leaching for gray cast iron filter housings exposed to an internal 
 
environment of lubricating oil will be effe ctively managed by the One-Time Inspection Program for Selective Leaching.
 
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).
 
3.2.3  Conclusion The staff concludes that the applicant has provided sufficient information to demonstrate
 
that the effects of aging for the engineered safety features system components within the 3-324 scope of license renewal and subject to an AMR will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
 
3.3  Aging Management of Auxiliary Systems This section of the SER documents the staff's review of the applicant's AMR results for the
 
auxiliary systems component s and component groups of:
fuel storage racks - new and spent fuel  spent fuel cooling and purification system  overhead heavy and refueling load handling systems  nuclear service cooling water systems  component cooling water system  auxiliary component cooling water system  turbine plant cooling water system  river intake structure system  compressed air systems  chemical and volume control and boron recycle systems  ventilation systems - control building (CB)  ventilation systems - auxiliary building (AB)  ventilation systems - containment building (CTB)  ventilation systems - fuel handling building (FHB)  ventilation systems - diesel generator building  ventilation systems - aux iliary feedwater pumphouse  ventilation systems - miscellaneous  ventilation systems - radwaste buildings  fire protection systems  emergency diesel generator system  demineralized water system  hydrogen recombiner and monitoring system  drain systems  potable and utility water systems  radiation monitoring system  reactor makeup water storage tank and degasifier system  sampling systems  auxiliary gas systems  chilled water systems  waste management systems  thermal insulation  miscellaneous leak detection systems 3.3.1  Summary of Technical Information in the Application LRA Section 3.3 provides AMR result s for the auxiliary systems components and component groups. LRA Table 3.3.1, "Summary of Aging Management Evaluations for
 
Auxiliary Systems in Chapter VII of NURE G-1801," is a summary comparison of the applicant's AMRs with those evaluated in the GALL Report for the auxiliary systems components and component groups.
3-325  The applicant's AMRs evaluated and incorporated applicable plant-specific and industry
 
operating experience in the determination of AERMs. The plant-specific evaluation included
 
condition reports and discussions with appropriate site personnel to identify AERMs. The
 
applicant's review of industry operating experience included a review of the GALL Report
 
and operating experience issues identified since the issuance of the GALL Report.
 
3.3.2 Staff Evaluation The staff reviewed LRA Section 3.3 to determine whether the applicant provided sufficient
 
information to demonstrate that the effect s 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).
 
The staff conducted an audit of AMRs to ensure the applicant's claim that certain AMRs
 
were consistent with the GALL Report. The staff did not repeat its review of the matters
 
described in the GALL Report; however, the staff did verify that the material presented in
 
the LRA was applicable and that the applicant identified the appropriate GALL Report
 
AMRs. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details
 
of the staff's audit evaluation are documented in SER Section 3.3.2.1.
 
In the audit, the staff also selected AMRs consistent with the GALL Report and for which
 
further evaluation is recommended. The staff confirmed that the applicant's further
 
evaluations were consistent with the SRP-LR Section 3.3.2.2 acceptance criteria. The
 
staff's audit evaluations are documented in SER Section 3.3.2.2.
 
The staff also conducted a technical review of the remaining AMRs not consistent with or
 
not addressed in the GALL Report. The technical review evaluated whether all plausible
 
aging effects have been identified and whether the aging effects listed were appropriate for
 
the material-environment combinations specified. The staff's evaluations are documented in
 
SER Section 3.3.2.3.
 
For SSCs which the applicant claimed were not applicable or required no aging
 
management, the staff reviewed the AMR line items and the plant's operating experience to
 
verify the applicant's claims.
 
Table 3.3-1 summarizes the staff's evaluation of components, aging effects or mechanisms, and AMPs listed in LRA Section 3.3 and addressed in the GALL Report.
 
Table 3.3-1  Staff Evaluation for Auxiliary System Components in the GALL Report Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation
 
3-326 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel cranes -
structural girders
 
exposed to air -
 
indoor uncontrolled (external)
 
(3.3.1-1)
Cumulative fatigue damage TLAA to be evaluated for
 
structural girders of
 
cranes. See the
 
SRP-LR, Section 4.7
 
for generic guidance
 
for meeting the
 
requirements of 10 CFR 54.21(c)(1). Yes TLAA Fatigue is not a TLAA (See
 
SER Section
 
3.3.2.2.1)
Steel and stainless
 
steel piping, piping
 
components, piping
 
elements, and heat
 
exchanger
 
components exposed
 
to air - indoor
 
uncontrolled, treated borated water or treated water
 
(3.3.1-2)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes TLAA Fatigue is a TLAA (See
 
SER Section
 
3.3.2.2.1)
Stainless steel heat
 
exchanger tubes
 
exposed to treated water (3.3.1-3)
Reduction of heat transfer
 
due to fouling Water Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.3.2.2.2)
Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to sodium
 
pentaborate solution
> 60&deg;C (> 140&deg;F)
 
(3.3.1-4)
Cracking due to stress corrosion
 
cracking Water Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.3.2.2.3)
Stainless steel and
 
stainless clad steel
 
heat exchanger
 
components exposed to treated water
> 60&deg;C (> 140&deg;F)
 
(3.3.1-5)
Cracking due to stress corrosion
 
cracking A plant-specific aging management
 
program is to be
 
evaluated. Yes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.3.2.2.3)
Stainless steel diesel
 
engine exhaust
 
piping, piping
 
components, and
 
piping elements
 
exposed to diesel
 
exhaust (3.3.1-6)
Cracking due to stress corrosion
 
cracking A plant-specific aging management
 
program is to be
 
evaluated. Yes Piping and Duct Internal Inspection
 
Program (B.3.22) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.3) 3-327 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel non-regenerative heat
 
exchanger
 
components exposed
 
to treated borated water > 60&deg;C
(> 140&deg;F)
 
(3.3.1-7)
Cracking due to stress corrosion
 
cracking and cyclic loading Water Chemistry and a plant-specific
 
verification program.
 
An acceptable
 
verification program
 
is to include
 
temperature and radioactivity
 
monitoring of the shell side water, and eddy current testing
 
of tubes. Yes Water  Chemistry
 
Control Program (B.3.28);
One-Time 
 
Inspection
 
Program (B.3.17) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.4)
Stainless steel
 
regenerative heat
 
exchanger
 
components exposed
 
to treated borated water > 60&deg;C
(> 140&deg;F)
 
(3.3.1-8)
Cracking due to stress corrosion
 
cracking and cyclic loading Water Chemistry and a plant-specific
 
verification program.
The AMP is to be augmented by verifying the absence
 
of cracking due to
 
stress corrosion cracking and cyclic
 
loading. A plant-
 
specific aging
 
management
 
program is to be
 
evaluated. Yes Water  Chemistry
 
Control Program (B.3.28);
One-Time 
 
Inspection
 
Program (B.3.17) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.4)
Stainless steel high-
 
pressure pump
 
casing in PWR
 
chemical and volume control system
 
(3.3.1-9)
Cracking due to stress corrosion
 
cracking and cyclic loading Water Chemistry and a plant-specific
 
verification program.
The AMP is to be augmented by verifying the absence
 
of cracking due to
 
stress corrosion cracking and cyclic
 
loading. A plant-
 
specific aging
 
management
 
program is to be
 
evaluated. Yes Not applicable Not applicable (See SER Section 3.3.2.2.4)
High-strength steel
 
closure bolting exposed to air with steam or water
 
leakage.
(3.3.1-10)
Cracking due to stress corrosion cracking, cyclic
 
loading Bolting Integrity. The AMP is to be augmented by
 
appropriate
 
inspection to detect
 
cracking if the bolts are not otherwise
 
replaced during
 
maintenance. Yes Not applicable Not applicable (See SER Section 3.3.2.2.4) 3-328 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Elastomer seals and components exposed
 
to air - indoor
 
uncontrolled (internal/external)
 
(3.3.1-11)
Hardening and loss of strength
 
due to elastomer
 
degradation A plant-specific aging management
 
program is to be
 
evaluated.
Yes Periodic Surveillance and
 
Preventive
 
Maintenance
 
Activities
 
Program (B.3.21); Piping
 
and Duct Internal Inspection
 
Program (B.3.22);
 
External Surfaces Monitoring 
 
Program (B.3.8) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.5)
Elastomer lining
 
exposed to treated water or treated borated water
 
(3.3.1-12)
Hardening and loss of strength
 
due to elastomer
 
degradation A plant-specific aging management
 
program is to be
 
evaluated.
Yes Periodic Surveillance and
 
Preventive
 
Maintenance
 
Activities
 
Program (B.3.21); Piping
 
and Duct Internal Inspection
 
Program (B.3.22) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.5)
Boral, boron steel
 
spent fuel storage
 
racks neutron-
 
absorbing sheets
 
exposed to treated water or treated borated water
 
(3.3.1-13)
Reduction of neutron-absorbing capacity and
 
loss of material
 
due to general
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated. Yes Water  Chemistry
 
Control Program (B.3.28)
One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.6)
Steel piping, piping
 
component, and
 
piping elements
 
exposed to
 
lubricating oil
 
(3.3.1-14)
Loss of material due to general, pitting, and
 
crevice corrosion Lubricating Oil Analysis and One-Time InspectionYes Oil Analysis Program (B.3.16);
One-Time 
 
Inspection
 
Program (B.3.17)  Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.7)
Steel reactor coolant
 
pump oil collection system piping, tubing, and valve
 
bodies exposed to
 
lubricating oil
 
(3.3.1-15)
Loss of material due to general, pitting, and
 
crevice corrosion Lubricating Oil Analysis and One-Time InspectionYes One-Time Inspection
 
Program (B.3.17)  Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.7) 3-329 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel reactor coolant pump oil collection system tank exposed
 
to lubricating oil
 
(3.3.1-16)
Loss of material due to general, pitting, and
 
crevice corrosion Lubricating Oil Analysis and One-Time Inspection
 
to evaluate the
 
thickness of the lower portion of the
 
tank Yes One-Time Inspection
 
Program (B.3.17) Consistent with the  GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.7)
Steel piping, piping
 
components, and
 
piping elements
 
exposed to treated water (3.3.1-17)
Loss of material due to general, pitting, and
 
crevice corrosion Water Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.3.2.2.7)
Stainless steel and
 
steel diesel engine
 
exhaust piping, piping components, and piping elements
 
exposed to diesel
 
exhaust (3.3.1-18)
Loss of material/general (steel only),
pitting and
 
crevice corrosion A plant-specific aging management
 
program is to be
 
evaluated. Yes Piping and Duct Internal Inspection
 
Program (B.3.22) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.7) Steel (with or without coating or wrapping)
 
piping, piping
 
components, and
 
piping elements
 
exposed to soil
 
(3.3.1-19)
Loss of material due to general, pitting, crevice, and microbiologically
 
influenced
 
corrosion Buried Piping and Tanks Surveillance
 
or
 
Buried Piping and Tanks Inspection Yes Buried Piping and Tank Inspection 
 
Program (B.3.4)  Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.8)
Steel piping, piping
 
components, piping
 
elements, and tanks
 
exposed to fuel oil
 
(3.3.1-20)
Loss of material due to general, pitting, crevice, and microbiologically
 
influenced
 
corrosion, and
 
fouling Fuel Oil Chemistry and One-Time
 
Inspection Yes Diesel Fuel Oil Program (B.3.7);
One-Time Inspection
 
Program (B.3.17);
 
Periodic Surveillance and
 
Preventive
 
Maintenance
 
Activities
 
Program (B.3.21)              Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.9)
Steel heat exchanger
 
components exposed
 
to lubricating oil
 
(3.3.1-21)
Loss of material due to general, pitting, crevice, and microbiologically
 
influenced
 
corrosion, and
 
fouling Lubricating Oil Analysis and One-Time InspectionYes Oil Analysis Program (B.3.16) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.9) 3-330 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel with elastomer lining or stainless
 
steel cladding piping, piping components, and piping elements
 
exposed to treated water and treated borated water
 
(3.3.1-22)
Loss of material due to pitting
 
and crevice corrosion (only
 
for steel after
 
lining/cladding
 
degradation) Water Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.3.2.2.10)
Stainless steel and steel with stainless
 
steel cladding heat
 
exchanger
 
components exposed to treated water
 
(3.3.1-23)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.3.2.2.10)
Stainless steel and
 
aluminum piping, piping components, and piping elements
 
exposed to treated water (3.3.1-24)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.3.2.2.10) Copper alloy HVAC
 
piping, piping
 
components, piping
 
elements exposed to
 
condensation (external)
 
(3.3.1-25)
Loss of material due to pitting
 
and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated. Yes External Surfaces Monitoring 
 
Program (B.3.8);
 
Piping and Duct
 
Internal Inspection
 
Program (B.3.22)  Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.10) Copper alloy piping, piping components, and piping elements
 
exposed to
 
lubricating oil
 
(3.3.1-26)
Loss of material due to pitting
 
and crevice
 
corrosion Lubricating Oil Analysis and One-Time InspectionYes Oil Analysis Program (B.3.16);
One-Time 
 
Inspection
 
Program (B.3.17)              Consistent with the  GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.10)
Stainless steel HVAC
 
ducting and
 
aluminum HVAC
 
piping, piping
 
components and
 
piping elements
 
exposed to
 
condensation
 
(3.3.1-27)
Loss of material due to pitting
 
and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated. Yes External Surfaces Monitoring 
 
Program (B.3.8);
 
Piping and Duct
 
Internal Inspection
 
Program (B.3.22);
Bolting Integrity
 
Program (B.3.2)  Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.10) 3-331 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Copper alloy fire protection piping, piping components, and piping elements
 
exposed to
 
condensation (internal)
 
(3.3.1-28)
Loss of material due to pitting
 
and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated. Yes Not applicable Not applicable (See SER Section 3.3.2.2.10)
Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to soil
 
(3.3.1-29)
Loss of material due to pitting
 
and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated. Yes Buried Piping and Tank Inspection 
 
Program (B.3.4)      Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.10)
Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to sodium
 
pentaborate solution
 
(3.3.1-30)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.3.2.2.10) Copper alloy piping, piping components, and piping elements
 
exposed to treated water (3.3.1-31)
Loss of material due to pitting, crevice, and
 
galvanic corrosion Water Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.3.2.2.11)
Stainless steel, aluminum and copper alloy piping, piping components, and piping elements
 
exposed to fuel oil
 
(3.3.1-32)
Loss of material due to pitting, crevice, and microbiologically
 
influenced
 
corrosion Fuel Oil Chemistry and One-Time
 
Inspection Yes Diesel Fuel Oil Program (B.3.7);
One-Time Inspection
 
Program (B.3.17); Fire
 
Protection
 
Program (B3.9)* 
 
(*with Diesel Fuel Oil Program applicable to
 
diesel-driven fire
 
pump fuel oil supply line only) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.12) 3-332 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to
 
lubricating oil
 
(3.3.1-33)
Loss of material due to pitting, crevice, and microbiologically
 
influenced
 
corrosion Lubricating Oil Analysis and One-Time InspectionYes Oil Analysis Program (B.3.16);
One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.3.2.2.12)
Elastomer seals and
 
components exposed
 
to air - indoor
 
uncontrolled (internal
 
or external)
 
(3.3.1-34)
Loss of material due to wear A plant-specific aging management
 
program is to be
 
evaluated. Yes Not applicable Not applicable (See SER Section 3.3.2.2.13) Steel with stainless
 
steel cladding pump
 
casing exposed to treated borated water
 
(3.3.1-35)
Loss of material due to cladding
 
breach A plant-specific aging management
 
program is to be
 
evaluated.
 
Reference NRC
 
IN 94-63, "Boric Acid
 
Corrosion of
 
Charging Pump Casings Caused by
 
Cladding Cracks." Yes Not applicable Not applicable (See SER Section 3.3.2.2.14)
Boraflex spent fuel
 
storage racks
 
neutron-absorbing
 
sheets exposed to treated water
 
(3.3.1-36)
Reduction of neutron-absorbing capacity due to
 
boraflex degradation Boraflex Monitoring No Not applicable Not applicable to PWRs Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to treated water > 60&deg;C
(> 140&deg;F)
 
(3.3.1-37)
Cracking due to stress corrosion
: cracking, intergranular
 
stress corrosion
 
cracking BWR Reactor Water Cleanup System No Not applicable Not applicable to PWRs Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to treated water > 60&deg;C
(> 140&deg;F)
 
(3.3.1-38)
Cracking due to stress corrosion
 
cracking BWR Stress Corrosion Cracking and Water ChemistryNo Not applicable Not applicable to PWRs 3-333 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel BWR spent fuel storage racks exposed to treated water > 60&deg;C
(> 140&deg;F)
 
(3.3.1-39)
Cracking due to stress corrosion
 
cracking Water Chemistry No Not applicable Not applicable to PWRs Steel tanks in diesel fuel oil system
 
exposed to air -
 
outdoor (external)
 
(3.3.1-40)
Loss of material due to general, pitting, and
 
crevice corrosion Aboveground Steel Tanks No Not used  Not used (See SER Section
 
3.3.2.1.1)
High-strength steel
 
closure bolting exposed to air with steam or water
 
leakage (3.3.1-41)
Cracking due to cyclic loading, stress corrosion
 
cracking Bolting Integrity No Not applicable Not applicable (See SER Section 3.3.2.1.1)
Steel closure bolting exposed to air with steam or water
 
leakage (3.3.1-42)
Loss of material due to general
 
corrosion Bolting Integrity No Not applicable Not applicable (See SER Section 3.3.2.1.1)
Steel bolting and
 
closure bolting
 
exposed to air -
 
indoor uncontrolled (external) or air -
 
outdoor (external)
 
(3.3.1-43)
Loss of material due to general, pitting, and
 
crevice corrosion Bolting Integrity No Bolting Integrity Program (B.3.2) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1.3)
Steel compressed air system closure
 
bolting exposed to
 
condensation
 
(3.3.1-44)
Loss of material due to general, pitting, and
 
crevice corrosion Bolting Integrity No Bolting Integrity Program (B.3.2) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1.4)
Steel closure bolting
 
exposed to air -
 
indoor uncontrolled (external)
 
(3.3.1-45)
Loss of preload due to thermal
 
effects, gasket
 
creep, and self-
 
loosening Bolting Integrity No Bolting Integrity Program (B.3.2) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1.5)
Stainless steel and
 
stainless clad steel
 
piping, piping
 
components, piping
 
elements, and heat
 
exchanger
 
components exposed to closed cycle
 
cooling water > 60&deg;C
(> 140&deg;F)
 
(3.3.1-46)
Cracking due to stress corrosion
 
cracking Closed-Cycle Cooling Water System No Closed Cooling Water Program (B.3.6) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) 3-334 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel piping, piping components, piping
 
elements, tanks, and
 
heat exchanger
 
components exposed to closed cycle cooling water
 
(3.3.1-47)
Loss of material due to general, pitting, and
 
crevice corrosion Closed-Cycle Cooling Water System No Closed Cooling Water Program (B.3.6) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Steel piping, piping
 
components, piping
 
elements, tanks, and
 
heat exchanger
 
components exposed to closed cycle cooling water
 
(3.3.1-48)
Loss of material due to general, pitting, crevice, and galvanic
 
corrosion Closed-Cycle Cooling Water System No Closed Cooling Water Program (B.3.6) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Stainless steel; steel with stainless steel
 
cladding heat
 
exchanger
 
components exposed to closed cycle cooling water
 
(3.3.1-49)
Loss of material due to microbiologically
 
influenced
 
corrosion Closed-Cycle Cooling Water System No Not applicable Not applicable to PWRs Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to closed cycle cooling water
 
(3.3.1-50)
Loss of material due to pitting
 
and crevice
 
corrosion Closed-Cycle Cooling Water System No Closed Cooling Water Program (B.3.6) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Copper alloy piping, piping components, piping elements, and
 
heat exchanger
 
components exposed to closed cycle cooling water
 
(3.3.1-51)
Loss of material due to pitting, crevice, and
 
galvanic corrosion Closed-Cycle Cooling Water System No Closed Cooling Water Program (B.3.6) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Steel, stainless steel, and copper alloy heat
 
exchanger tubes
 
exposed to closed cycle cooling water
 
(3.3.1-52)
Reduction of heat transfer
 
due to fouling Closed-Cycle Cooling Water System No Not applicable Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) 3-335 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel compressed air system piping, piping
 
components, and
 
piping elements
 
exposed to
 
condensation (internal)
 
(3.3.1-53)
Loss of material due to general
 
and pitting
 
corrosion Compressed Air Monitoring No Not applicable Not applicable (See SER Section 3.3.2.1.1)
Stainless steel
 
compressed air system piping, piping
 
components, and
 
piping elements
 
exposed to internal
 
condensation
 
(3.3.1-54)
Loss of material due to pitting
 
and crevice
 
corrosion Compressed Air Monitoring No Not applicable Not applicable (See SER Section 3.3.2.1.1)
Steel ducting closure
 
bolting exposed to air
- indoor uncontrolled (external)
 
(3.3.1-55)
Loss of material due to general
 
corrosion External Surfaces Monitoring No Bolting Integrity Program (B.3.2) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1.3)
Steel HVAC ducting
 
and components
 
external surfaces
 
exposed to air -
 
indoor uncontrolled (external)
 
(3.3.1-56)
Loss of material due to general
 
corrosion External Surfaces Monitoring No External Surfaces Monitoring
 
Program (B.3.8) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Steel piping and
 
components external
 
surfaces exposed to
 
air - indoor
 
uncontrolled (external)
 
(3.3.1-57)
Loss of material due to general
 
corrosion External Surfaces Monitoring No External Surfaces Monitoring
 
Program (B.3.8) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Steel external
 
surfaces exposed to
 
air - indoor
 
uncontrolled (external), air -
 
outdoor (external),
and condensation (external)
 
(3.3.1-58)
Loss of material due to general
 
corrosion External Surfaces Monitoring No External Surfaces Monitoring
 
Program (B.3.8) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Steel heat exchanger
 
components exposed
 
to air - indoor
 
uncontrolled (external) or air -
 
outdoor (external)
 
(3.3.1-59)
Loss of material due to general, pitting, and
 
crevice corrosion External Surfaces Monitoring No External Surfaces Monitoring
 
Program (B.3.8) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) 3-336 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel piping, piping components, and
 
piping elements
 
exposed to air -
 
outdoor (external)
 
(3.3.1-60)
Loss of material due to general, pitting, and
 
crevice corrosion External Surfaces Monitoring No Not used  Not used (See SER Section
 
3.3.2.1.1)
Elastomer fire barrier
 
penetration seals
 
exposed to 
 
air - outdoor or 
 
air - indoor
 
uncontrolled
 
(3.3.1-61)
Increased
: hardness, shrinkage and
 
loss of strength
 
due to weathering Fire Protection No Fire Protection Program (B.3.9) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Aluminum piping, piping components, and piping elements exposed to raw water
 
(3.3.1-62)
Loss of material due to pitting
 
and crevice
 
corrosion Fire Protection No Fire Protection Program (B.3.9) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Steel fire rated doors
 
exposed to air -
 
outdoor or 
 
air - indoor
 
uncontrolled
 
(3.3.1-63)
Loss of material due to wear Fire Protection No Fire Protection Program (B.3.9) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Steel piping, piping
 
components, and
 
piping elements
 
exposed to fuel oil
 
(3.3.1-64)
Loss of material due to general, pitting, and
 
crevice corrosion Fire Protection and Fuel Oil Chemistry No Fire Protection Program (B.3.9);
 
Diesel Fuel Oil
 
Program (B.3.7)  Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1.6)
Reinforced concrete
 
structural fire barriers
- walls, ceilings and
 
floors exposed to air
- indoor uncontrolled
 
(3.3.1-65)
Concrete cracking and
 
spalling due to
 
aggressive
 
chemical attack, and reaction with
 
aggregates Fire Protection and Structures Monitoring
 
Program No Fire Protection Program (B.3.9)
 
and Structural
 
Monitoring
 
Program (B.3.32) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Reinforced concrete
 
structural fire barriers
- walls, ceilings and
 
floors exposed to air
- outdoor
 
(3.3.1-66)
Concrete cracking and
 
spalling due to freeze thaw, aggressive
 
chemical attack, and reaction with
 
aggregates Fire Protection and Structures Monitoring
 
Program No Structural Monitoring
 
Program (B.3.32) or
 
Inservice
 
Inspection Program - IWL (B.3.31) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Reinforced concrete
 
structural fire barriers
- walls, ceilings and
 
floors exposed to air
- outdoor or air -
 
indoor uncontrolled
 
(3.3.1-67)
Loss of material due to corrosion
 
of embedded
 
steel Fire Protection and Structures Monitoring
 
Program No Fire Protection Program (B.3.9)
 
and Structural
 
Monitoring
 
Program (B.3.32)
Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) 3-337 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel piping, piping components, and
 
piping elements exposed to raw water
 
(3.3.1-68)
Loss of material due to general, pitting, crevice, and microbiologically
 
influenced
 
corrosion, and
 
fouling Fire Water System No Fire Protection Program (B.3.9) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Stainless steel
 
piping, piping
 
components, and
 
piping elements exposed to raw water
 
(3.3.1-69)
Loss of material due to pitting
 
and crevice
 
corrosion, and
 
fouling Fire Water System No Fire Protection Program (B.3.9) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Copper alloy piping, piping components, and piping elements exposed to raw water
 
(3.3.1-70)
Loss of material due to pitting, crevice, and microbiologically
 
influenced
 
corrosion, and
 
fouling Fire Water System No Fire Protection Program (B.3.9) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Steel piping, piping
 
components, and
 
piping elements
 
exposed to moist air
 
or condensation (internal)
 
(3.3.1-71)
Loss of material due to general, pitting, and
 
crevice corrosion Inspection of Internal Surfaces in
 
Miscellaneous Piping
 
and Ducting
 
Components No Not applicable Not applicable (See SER Section 3.3.2.1.1)
Steel HVAC ducting
 
and components
 
internal surfaces
 
exposed to
 
condensation (internal)
 
(3.3.1-72)
Loss of material due to general, pitting, crevice, and (for drip
 
pans and drain
 
lines) microbiologically
 
influenced
 
corrosion Inspection of Internal Surfaces in
 
Miscellaneous Piping
 
and Ducting
 
Components No Piping and Duct Internal Inspection
 
Program (B.3.22) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Steel crane structural
 
girders in load handling system
 
exposed to air -
 
indoor uncontrolled (external)
 
(3.3.1-73)
Loss of material due to general
 
corrosion Inspection of Overhead Heavy
 
Load and Light Load (Related to
 
Refueling) Handling Systems No Overhead and Refueling Crane
 
Inspection
 
Program (B.3.20);
 
Structural
 
Monitoring
 
Program (B.3.32) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1.7) 3-338 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel cranes - rails exposed to air -
 
indoor uncontrolled (external)
 
(3.3.1-74)
Loss of material due to Wear Inspection of Overhead Heavy
 
Load and Light Load (Related to
 
Refueling) Handling Systems No Overhead and Refueling Crane
 
Inspection
 
Program (B.3.20) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Elastomer seals and
 
components exposed to raw water
 
(3.3.1-75)
Hardening and loss of strength
 
due to elastomer
 
degradation;
 
loss of material
 
due to erosion Open-Cycle Cooling Water System No Not applicable Not applicable (See SER Section 3.3.2.1.1)
Steel piping, piping
 
components, and
 
piping elements (without lining/
coating or with
 
degraded lining/coating) exposed to raw water
 
(3.3.1-76)
Loss of material due to general, pitting, crevice, and microbiologically
 
influenced
 
corrosion, fouling, and
 
lining/coating
 
degradation Open-Cycle Cooling Water System No Generic Letter 89-13 Program (B.3.12); Piping
 
and Duct Internal Inspection
 
Program (B.3.22) Consistent with the GALL Report (See
 
SER Section 
 
3.3.2.1.10)
Steel heat exchanger
 
components exposed to raw water
 
(3.3.1-77)
Loss of material due to general, pitting, crevice, galvanic, and microbiologically
 
influenced
 
corrosion, and
 
fouling Open-Cycle Cooling Water System No Generic Letter 89-13 Program (B.3.12) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Stainless steel, nickel alloy, and copper alloy piping, piping components, and piping elements exposed to raw water
 
(3.3.1-78)
Loss of material due to pitting
 
and crevice
 
corrosion Open-Cycle Cooling Water System No Generic Letter 89-13 Program (B.3.12) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Stainless steel
 
piping, piping
 
components, and
 
piping elements exposed to raw water
 
(3.3.1-79)
Loss of material due to pitting
 
and crevice
 
corrosion, and
 
fouling Open-Cycle Cooling Water System No Generic Letter 89-13 Program (B.3.12); Piping
 
and Duct Internal Inspection
 
Program (B.3.22) Consistent with the GALL Report (See
 
SER Section 
 
3.3.2.1.8)
Stainless steel and copper alloy piping, piping components, and piping elements exposed to raw water
 
(3.3.1-80)
Loss of material due to pitting, crevice, and microbiologically
 
influenced
 
corrosion Open-Cycle Cooling Water System No Not used  Not used (See SER Section
 
3.3.2.1.1) 3-339 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Copper alloy piping, piping components, and piping elements, exposed to raw water
 
(3.3.1-81)
Loss of material due to pitting, crevice, and microbiologically
 
influenced
 
corrosion, and
 
fouling Open-Cycle Cooling Water System No Not applicable Not applicable (See SER Section 3.3.2.1.1) Copper alloy heat
 
exchanger
 
components exposed to raw water
 
(3.3.1-82)
Loss of material due to pitting,
: crevice, galvanic, and microbiologically
 
influenced
 
corrosion, and
 
fouling Open-Cycle Cooling Water System No Generic Letter 89-13 Program (B.3.12);
 
Periodic Surveillance and
 
Preventive
 
Maintenance
 
Activities (B.3.21) Consistent with the GALL Report (See
 
SER Section 
 
3.3.2.1.9)
Stainless steel and copper alloy heat
 
exchanger tubes exposed to raw water
 
(3.3.1-83)
Reduction of heat transfer
 
due to fouling Open-Cycle Cooling Water System No Generic Letter 89-13 Program (B.3.12) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Copper alloy
> 15% Zn piping, piping components, piping elements, and
 
heat exchanger
 
components exposed to raw water, treated water, or closed cycle cooling water
 
(3.3.1-84)
Loss of material due to selective
 
leaching Selective Leaching of Materials No One-Time Inspection
 
Program for
 
Selective
 
Leaching (B.3.19) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Gray cast iron piping, piping components, and piping elements exposed to soil, raw water, treated water, or closed-cycle cooling water
 
(3.3.1-85)
Loss of material due to selective
 
leaching Selective Leaching of Materials No One-Time Inspection
 
Program for
 
Selective
 
Leaching (B.3.19) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Structural steel (new
 
fuel storage rack assembly) exposed
 
to air - indoor
 
uncontrolled (external)
 
(3.3.1-86)
Loss of material due to general, pitting, and
 
crevice corrosion Structures Monitoring Program No Not used  Not used (See SER Section
 
3.3.2.1.1) 3-340 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Boraflex spent fuel storage racks
 
neutron-absorbing
 
sheets exposed to treated borated water
 
(3.3.1-87)
Reduction of neutron-absorbing capacity due to
 
boraflex degradation Boraflex Monitoring No Not applicable Not applicable (See SER Section 3.3.2.1.1)
Aluminum and copper alloy
> 15% Zn piping, piping components, and piping elements exposed to air with borated water
 
leakage (3.3.1-88)
Loss of material due to boric acid
 
corrosion Boric Acid Corrosion No Boric Acid Corrosion
 
Control Program (B.3.3) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Steel bolting and
 
external surfaces exposed to air with borated water
 
leakage (3.3.1-89)
Loss of material due to boric acid
 
corrosion Boric Acid Corrosion No Boric Acid Corrosion
 
Control Program (B.3.3) Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Stainless steel and steel with stainless
 
steel cladding piping, piping components, piping elements, tanks, and fuel
 
storage racks
 
exposed to treated borated water > 60&deg;C
(> 140&deg;F)
 
(3.3.1-90)
Cracking due to stress corrosion
 
cracking Water Chemistry No Water Chemistry Control Program (B.3.28); and One-Time Inspection
 
Program (B.3.17)  Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Stainless steel and steel with stainless
 
steel cladding piping, piping components, and piping elements
 
exposed to treated borated water
 
(3.3.1-91)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry No Water Chemistry Control Program (B.3.28)  Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Galvanized steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to air -
 
indoor uncontrolled
 
(3.3.1-92) None None No None Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) 3-341 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Glass piping elements exposed to
 
air, air - indoor
 
uncontrolled (external), fuel oil, lubricating oil, raw water, treated water, and treated borated water (3.3.1-93) None None No None Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Stainless steel and nickel alloy piping, piping components, and piping elements
 
exposed to air -
 
indoor uncontrolled (external)
 
(3.3.1-94) None None No None Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Steel and aluminum
 
piping, piping
 
components, and
 
piping elements
 
exposed to air -
 
indoor controlled (external)
 
(3.3.1-95) None None No Not applicable Not applicable (See SER Section 3.3.2.1.1)
Steel and stainless
 
steel piping, piping
 
components, and
 
piping elements in
 
concrete (3.3.1-96) None None No None Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Steel, stainless steel, aluminum, and copper alloy piping, piping components, and piping elements
 
exposed to gas
 
(3.3.1-97) None None No None Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) Steel, stainless steel, and copper alloy
 
piping, piping
 
components, and
 
piping elements
 
exposed to dried air
 
(3.3.1-98) None None No None Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1) 3-342 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel and copper alloy
< 15% Zn piping, piping components, and piping elements exposed to air with borated water
 
leakage (3.3.1-99) None None No None Consistent with the GALL Report (See
 
SER Section
 
3.3.2.1)  The staff's review of the auxiliary system s component groups followed 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 staff's review of AMPs
 
credited to manage or monitor aging effect s of the auxiliary systems components is documented in SER Section 3.0.3.
3.3.2.1  AMR Results Consistent with the GALL Report LRA Section 3.3.2.1 identifies the materials, environments, AERMs, and the following
 
programs that manage aging effects fo r the auxiliary systems components:
ACCW System Carbon Steel Components Program Bolting Integrity Program Boric Acid Corrosion Control Program Buried Piping and Tanks Inspection Program Closed Cooling Water Program Diesel Fuel Oil Program External Surfaces Monitoring Program Fire Protection Program Flow-Accelerated Corrosion Program Generic Letter 89-13 Program Inservice Inspection Program Oil Analysis Program One-Time Inspection Program One-Time Inspection Program for Selective Leaching Overhead and Refueling Crane Inspection Program Periodic Surveillance and Preventive Maintenance Activities Piping and Duct Internal Inspection Program Water Chemistry Control Program
 
3-343  LRA Tables 3.3.2-1 through 3.3.2-32 summa rize 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
 
staff's audit and review determined whether the plant-specific components of these GALL
 
Report component groups were bounded by the GALL Report evaluation.
 
The applicant noted for each AMR line item how the information in the tables aligns with the
 
information in the GALL Report. The staff audited those AMRs with Notes A 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
 
Report AMP. The staff audited these line items to verify consistency with the GALL Report
 
and validity of the AMR for the site-specific conditions.
 
Note B indicates that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the
 
GALL Report AMP. The staff audited these line items to verify consistency with the GALL
 
Report and verified that the identified exceptions to the GALL Report AMPs have been
 
reviewed and accepted. The staff also determined whether the applicant's AMP was
 
consistent with the GALL Report AMP and whether the AMR was valid for the site-specific
 
conditions.
 
Note C indicates that the component for the AMR line item, although different from, is
 
consistent with the GALL Report for material, environment, and aging effect. In addition, the
 
AMP is consistent with the GALL Report 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 determined
 
whether the AMR line item of the different component was applicable to the component
 
under review and whether the AMR was valid for the site-specific conditions.
 
Note D indicates that the component for the AMR line item, 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 Report AMP. The staff audited these line items to
 
verify consistency with the GALL Report. The staff verified whether the AMR line item of the
 
different component was applicable to the component under review and whether the
 
identified exceptions to the GALL Report AMPs have been reviewed and accepted. The
 
staff also determined whether the applicant's AMP was consistent with the GALL Report
 
AMP and whether the AMR was valid for the site-specific conditions.
 
Note E indicates that the AMR line item is consistent with the GALL Report for material, environment, and aging effect, but credits a different AMP or NUREG-1801 identifies a
 
plant specific aging management program. The staff audited these line items to verify
 
consistency with the GALL Report. The staff also determined whether the credited AMP
 
would manage the aging effect consistently with the GALL Report AMP and whether the
 
AMR was valid for the site-specific conditions.
 
3-344 3.3.2.1.1  AMR Results Identified as Not Applicable
 
In LRA Table 3.3.1, the staff identified items 41, 42, 53, 54, 71, 75, 81, 87, and 95 as "Not
 
Applicable" since the component/material/environm ent combination does not exist or is not within the scope of license renewal at VEGP. For each of these line items, the staff
 
reviewed the LRA and the applicant's supporting license renewal basis documents, and
 
confirmed the applicant's claim that the co mponent/material/environment combination does not exist at VEGP. On the basis that VEGP does not have the
 
component/material/environment combination for these Table 1 line items, the staff finds
 
that these AMRs are not applicable to VEGP.
 
In LRA Table 3.3.1, the staff identified items 40, 60, 65, 66, 67, 80, and 86 as "not used"
 
since the component/material/environment co mbination is addressed by another Table 1 line item. For each of these line items, the staff reviewed the LRA and license renewal
 
basis document and confirmed that the line item was not used in the LRA. In addition, the
 
staff confirmed that the aging effects addre ssed by these line items were addressed by other appropriate Table 1 AMR line items. On this basis, the staff finds the applicant's
 
identification of these Table 1 AMR line items as "not used" acceptable.
3.3.2.1.2  Loss of Material Due to Pitting and Crevice Corrosion In LRA Table 3.3.2-11 and Table 3.3.2-14, the applicant provides a number of AMR items
 
on loss of material in copper alloy auxiliary building or fuel handling building ventilation
 
system component cooling coil components t hat are exposed to an air-indoor (exterior) (condensation) environment. During the audit and review, the staff noted that the applicant
 
had aligned these AMR items to either GALL AMR Item VII.F1-16 or Item VII.F2-14 under
 
NEI 95-10 formatting Note B. The staff also noted the applicant credited its External
 
Surfaces Monitoring Program to manage loss of material in these components. GALL AMR
 
Item VII.F1-16, recommends that a plant-specific AMP be evaluated and credited to
 
manage this aging effect. The staff asked the applicant to explain why a Note B is shown, consistent with the GALL Report with AMP exceptions, instead of Note E; the GALL Report
 
identifies a plant-specific AMP. 
 
In its response dated February 8, 2008, the applicant stated that Note B for the specified
 
AMR items on these component cooling coil components should be designated as a Note E
 
and that Note E is appropriate because the GALL AMR items VII.F1-16 or Item VII.F2-14
 
that aligns with these AMR items identify that a plant-specific AMP be credited for aging
 
management, while the AMP credited in the LRA, External Surfaces Monitoring Program, is a GALL Report-based AMP with exceptions tak en in the program elements for the AMP.
The applicant stated that since a different AMP is credited while the material, environment
 
and aging effect are consistent with the GALL Report, a Note E should have been specified
 
instead of a Note B. The applicant stated that the LRA line item for this component will be
 
amended to change the note from a B to an E. The staff confirmed that the applicant
 
revised the LRA in a letter dated March 20, 2008.
 
The staff verified that the External Surfaces Monitoring Program is an applicable AMP to
 
credit for managing loss of material due to general, pitting, and crevice corrosion in the
 
external surfaces of metallic components that are susceptible to oxidation (corrosion) in
 
uncontrolled air environments, including those t hat may expose the components to external condensation. The staff finds the applicant's response acceptable because the LRA AMR
 
items for these components have been amended to reflect alignment under NEI 95-10 Note 3-345 format E instead of B and because the External Surface Monitoring Program is an acceptable program to credit for management of loss of material due to general, pitting and
 
crevice corrosion in the external surfaces of metallic components that are exposed to
 
uncontrolled air environments. The staff provides it s evaluation of the ability of the External Surfaces Monitoring Program to manage loss of material due to general, pitting, and
 
crevice corrosion in SER Section3.0.3.2.5.   
 
In LRA Table 3.3.1, Item 3.3.1-25, and in LRA Tables 3.3.2-5, 3.3.2-10, 3.3.2-11, 3.3.2-12, 3.3.2-13, and 3.3.2-14, the applicant includes a number of AMRs on management of loss of
 
material of copper alloy HVAC piping, piping components and piping elements in the
 
containment spray, emergency core cooling, component cooling water, chemical and
 
volume control and boron recycle, control building ventilation, auxiliary ventilation, containment building ventilation and fuel handling building ventilation systems under exposure to an external condensation environm ent. In these AMRs, the applicant credits either the External Surfaces Monitoring Program or Piping and Duct Internal Inspection
 
Program to manage loss of material. During the audit and review, the staff noted that the
 
Type "2" AMR items pointing to LRA Table 3.3.1, AMR Item 3.3.1-25 identified these AMRs
 
as being consistent with GALL under Note E. The staff also noted that the applicant had
 
aligned some of the AMRs on copper alloy HVAC piping, piping components, and piping
 
elements in the containment spray system and the emergency core cooling systems (as described in LRA Tables 3.2.2.-1 and 3.2.2-2 for emergency safety feature components) to
 
LRA AMR Item 3.3.1-25 and that, like AMR counter parts for the some of auxiliary system HVAC components, the applicant credited the Piping and Duct Internal Inspection Program
 
to manage loss of material in these emergency safety feature HVAC components. 
 
The staff reviewed the AMR result items referring to Note E and determined that the
 
component type, material, environment, and aging effect are consistent with those of the
 
corresponding line of the GALL Report. 
 
However, where the GALL Report recommends a plant-specific AMP, the applicant
 
proposed the External Surfaces Monitoring Program or the Piping and Duct Internal
 
Inspection Program, which are GALL-based AMPs for the VEGP LRA. 
 
The staff verified that the VEGP External Surfaces Monitoring Program is a new program
 
that inspects external surfaces of mechanical system components requiring aging
 
management for license renewal in external ai r environments. Surfaces constructed from materials susceptible to aging in these environments are inspected at frequencies that
 
assure the effects of aging are managed such that system components will perform their intended function during the period of extended operation. The program will be a monitoring
 
program, which manages aging effects through periodic visual inspections of external
 
surfaces of components such as piping, piping components, ducting, and other components
 
for evidence of material loss. On the basis of the periodic visual inspections of the piping, piping components, ducting, and other components to detect loss of material, the staff finds
 
the applicant's use of the External Surfaces Monitoring Program acceptable.
 
The VEGP Piping and Duct Inspection Program is a new program that will manage
 
corrosion of steel, stainless steel, and copper alloy components. Components included
 
within the scope of this program are not addressed by other VEGP aging management
 
programs. The VEGP Piping and Duct Internal Inspection Program will monitor not only
 
component surfaces through visual inspection, but may also use non-visual techniques to monitor parameters such as wall thickness and elasticity. On the basis of the periodic visual 3-346 and non-visual technique inspections of the piping, piping components, ducting, and other components to detect loss of material, the staff finds the applicant's use of the Piping and
 
Duct Inspection Program acceptable. 
 
On the basis of its review of the AMR result items as described in the preceding paragraphs
 
and its comparison of the applicant's results to corresponding recommendations in the
 
GALL Report, the staff finds that the applicant addressed the aging effect or mechanism
 
appropriately as recommended by the GALL Report.
The staff's evaluations of the External Surfaces Monitoring Program and Piping and Duct Internal Inspection Program are
 
documented in SER Sections 3.0.3.2.5 and 3.0.3.2.13, respectively.
 
3.3.2.1.3  Loss of Material Due to General, Pitting, and Crevice Corrosion In Closure
 
Bolting
 
LRA Table 3.3.1, AMR items 3.3.1-43 and 3.3.1-44 provide the applicant's AMRs on
 
management of loss of material due general, pitting and crevice corrosion in miscellaneous
 
steel auxiliary system closure bolts that ar e exposed to either, uncontrolled indoor air, outdoor air, or condensation environments. In these AMRs, the applicant credits its Bolting
 
Integrity Program to manage loss of material due to general, pitting, and crevice corrosion
 
in the bolts. During the audit and review, the staff noted that the Type "2" AMR items
 
pointing to LRA Table 3.3.1, AMR items 3.3.1-43 and 3.3.1-44 identified these AMRs as
 
being consistent with GALL under Note E. 
 
The corresponding AMR items in the GALL Report are AMR items 43 and 44 in Table 3 of the GALL Report, Volume 1. The GALL Report recommends using GALL AMP XI.M.18, "Bolting Integrity," to manage loss of material in these bolting components. The staff
 
reviewed the AMR result items referring to Note E and determined that the component type, material, environment, and aging effect are consistent with those recommended in the
 
corresponding AMR items in the GALL Report. The staff noted that the applicant's Bolting
 
Integrity Program is a plant-specific program for the LRA. 
 
The staff verified that the scope of the applicant's Bolting Integrity Program is credited to
 
manage cracking, loss of material, and loss of preload both safety-related and nonsafety-
 
related closure bolting for pressure-retaining components within the scope of license
 
renewal, with the exception of the reactor vessel head studs which are managed in
 
accordance with the applicant's Reactor Vessel Head Closure Stud Program. The staff's
 
evaluation of the Bolting Integrity Program is documented in SER Section 3.0.3.3.2. The
 
staff's evaluation of the Bolting Integrity includes an assessment of ability of the program
 
elements to manage aging consistent with the staff's recommended criteria for AMP
 
program elements in Section A.2.1.3 of NRC Branch Position No. RLSB-1 (i.e., in Appendix
 
A of the SRP-LR [NUREG-1800, Revision 1]).
 
LRA Table 3.3.1, AMR Item 3.3.1-55 provides the applicant's AMR on management of loss
 
of material due general, pitting and crevice corrosion in ducting (HVAC) closure bolts that
 
are exposed to uncontrolled indoor air. In this AMR, the applicant credits its Bolting Integrity
 
Program to manage loss of material in the closure bolts. During the audit and review, the
 
staff noted that the Type "2" AMR items pointing to LRA Table 3.3.1, Item 3.3.1-55
 
identified the AMRs as being consistent with GALL under Note E. 
 
The corresponding GALL AMR Item is AMR Item 55 in Table 3 of the GALL Report, Volume
: 1. The staff reviewed the applicant's AMR item and noted that the component type, 3-347 material, environment, and aging effect are consistent with those described in the corresponding AMR item in the GALL Report. However, the staff also noted that the GALL Report recommends that GALL AMP XI.M36, "External Surfaces Monitoring," be credited
 
for aging management whereas the applicant has credited its Bolting Integrity Program, which is a plant-specific program for the LRA. The staff evaluation of the Bolting Integrity
 
Program is documented in SER Section 3.0.3.3.2.
 
The staff verified that the applicant's Bolting Integrity Program is credited to manage
 
cracking, loss of material, and loss of preload both safety-related and nonsafety-related
 
closure bolting for pressure-retaining components within the scope of license renewal, with
 
the exception of the reactor vessel head studs which are managed in accordance with the
 
applicant's Reactor Vessel Head Closure Stud Program. The staff's evaluation of the
 
Bolting Integrity Program is documented in SER Section 3.0.3.3.2. The staff's evaluation of
 
the Bolting Integrity includes an assessment of ability of the program elements to manage
 
aging consistent with the staff's recommended criteria for AMP program elements in
 
Section A.2.1.3 of NRC Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR
 
[NUREG-1800, Revision 1]). Based on this review, the staff finds that it is acceptable to
 
credit the Bolting Integrity Program as an alternative program to manage loss of material in
 
these steel duct bolting components.
 
On the basis of its review of the AMR result items as described in the preceding paragraphs
 
and its comparison of the applicant's results to corresponding recommendations in the
 
GALL Report, the staff finds that the applicant appropriately addressed the aging effects or
 
mechanisms as recommended by the GALL Report.
 
3.3.2.1.4  Loss of Preload Due to Thermal Effects, Gasket Creep, and Self-loosening In
 
Bolting Components
 
LRA Table 3.3.1, AMR Item 3.3.1-45 provides the applicant's AMR on management of loss
 
of preload in miscellaneous auxiliary system steel closure bolting under exposure to uncontrolled indoor air. In this AMR, the applicant credits its Bolting Integrity Program to
 
manage loss of preload in the bolting components. During the audit and review, the staff
 
noted that the Type "2" AMR items pointing to LRA Table 3.3.1, Item 3.3.1-45 identified
 
these AMRs as being consistent with GALL under Note E. 
 
The corresponding GALL AMR item is AMR Item 45 in Table 3 of the GALL Report, Volume
: 1. In this AMR, the GALL Report recommends using GALL AMP XI.M18, "Bolting Integrity,"
 
to manage loss of preload in the bolting components. The staff reviewed the AMR result
 
items referring to Note E and determined that the component type, material, environment, and aging effect are consistent with those of the corresponding line of the GALL Report.
 
The staff also noted that, although the applicant credited its Bolting Integrity Program, the
 
Bolting Integrity Program is a plant-specific program for the LRA. 
 
The staff verified that the applicant's Bolting Integrity Program is credited to manage
 
cracking, loss of material, and loss of preload both safety-related and nonsafety-related
 
closure bolting for pressure-retaining components within the scope of license renewal, with
 
the exception of the reactor vessel head studs which are managed in accordance with the
 
applicant's Reactor Vessel Head Closure Stud Program. The staff's evaluation of the
 
Bolting Integrity Program is documented in SER Section 3.0.3.3.2. The staff's evaluation of
 
the Bolting Integrity Program includes an assessment of ability of the program elements to
 
manage aging consistent with the staff's re commended criteria for AMP program elements 3-348 in Section A.2.1.3 of NRC Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR
[NUREG-1800, Revision 1]). 
 
On the basis of its review of the AMR result item as described in the preceding paragraphs
 
and its comparison of the applicant's results to corresponding recommendations in the
 
GALL Report, the staff finds that the applicant appropriately addressed the aging effect or
 
mechanism as recommended by the GALL Report.
 
3.3.2.1.5  Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion 
 
During the audit and review, the staff noted that LRA Table 3.3.2-10 includes an AMR item
 
on management of loss of material due to pitting, crevice, and galvanic corrosion in
 
stainless steel normal charging pump motor cooler tubesheets for the surfaces that are
 
exposed to closed-cycle cooling water. In this AMR, the staff noted that the applicant
 
credited its Closed-Cycle Cooling Water Program to manage loss of material in these
 
stainless steel components. The staff noted that the applicant aligned this Type "2" AMR
 
item to GALL AMR Item VII.E1-2 and to LRA AMR Item 3.3.1-51, which pertain to the
 
management of loss material in copper alloy piping, piping component, piping elements, and heat exchanger components that are ex posed to the same environment. The GALL AMR recommends that the AMP XI.M21, "Clos ed-Cycle Cooling Water System Program,"
be credited to manage loss of material due to pitting, crevice and galvanic corrosion in the
 
copper alloy component surfaces that are exposed to closed cycle cooling water.
 
The staff asked the applicant to explain why the aging management program in the AMR
 
item associated with the GALL AMR Item VII.E1-2 is appropriate to manage loss of material
 
due to pitting, crevice, and galvanic corrosion in these stainless steel components. 
 
In its response dated February 8, 2008, the applicant stated that the Type "2" AMR item in
 
LRA Table 3.3.2-10 for the CVCS normal charging pump motor cooler tubesheets
 
incorrectly aligned the AMR item to LRA Table 3.3.1 AMR Item 3.3.1-51 and to GALL AMR
 
VII.E1-2. The applicant stated that, since the component is made of stainless steel and not
 
copper alloy, the AMR item should have been aligned to LRA Table 3.2.1 AMR Item 3.2.1-
 
28 and to GALL AMR Item V.D1-4. The applicant stated that the LRA line item for this
 
component in Table 3.3.2-10 will be amended to reflect alignment to LRA Table 3.2.1 AMR
 
Item 3.2.1-28 and to GALL AMR Item V.D1-4. The applicant also stated that this change is
 
administrative and does not alter the AMP (i.e
., the Closed-Cycle Cooling Water Program) that is credited to manage loss of material in the component surfaces that are exposed to
 
closed-cycle cooling water.
 
The staff confirmed that the applicant made the applicable amendment of the LRA in a
 
letter dated March 20, 2008. The staff also reviewed the recommendations in GALL AMR
 
V.D1-4 and verified that, like the recommendation in GALL AMR VII.E1-2 for copper alloy
 
components, GALL AMR V.D1-4 recommends that GALL AMP XI.M21, "Closed-Cycle Cooling Water System," be credited to manage loss of material due to corrosion effects in
 
stainless steel heat exchanger component surfaces that are exposed to close-cycle cooling water. Based on this review, the staff finds that the change in the LRA is an administrative
 
change of the application and that the applicant has provided an acceptable basis for
 
crediting the Closed-Cycle Cooling Water Program for these stainless steel components.
 
The staff's question on this matter is resolved.
 
On the basis of its review of the AMR result item as described in the preceding paragraphs 3-349 and its comparison of the applicant's results to corresponding recommendations in the GALL Report, the staff finds that the applicant appropriately addressed the aging effect or
 
mechanism as recommended by the GALL Report.
3.3.2.1.6  Loss of Material Due to General, Pitting, and Crevice Corrosion 
 
LRA Table 3.3.1, AMR Item 3.3.1-64 provides the applicant's AMR for managing loss of
 
material of steel auxiliary system piping, piping components, and piping elements that are exposed to fuel oil. In this AMR, the applicant credited its Fire Protection Program and Fuel
 
Oil Chemistry Program to manage loss of ma terial due to general, pitting, and crevice corrosion in component surfaces that are exposed to fuel oil. During the audit and review, the staff noted the Type "2" AMR result items pointing LRA Table 3.3.1, Item 3.3.1-64
 
identified these AMRs as being consistent with GALL under Note E. 
 
The corresponding GALL AMR items are AMR Item 64 in Table 3 of the GALL Report, Volume 1 and AMR Item VII.G-21 in the GALL Report Volume 2 (GALL AMR VII.G-21).
These GALL AMRs recommend that GALL AMP XI.M26, "Fire Protection," and GALL AMP XI.M30, "Fuel Oil Chemistry," be credited to manage loss of material due to general, pitting, and crevice corrosion in the components surfaces that are exposed to fuel oil.
 
The staff reviewed the AMR result items referring to Note E and verified that the component
 
type, material, environment, and aging effect are consistent with the corresponding AMR
 
items in the GALL Report. The staff also verified that the applicant credited its Diesel Fuel
 
Oil Program and its Fire Protection Program to manage loss of material in the component surfaces that are exposed to fuel oil. The staff verified that the applicant's Fire Protection
 
Program is an existing AMP that is consistent with the recommendations in both GALL AMP XI.M26, "Fire Protection," and GALL AMP XI.M27, "Fire Water System," and that the
 
program includes an exception to GALL and thr ee enhancements of the program in order to make it consistent with the program elements in the GALL. The staff also verified that the
 
scope of the AMP includes the fuel oil delivery lines for both the diesel driven fire pumps
 
and emergency diesel generators. The staff's evaluation of the applicant's Fire Protection
 
Program is described in SER Section 3.0.3.2.6. The staff's evaluation of Fire Protection
 
Program includes an assessment of the abilit y of the program elements to manage aging consistent with the program element recommendations in the corresponding GALL AMPs
 
and of the exception and enhancements taken in the AMP. Based on this review, the staff
 
finds that the applicant has created a valid basis for crediting its Fire Protection Program to
 
manage loss of material in the fuel oil delivery lines to the diesel-driven fire protection
 
pumps under exposure to the diesel fuel oil environment.
 
The staff noted that the applicant's Diesel Fuel Oil Program is an existing plant-specific
 
program for the VEGP LRA. The staff verified that the applicant credits it Diesel Fuel Oil
 
Program to manage loss of material in the plant components that are exposed to diesel fuel
 
oil and that the scope of the AMP includes the diesel fuel oil delivery systems for both the
 
emergency diesel generators and the diesel engine-driven fire water pumps. With respect
 
to the AMP's program elements regarding the fuel oil delivery lines to the diesel-driven fire protection pumps the staff specifically verified that the VEGP Diesel Fuel Oil Program
 
manages loss of material in the delivery lines through the visual inspections performed in
 
accordance with the applicant's Fire Protection Program. The staff's evaluation of the
 
applicant's Diesel Fuel Oil Program is described in SER Section 3.0.3.2.6. The staff's
 
evaluation of the Diesel Fuel Oil Program includes an assessment of the ability of the
 
program elements to manage aging consistent with the staff's recommended criteria for 3-350 AMP program elements in Section A.2.1.3 of NRC Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision 1]). Based on this review, the staff
 
finds that the applicant has created a valid basis for crediting its Diesel Fuel Oil Program to
 
manage loss of material in the component surfaces that are exposed to the diesel fuel oil
 
environment. 
 
On the basis of its review of the AMR result items as described in the preceding paragraphs
 
and its comparison of the applicant's results to corresponding recommendations in the
 
GALL Report, the staff finds that the applicant appropriately addressed the aging effect or
 
mechanism as recommended by the GALL Report.
3.3.2.1.7 Loss of Material Due to General Corrosion
 
LRA Table 3.3.1, Item 3.3.1-73 provides the applicant's AMR for managing loss of material
 
of steel crane structural girders in load handling system under exposure to an uncontrolled
 
indoor air environment. In the AMR, the applicant credits its Overhead and Refueling Crane
 
Inspection Program to manage loss of material due to general corrosion in these girders.
 
During the audit and review, the staff noted the Type "2" AMR items pointing LRA Table
 
3.3.1, Item 3.3.1-73 were designated as being consistent with GALL under Note E. 
 
The corresponding GALL AMR items are AMR Item 73 in Table 3 of the GALL Report, Volume 1 and AMR Item VII.B-3 in the GALL Report Volume 2 (GALL AMR VII.B-3). These GALL AMRs recommend that GALL AMP XI.M23, "Inspection of Overhead Heavy Load and
 
Light Load (Related to Refueling) Handling Systems," be credited to manage loss of
 
material due to general corrosion in the girder surfaces that are exposed to uncontrolled
 
indoor air.
 
The staff reviewed the AMR result items referring to Note E and determined that the
 
component type, material, environment, and aging effect are consistent with those of the
 
corresponding line of the GALL Report. The staff verified that, consistent with the AMR
 
recommendations in GALL, the applicant credited its Overhead and Refueling Crane
 
Inspection Program to manage loss of material in the girder surfaces that are exposed to
 
uncontrolled indoor. The staff verified that the Overhead and Refueling Crane Inspection
 
Program is identified as an AMP that is entirely consistent with the program elements recommended in GALL AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems," without exception, and that the scope of the
 
applicant's program includes the crane bridge and trolley structural girders and beams and
 
the crane rails and support girders within the scope of license renewal. The staff's
 
evaluation of the Overhead and Refueling Crane Inspection Program is documented in SER
 
Section 3.0.3.1.3. The staff's evaluation of Overhead and Refueling Crane Inspection
 
Program includes an assessment of the abilit y of the program elements to manage aging consistent with the program element recommendations in GALL AMP XI.M23. Based on
 
this review, the staff finds that the applicant has created a valid basis for crediting its
 
Overhead and Refueling Crane Inspection Program to manage loss of material in these
 
crane girders.
 
On the basis of its review of the AMR result items as described in the preceding paragraphs
 
and its comparison of the applicant's results to corresponding recommendations in the
 
GALL Report, the staff finds that the applicant appropriately addressed the aging effect or
 
mechanism as recommended by the GALL Report.
 
3-351 3.3.2.1.8 Loss of Material Due to Pitting and Crevice Corrosion
 
LRA Table 3.3.1, Item 3.3.1-79 provides the applicant's AMR for managing loss of material
 
due to pitting corrosion, crevice corrosion or fouling in stainless steel piping, piping
 
components, piping elements, and system strainers in the turbine plant cooling water
 
system under exposure to the raw water environment of the river water. In this AMR, the applicant credited its Piping and Duct Internal Inspection Program to manage loss of
 
material in the component surfaces that are exposed internally to the river water. During the
 
audit and review, the staff noted that the Type "2" AMR items pointing to LRA Table 3.3.1, Item 3.3.1-79 were designated as being consistent with GALL under Note E.
 
The corresponding GALL AMR items are AMR Item 79 in Table 3 of the GALL Report, Volume 1 and AMR Item VII.C1-15 in the GALL Report Volume 2 (GALL AMR VII.C1-15).
 
These GALL AMRs recommend that GALL AMP XI.M20, "Open-Cycle Cooling Water System," be credited to manage loss of material due to pitting corrosion, crevice corrosion
 
or fouling in the piping, piping component, and piping element surfaces that are exposed to
 
the raw water environment.
 
The staff reviewed the Type "2" AMR items referring to Note E and determined that the
 
component type, material, environment, and aging effect are consistent with those of the
 
corresponding line of the GALL Report. However, the staff noted that, while the GALL Report recommends GALL AMP XI.M20, "Open-Cycle Cooling Water System," the applicant credited its Piping and Duct Internal Inspection Program to manage loss of
 
material in these stainless steel piping components. 
 
The staff verified that the applicant's Piping and Duct Internal Inspection Program is a new
 
program for managing, in part, loss of material due to pitting corrosion in internal surfaces
 
of piping and duct components that are not addressed by other aging management
 
programs. The staff verified that the program has been identified as an AMP that is consistent with program elements in GALL AMP XI.M38, "Inspection of Internal Surfaces in
 
Miscellaneous Piping and Ducting Components, with exceptions. The staff also verified that like GALL AMP XI.M20, "Open-Cycle Cooling Wa ter System," the scope of the applicant's program, in part, credits visual examinations to manage corrosion in the internal surfaces of
 
stainless steel piping components that are exposed internally to raw water. The staff also
 
verified that the applicant has addressed the need to implement this AMP in accordance
 
with LRA Commitment No. 19, which was placed on UFSAR Supplement Section A.2.22
 
and provided in the applicant's letter of March 20, 2008. The staff's evaluation of the Piping
 
and Duct Internal Inspection Program is documented in SER Section 3.0.3.2.13. The staff's
 
evaluation of Piping and Duct Internal Inspection Program includes an assessment of the
 
ability of the program elements to manage aging consistent with the program element recommendations in GALL AMP XI.M38 and of the exceptions taken in the AMP and the
 
enhancement of the program to include LRA Commitment No. 19. The staff's evaluation of
 
the Piping and Duct Internal Inspection Program also includes the staff's resolution of RAI
 
3.3-1/3.4-1 on justification for crediting programs like the Piping and Duct Internal
 
Inspection Program and the External Surfac es Monitoring Program to manage cracking and changes in material properties for polymer or elastomer components. However, the staff
 
noted this RAI is not relevant to the assessment of this AMR because it pertains to
 
management of loss of material in stainless steel piping components. 
 
Based on this review, the staff finds that the applicant has created a valid basis for crediting
 
its Piping and Duct Internal Inspection Program to manage loss of material in the stainless 3-352 steel piping components that are exposed to raw water. On the basis of its review of the AMR result items as described in the preceding paragraphs and its comparison of the
 
applicant's results to corresponding recommendations in the GALL Report, the staff also
 
finds that the applicant addressed the aging effect or mechanism appropriately as
 
recommended by the GALL Report.
 
3.3.2.1.9  Loss of Material Due to Pitting, Crevice, Galvanic, and Microbiologically
 
Influenced Corrosion, and Fouling
 
LRA Table 3.3.1, Item 3.3.1-82 provides the applicant's AMR for managing loss of material
 
in the copper alloy steam generator blowdown corrosion product monitor cooler shells and
 
heads under exposure to an internal a raw water (river water) environment. In the AMR, the
 
applicant credited its Periodic Surveillance and Preventive Maintenance Activities Program.
 
During the audit and review, the staff noted that the Type "2" AMR item pointing to LRA
 
Table 3.3.1, Item 3.3.1-82 was designated as being consistent with GALL under Note E.
 
The corresponding GALL AMR items are AMR Item 82 in Table 3 of the GALL Report, Volume 1 and AMR Item VII.C1-3 in the GALL Report Volume 2 (GALL AMR VII.C1-3).
 
These GALL AMRs recommend that GALL AMP XI.M20, "Open-Cycle Cooling Water System," be credited to manage loss of material due to pitting corrosion, crevice corrosion, galvanic corrosion, microbiologically-influenced corrosion, or fouling in copper alloy heat
 
exchanger surfaces in the service water system that are exposed to a raw water
 
environment.
 
The staff reviewed the AMR result item referring to Note E and determined that the
 
component type, material, environment, and aging effect are consistent with those of the
 
corresponding line of the GALL Report. However, the staff noted that, while the GALL Report recommends GALL AMP XI.M20, "Open-Cycle Cooling Water System," the applicant credited its Periodic Surveillance and Preventive Maintenance Activities Program
 
to manage loss of material in these corrosion product monitor shells and heads. The staff's
 
evaluation of the Periodic Surveillance and Preventive Maintenance Activities Program is
 
documented in SER Section 3.0.3.3.6. 
 
The staff verified that the applicant's Periodic Surveillance and Preventive Maintenance
 
Activities is an existing program that credited both existing and new periodic inspections
 
and tests to manage the aging effects applicable to the components included in the
 
program. The staff verified that the steam generator blowdown corrosion product monitor
 
coolers are within the scope of the applicant's Periodic Surveillance and Preventive
 
Maintenance Activities Program and that the Periodic Surveillance and Preventive
 
Maintenance Activities Program credits eit her visual examinations or non-visual examination techniques to monitor for corrosion or fouling that occur in these components.
 
The staff also verified that these corrosion product monitor coolers are cooled by raw water, but not by raw water that is categorized as essential service water (i.e, nuclear cooling
 
service water) and thus, are not within the scope of the applicant's Generic Letter 89-13 Program (which is the applicant's counterpart to GALL AMP XI.M20). The staff finds this to
 
be an acceptable approach to aging management because the methods are consistent with those recommended in GALL AMP XI.M20, and because the steam generator blowdown
 
corrosion product monitor coolers are not within the scope of the applicant's Generic Letter
 
89-13 Program. 
 
The staff's evaluation of the Periodic Surveillance and Preventive Maintenance Activities 3-353 Program is documented in SER Section 3.0.3.3.6. The staff's evaluation of the Periodic Surveillance and Preventive Maintenance Activiti es Program includes an assessment of the ability of the program elements to manage aging consistent with the staff's recommended
 
criteria for AMP program elements in Section A.2.1.3 of NRC Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision 1]). Based on this review, the
 
staff finds that the applicant has created a valid basis for crediting its Periodic Surveillance
 
and Preventive Maintenance Activities Program to manage loss of material in the steam
 
generator blowdown corrosion product monitor cooler heads and shells that are exposed to
 
the raw water environment. 
 
On the basis of its review of the AMR result items as described in the preceding paragraphs
 
and its comparison of the applicant's results to corresponding recommendations in the
 
GALL Report, the staff finds that the applicant addressed the aging effect or mechanism
 
appropriately as recommended by the GALL Report.
 
3.3.2.1.10  Loss of Material Due to General, Pitting, Crevice, and Microbiologically
 
Influenced Corrosion, Fouling, and Lining/Coating Degradation
 
LRA Table 3.3.1, Item 3.3.1-76 provides the applicants AMR for managing loss of material
 
for steel piping, piping components, and piping elements (without lining/coating or with
 
degraded lining/coating) in the nuclear service water cooling, turbine plant cooling water
 
system, river intake structure system, potable and utility water systems, and sampling systems under exposure to an internal raw wate r - river water environment. In these AMRs, the applicant credits its Piping and Duct Internal Inspection Program to manage loss of
 
material due to general corrosion, pitting corrosion, crevice corrosion, galvanic corrosion, microbiologically-influenced corrosion, fouling, or coating degradation. During the audit and
 
review, the staff noted that the Type "2" AMR items pointing to LRA Table 3.3.1, Item 3.3.1-
 
76 designated that the AMRs are consistent with GALL under Note E.
 
The corresponding GALL AMR items are AMR Item 76 in Table 3 of the GALL Report, Volume 1 and AMR Item VII.C1-19, VII.C3-10, and VII.H2-22 in the GALL Report Volume 2 (GALL AMRs VII.C1-19, VII.C3-10, and V II.H2-22). These GALL AMRs recommend that GALL AMP XI.M20, "Open-Cycle Cooling Wate r System," be credited to manage loss of material due to general corrosion, pitting corrosion, crevice corrosion, galvanic corrosion, microbiologically-influenced corrosion, fouling, or coating degradation in piping, piping
 
component, and piping element surfaces (with interior liners/coatings or with degraded
 
liners/coatings) that are exposed to a raw water environment.
 
The staff reviewed the AMR result items referring to Note E and determined that the
 
component type, material, environment, and aging effect are consistent with those of the
 
corresponding line of the GALL Report. However, the staff notes that, where the GALL Report recommends GALL AMP XI.M20, "Open-Cycle Cooling Water System," the applicant credited its Piping and Duct Internal Inspection Program to manage the loss of
 
material in the steel component surfaces that are exposed internally to a raw water
 
environment. The staff's evaluation of the Piping and Duct Internal Inspection Program is
 
documented in SER Section 3.0.3.2.13. 
 
The staff verified that the applicant's Piping and Duct Internal Inspection Program is a new
 
program for managing, in part, loss of material due to pitting corrosion in internal surfaces
 
of piping and duct components that are not addressed by other aging management
 
programs. The staff verified that the program has been identified as an AMP that is 3-354 consistent with program elements in GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, with exceptions. The staff also verified that like GALL AMP XI.M20, "Open-Cycle Cooling Wa ter System," the scope of the applicant's program, in part, credits visual examinations to manage corrosion in the internal surfaces of
 
stainless steel piping components that are exposed internally to raw water. The staff also
 
verified that the applicant has addressed the need to implement this AMP in accordance
 
with LRA Commitment No. 19, which was placed on UFSAR Supplement Section A.2.22
 
and provided in the applicant's letter of March 20, 2008. The staff's evaluation of the Piping
 
and Duct Internal Inspection Program is documented in SER Section 3.0.3.2.13. The staff's
 
evaluation of Piping and Duct Internal Inspection Program includes an assessment of the
 
ability of the program elements to manage aging consistent with the program element recommendations in GALL AMP XI.M38 and of the exceptions taken in the AMP and the
 
enhancement of the program to include LRA Commitment No. 19. The staff's evaluation of
 
the Piping and Duct Internal Inspection Program also includes the staff's resolution of RAI
 
3.3-1/3.4-1 on justification for crediting programs like the Piping and Duct Internal
 
Inspection Program and the External Surfac es Monitoring Program to manage cracking and changes in material properties for polymer or elastomer components. 
 
However, the staff noted this RAI is not relevant to the assessment of this AMR because it
 
pertains to management of loss of material in steel piping, piping components, and piping
 
elements. 
 
On the basis of its review of the AMR result items as described in the preceding paragraphs
 
and its comparison of the applicant's results to corresponding recommendations in the
 
GALL Report, the staff finds that the applicant addressed the aging effect or mechanism
 
appropriately as recommended by the GALL Report.
 
3.3.2.1.11  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 loss of material due to wear in elastomer seals and
 
components exposed to an air - indoor (uncontrolled) environment as an aging effect not
 
applicable because auxiliary systems AMR resu lts do not include elastomer seals exposed to any environment conducive to a loss of material due to wear. LRA Section 3.3.2.2.5
 
addresses aging management of elastomer degradation.
 
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 the aging effect is
 
adequately managed.
 
On the basis that VEGP does not have elastomer seals and components exposed to any
 
environment conductive to loss of material due to wear, the staff finds acceptable the
 
applicant's evaluation that this aging effect is not applicable to VEGP.
 
Based on the programs identified above, the staff concludes that the applicant has provided
 
an acceptable basis why the recommended criterion in SRP-LR Section 3.3.2.2.13 is not
 
applicable to the VEGP LRA.
 
3-355 3.3.2.1.12  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 loss of material due to cladding breach for steel charging
 
pump casings with stainless steel cladding exposed to borated water as an aging effect not
 
applicable because auxiliary system AMR result s do not include steel pump casings with stainless steel cladding exposed to borated water. VEGP normal charging pump casings
 
are fabricated from stainless steel, not clad carbon steel. 
 
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.
 
On the basis that VEGP does not have stainless steel clad pump casings exposed to any
 
environment conductive to loss of material due to wear, the staff finds acceptable the
 
applicant's evaluation that this aging effect is not applicable to VEGP.
 
Based on the programs identified above, the staff concludes that the applicant has provided
 
an acceptable basis why the recommended criterion in SRP-LR Section 3.3.2.2.14 is not
 
applicable to the VEGP LRA.
 
3.3.2.1.13  Quality Assurance for Aging Management of Nonsafety-Related Components 
 
SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.
 
The staff evaluated the applicant's claim of consistency with the GALL Report. The staff
 
also reviewed information pertaining to the applicant's consideration of recent operating
 
experience and proposals for managing aging effects. On the basis of its review, the staff
 
concludes that the AMR results, which the applicant claimed to be consistent with the GALL
 
Report, are indeed consistent with 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 their intended function(s) will be maintained consistent with
 
the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.3.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended In LRA Section 3.3.2.2, the applicant further evaluated aging management, as
 
recommended by the GALL Report, for the auxiliary systems co mponents and provided information concerning how it will manage the following aging effects:
 
cumulative fatigue damage reduction of heat transfer due to fouling cracking due to SCC cracking due to SCC and cyclic loading hardening and loss of strength due to elastomer degradation
 
3-356  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, and microbiologically-influenced corrosion and fouling loss of material due to pitting and crevice corrosion loss of material due to pitting, crevice, and galvanic corrosion loss of material due to pitting, crevice, and microbiologically-influenced corrosion loss of material due to wear loss of material due to cladding breach QA for aging management of nonsafety-related components For component groups evaluated in the GALL Report, for which the applicant claimed
 
consistency with the report and for which the report recommends further evaluation, the
 
staff audited and reviewed the applicant's evaluation to determine whether it adequately
 
addressed the issues further evaluated. In addition, the staff reviewed the applicant's
 
further evaluations against the criteria contained in SRP-LR Section 3.3.2.2.The staff's
 
review of the applicant's further evaluation follows.
 
3.3.2.2.1 Cumulative Fatigue Damage
 
SRP-LR Section 3.3.2.2.1 states that fatigue is a TLAA in accordance with the definition
 
criteria for a TLAA in 10 CFR 54.3 and is to be evaluated for acceptance in accordance with
 
the criteria that are described in 10 CFR 54.21(C)(1). 
 
In LRA Section 3.3.2.2.1, the applicant stated that load handling members subjected to
 
fatigue loading conditions such as crane runways are accounted for by design. The
 
applicant stated that crane use is limited and t he number of stress cycles experienced is low in terms of fatigue service life when considering the period of extended operation.
 
Based on this clarification, the applicant stated that potential fatigue of the cranes is not a
 
TLAA for the LRA.
 
On the basis that plant cranes are designed for a large number of stress cycles in industrial
 
use, and the actual use of cranes in a nuclear power plant is low in terms of fatigue service
 
when also considering the period of extended operation, the staff finds acceptable the
 
applicant's evaluation that no TLAA for fatigue of load handling components is required at
 
VEGP. 
 
In Section 3.3.2.2.1 of the LRA, the applicant did identify metal fatigue of the piping in the
 
auxiliary systems as an analysis that meets the definition of a TLAA in 10 CFR 54.3. The
 
staff verified that the applicant included this TLAA in LRA Section 4.3.2, which addresses
 
metal fatigue of non-ASME Code Class 1 piping system components. SER Section 4.3.2
 
documents the staff's review of the applicant's evaluation of this TLAA. 
 
3-357 Based on this review, the staff finds that the applicant has provided an acceptable basis for identifying those auxiliary system components t hat within the scope of the applicant's TLAA on metal fatigue for VEGP non-Class 1 piping components
 
3.3.2.2.2 Reduction of Heat Transfer Due to Fouling
 
In LRA Section 3.3.2.2.2, the applicant addresses reduction of heat transfer due to fouling
 
in stainless steel heat exchanger tubes exposed to treated water as an aging effect not
 
applicable to VEGP, a PWR plant. Applicable items are found only in BWR spent fuel
 
cooling and cleanup and reactor water cleanup systems.
 
SRP-LR Section 3.3.2.2.2 is the Section in NUREG-1800, Revision 1 that corresponds to
 
LRA Section 3.3.2.2.2. In SRP-LR Section 3.3.2.2.2, the staff states that reduction of heat
 
transfer due to fouling may occur in stainless steel heat exchanger tubes exposed to
 
treated water and that the existing program relies on control of water chemistry to manage
 
reduction of heat transfer due to fouling. However, the staff clarifies that control of water
 
chemistry may be inadequate and that as a result, the GALL Report recommends that the
 
effectiveness of the water chemistry control program should be verified to ensure that
 
reduction of heat transfer due to fouling is not occurring. The staff states that a one-time
 
inspection is an acceptable method to ensure that reduction of heat transfer is not occurring
 
and that the component's intended function will be maintained during the period of
 
extended operation.
 
The staff reviewed LRA Section 3.3.2.2.2 against the criteria in SRP-LR Section 3.3.2.2.2.
 
On the basis that the GALL Report Volume 2 items associated with this Table 1 line Item
 
3.3.1-3 apply to BWR plants only and the stainless steel heat exchanger tubes subject to
 
reduction of heat transfer due to fouling are associated with the BWR systems spent fuel
 
pool cooling and cleanup and reactor water cleanup, the staff finds acceptable the
 
applicant's evaluation that this aging effect is not applicable to VEGP, a PWR plant.
 
On the basis that VEGP does not have any components from this group, the staff finds that
 
this aging effect is not applicable to VEGP.
 
3.3.2.2.3 Cracking Due to Stress Corrosion Cracking 
 
The staff reviewed LRA Section 3.3.2.2.3 against the following criteria in SRP-LR
 
Section 3.3.2.2.3:
 
  (1) LRA Section 3.3.2.2.3 addresses cracking due to SCC in stainless steel piping, piping components, and piping elements of the BWR standby liquid control system
 
as an aging effect not applicable to VEGP, a PWR plant.
SRP-LR Section 3.3.2.2.3 states that cracking due to SCC could occur in the
 
stainless steel piping, piping components, and piping elements of the BWR standby
 
liquid control system that are exposed to sodium pentaborate solution greater than
 
60 &deg;C (140 &deg;F).
 
The staff noted that this line item is applicable to BWR standby liquid control system
 
piping and components and; therefore, not applicable because VEGP is a PWR.
3-358 On this basis, the staff finds that this aging effect is not applicable to this component type to VEGP, a PWR plant.
 
  (2) LRA Section 3.3.2.2.3 addresses cracking due to SCC in stainless steel and stainless clad steel heat exchanger components exposed to treated water greater
 
than 140 &deg;F in the BWR reactor coolant cleanup system as an aging effect not
 
applicable to VEGP, a PWR plant.
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 &deg;C (140 &deg;F).
The staff noted that this line item is applicable to BWR standby liquid control system
 
piping and components and; therefore, not applicable because VEGP is a PWR. On
 
this basis, the staff finds that this aging effect is not applicable to this component
 
type to VEGP, a PWR plant.
 
  (3) LRA Section 3.3.2.2.3 addresses cracking due to SCC that may occur in stainless steel diesel engine exhaust piping, piping components, and piping elements
 
exposed to diesel exhaust as an aging effect that the Piping and Duct Internal
 
Inspection Program will manage for stainless steel piping components.
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 the aging effect is adequately managed.
The staff noted that the plant-specific AMP proposed by the applicant is the Piping
 
and Duct Internal Inspection Program. The staff reviewed the Piping and Duct
 
Internal Inspection Program and determined that the aging effect of cracking will be
 
adequately managed by using visual inspection techniques to inspect representative
 
samples of diesel exhaust components. The staff's evaluation of the Piping and
 
Duct Internal Inspection Program is documented in SER Section 3.0.3.2.13. The
 
staff finds that this program includes activities that are adequate to manage cracking 
 
in stainless steel diesel engine exhaust piping, piping components, and piping
 
elements exposed to diesel exhaust.
 
On the basis of its review of the AMR result items as described in the preceding
 
paragraphs and its comparison of the applicant's results to corresponding
 
recommendations in the GALL Report, the staff finds that the applicant addressed
 
the aging effect or mechanism appropriately as recommended by the GALL Report.
 
Based on the programs identified above, the staff concludes that the applicant's 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 concludes 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).
 
3-359 3.3.2.2.4 Cracking Due to Stress Corrosion Cracking and Cyclic Loading
 
The staff reviewed LRA Section 3.3.2.2.4 against the following criteria in SRP-LR
 
Section 3.3.2.2.4:
 
  (1) LRA Section 3.3.2.2.4 addresses cracking due to SCC in stainless steel PWR nonregenerative heat exchanger components exposed to borated water greater
 
than 140 &deg;F as an aging effect to be managed by the Water Chemistry Control
 
Program and the One-Time Inspection Program.
SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may
 
occur in stainless steel PWR nonregenerative heat exchanger components exposed
 
to treated borated water greater than 60 &deg;C (140 &deg;F) 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.
The staff noted that the plant-specific AMP proposed by the applicant is the Water
 
Chemistry Program and verified with the One-Time Inspection Program. The staff
 
reviewed the Water Chemistry Program and the One-Time Inspection Program. The
 
staff concludes that the aging effects of cracking and cyclic loading will be
 
adequately managed by the Water Chemistry Program and its effectiveness will be adequately verified with the One-Time Inspection Program which specifies the
 
performance of internal inspections. The staff's evaluation of the Water Chemistry
 
Program is documented in SER Section 3.0.3.1.4. The staff's evaluation of the One-
 
Time Inspection Program is documented in SER Section 3.0.3.1.2. The staff finds
 
that these programs include activities are adequate to manage cracking and cyclic
 
loading in stainless steel PWR non-regenerative heat exchanger components
 
exposed to treated borated water.
 
On the basis of its review of the AMR result items as described in the preceding
 
paragraphs and its comparison of the applicant's results to corresponding
 
recommendations in the GALL Report, the staff finds that the applicant addressed
 
the aging effect or mechanism appropriately as recommended by the GALL Report.
 
(2) LRA Section 3.3.2.2.4 addresses cracking due to SCC in stainless steel PWR regenerative heat exchanger components exposed to borated water greater than
 
140 &deg;F as an aging effect to be managed by the Water Chemistry Control Program
 
and the One-Time Inspection Program.
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 60 &deg;C (140 &deg;F). 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 3-360 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.
The staff reviewed LRA Section 3.3.2.2.4 which credits the Water Chemistry Control
 
and the One-Time Inspection Programs in combination for managing cracking due
 
to SCC and cyclic loading of stainless steel regenerative heat exchanger
 
components. The staff concludes that the One-Time Inspection Program is being
 
used to verify the effectiveness of the Water Chemistry Control Program to manage cracking for stainless steel regenerative heat exchanger components. On the basis
 
of its review, the staff finds that the applicant has met the criteria of SRP-LR Section
 
3.3.2.2.4 by verifying the effectiveness of the Water Chemistry Control Program by one-time inspections.
 
LRA Table 3.3.1, Item 3.3.1-08, states that cracking of stainless steel regenerative
 
heat exchanger components in the emergency core cooling and chemical and
 
volume control and boron recycle systems exposed to treated borated water
 
(>140 &deg;F) is managed with a combination of the Water Chemistry Control and the
 
One-Time Inspection Programs. During the audit and review, the staff noted that the
 
AMR result items pointing to LRA Table 3.3.1, Item 3.3.1-08 refer to Note E.
 
The staff reviewed the AMR result items referring to Note E and determined that the
 
component type, material, environment, and aging effect are consistent with those
 
of the corresponding line of the GALL Report. The GALL Report recommends using a combination of GALL AMP XI.M2, "Water Chemistry" and a plant-specific
 
verification program. The applicant proposed using the Water Chemistry Control Program, which is consistent with GALL AMP XI.M2, with the One-Time Inspection
 
Program as the verification program. The staff evaluations of the Water Chemistry
 
Control and One-Time Inspection Programs are documented in SER Sections
 
3.0.3.1.4 and 3.0.3.1.2, respectively.
 
The One-Time Inspection Program uses one-time inspections to verify the
 
effectiveness of the Water Chemistry Control Program. The staff confirmed that the
 
emergency core cooling and chemical and volume control and boron recycle
 
systems are included within the scope of the One-Time Inspection Program to verify the effectiveness of the Water Chemistry Control Program to manage cracking. On
 
the basis of the use of the one-time visual inspections in these systems, the staff
 
finds the applicant's use of the Water Chemistry Control Program and One-Time
 
Inspection Program to be acceptable because it is conformance with the SRP-LR
 
and the GALL Report. 
 
On the basis of its review of the AMR result items as described in the preceding
 
paragraphs and its comparison of the applicant's results to corresponding
 
recommendations in the GALL Report, the staff finds that the applicant addressed
 
the aging effect or mechanism appropriately as recommended by the GALL Report.
 
  (3) LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading in stainless steel high-pressure pump casings in a treated borated water environment
 
in the chemical and volume control system as an aging effect not applicable 3-361 because the high-pressure pumps in that sy stem operate at temperatures below the SCC threshold and because these pumps are centrifugal (not positive-
 
displacement) with no significant cyclic loading likely.
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 staff reviewed LRA Section 3.3.2.2.4 which states that cracking due to stress
 
corrosion cracking and cyclic loading is not applicable to VEGP stainless steel
 
high-pressure pump casings in a treated borated water environment in the chemical
 
volume and control system. The staff noted that the normal operating temperatures
 
for the VEGP stainless steel high pressure chemical volume and control system
 
pumps are less than 140 &deg;F. Thus, the operating temperature for these pump
 
casings is less than the temperature threshold for initiation of SCC in stainless steel materials in Section IX of the GALL Report, Volume 2. Further, the staff noted that
 
the pumps within the scope of license renewal are centrifugal pumps and are
 
therefore not subject to cyclic loading stresses. On the basis of its review, the staff
 
finds that the applicant has created a valid basis for concluding that cracking due to
 
SCC or cyclical loading is not an aging effect requiring management for the VEGP
 
high pressure stainless steel chemical volume and control system pumps because
 
the pumps operate at temperature less than that used by the staff for initiation of
 
SCC and because the pump casings are not subject to significant cyclical loading
 
stresses.
 
On the basis of its review of the AMR result items as described in the preceding
 
paragraphs and its comparison of the applicant's results to corresponding
 
recommendations in the GALL Report, the staff finds that the applicant addressed
 
the aging effect or mechanism appropriately as recommended by the GALL Report.
 
  (4) LRA Section 3.3.2.2.4 addresses cracking of high-strength closure bolting for chemical and volume control system bolting exposed to steam or water leakage as
 
an aging effect not applicable because the auxiliary systems have no high-strength bolting. Certified material test reports for a sample population of A193 Gr. B7
 
bolting, indicate that the actual yield strengths of this bolting material do not exceed
 
150 ksi. Plant-specific operating experience supports this indication.
The staff reviewed LRA Section 3.3.2.2.4 which states that cracking due to stress
 
corrosion cracking and cyclic loading is not applicable to VEGP steel closure bolting
 
in an air with steam or water leakage environment in the chemical volume and
 
control system. The staff noted that the applicant states in LRA Section 3.3.2.2.4
 
that no high strength closure bolting is used in VEGP auxiliary systems. On the
 
basis of its review, the staff finds that the applicant has met the criteria of SRP-LR
 
Section 3.3.2.2.4 by confirming that the aging effects are not applicable because
 
actual VEGP bolting material does not exceed 150 ksi yield strength (which is the
 
threshold of high-strength steel bolting material) and that this aging effect is not
 
applicable.
 
On the basis of its review of the AMR result items as described in the preceding
 
paragraphs and its comparison of the applicant's results to corresponding 3-362 recommendations in the GALL Report, the staff finds that the applicant addressed the aging effect or mechanism appropriately as recommended by the GALL Report.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.3.2.2.4 criteria. 
 
For those line items that apply to LRA Section 3.3.2.2.4, the staff concludes 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).
 
3.3.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation 
 
The staff reviewed LRA Section 3.3.2.2.5 against the following criteria in SRP-LR
 
Section 3.3.2.2.5:
 
  (1) LRA Section 3.3.2.2.5 addresses hardening and loss of strength due to elastomer degradation of seals and components in heating, ventilation, and air conditioning (HVAC) systems as aging effects m anaged by the Periodic Surveillance and Preventive Maintenance Activities, the Piping and Duct Internal Inspection Program, or the External Surfaces Monitoring Program for HVAC components aligned with
 
this summary item. The External Su rfaces Monitoring Program will manage degradation of the external surfaces of ventilation system elastomer flexible connectors. The Periodic Surveillance and Preventive Maintenance Activities will
 
manage degradation of elastomeric seals in the control room filter units. The Piping
 
and Duct Internal Inspection Program will manage degradation of internal surfaces
 
of ventilation system elastomer flexible connectors. Components aligned to this
 
summary item as substitutes include the boric acid storage tank diaphragms, for
 
which the Periodic Surveillance and Preventive Maintenance Activities will manage
 
degradation of surfaces exposed to an air - indoor environment.
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 staff reviewed LRA Section 3.3.2.2.5 which addresses hardening and loss of
 
strength due to elastomer degradation for HVAC components. The staff noted that
 
instead of a plant-specific AMP recommended by the GALL Report, the applicant
 
proposed the combination of three AMPs to manage the aging effects of hardening
 
and loss of strength due to elastomer degradation of elastomer seals and
 
components in air - indoor. 
 
The AMPs proposed by the applicant are t he Periodic Surveillance and Preventive Maintenance Activities (evaluated in SER Section 3.0.3.3.6), the Piping and Duct
 
Internal Inspection Program (evaluated in SER Section 3.0.3.2.13), and the External
 
Surfaces Monitoring Program (evaluated in SER Section 3.0.3.2.5). 
 
The staff noted that the Periodic Surveillance and Preventive Maintenance 3-363 Activities, the Piping and Duct Internal Inspection Program, and the External Surfaces Monitoring Program contain in spection activities for elastomeric components including determining whether degradation has occurred, by physical
 
manipulation. For the External Surfaces Monitoring Program, the applicant will
 
inspect accessible elastomer components routinely, and inaccessible components
 
either during outages, or by remote means. For the Periodic Surveillance and
 
Preventive Maintenance Activities, the applicant will inspect the boric acid storage
 
tank diaphragm surfaces exposed to air. For the Piping and Duct Internal Inspection
 
Program, the applicant will manage internal su rfaces of ventilation system elastomer flexible connectors. 
 
In RAI 3.3-1/3.4-1, the staff asked the applicant to justify how visual examinations
 
alone credited in programs such as the External Surfaces Monitoring Program or the
 
Piping and Duct Internal Inspection Program would be capable of detecting a crack
 
or managing material property changes in elastomeric, plastic or polymeric
 
components. 
 
In the applicant's response to RAI 3.3-1/3.4-1 dated June 23, 2008, the applicant confirmed
 
that programs crediting visual examinations of elastomeric or polymeric materials also
 
credit tactile techniques in conjunction with visual examinations to monitor for indications
 
that may be indicative of changes in the strength or hardness properties of  materials, and
 
that these tactile techniques include scratching the material surface to screen for waxy or
 
chalky residues (which can be indicative of polymer breakdown), pressing the polymer to
 
qualitatively evaluate resiliency, bending or folding the polymer to identify crazing (surface
 
cracking) or whitening (which can be indicative of reduced bonding of the filler), and
 
stretching to evaluate tear resistance. The staff finds these additional techniques to be
 
acceptable because the applicant will not be relying solely on visual examinations alone as
 
the basis for aging management, and because these tactile activities are physical
 
monitoring techniques that are be capable of indicating a change in the hardness or
 
strength properties of the elastomeric materials. RAI 3.3-1/3.4-1 is resolved with respect to
 
managing changes in material properties for these elastomeric auxiliary system piping
 
components.
On the basis of its review of the AMR result items as described in the preceding paragraphs
 
and its comparison of the applicant's results to corresponding recommendations in the
 
GALL Report, the staff finds that the applicant addressed the aging effect or mechanism
 
appropriately as recommended by the GALL Report.
 
  (2) LRA Section 3.3.2.2.5 addresses loss of strength due to elastomer degradation of elastomer linings of the filters, valves, and ion exchangers in spent fuel pool cooling
 
and purification systems as an aging effect to be managed by the Periodic
 
Surveillance and Preventive Maintenance Activities for boric acid storage tank
 
diaphragms aligned to this summary item as substitutes. VEGP has no have
 
elastomer linings in the spent fuel pool cooling and purification system.
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 3-364 the linings in the environment to ensure that these aging effects are adequately managed. The staff reviewed LRA Section 3.3.2.2.5 which addresses loss of strength due to
 
elastomer degradation for spent fuel pool cooling and purification system
 
component linings. The staff noted that instead of a plant-specific AMP
 
recommended by the GALL Report, the applicant proposed the combination of two
 
AMPs to manage the aging effects of hardening and loss of strength due to
 
elastomer degradation of elastomer linings in treated water or borated water. The
 
AMPs proposed by the applicant are t he Periodic Surveillance and Preventive Maintenance Activities (evaluated in SER Section 3.0.3.3.6), and the Piping and
 
Duct Internal Inspection Program (evaluated in SER Section 3.0.3.2.13). The staff
 
also noted that although VEGP does not have spent fuel pool cooling and cleanup
 
system components with elastomer linings, the boric acid storage tank diaphragms
 
are evaluated with this summary item.
 
The staff noted that the Periodic Surveillance and Preventive Maintenance Activities
 
and the Piping and Duct Internal Inspection Program both contain inspection
 
activities for elastomeric components including determining whether degradation
 
has occurred, by physical manipulation. For the Periodic Surveillance and
 
Preventive Maintenance Activities, the applicant will inspect the boric acid storage
 
tank diaphragm surfaces exposed to treated borated water. For the Piping and Duct
 
Internal Inspection Program, the applicant will manage internal surfaces of
 
ventilation system elastomer flexible connectors.
 
In RAI 3.3-1/3.4-1, the staff asked the applicant to justify how visual examinations
 
alone credited in programs such as the External Surfaces Monitoring Program or the
 
Piping and Duct Internal Inspection Program would be capable of detecting a crack
 
or managing material property changes in elastomeric, plastic or polymeric
 
components. 
 
In the applicant's response to RAI 3.3-1/3.4-1 dated June 23, 2008, the applicant
 
confirmed that programs crediting visual examinations of elastomeric/polymeric materials also credit tactile techniques in conjunction with visual examinations to
 
monitor for indications that may be indicative of changes in the strength or hardness
 
properties of  materials, and that these tactile techniques include scratching the
 
material surface to screen for waxy or chalky residues (which can be indicative of
 
polymer breakdown), pressing the polymer to qualitatively evaluate resiliency, bending or folding the polymer to identify crazing (surface cracking) or whitening (which can be indicative of reduced bonding of the filler), and stretching to evaluate
 
tear resistance. The staff finds these additional techniques to be acceptable
 
because the applicant will not be relying solely on visual examinations alone as the
 
basis for aging management, and because these tactile activities are physical
 
monitoring techniques that are capable of indicating a change in the hardness or
 
strength properties of the elastomeric materials. RAI 3.3-1/3.4-1 is resolved with respect to managing changes in material properties for the elastomeric spent fuel
 
cooling and cleanup system components.
 
On the basis of its review of the AMR result items as described in the preceding
 
paragraphs and its comparison of the applicant's results to corresponding 3-365 recommendations in the GALL Report, the staff finds that the applicant addressed the aging effect or mechanism appropriately as recommended by the GALL Report.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.3.2.2.5 criteria. For those line items that apply to LRA
 
Section 3.3.2.2.5, the staff concludes 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
 
Summary of Technical Information in the Application This section of the original application was amended in a letter dated January 20, 2009. The description below reflects the
 
revision.
 
LRA Section 3.3.2.2.6 addresses reduction of neutron-absorbing capacity and loss of
 
material due to general corrosion in the neutron-absorbing sheets of spent fuel storage
 
racks exposed to treated or borated water as aging effects. The reduction in neutron-
 
absorbing capacity for the Boron-Carbide materials will be managed with the One-Time
 
Inspection Program and the loss of material due to corrosion will be managed by the Water
 
Chemistry Control Program for the aluminum cladding material.
 
Staff Evaluation In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section 3.3.2.2.6 on the applicant's management of the reduction of neutron-
 
absorbing capacity and the loss of material 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 LRA Section 3.3.2.2.6 against the staff's recommended regulatory
 
criteria in SRP-LR Section 3.3.2.2.6 and in GALL AMR Item VII.A2-5 of the GALL Report, Volume 2. 
 
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.
In the original application, the staff reviewed LRA Section 3.3.2.2.6 in which the applicant
 
evaluated a scenario where a reduction of neutron-absorbing capacity might occur in the
 
neutron-absorbing sheets of the spent fuel storage racks at VEGP due to general corrosion. The staff questioned the rationale provided by the licensee. In RAIs dated November 18, 2008, the staff requested that the applicant provide additional details on neutron-absorbing
 
materials in the spent fuel pool. 
 
The licensee responded to the RAIs in a letter dated December 16, 2008. The staff
 
reviewed the information provided in the licensee's response to the RAIs and a needed
 
additional clarification. The staff had a teleconference with the licensee on January 8, 2009
 
to clarify the responses to the RAIs.
3-366  After the teleconference on January 8, 2009, the licensee made an additional commitment
 
to LRA Appendix A, Commitment No. 37, in a letter dated January 20, 2009, that: "SNC will
 
also perform a baseline inspection and a follow-up inspection to measure the effectiveness
 
of the Boral neutron absorber panels on Unit 1 to provide reasonable assurance that the
 
panels will continue to perform their reactivity control function during the period of extended
 
operation. These inspections will be included in the One-Time Inspection Program which is
 
to be implemented for license renewal. The baseline inspection will be performed prior to
 
the period of extended operation. The follow-up inspection will be performed at a date to be
 
determined based on the results of the baseline inspection and relevant industry guidance, not to exceed ten years after the baseline inspection." 
 
In addition, in the January 20, 2009 letter, the licensee amended their application as
 
described above. This revision included an addition to the One-Time Inspection Program to
 
include the inspection of the Boral. The One-Time Inspection Program would require the
 
inspection plan to include the sample size and location of the samples, the examination
 
technique, detection of aging effects, acceptance criteria, evaluation of the need for follow-
 
up examinations and corrective actions. The applicant has also stated that they will
 
perform a baseline inspection along with follow up inspections of the effectiveness of the
 
Boral. The staff reviewed the One-Time Inspection Program (see Section 3.0.3.1.2) and the
 
Commitment and found it to be acceptable since it gives reasonable assurance that the
 
neutron-absorbing capacity will be adequately managed during the period of extended
 
operation.
 
In its response to the RAIs the licensee also provided information on relevant industry and
 
operating experience. The licensee addressed an NRC Operations Event Report (ADAMS
 
Accession No. ML032880525) concerning a 2003 Seabr ook event by providing references to past letters from the licensee and a description of studies performed. In addition, the
 
licensee stated:
 
"Specific to VEGP, it is important to note that the VEGP Boral storage rack cells are
 
vented so that gas cannot accumulate. The use of venting has been successful
 
throughout the industry in minimizing bulge formation. Additionally, the SNC
 
response to staff RAI 1, part "b" documented in Enclosure 2 of SNC letter Nl 0803 (ML051260207) describes that, for the racks supplied to VEGP, Maine Yankee
 
had routinely performed drag testing and visual inspection. Prior to shipping the
 
racks to VEGP, the last two surveillances showed no signs of swelling or bulging. 
 
The experiences of other PWR units having Boral surveillance coupons are
 
available to SNC through the EPRI Neutron Absorber Users Group and by the 10
 
CFR 50.21 reporting process. As listed in EPRI 1013721, Boral is in use as a wetted
 
system neutron absorber in numerous domestic and international units. At present, SNC is unaware of any Boral degradation event having safety significance."
The staff has reviewed and confirmed the operating experience and the staff finds this acceptable since the operating experience supports the conclusion that the commitment of
 
the One-Time Inspection Program along with monitoring industry and operating experience
 
and being part of the EPRI Neutron Absorbers Group will effectively manage the loss of
 
neutron-absorbing capacity and degradation of Boral. 
 
3-367 The staff reviewed the ability of the Water Chemistry Control Program, which will control the quality of the spent fuel pool water, to manage the loss of material of the aluminum cladding
 
of the Boral material. On the basis that the quality of the spent fuel pool water will be
 
continuously monitored and corrective actions taken as necessary, the staff concludes that
 
the Water Chemistry Control Program will effectively manage the aging effect of loss of
 
material through the period of extended operation. The staff asked the licensee an RAI on
 
the degradation of the Boraflex material. The licensee stated that they no longer take credit
 
for the material for criticality and therefore do not monitor the material. However, they do
 
monitor the silica levels in the pool that are caused by the leaching of silica from the
 
Boraflex material. The staff finds the applicant's response to the RAI is acceptable. The
 
staff's concern in the RAI is resolved.
 
The staff reviewed the applicant's application, response to RAIs and the Commitment, and
 
the staff concludes that the applicant's responses and 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
 
concludes that the LRA is consistent with the GALL Report and the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
 
Commitment. The licensee made an additional commitment to LRA Appendix A, Commitment No. 37 in letter dated January 20, 2009 that:
 
"SNC will also perform a baseline inspection and a follow-up inspection to measure
 
the effectiveness of the Boral neutron absorber panels on Unit 1 to provide
 
reasonable assurance that the panels will continue to perform their reactivity control
 
function during the period of extended operation. These inspections will be included
 
in the One-Time Inspection Program which is to be implemented for license
 
renewal. The baseline inspection will be performed prior to the period of extended
 
operation. The follow-up inspection will be performed at a date to be determined
 
based on the results of the baseline inspection and relevant industry guidance, not
 
to exceed ten years after the baseline inspection."
 
This is found to be acceptable by the staff since it demonstrates that the neutron-absorbing
 
capacity will be adequately managed during the period of extended operation.
 
Conclusion.
The staff reviewed the applicant's application and amendment, response to RAIs and the Commitment, and the staff concludes that the applicant's responses and
 
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 concludes that the LRA is consistent with the GALL Report and
 
the applicant has demonstrated that the effects of aging will be adequately managed so
 
that the intended 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 criteria in SRP-LR
 
Section 3.3.2.2.7:
 
  (1) LRA Section 3.3.2.2.7 addresses loss of material due to general, pitting, and crevice corrosion for steel piping components, valves, and tanks in the reactor coolant 3-368 pump oil collection system exposed to lubricating oil as an aging effect for which the GALL Report recommends one-time inspections to verify the effectiveness of the
 
lubricating oil program for control of the lubricating oil environment and to evaluate
 
the thickness of the lower portion of the reactor coolant pump oil collection tank.
 
Steel piping components and tanks of the reactor coolant pump oil collection system
 
are not exposed continuously to a lubricat ing oil environment maintained by the Oil Analysis Program so this program is not credited for managing loss of material for
 
them. Instead, the One-Time Inspec tion Program will manage these components using visual or volumetric nondestructive examination techniques to inspect a representative sample of the internal surfaces for significant corrosion. In addition, the One-Time Inspection Program will evaluate the thickness of the lower portion of
 
a representative sample of the reactor coolant pump oil collection tanks. The reactor
 
coolant pump oil collection system is part of the RCS. LRA Section 3.1 presents
 
AMR results for the reactor coolant oil collection system. Consistent with the GALL
 
Report with exceptions, the Oil Analysis Program and the One-Time Inspection 
 
Program will manage auxiliary system steel piping and components exposed to lubricating oil.
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 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. 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 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 staff reviewed the Oil Analysis Program and the One-Time Inspection Program
 
and determined that the aging effect of loss of material due to general, pitting, and
 
crevice corrosion in steel components exposed to lubricating oil will be effectively managed. The staff concludes that the One-Time Inspection Program is being used
 
to verify the effectiveness of the Oil Analysis Program to manage loss of material
 
due to general, pitting and crevice corrosion for steel components exposed to
 
lubricating oil. In addition, the One-Time Inspection Program, as stated in LRA
 
Section 3.3.2.2.7, determines the thickness of the lower portion of the reactor
 
coolant pump oil collection tank. On the basis of its review, the staff finds that the
 
applicant has met the criteria of SRP-LR Section 3.3.2.2.7 by verifying the 3-369 effectiveness of the Oil Analysis Program by one-time inspections and using one-time inspections to determine the thickness of the reactor coolant pump oil
 
collection tank. The staff's review of the Oil Analysis Program and the One-Time 
 
Inspection Program is documented in SER Sections 3.0.3.2.10 and 3.0.3.1.2, respectively.
 
LRA Table 3.3.1, Item 3.3.1-15, states that loss of material of steel reactor coolant
 
pump oil collection components in the reactor coolant and connected lines system
 
exposed to lubricating oil is managed with the One-Time Inspection Program.
 
During the audit and review, the staff noted that the AMR result items pointing to
 
LRA Table 3.3.1, Item 3.3.1-15 refer to Note E.
 
The staff reviewed the AMR result items referring to Note E and determined that the
 
component type, material, environment, and aging effect are consistent with those
 
of the corresponding line of the GALL Report. The GALL Report recommends using a combination of GALL AMP XI.M39, "Lubricating Oil Analysis" and GALL AMP XI.M32, "One Time Inspection," as a verification program. The applicant proposed
 
using only the One-Time Inspection Program. The staff evaluation of the One-Time
 
Inspection Program is documented in SER Section 3.0.3.1.2.
 
Steel piping components and tanks of the VEGP reactor coolant pump oil collection
 
system are not continuously exposed to a lubricating oil environment that is maintained by the Oil Analysis Program. Ther efore, the Oil Analysis Program is not required for managing the loss of material of these components. The reactor coolant
 
pump oil collection components need only be monitored for potential aging effect by
 
the One-Time Inspection Program. The One-Time Inspection Program will use
 
visual or volumetric NDE techniques to inspect a representative sample of the
 
internal surfaces to assure there is no significant corrosion. In addition, the One-
 
Time Inspection Program will evaluate the thickness of the lower portion of a
 
representative sample of the RCP oil collection tanks. 
 
The staff confirmed that loss of material of the internal surfaces of carbon steel
 
components (including thickness verification of tank bottom surfaces) in the RCP oil
 
collection system is included within the scope of the One-Time Inspection Program.
 
On the basis that these components are not continuously exposed to a lubricating
 
oil environment that is maintained by the Oil Analysis Program, the staff finds the applicant's use of the One-Time Inspection Program alone acceptable to confirm
 
that loss of material is not occurring or is occurring so slowly as to not affect the
 
intended functions of these components. 
 
On the basis of its review of the AMR result items as described in the preceding
 
paragraphs and its comparison of the applicant's results to corresponding
 
recommendations in the GALL Report, the staff finds that the applicant addressed
 
the aging effect or mechanism appropriately as recommended by the GALL Report.
 
  (2) LRA Section 3.3.2.2.7 addresses loss of material in BWR reactor water cleanup and shutdown cooling systems as an aging effect not applicable to VEGP, a PWR plant.
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 3-370 elements in the BWR reactor water cleanup and shutdown cooling systems exposed to treated water.
The staff finds acceptable the applicant's evaluation that this aging effect is not
 
applicable to VEGP because VEGP is not a BWR-design reactor.
 
  (3) LRA Section 3.3.2.2.7 addresses loss of material due to general, pitting, and crevice corrosion in steel and stainless steel diesel exhaust piping components exposed to
 
diesel exhaust as an aging effect to be managed by the Piping and Duct Internal
 
Inspection Program.
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
 
the aging effect is adequately managed.
The staff reviewed LRA Section 3.3.2.2.7 which addresses loss of material due to
 
general, pitting, and crevice corrosion in steel and stainless steel diesel exhaust
 
components. The staff noted that the plant-specific AMP proposed by the applicant
 
is the Piping and Duct Internal Inspection Program. The staff reviewed the Piping
 
and Duct Internal Inspection Program and verified that the aging effect of loss
 
material will be adequately managed by using visual inspection techniques to
 
inspect representative samples of diesel exhaust components. The staff's
 
evaluation of the Piping and Duct Internal Inspection Program is documented in
 
SER Section 3.0.3.2.13. The staff finds that this program includes activities that are
 
adequate to manage loss of material in steel and stainless steel diesel engine
 
exhaust piping, piping components, and piping elements exposed to diesel exhaust.
 
On the basis of its review of the AMR result items as described in the preceding
 
paragraphs and its comparison of the applicant's results to corresponding
 
recommendations in the GALL Report, the staff finds that the applicant addressed
 
the aging effect or mechanism appropriately as recommended by the GALL Report.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.3.2.2.7 criteria. For those line items that apply to LRA
 
Section 3.3.2.2.7, the staff concludes 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 due to general, pitting, crevice, and
 
microbiologically-influenced corrosion for steel piping components buried in soil as aging
 
effects to be managed, consistent with the GALL Report AMP with exceptions, by the
 
Buried Piping and Tanks Inspection Program.
 
3-371 SRP-LR Section 3.3.2.2.8 states that loss of material due to general, pitting, and crevice corrosion, and microbiologically-influenced corrosion 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 effects of loss of material from
 
general, pitting, and crevice corrosion and microbiologically-influenced corrosion. The
 
effectiveness of the buried piping and tanks inspection program should be verified to
 
evaluate an applicant's inspection frequency and operating experience with buried
 
components, ensuring that loss of material does not occur.
 
The staff reviewed the Buried Piping and Tanks Inspection Program and verified that the
 
applicant credits the program to manage loss of material in buried piping and tank
 
components and the program's ability to detect aging effects. The staff also reviewed the
 
plant operating experience relevant to the Buried Piping and Tanks Inspection Program and
 
verified that the program credits inspections of the external surfaces of buried piping and
 
tanks when the piping or tanks are excavated for maintenance or when the external
 
component surfaces are exposed for any other reason. The staff verified that, prior to
 
entering the period of extended operation, the applicant indicated that it will perform a
 
review to determine if at least one opportunistic or focused inspection of buried piping and
 
tanks has been performed within the ten year period prior to the period of extended
 
operation, and if an inspection did not occur, a focused inspection will be performed prior to
 
the period of extended operation. In addition, the staff also verified that the applicant
 
credited a focused inspection of buried piping and tanks to be performed within ten years
 
after entering the period of extended operation, unless an evaluation determined that
 
sufficient opportunistic and focused inspections have occurred during this time to
 
demonstrate the ability of the underground coatings to protect the underground piping and
 
tanks from degradation. The staff verified that this is consistent with staff's recommended
 
aging management basis for buried pipes in the "detection of aging effects" program element in GALL AMP XI.M34, "Buried Piping and Tanks Inspection." Based on this review, the staff finds that the applicant has provided an acceptable basis for crediting its Buried
 
Piping and Tanks Inspection Program to manage loss of material in these steel buried pipe
 
and tanks components because it is consistent with the GALL Report.
 
Based on the programs identified above, the staff concludes that the applicant's 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 concludes 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 criteria in SRP-LR Section
 
3.3.2.2.9:
 
  (1) LRA Section 3.3.2.2.9 addresses loss of material due to general, pitting, crevice and microbiologically-influenced corrosion for steel piping components and tanks
 
exposed to fuel oil as an aging effect which may occur at locations where
 
contaminants accumulate and for which the GALL Report recommends a one-time
 
inspection of selected components to verify the effectiveness of the fuel oil 3-372 chemistry program. The LRA states that, consistent with the GALL Report, the plant-specific Diesel Fuel Oil Program will manage the aging effect in EDG system components, and that One-Time Inspection Program is credited to verify the
 
program effectiveness Diesel Fuel Oil Pr ogram by inspecting selected components where contaminants may accumulate. The LRA states that, unlike the GALL Report
 
AMP, the Diesel Fuel Oil Program and the Periodic Surveillance and Preventive Maintenance Activities will manage the aging effect in the EDG fuel oil storage
 
tanks. The Periodic Surveillance and Preventive Maintenance Activities visually
 
inspect these tanks periodically.
SRP-LR Section 3.3.2.2.9 states that loss of material due to general, pitting, and
 
crevice corrosion, microbiologically-influenced corrosion, 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 programs to manage
 
loss of material due to general, pitting, and crevice corrosion, microbiologically-
 
influenced corrosion, 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 staff reviewed the Diesel Fuel Oil Program, One-Time Inspection Program and Periodic Surveillance and Preventive Maintenance Activities Program that the
 
applicant proposes to use to manage aging effects of steel piping and tanks in fuel
 
oil environments. The staff verified that the Diesel Fuel Oil Program is credited to
 
maintain the fuel oil quality by testing new fuel oil to quality standards prior to
 
introducing it into plant storage tanks. The staff verified that the program calls for
 
periodic sampling and testing of the fuel oil storage tank diesel fuel inventory to test
 
for water accumulation, biological organisms, and particulate-based sediments. The
 
Diesel Fuel Oil Program has requirements to invoke corrective actions when the fuel
 
oil condition is found to be out of tolerance with specifications. The staff verified that
 
the applicant credits either its One-Time Inspection Program or its Periodic
 
Surveillance and Preventive Maintenance Activities Program to verify the Diesel
 
Fuel Oil Program effectiveness. The staff verified that the crediting of the One-Time
 
Inspection Program is consistent with the staff's guidance in SPR-LR Section
 
3.3.2.2.9, Item (1).
The staff verified that the Periodic Surveillance and Preventive Maintenance
 
Activities Program is an acceptable program to verify the effectiveness of the Diesel
 
Fuel Oil Program to manage loss of material in the buried storage tank components
 
because the program credits visual inspections that will be performed periodically
 
instead of one time basis and that will monitor for signs of corrosion in the tanks and
 
degradation in the interior tank liner/coating surfaces. 
 
The staff also verified that the LRA includes LRA Table 3.3.1, Item 3.3.1-20 and
 
associated type "2" AMR lines items that point to SRP-LR Section 3.3.2.2.9, Item
 
(2). Like SRP-LR Section 3.3.2.2.9, Item (1), the staff verified that in these AMR
 
items, the applicant credits its Diesel Fuel Oil Program and either the One-Time 3-373 Inspection Program or Periodic Surveillance and Preventive Maintenance Activities Program to verify the effectiveness of t he Diesel Fuel Oil Program in managing loss of material in the interior buried piping and tank surfaces that are exposed to diesel
 
fuel. The staff's evaluations of the Diesel Fuel Oil Program, One-Time Inspection
 
Program and Periodic Surveillance and Prev entive Maintenance Activities Program are documented in SER Sections 3.0.3.3.3, 3.0.3.1.2 and 3.0.3.3.6, respectively.
 
On the basis of its review of the AMR result items as described in the preceding
 
paragraphs and its comparison of the applicant's results to corresponding
 
recommendations in the GALL Report, the staff finds that the applicant addressed
 
the aging effect or mechanism appropriately as recommended by the GALL Report.
 
  (2) LRA Section 3.3.2.2.9 addresses loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion and fouling for steel heat exchanger
 
components exposed to lubricating oil as an aging effect for which the GALL Report
 
recommends a one-time inspection to verify the effectiveness of the lube oil
 
program. Consistent with the GALL Report AMP with exceptions, the Oil Analysis
 
Program will manage the aging effect and the One-Time Inspection Program will
 
verify program effectiveness by inspec ting selected components at susceptible locations.
SRP-LR Section 3.3.2.2.9 states that loss of material due to general, pitting, and
 
crevice corrosion, microbiologically-influenced corrosion, 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 co rrosion 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 staff reviewed LRA Section 3.3.2.2.9 which addresses loss of material due to
 
general, pitting, and crevice corrosion, microbiologically-influenced corrosion, and
 
fouling in steel heat exchanger components in lubricating oil. The staff verified that
 
the applicant credits its Oil Analysis Program to manage loss of material due to
 
general, pitting, and crevice corrosion, microbiologically-influenced corrosion, and
 
fouling may occur in steel heat exchanger components exposed to lubricating oil
 
and its One-Time Inspection Program to veri fy the program effectiveness of its Oil Analysis Program in managing this aging effect. The staff reviewed the VEGP Oil
 
Analysis Program and verified that the program is a mitigative program that is
 
specifically designed to manage the effects of aging in plant components that are
 
exposed to lubricating oil. The staff also verified that the VEGP One-Time
 
Inspection Program includes visual inspection techniques to verify the effectiveness
 
of the Oil Analysis Program. The staff's ev aluation of the Oil Analysis Program is documented in SER Section 3.0.3.2.10. The staff's evaluation of the One-Time
 
Inspection Program is documented in SER Section 3.0.3.1.2. Based on this review, the staff finds that the applicant has provided a valid basis for managing loss of 3-374 material in the heat exchanger components that are exposed to lubricating oil because it in conformance with the recommendation in SRP-LR Section 3.3.2.2.9, Item (2) and the AMRs in the GALL report that are invoked by this SRP-LR section. 
 
On the basis of its review of the AMR result items as described in the preceding
 
paragraphs and its comparison of the applicant's results to corresponding
 
recommendations in the GALL Report, the staff finds that the applicant addressed
 
the aging effect or mechanism appropriately as recommended by the GALL Report.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.3.2.2.9 criteria. For those line items that apply to LRA
 
Section 3.3.2.2.9, the staff concludes 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 criteria in SRP-LR
 
Section 3.3.2.2.10:
 
  (1) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion for elastomer lining or stainless steel cladding exposed to treated water or
 
borated water by degradation as an aging effect not applicable because AMR
 
results for the spent fuel pool cooling and purification system do not include
 
elastomer-lined carbon steel components. Other GALL Report Volume 2 items in
 
this summary item are for BWRs; VEGP is a Westinghouse PWR.
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 that are exposed to treated water and treated borated water if the
 
cladding or lining is degraded.
The staff reviewed LRA Section 3.3.2.2.10. The staff verified that the stated SRP-LR
 
guidance is applicable only to steel spent fuel cooling and cleanup system piping
 
that are designed with interior elastomeric liners (i.e. PWR spent fuel cooling and
 
cleanup systems) or interior stainless steel cladding (BWR spent fuel cooling and
 
cleanup systems). The staff verified that the GALL AMRs invoked by this SRP-LR
 
section for steel piping components with interior stainless steel cladding are
 
applicable to BWR designed facilities only. Based on this assignment, the staff finds
 
that the recommendation in SRP-LR 3.3.2.2.10, Item (1) for steel piping components
 
with interior stainless steel cladding is not applicable to VEGP because VEGP is
 
PWR. 
 
The staff also verified that the recommended guidance in SRP-LR Section
 
3.3.2.2.10, Item (1), as it pertains to steel spent fuel cooling and cleanup system
 
piping components with interior elastomeric liners is not applicable to the VEGP
 
LRA because the VEGP design does not include any elastomer lined steel piping
 
components that are exposed to either a treated water or borated treated water
 
environment. On the basis of this review, the staff finds that the applicant does not 3-375 need to meet or conform to the recommended criteria in SRP-LR Section 3.3.2.2.10, Item (1) because the criteria in the SRP-LR section are not applicable to the VEGP
 
design. 
 
On the basis of its review of the AMR result items as described in the preceding
 
paragraphs and its comparison of the applicant's results to corresponding
 
recommendations in the GALL Report, the staff finds that the applicant addressed
 
the aging effect or mechanism appropriately as recommended by the GALL Report.
 
  (2) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in BWR spent fuel pool cooling and cleanup, reactor water cleanup, and
 
shutdown cooling system piping exposed to treated water as an aging effect not
 
applicable to VEGP, a PWR plant.
 
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 stainless steel and steel with stainless steel cladding heat
 
exchanger components exposed to treated water.
The staff verified that the recommended criteria in SRP-LR Section 3.3.2.2.10, item
 
(2) are applicable only to stainless steel piping components and steel piping
 
components with interior stainless steel cladding that are located in BWR spent fuel
 
pool cooling, reactor water cleanup, and shutdown cooling system. Based on this
 
review, the staff finds that the applicant has provided an acceptable basis for
 
concluding the recommended criteria in SRP-LR Section 3.3.2.2.10, Item (2) are not
 
applicable to the VEGP LRA because the units at VEGP are Westinghouse
 
designed PWRs.
 
  (3) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion for copper alloy HVAC components exposed to condensation as an aging
 
effect for which the GALL Report recommends a plant-specific program. The
 
External Surfaces Monitoring Program will manage loss of material due to
 
condensation on exposed surfaces of copper alloy auxiliary system components.
The Piping and Duct Internal Inspection Program will manage loss of material for
 
copper alloy surfaces internal to auxiliary system co mponents and exposed to condensation.
SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice
 
corrosion may occur in copper alloy heating, ventilation, and air conditioning (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 the aging effect is adequately managed.
The staff reviewed LRA Section 3.3.2.2.10. The staff noted that the applicant 
 
credited its External Surfaces Monitoring Program to manage loss of material in the
 
external surfaces of copper alloy auxilia ry system components that may be exposed to condensation and Piping and Duct Internal Inspection Program to manage loss of
 
material in the internal surfaces of copper alloy auxiliary system components that
 
may be exposed to condensation. The staff reviewed the External Surfaces
 
Monitoring Program and the Piping and Duct Internal Inspection Program and 3-376 verified that both programs are GALL-based programs that are credited for managing loss of material in metal components that are exposed to atmospheric
 
environments, including those air environments that might result in condensation of
 
the components. The staff's evaluation of t he External Surfaces Monitoring Program is documented in SER Section 3.0.3.2.5. The staff's evaluation of the Piping and
 
Duct Internal Inspection Program is documented in SER Section 3.0.3.2.13. The
 
staff evaluations include an assessment of the ability of the programs to manage
 
loss of material in the metal surfaces that are exposed to an air environment, including those air environments that may result in condensation on the component
 
surfaces. 
 
Based on this review, the staff finds that the applicant has provided an acceptable
 
basis for managing loss of material in the copper alloy HVAC components that are
 
exposed to a condensation environment because the External Surfaces Monitoring
 
Program and the Piping and Duct Internal Inspection Program are valid programs to
 
credit for management of loss of material t hat may occur in metal auxiliary systems components that are exposed to a condensation environment.
 
On the basis of its review of the AMR result items as described in the preceding
 
paragraphs and its comparison of the applicant's results to corresponding
 
recommendations in the GALL Report, the staff finds that the applicant addressed
 
the aging effect or mechanism appropriately as recommended by the GALL Report.
 
  (4) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion for copper alloy piping components exposed to lubricating oil as an aging
 
effect for which the GALL Report recommends a one-time inspection to verify the
 
effectiveness of the lubricating oil program. Consistent with the GALL Report AMP
 
with exceptions, the Oil Analysis Progr am will manage the aging effect and the One-Time Inspection Program will verify progr am effectiveness by inspecting selected components at susceptible locations.
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 staff reviewed LRA Section 3.3.2.2.10, and the AMRs in the application that are
 
based on this section. The staff verified that the applicant credits its Oil Analysis
 
Program to manage loss of material in the copper alloy piping components that are
 
exposed to lubricating oil and its One-Time Inspection Program to verify that the Oil
 
Analysis Program is effective in managing loss of material in these copper alloy
 
components. The staff concludes that the One-Time Inspection Program is being 3-377 used to verify the effectiveness of the Oil Analysis Program to manage loss of material for copper alloy components exposed to lubricating oil. 
 
On the basis of its review, the staff finds that the applicant has met the criteria of
 
SRP-LR Section 3.3.2.2.10 by verifying the effectiveness of the Oil Analysis
 
Program by one-time inspections. The staff's evaluation of the Oil Analysis Program and the One-Time Inspection Program is documented in SER Sections 3.0.3.2.10
 
and 3.0.3.1.2, respectively. 
 
Based on the programs identified above, the staff concludes that the applicant's
 
programs meet SRP-LR Section 3.3.2.2.10 criteria. For those line items that apply to
 
LRA Section 3.3.2.2.10, the staff concludes 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).
 
  (5) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion for aluminum piping and stainless steel ducting components exposed to
 
condensation as an aging effect to be managed by the External Surfaces Monitoring
 
Program for stainless steel component surfaces and by the Bolting Integrity
 
Program for stainless steel bolting. The Piping and Duct Internal Inspection Program
 
will manage loss of material from stainless steel surfaces exposed to condensation
 
for surfaces internal to HVAC and other components.
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 the aging effect is adequately managed.
The staff reviewed the External Surfaces Monitoring Program, Piping and Duct
 
Internal Inspection Program and Bolting Integrity Program which the applicant
 
proposed to use to manage loss of material on exposed surfaces of stainless steel
 
components. Depending on the component inspection location, the applicant will
 
use either the External Surfaces Monitoring Program or Piping and Duct Internal
 
Inspection Program. For stainless steel bolting exposed to condensation, the
 
applicant will use the Bolting Integrity Program. The staff verified that all of these programs are based on corresponding programs that are provided in Section XI of
 
the GALL Report, Volume 2, and that all three programs use visual inspection
 
techniques to detect loss of material for stainless steel components. 
 
However, the staff did note some inconsistencies with the AMR items in the
 
application that are based on LRA Section 3.3.2.2.10, Item (5). During the audit and
 
review, the staff noted that in LRA Table 3.3.2-6, on page 3.3-114, the AMR line
 
item component closure bolting, material stainless steel in an air-indoor (exterior)
(condensation) environment, aging effect loss of material, AMP Bolting Integrity
 
Program, LRA Table 1, Item 3.3.1-27, GALL Report Item VII.F2-1, Note E; is shown
 
twice. The staff asked the applicant to explain why the line item is shown twice since
 
the component is identical and also the material, environment, aging effect and
 
aging management program.
3-378  In its response letter of February 8, 2008, the applicant stated that the duplication of
 
the line item in LRA Table 3.3.2-6, on page 3.3-114, was an error and one of the
 
line items would be removed from LRA Table 3.3.2-6. The applicant also stated that
 
the LRA will be amended to remove one of the duplicate AMR line items shown on
 
LRA page 3.3-114. The staff verified that the applicant amended the LRA in a letter
 
dated March 20, 2008.
 
The staff finds the applicant's response acceptable because the applicant amended
 
the LRA to remove one of the duplicate AMR line items from the LRA. The
 
evaluation of the use of the Bolting Integrity Program to manage loss of material for
 
the closure bolting is provided below.
 
During the audit and review, the staff noted that in LRA Table 3.3.2-12, on page 3.3-
 
159 for AMR component cooling coils (essential chilled water), material stainless
 
steel in an air-indoor (exterior) (condensation) environment, aging effect loss of
 
material, LRA Table 1, Item 3.3.1-27 and GALL Report Item VII.F2-1, a Note B is
 
shown. GALL Report Volume 2 Item VII.F2-1 calls for a plant-specific AMP. The
 
staff asked the applicant to explain why a Note B is shown, consistent with the
 
GALL Report with AMP exceptions, instead of Note E; the GALL Report identifies a
 
plant-specific AMP. The applicant has assigned the External Surfaces Monitoring
 
Program to manage loss of material for this component.
 
In its response letter of February 8, 2008, the applicant stated that Note B for the
 
AMR component cooling coils in LRA Table 3.3.2-12 on page 3.3-159 should be a
 
Note E. Note E is appropriate because GALL Report Volume 2 Item VII.F2-1 that
 
aligns with this AMR line item identifies a plant-specific AMP, while the AMP
 
credited in the LRA, External Surfaces Monitoring Program, is a GALL Report AMP with exceptions. Since a different AMP is credited while the material, environment
 
and aging effect are consistent with the GALL Report, a Note E should have been
 
specified instead of a Note B. The applicant also stated that the LRA line item for
 
this component will be amended to change the note from a B to an E. The staff
 
verified that the applicant amended the LRA in a letter dated March 20, 2008.
 
The staff finds the applicant's response acceptable because the applicant amended
 
the LRA AMR line item for this component to designate show the correct Note E, instead of B. The evaluation of the use of the External Surfaces Monitoring Program
 
to manage loss of material for the cooling coils (essential chilled water) is provided
 
below.
 
During the audit and review, the staff noted that in LRA Table 3.3.2-12 on page 3.3-
 
160 for AMR component cooling coils (nuclear service cooling water), material
 
stainless steel in an air-indoor (exterior) (condensation) environment, aging effect
 
loss of material, LRA Table 1, Item 3.3.1-27 and GALL Report Item VII.F2-1, a Note
 
B is shown. GALL Report Volume 2 Item VII.F2-1 calls for a plant-specific AMP. The
 
staff asked the applicant to explain why a Note B is shown, consistent with the
 
GALL Report with AMP exceptions, instead of Note E; the GALL Report identifies a
 
plant-specific AMP. The applicant has assigned the External Surfaces Monitoring
 
Program to manage loss of material for this component.
 
In its response dated February 8, 2008, the applicant stated that Note B for the 3-379 AMR component cooling coils in LRA Table 3.3.2-12 on page 3.3-160 should be a Note E. Note E is appropriate because GALL Report Volume 2 Item VII.F2-1 that
 
aligns with this AMR line item identifies a plant-specific AMP, while the AMP
 
credited in the LRA, External Surfaces Monitoring Program, is a GALL Report AMP with exceptions. Since a different AMP is credited while the material, environment
 
and aging effect are consistent with the GALL Report, a Note E should have been
 
specified instead of a Note B. The applicant also stated that the LRA line item for
 
this component will be amended to change the note from a B to an E. The staff
 
verified that the applicant amended the LRA in a letter dated March 20, 2008.
 
The staff finds the applicant's response acceptable because the applicant amended
 
the LRA AMR line item for this component designate the correct Note E, instead of
 
B. The evaluation of the use of the External Surfaces Monitoring Program to
 
manage loss of material for the cooling coils (nuclear service cooling water) is
 
provided below.
 
LRA Table 3.3.1, Item 3.3.1-27 states that loss of material of stainless steel HVAC
 
ducting and aluminum HVAC piping, piping components and piping elements in the
 
nuclear service cooling water, auxiliary component cooling water, chemical and
 
volume control and boron recycle, auxiliary building ventilation, and containment
 
building ventilation systems exposed to condensation is managed with either the External Surfaces Monitoring Program, Piping and Duct Internal Inspection Program
 
or the Bolting Integrity Program. During the audit and review, the staff noted that the
 
AMR result items pointing to LRA Table 3.3.1, Item 3.3.1-27, refer to Note E.
 
The staff reviewed the AMR result items referring to Note E and determined that the
 
component type, material, environment, and aging effect are consistent with those
 
of the corresponding line of the GALL Report. However, where the GALL Report
 
recommends a plant-specific AMP, the applicant proposed the External Surfaces
 
Monitoring Program, Piping and Duct Internal Inspection Program or the Bolting
 
Integrity Program depending on the component location. The staff evaluations of the
 
External Surfaces Monitoring Program, Piping and Duct Internal Inspection Program
 
and Bolting Integrity Program are documented in SER Sections 3.0.3.2.5, 3.0.3.2.13, and 3.0.3.3.2, respectively.
 
The VEGP External Surfaces Monitoring Program is a new program that inspects
 
external surfaces of mechanical sy stem components requiring aging management for license renewal in external air environments. Surfaces constructed from
 
materials susceptible to aging in these environments are inspected at frequencies
 
that assure the effects of aging are managed such that system components will perform their intended function during the period of extended operation. The
 
program will be a monitoring program wh ich manages aging effects through periodic visual inspections of external surfaces of components such as piping, piping
 
components, ducting, and other components for evidence of material loss. On the
 
basis of the periodic visual inspections of the piping, piping components, ducting, and other components to detect loss of material, the staff finds the applicant's use of
 
the External Surfaces Monitoring Program for external component surfaces to be
 
acceptable.
 
The VEGP Piping and Duct Inspection Program is a new program that, in part, will
 
manage corrosion of steel, stainless steel, aluminum and copper alloy components.
 
Components included within the scope of this program are not addressed by other 3-380 VEGP aging management programs. The VEGP Piping and Duct Internal Inspection Program will monitor not only component surfaces through visual inspection, but
 
may also use non-visual NDE techniques to monitor parameters such as wall
 
thickness.
 
On the basis of the periodic visual and non-visual technique inspections of the
 
piping, piping components, ducting, and other components to detect loss of material
 
in these stainless steel and aluminum HVAC components, the staff finds the
 
applicant's use of the Piping and Duct Inspection Program acceptable. 
 
The Bolting Integrity Program is a new plant-specific program to manage cracking, loss of material, and loss of preload in mechanical bolted closures. The VEGP
 
Bolting Integrity Program applies to safety-related and nonsafety-related bolting for
 
pressure-retaining components within the scope of license renewal, with the
 
exception of the reactor vessel head studs which are addressed by the Reactor
 
Vessel Head Closure Stud Program. Visual inspections are conducted to detect loss
 
of preload resulting in joint leakage and to detect fastener degradation due to
 
cracking or loss of material. On the basis of the periodic visual inspections of the
 
closure bolting to detect loss of material, the staff finds the applicant's use of the
 
Bolting Integrity Program acceptable. 
 
On the basis of its review of the AMR result items as described in the preceding
 
paragraphs and its comparison of the applicant's results to corresponding
 
recommendations in the GALL Report, the staff finds that the applicant addressed
 
the aging effect or mechanism appropriately as recommended by the GALL Report.
 
  (6) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion for copper alloy fire protection system piping components exposed to
 
internal condensation as an aging effect not applicable because auxiliary system
 
AMRs do not include copper alloy fire protection piping components exposed to an
 
internal condensation environment.
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 staff reviewed LRA Section 3.3.2.2.10 which states that loss of material is not
 
applicable to VEGP copper alloy fire protection system components exposed to
 
internal condensation. The staff noted that the applicant states in LRA Section
 
3.3.2.2.10 that no copper alloy fire protection components exist at VEGP that are
 
exposed to an internal condensation environment. 
 
On the basis of its review, the staff finds that the applicant has provided an
 
acceptable basis for concluding that the criteria of SRP-LR Section 3.3.2.2.10, Item
 
(6) are not applicable to the VEGP LRA because the VEGP design does not include
 
any copper alloy fire protection system components that are exposed to an internal condensation environment.
 
3-381 (7) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion for stainless steel piping components exposed to soil as an aging effect to
 
be managed by the Buried Piping and Tanks Inspection Program.
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.
 
LRA Table 3.3.1, Item 3.3.1-29, states that loss of material due to pitting and crevice
 
corrosion of stainless steel piping components exposed to soil is managed by the
 
Buried Piping and Tanks Inspection Program. During the audit and review, the staff
 
noted that the AMR result item pointing to LRA Table 3.3.1, Item 3.3.1-29, refers to
 
Note E.
The staff reviewed the AMR result item referring to Note E and determined that the
 
component type, material, environment, and aging effect are consistent with those
 
of the corresponding line of the GALL Report. However, where the GALL Report
 
recommends a plant-specific AMP, the applicant proposed the Buried Piping and
 
Tanks Inspection Program. As a result of this determination, the staff reviewed the
 
Buried Piping and Tanks Inspection Program in order to determine whether the
 
program is a valid AMP to credit for the management of loss of material in buried
 
stainless steel auxiliary system pipi ng, piping components and piping elements.
The staff noted the VEGP Buried Piping and Tanks Inspection Program is credited
 
for buried stainless steel piping components in addition to buried steel piping
 
components and tanks. The staff also noted that the program credits visual
 
inspections of the external surfaces of these buried components when the soil or
 
material around the pipe components is excavated for maintenance or when the
 
surfaces are exposed for any other reason. The staff also verified that the program
 
credits a focused inspection of stainless steel buried piping to be performed within
 
ten (10) years after entering the period of extended operation, unless an evaluation
 
determined that sufficient opportunistic and focused inspections have occurred
 
during this time to demonstrate the ability of the underground coatings to protect
 
the underground piping from degradation. The staff also verified that the scope of
 
the program calls for the inspection results to be documented and retained. 
 
The staff also noted that the program element aspects of the applicant's Buried
 
Piping and Tanks Inspection Program (as discussed in the previous paragraph) are consistent with the program elements in GALL AMP XI.M34, "Buried Piping and
 
Tanks Inspection," and that the applicant's crediting of this AMP for aging
 
management is meets the staff's AMR recommendations in SRP-LR Section
 
3.3.2.2.10, Item (5), and in AMR items VII.C1-16, VII.C3-8, VII.G-20, VII.H1-7, and
 
VIIH2-19 of the GALL Report, Volume 2. Based on this review, the staff finds that
 
the applicant has provided an acceptable basis for crediting the Buried Piping and
 
Tanks Inspection Program to manage loss of material due to pitting and crevice
 
corrosion in stainless steel auxiliary sy stem piping, piping components, and piping elements exposed to soil, because the progr am is a GALL-based program that is designed to perform inspection-based condition monitoring of buried piping, piping
 
components, and piping elements, and because the crediting of this AMP satisfies
 
the staff's recommendation that an AMP be evaluated and credited for aging
 
management of loss of material in these components, 3-382  The staff's evaluation of the Buried Piping and Tanks Inspection Program is
 
documented in SER Section 3.0.3.2.2. On the basis of its review of the AMR result
 
item as described in the preceding paragraphs and its comparison of the applicant's
 
results to corresponding recommendations in the GALL Report, the staff finds that 
 
the applicant addressed the aging effect or mechanism appropriately as
 
recommended by the GALL Report.
 
  (8) LRA Section 3.3.2.2.10 addresses loss of material for stainless steel piping components exposed to treated water and sodium pentaborate in BWR standby
 
liquid control systems as an aging effect not applicable to VEGP, a PWR plant.
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 standby liquid contro l system exposed to sodium pentaborate solution.
The staff's recommendations in SRP-LR Section 3.3.2.2.10, Item (8) are only
 
applicable to the management of loss of material in piping components of BWR
 
standby liquid control systems that are exposed to borated water. 
 
Based on this review, the staff finds that the applicant has provided an acceptable basis for
 
concluding that the recommendations in SRP-LR Section 3.3.2.2.10, Item (8) are not
 
applicable to the VEGP LRA, because the VEGP units are Westinghouse-designed PWRs
 
and are not BWR design reactors.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.3.2.2.10 criteria. For those line items that apply to LRA
 
Section 3.3.2.2.10, the staff concludes 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 loss of material for BWR standby liquid control, spent
 
fuel pool cooling and cleanup, reactor water cleanup, and shutdown cooling system copper
 
alloy piping components exposed to treated water as an aging effect not applicable to
 
VEGP, a PWR plant.
 
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.
 
The staff's recommendations in SRP-LR Section 3.3.2.2.11 are only applicable to the
 
management of loss of material in copper alloy piping components of BWR standby liquid
 
control systems, spent fuel pool cooling and cleanup systems, reactor water cleanup
 
systems, and shutdown cooling system that are exposed to treated water.
3-383  Based on this review, the staff finds that the applicant has provided an acceptable basis for
 
concluding that the recommendations in SRP-LR Section 3.3.2.2.11 are not applicable to
 
the VEGP LRA, because the VEGP units are Westinghouse-designed PWRs and are not
 
BWR design reactors.
 
3.3.2.2.12 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced
 
Corrosion
 
The staff reviewed LRA Section 3.3.2.2.12 against the following criteria in SRP-LR
 
Section 3.3.2.2.12:
 
  (1) LRA Section 3.3.2.2.12 addresses loss of material due to pitting, crevice, and microbiologically-influenced corrosion for stainless steel, aluminum, and copper
 
alloy piping components exposed to fuel oil as an aging effect for which the GALL
 
Report recommends a one-time inspection to verify the effectiveness of the fuel oil
 
chemistry control program. The plant-specif ic Diesel Fuel Oil Program manages the aging effect for EDG system components. The One-Time Inspection Program
 
verifies program effectiveness by inspecting selected components at susceptible 
 
locations. The Diesel Fuel Oil Program and the Fire Protection Program will manage
 
the aging effect for copper alloy valve bodies in the fire protection fuel oil system.
SRP-LR Section 3.3.2.2.12 states that loss of material due to pitting and crevice
 
corrosion, and microbiologically-influenced corrosion 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 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.
 
LRA Table 3.3.1, Item 3.3.1-32 states that loss of material of stainless steel, aluminum and copper alloy piping, piping components, and piping elements
 
exposed to fuel oil (except for copper alloy valve bodies in the fire protection fuel oil
 
system) is managed by the Diesel Fuel Oil and One-Time Inspection Programs.
Loss of material for copper alloy valve bodies in the fire protection fuel oil system is
 
managed by the Diesel Fuel Oil and Fire Protection Programs. During the audit and
 
review, the staff noted that the AMR result items pointing to LRA Table 3.3.1, Item
 
3.3.1-32 refer to Note E.
 
The staff reviewed these AMR result items referring to Note E and determined that
 
the component type, material, environment, and aging effect are consistent with
 
those of the corresponding line of the GALL Report. The staff noted that the GALL Report recommends using a combination of GALL AMP XI.M30, "Fuel Oil Chemistry" and GALL AMP XI.M32, "One Time Inspection," as a verification
 
program. The staff noted that the applicant credits its Diesel Fuel Oil Program, 3-384 which is a plant-specific program, to manage loss of material in the stainless steel, aluminum, and copper-alloy auxiliary system components that are exposed to diesel fuel oil and either its One-Time Inspection Program or Fire Protection Program to
 
verify the effectiveness of the Diesel Fuel Oil Program in managing loss of material
 
in the component surfaces that are exposed to diesel fuel oil. 
 
The staff reviewed the Diesel Fuel Oil Program, One-Time Inspection Program and
 
Fire Protection Program that the applicant proposes to use to manage aging effects
 
of stainless steel, aluminum, and copper alloy piping in fuel oil environments. The
 
staff noted that the Diesel Fuel Oil Program is credited and designed to maintain the
 
quality of diesel fuel oil in the diesel fuel oil storage tanks by testing it to standards
 
prior to introducing it into plant's diesel fuel oil storage tanks. The staff noted that
 
the program also performs periodic diesel fuel oil quality testing of the existing fuel
 
oil inventory for water impurity accumulation, biological organisms, and particulates
 
and sediments and that the program has administrative applicant-imposed requirements to invoke corrective actions when the quality of the fuel oil is
 
determined to be out of tolerance with the applicant's fuel oil testing standards. The
 
staff noted that these tests are required through an administrative control program
 
that is within the scope of VEGP Technical Specification No. 5.5.13. The staff finds
 
this to be an acceptable program for managing loss of material in these diesel fuel
 
oil system components because it is consistent with the staff's recommendations in
 
AMR 32 of Table 3 in GALL, Volume 1 and because the program is required to be
 
administratively controlled through Technical Specification No. 5.5.13. 
 
The staff verified that the applicant's One-Time Inspection Program is credited, in
 
part, to confirm the effectiveness of the Diesel Fuel Oil Program in managing loss of
 
material in these emergency diesel generator system components. The staff finds
 
this to be an acceptable program for managing loss of material in these diesel fuel
 
oil system components because it is consistent with the staff's recommendations in
 
AMR 32 of Table 3 in GALL, Volume 1. 
 
The staff noted that the applicant has credited its Fire Protection Program as an
 
alternative program for verifying the effect iveness of the Diesel Fuel Oil Program for those copper alloy valve bodies in the fire protection fuel oil system because the
 
applicant will implement visual inspections for aging effects which will be performed
 
while the fire pump diesel engine is running during fire suppression system pump
 
tests. The staff finds that the greater periodicity of the visual inspections performed
 
under the Fire Protection Program makes the program an acceptable alternative to
 
the One-Time Inspection Program.
 
The staff's evaluations of Diesel Fuel O il Program, One-Time Inspection Program, and Fire Protection Program are discussed in SER Sections 3.0.3.3.3, 3.0.3.1.2, and 3.0.3.2.6, respectively. On the basis of the requirements of the Diesel Fuel Oil
 
Program, One-Time Inspection Program, and Fire Protection Program, the staff
 
concludes these programs will adequately manage the loss of material aging effect
 
of stainless steel, aluminum, and copper alloy piping that are exposed to diesel fuel
 
oil environments through the period of extended operation. 
 
On the basis of its review of the AMR result item as described in the preceding
 
paragraphs and its comparison of the applicant's results to corresponding 3-385 recommendations in the GALL Report, the staff finds that the applicant addressed the aging effect or mechanism appropriately as recommended by the GALL Report.
 
    (2) LRA Section 3.3.2.2.12 addresses loss of material due to pitting, crevice, and microbiologically-influenced corrosion in stainless steel piping components exposed
 
to lubricating oil as an aging effect for which the GALL Report recommends a one-
 
time inspection to verify the effectiveness of the lubricating oil program. Consistent
 
with the GALL Report AMP with exceptions , the Oil Analysis Program and the One-Time Inspection Program will manage the aging effect.
SRP-LR Section 3.3.2.2.12 states that loss of material due to pitting, crevice, and
 
microbiologically-influenced corrosion 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 co rrosion 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 staff reviewed the Oil Analysis Program and the One-Time Inspection Program
 
and determined that the aging effect of loss of material due to pitting, crevice, and
 
microbiologically induced corrosion in stainless steel components exposed to
 
lubricating oil will be effectively managed. The staff concludes that the One-Time
 
Inspection Program is being used to verify the effectiveness of the Oil Analysis
 
Program to manage loss of material due to pitting, crevice, and microbiologically
 
induced corrosion for stainless steel components exposed to lubricating oil. The
 
staff's evaluations of the Oil Analysis Program and the One-Time Inspection
 
Program are documented in SER Sections 3.0.3.2.10 and 3.0.3.1.2, respectively.
 
On the basis of its review, the staff finds that the applicant has met the criteria of
 
SRP-LR Section 3.3.2.2.12 by verifying the effectiveness of the Oil Analysis
 
Program by one-time inspections.
 
On the basis of its review of the AMR result items as described in the preceding
 
paragraphs and its comparison of the applicant's results to corresponding
 
recommendations in the GALL Report, the staff finds that the applicant addressed
 
the aging effect or mechanism appropriately as recommended by the GALL Report.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.3.2.2.12 criteria. For those line items that apply to LRA
 
Section 3.3.2.2.12, the staff concludes 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).
 
3-386 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 loss of material due to wear in elastomer seals and
 
components exposed to an air - indoor (uncontrolled) environment as an aging effect not
 
applicable because auxiliary systems AMR resu lts do not include elastomer seals exposed to any environment conducive to a loss of material due to wear. LRA Section 3.3.2.2.5
 
addresses aging management of elastomer degradation.
 
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 the aging effect is
 
adequately managed.
 
On the basis that VEGP does not have elastomer seals and components exposed to any
 
environment conductive to loss of material due to wear, the staff finds acceptable the
 
applicant's evaluation that this aging effect is not applicable to VEGP.
 
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 loss of material due to cladding breach for steel charging
 
pump casings with stainless steel cladding exposed to borated water as an aging effect not
 
applicable because auxiliary system AMR result s do not include steel pump casings with stainless steel cladding exposed to borated water. VEGP normal charging pump casings
 
are fabricated from stainless steel, not clad carbon steel. 
 
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.
 
On the basis that VEGP does not have stainless steel clad pump casings exposed to
 
treated borated water, the staff finds acceptable the applicant's evaluation that this aging
 
effect is not applicable to VEGP.
 
Based on the above, the staff concludes that the applicant meets SRP-LR
 
Section 3.3.2.2.14 criteria. The staff concludes 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).
 
3.3.2.2.15 Quality Assurance for Aging Management of Nonsafety-Related Components 
 
SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.
 
3-387 3.3.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report In LRA Tables 3.3.2-1 through 3.3.2-32, the staff reviewed additional details of the AMR
 
results for material, environment, AERM, and AMP combinations not consistent with or not
 
addressed in the GALL Report.
 
In LRA Tables 3.3.2-1 through 3.3.2-32, 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.
 
For component type, material, and environment combinations not evaluated in the GALL
 
Report, the staff reviewed the applicant's 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 staff's evaluation is documented in the following sections.
 
3.3.2.3.1  Fuel Storage Racks: New and Spent Fuel - Summary of Aging Management
 
Review - LRA Table 3.3.2-1 
 
LRA Table 3.3.2-1 of the original application was amended on January 20, 2009 and the
 
description below reflects the revision.
 
The staff reviewed LRA Table 3.3.2-1, which summarizes the results of AMR evaluations
 
for the fuel storage racks: new and spent fuel component groups.
 
In LRA Table 3.3.2-1, the applicant's AMR determined that loss of material for Boral in the
 
spent fuel storage racks exposed to an exterior borated water environment was the only
 
aging effect requiring management. This determination is different from the GALL Report, where GALL AMR Item VII.A2-5 identifies the reduction of neutron-absorbing capacity as
 
another applicable aging effect requiring management.
 
The applicant proposed to manage the loss of material for Boral in the spent fuel storage racks exposed to an exterior borated water environment using the Water Chemistry Control
 
Program. The staff's evaluation of the Water Chemistry Control Program is documented in SER Section 3.0.3.1.4. The Water Chemistry Control Program description states that it is
 
an existing program that mitigates loss of material, cracking, and reduction in heat transfer
 
in system components and structures through t he control of water chemistry. The program includes control of detrimental chemical species and the addition of chemical agents. This program is consistent with GALL AMP XI.M2, "Water Chemistry." The staff reviewed the
 
Water Chemistry Control Program which will control the quality of the spent fuel pool
 
borated water to prevent the loss of material of the aluminum cladding for the Boral spent
 
fuel storage racks. On the basis that the quality of the borated spent fuel pool water will be
 
continuously maintained, the staff concludes that the Water Chemistry Control Program will 3-388 adequately manage the aging effect of loss of material through the period of extended operation. On the basis of its review, the staff finds that the aging effect of loss of material
 
for Boral spent fuel storage racks exposed to an exterior borated water environment will be
 
effectively managed by the Water Chemistry Control Program.
 
As described in the original application, the applicant's AMR of this component determined
 
that reduction of neutron absorbing capacity was not an aging effect requiring
 
management. The staff questioned the rationale provided by the licensee in RAIs dated
 
November 18, 2008.
 
As revised by submittal on January 20, 2009, the applicant proposed, in LRA Table 3.3.2-1, to manage the reduction of neutron-absorbing capacity with a One-Time Inspection
 
Program. The staff reviewed the response, as evaluated in Section 3.3.2.2.6, and has
 
concluded that the neutron-absorbing capacity will be adequately managed in the period of
 
extended operation. 
 
On the basis of its review, the staff finds that the applicant has appropriately evaluated the
 
AMR results for the spent fuel storage racks 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  Spent Fuel Pool Cooling and Purification System: Summary of Aging
 
Management Review - LRA Table 3.3.2-2 
 
The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations
 
for the spent fuel pool cooling and purification system component groups.
 
In LRA Table 3.3.2-2, the applicant proposed to manage loss of preload for stainless steel
 
closure bolting exposed to an external environment of indoor air using the Bolting Integrity
 
Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e. in Appendix A of the SRP-LR [NUREG-1800, Revision 1]). 
 
On the basis of its review, the staff finds that, because these components will be inspected
 
periodically, the aging effect of loss of preload of stainless steel closure bolting exposed to
 
an external environment of indoor air will be effectively managed by the Bolting Integrity 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 3-389 will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.3.2.3.4  Nuclear Service Cooling Wate r Systems: Summary of Aging Management Review - LRA Table 3.3.2-4 
 
In LRA Table 3.3.2-4, the applicant proposed to manage loss of material for either carbon
 
steel or stainless steel closure bolting exposed to an external environment of air subject to being wetted with raw water, using the Bolting Integrity Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of material of either carbon steel or stainless 
 
steel closure bolting exposed to an external environment of air subject to being wetted with
 
raw water will be effectively managed by the Bolting Integrity Program.
 
In LRA Table 3.3.2-4, the applicant proposed to manage loss of preload for either carbon
 
steel or stainless steel closure bolting exposed to either an external air (outdoor or indoor)
 
environment or external environment of raw water using the Bolting Integrity Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). 
 
On the basis of its review, the staff finds that, because these components will be inspected
 
periodically, the aging effect of loss of preload of carbon steel closure bolting exposed to
 
either an external air (outdoor or indoor) envir onment or external environment of raw water will be effectively managed by the Bolting Integrity Program.
 
In LRA Table 3.3.2-4, the applicant proposed to manage cracking for stainless steel closure
 
bolting exposed to an external environment of air (outdoor) subject to being wetted with raw
 
water, using the Bolting Integrity Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific 3-390 program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of cracking of stainless steel closure bolting exposed
 
to an external environment of air (outdoor) subject to being wetted with raw water will be
 
effectively managed by the Bolting Integrity Program.
 
In LRA Table 3.3.2-4, the applicant proposed to manage loss of material for nickel alloy
 
piping components exposed to an external environment of air (indoor) with condensation, using the External Surfaces Monitoring Program.
 
The staff verified that the VEGP External Surfaces Monitoring Program is a new program
 
that inspects external surfaces of mechanical system components requiring aging
 
management for license renewal in external ai r environments. Surfaces constructed from materials susceptible to aging in these environments are inspected at frequencies that
 
assure the effects of aging are managed such that system components will perform their intended function during the period of extended operation. The program will be a monitoring
 
program, which manages aging effects through periodic visual inspections of external
 
surfaces of components such as piping, piping components, ducting, and other components
 
for evidence of material loss. The staff's evaluation of the External Surfaces Monitoring
 
Program is documented in SER Section 3.0.3.3.5. On the basis of its review, the staff finds
 
that because these components will be inspected periodically, the aging effect of loss of
 
material for nickel alloy piping components exposed to an external environment of air (indoor) with condensation will be effectively managed by the External Surfaces Monitoring
 
Program.
 
In LRA Table 3.3.2-4, the applicant proposed to manage change in material property (cracking) for PVC piping components exposed to an internal environment of air (indoor) or
 
external environment of air (outdoor), using the External Surfaces Monitoring Program.
 
The staff verified that the VEGP External Surfaces Monitoring Program is a new program
 
that inspects external surfaces of mechanical system components requiring aging
 
management for license renewal in external ai r environments. Surfaces constructed from materials susceptible to aging in these environments are inspected at frequencies that
 
assure the effects of aging are managed such that system components will perform their intended function during the period of extended operation. The program will be a monitoring
 
program, which manages aging effects through periodic visual inspections of external
 
surfaces of components such as piping, piping components, ducting, and other components
 
for evidence of material loss. The staff's evaluation of the External Surfaces Monitoring
 
Program is documented in SER Section 3.0.3.3.5. On the basis of its review, the staff finds
 
that because these components will be inspected periodically, the aging effect of change in
 
material property (cracking) for PVC piping components exposed to an internal environment of air (indoor) or external environment of air (outdoor) will be effectively managed by the External Surfaces Monitoring Program.
3-391  In LRA Table 3.3.2-4, the applicant proposed to manage change in material property (cracking) for PVC piping components exposed to an internal environment of drainage (dirty) or an internal environment of raw water, using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2  The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the nuclear service cooling water system within
 
the scope of the One-Time Inspection Program to confirm that the aging effect of change in
 
material property (cracking) in an interior environment for PVC piping components exposed to an internal environment of drainage (dirty) is managed. On the basis of its review, the
 
staff finds that the aging effect of change in material property (cracking) for PVC piping
 
components exposed to an interior drainage (dir ty) environment or an internal environment of raw water will be effectively managed by the One-Time Inspection Program.
 
In LRA Table 3.3.2-4, the applicant stated that PVC piping components exposed either to
 
an external soil environment or an interior treated water environment do not exhibit any aging effects requiring management. PVC, unlike metals, do not display corrosion rates and
 
depend on chemical resistance to the environment to which they are exposed. On this
 
basis, the staff finds that PVC piping components, exposed either to an external soil
 
environment or interior treated water env ironment exhibit no aging effects, and the component or structure will remain capable of performing intended functions consistent with
 
the CLB for the period of extended operation.
 
In LRA Table 3.3.2-4, the applicant stated that stainless steel piping components, pump
 
casings, flow orifices/elements and valve bodies exposed to either an internal air (indoor
 
and outdoor) environment or an external air (outdoor) environment do not exhibit any aging effects requiring management. The staff finds this acceptable because stainless steel is
 
highly resistant to corrosion in dry air in the absence of corrosive species, as cited in the
 
Metals Handbook, Volume 3 (p. 65) and Volume 13 (p. 555) (Ninth Edition, American
 
Society for Metals International, 1980 and 1987). Therefore, stainless steel in an internal air (indoor and outdoor) environment or an external air (outdoor) environment exhibits no aging effect, and the component or structure will remain capable of performing intended functions
 
consistent with the CLB for the period of extended operation.
 
In LRA Table 3.3.2-4, the applicant proposed to manage loss of material for stainless steel
 
piping components, pump casings, flow orif ice/elements and valve bodies, carbon steel piping components and valve bodies or copper alloy spray nozzles, oil coolers and piping
 
components exposed to an external environment of air subject to being wetted with raw
 
water, using the External Surfaces Monitoring Program.
 
The staff verified that the VEGP External Surfaces Monitoring Program is a new program
 
that inspects external surfaces of mechanical system components requiring aging
 
management for license renewal in external ai r environments. Surfaces constructed from materials susceptible to aging in these environments are inspected at frequencies that
 
assure the effects of aging are managed such that system components will perform their intended function during the period of extended operation. The program will be a monitoring
 
program, which manages aging effects through periodic visual inspections of external
 
surfaces of components such as piping, piping components, ducting, and other components
 
for evidence of material loss. The staff's evaluation of the External Surfaces Monitoring 3-392 Program is documented in SER Section 3.0.3.3.5. On the basis of its review, the staff finds that because these components will be inspected periodically, the aging effect of loss of
 
material for stainless steel piping components, pump casings, flow orifice/elements and
 
valve bodies, carbon steel piping components and valve bodies or copper alloy spray
 
nozzles, oil coolers and piping components ex posed to an external environment of air (outdoor) subject to being wetted with raw water will be effectively managed by the External
 
Surfaces Monitoring Program.
 
The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations
 
for the nuclear service cooling water systems component groups.
 
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).
 
3.3.2.3.5  Component Cooling Water System
: Summary of Aging Management Review -
LRA Table 3.3.2-5 
 
The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations
 
for the component cooling water system component groups.
 
During the audit and review, the staff noted that in LRA Table 3.3.2-5,on page 3.3-106, the
 
AMR line item component closure bolting, material stainless steel in an air-indoor (exterior)
 
environment, aging effect loss of preload, AMP Bolting Integrity Program, LRA Table 1
 
none, GALL Report item none, Note H, is shown twice. The staff asked the applicant to
 
explain why the line item is shown twice since the component is identical and also the
 
material, environment, aging effect and aging management program.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that the duplication of the line item in LRA Table
 
3.3.2-5 on page 3.3-106 was an error and one of the line items would be removed from
 
LRA Table 3.3.2-5. 
 
The applicant also stated that the LRA will be amended to remove one of the duplicate
 
AMR line items shown on LRA page 3.3-106. The staff confirmed that the applicant
 
amended the LRA in a letter dated March 20, 2008.
 
The staff finds the applicant's response acceptable since one of the duplicate AMR line
 
items for this component will be removed from the LRA. 
 
The evaluation of the use of the Bolting Integrity Program to manage loss of preload for the
 
closure bolting is provided below.
In LRA Table 3.3.2-5, the applicant proposed to manage loss of preload for stainless steel closure bolting exposed to an external environment of indoor air using the Bolting Integrity
 
Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, 3-393 and loss of preload both safety-related and nonsafety-related closure bolting for pressure-retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload of stainless steel closure bolting
 
exposed to an external environment of indoor air will be effectively managed by the Bolting Integrity Program.
 
In LRA Table 3.3.2-5, the applicant proposed to manage the loss of material for carbon
 
steel shells of CCW pump motor coolers ex posed to an interior air-ventilation environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the component cooling water system within the
 
scope of the One-Time Inspection Program to confirm that the aging effect of loss of
 
material in an interior air-ventilation environment is either not present or is proceeding very
 
slowly. In addition, the staff confirmed that the declaration that stainless steel components
 
exposed to an inside environment in a control room ventilation system experience no aging effects has been previously accepted by the staff in the Farley Nuclear Plant license
 
renewal application SER (NUREG-1825). The air/gas environment for the Farley control
 
room ventilation system is analogous to the interior air-ventilation environment. On the basis of its review, the staff finds that the aging effect of loss of material for carbon steel
 
shells of CCW pump motor coolers exposed to an interior air-ventilation environment will be effectively managed by the One-Time Inspection Program.
 
During the audit and review, the staff noted that in LRA Table 3.3.2-5 on page 3.3-109, the
 
AMR line item component CCW pump motor cool er tubesheets is exposed to an exterior air-ventilation environment. The staff asked the applicant to explain how these tubesheets
 
are exposed to an air-ventilation environment.
 
The applicant provided its response to the staff's question in a letter dated February 8, 2008. In its response, the applicant stated that the CCW pump motors are totally-enclosed
 
water-cooled motors. Each motor is cooled by recirculating internal air through a heat
 
exchanger which in turn is cooled by nuclear service cooling water. Fans internal to the
 
motor circulate the air through the rotor and stator and through the heat exchanger in a
 
closed recirculating loop. The heat exchanger is provided with condensate drains and
 
because the air is recirculated through the cooler and is dehumidified by draining off any
 
moisture that condenses on the heat exchanger tubes, the air internal to the heat
 
exchanger is considered to be air-ventilation. 
 
The staff finds the applicant's response acceptable because it adequately clarifies how the
 
CCW pump motor tubesheets are exposed to an air-ventilation environment. The evaluation of the applicant's declaration that copper alloy tubesheets of CCW pump motor coolers 3-394 exposed to an exterior air-ventilation environment do not exhibit any aging effects requiring management is provided below.
 
In LRA Table 3.3.2-5, the applicant stated that copper alloy tubesheets of CCW pump
 
motor coolers exposed to an exterior air-v entilation environment do not exhibit any aging effects requiring management. There is no corresponding GALL Report Table 1 line item or
 
GALL Report Volume 2 Chapter VII line item for this material/environment combination.
 
However, GALL Report Volume 2 does contain line item SP-6 for steam and power
 
conversion systems which applies to copper alloy piping, piping components, and piping
 
elements in an external indoor uncontrolled air environment. This GALL Report Volume 2
 
line item documents that there are no aging effects for this material/environment
 
combination. Because the GALL Report does not identify any aging effects requiring
 
management for copper alloy piping, piping components, and piping elements exposed to
 
indoor uncontrolled air which is either the same or a more aggressive environment than the
 
exterior air-ventilation environment for this copper alloy line item, the staff finds it
 
acceptable that there are no aging effects. Therefore, the staff concludes that copper alloy
 
tubesheets of CCW pump motor coolers exposed to an exterior air-ventilation environment do not exhibit aging effects requiring management. 
 
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  Auxiliary Component Cooling Wa ter System: Summary of Aging Management Review - LRA Table 3.3.2-6 
 
The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations
 
for the auxiliary component cooli ng water system component groups.
 
In LRA Table 3.3.2-6, the applicant proposed to manage loss of preload for stainless steel
 
closure bolting exposed to an external air (indoor) environment using the Bolting Integrity
 
Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e.; in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload of stainless steel closure bolting
 
exposed to an external air (indoor) environment will be effectively managed by the Bolting Integrity Program.
 
3-395 In LRA Table 3.3.2-6, the applicant proposed to manage cracking for carbon steel piping components (including startup strainer spools), pump casings, heat exchanger shells and
 
tubesheets, ACCW pump motor cooler channel heads, tanks (chemical addition and surge),
and valve bodies in the auxiliary component coo ling water system exposed to an internal environment of closed-cycle cooling wate r using the ACCW System Carbon Steel Components Program.
 
The staff's evaluation of the ACCW System Carbon Steel Component Program which is a new plant-specific program is documented in SER Section 3.0.3.3.1. The ACCW System
 
Carbon Steel Component Program description states that periodic visual inspections and
 
leakage monitoring of carbon steel component s exposed to auxiliary component cooling water are performed. The program is in response to VEGP operating experience related to
 
nitrite induced SCC leading to subsequent component leakage. The program includes
 
periodic and routine walkdowns performed by qualified personnel and continuous system leak detection. The leak detection includes monitoring for ACCW surge tank low-level
 
conditions which is an alarmed function. On the basis of its review, the staff finds that
 
because these components will be inspected periodically, and that leak detection is
 
continuously performed, the aging effect of cracking for carbon steel piping components (including startup strainer spools), pump casings, heat exchanger shells and tubesheets, ACCW pump motor cooler channel heads, tanks (chemical addition and surge), and valve
 
bodies exposed to an internal environment of cl osed-cycle cooling water will be effectively managed by the ACCW System Carbon Steel Component Program.
 
In LRA Table 3.3.2-6, the applicant proposed to manage loss of material for stainless steel
 
flow orifice/elements exposed to an external environment of air with condensation, using the External Surfaces Monitoring Program.
 
The staff verified that the VEGP External Surfaces Monitoring Program is a new program
 
that inspects external surfaces of mechanical system components requiring aging
 
management for license renewal in external ai r environments. Surfaces constructed from materials susceptible to aging in these environments are inspected at frequencies that
 
assure the effects of aging are managed such that system components will perform their intended function during the period of extended operation. The program will be a monitoring
 
program, which manages aging effects through periodic visual inspections of external
 
surfaces of components such as piping, piping components, ducting, and other components
 
for evidence of material loss. The staff's evaluation of the External Surfaces Monitoring
 
Program is documented in SER Section 3.0.3.3.5. On the basis of its review, the staff finds
 
that because these components will be inspected periodically, the aging effect of loss of
 
material for stainless steel flow orifice/el ements exposed to an external environment of air with condensation will be effectively managed by the External Surfaces Monitoring
 
Program.
 
In LRA Table 3.3.2-6, the applicant stated that copper alloy ACCW pump motor cooler
 
tubes and tubesheets exposed to an air (exterior) environment do not exhibit any aging
 
effects requiring management. The staff finds this acceptable because the GALL Report
 
does not identify any aging effects requiring management for copper alloy less than 15
 
percent Zn component types exposed to air with borated water leakage which is a more
 
aggressive environment than the air (exterior) environment in these line items. Therefore, copper alloy in an air (exterior) environment exhibits no aging effect, and the component or
 
structure will remain capable of performing intended functions consistent with the CLB for
 
the period of extended operation.
3-396  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  River Intake Structure System: Summary of Aging Management Review -
 
LRA Table 3.3.2-8 
 
The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations
 
for the river intake structure system component groups.
 
In LRA Table 3.3.2-8, the applicant proposed to manage loss of material for carbon steel
 
closure bolting exposed to an external environment of outdoor air (wetted) using the Bolting Integrity Program. 
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of material of carbon steel closure bolting
 
exposed to an external environment of outdoor air (wetted) will be effectively managed by the Bolting Integrity Program.
 
In LRA Table 3.3.2-8, the applicant proposed to manage loss of preload for carbon steel
 
closure bolting exposed to an external environment of air-outdoor using the Bolting Integrity
 
Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload of carbon steel closure bolting
 
exposed to an external environment of ai r-outdoor will be effectively managed by the Bolting Integrity Program.
 
3-397 In LRA Table 3.3.2-8, the applicant proposed to manage loss of material for carbon steel piping components and valve bodies exposed to an external environment of outdoor air (wetted) using the External Surfaces Monitoring Program.
 
The staff verified that the VEGP External Surfaces Monitoring Program is a new program
 
that inspects external surfaces of mechanical system components requiring aging
 
management for license renewal in external ai r environments. Surfaces constructed from materials susceptible to aging in these environments are inspected at frequencies that
 
assure the effects of aging are managed such that system components will perform their intended function during the period of extended operation. The program will be a monitoring
 
program, which manages aging effects through periodic visual inspections of external
 
surfaces of components such as piping, piping components, ducting, and other components
 
for evidence of material loss. The staff's evaluation of the External Surfaces Monitoring
 
Program is documented in SER Section 3.0.3.3.5. On the basis of its review, the staff finds
 
that because these components will be inspected periodically, the aging effect of loss of
 
material for carbon steel piping components and valve bodies exposed to an external
 
environment of outdoor air (wetted) will be e ffectively managed by the External Surfaces Monitoring 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).
 
3.3.2.3.9  Compressed Air Systems: Summary of Aging Management Review -
 
LRA Table 3.3.2-9 
 
The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations
 
for the compressed air systems component groups.
 
In LRA Table 3.3.2-9, the applicant proposed to manage loss of preload for stainless steel
 
closure bolting exposed to an external air (indoor) environment using the Bolting Integrity
 
Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload of stainless steel closure bolting
 
exposed to an external air (indoor) environment will be effectively managed by the Bolting Integrity Program.
 
3-398 On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the
 
GALL Report. The staff finds that the applicant has demonstrated that the effects of aging
 
will be adequately managed so that the intended function(s) will be maintained consistent
 
with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.3.2.3.10  Chemical and Volume Control and Boron Recycle Systems: Summary of Aging
 
Management Review - LRA Table 3.3.2-10 
 
The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations
 
for the chemical and volume control boron recycle systems component groups.
 
In LRA Table 3.3.2-10, the applicant proposed to manage loss of preload for stainless steel
 
closure bolting exposed to an external environment of indoor air using the Bolting Integrity
 
Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload of stainless steel closure bolting
 
exposed to an external environment of indoor air will be effectively managed by the Bolting Integrity Program.
 
In LRA Table 3.3.2-10, the applicant proposed to manage cracking for carbon steel shells
 
of excess letdown, letdown chiller, letdown, and seal water heat exchangers exposed to an
 
internal environment of closed cycle cooling water from the Auxiliary Component Cooling Water System (ACCW) using the ACCW System Carbon Steel Components Program.
 
The staff's evaluation of the ACCW Syst em Carbon Steel Components Program is documented in SER Section 3.0.3.3.1. The ACCW System Carbon Steel Components
 
Program description states cracking of carbon steel components exposed to auxiliary component cooling water is managed through a combination of leakage monitoring, routine
 
walkdowns and periodic visual inspections. The program is in response to operating
 
experience related to nitrite induced stress corrosion cracking (SCC) and subsequent
 
component leakage in the VEGP ACCW system components. This program is a plant-specific program. On the basis of its review, the staff finds that because these components
 
will be inspected periodically, the aging effect of cracking for carbon steel shells of excess
 
letdown, letdown chiller, letdown, and seal water heat exchangers exposed to an internal 
 
environment of closed cycle cooling water fr om the ACCW system will be effectively managed by the ACCW System Ca rbon Steel Components Program.
 
3-399 In LRA Table 3.3.2-10, the applicant proposed to manage loss of material from erosion for stainless steel letdown orifices and piping components exposed to an internal environment of borated water with a high differential pressure using the Inservice Inspection Program.
 
The staff's evaluation of the Inservice Inspection Program is documented in SER Section
 
3.0.3.3.4. The Inservice Inspection Program description states the program manages
 
cracking, loss of material, loss of preload, and loss of fracture toughness in components
 
crediting the program. The program uses periodic visual, surface, and volumetric
 
examination and leakage tests of Class 1, 2 and 3 pressure-retaining components, their
 
integral attachments, and supports to detect and characterize flaws. VT-1 visual
 
examinations are used to detect discontinuities and imperfections on the surfaces of
 
components, including such conditions as cracks, wear, corrosion, or erosion. This program
 
is a plant-specific program. On the basis of its review, the staff finds that because these
 
components will be inspected periodically, the aging effect of loss of material form erosion
 
for stainless steel letdown orifices and piping components exposed to an internal
 
environment of borated water with a high differential pressure will be effectively managed
 
by using the Inservice Inspection Program.
 
In LRA Table 3.3.2-10, the applicant proposed to manage the loss of material for carbon
 
steel shells of normal charging pump motor coolers exposed to an interior air-ventilation
 
environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the chemical and volume control and boron
 
recycle system within the scope of the One-Time Inspection Program to confirm that the
 
aging effect of loss of material in an interior air-ventilation environment is either not present
 
or is proceeding very slowly. In addition, the staff confirmed that the declaration that
 
stainless steel components exposed to an inside environment in a control room ventilation system experience no aging effects has been previ ously accepted by the staff in the Farley Nuclear Plant license renewal application SER (NUREG-1825). The air/gas environment for
 
the Farley control room ventilation system is analogous to the interior air-ventilation environment. 
 
On the basis of its review, the staff finds that the aging effect of loss of material for carbon
 
steel shells of normal charging pumps motor coolers exposed to an interior air-ventilation
 
environment will be effectively managed by the One-Time Inspection Program.
 
In LRA Table 3.3.2-10, the applicant proposed to manage cracking for carbon steel piping
 
components and valve bodies exposed to an inter nal environment of closed cycle cooling water from the ACCW using the ACCW System Carbon Steel Components Program.
 
The staff's evaluation of the ACCW Syst em Carbon Steel Components Program is documented in SER Section 3.0.3.3.1. The ACCW System Carbon Steel Components
 
Program description states cracking of carbon steel components exposed to auxiliary component cooling water is managed through a combination of leakage monitoring, routine
 
walkdowns and periodic visual inspections. The program is in response to operating
 
experience related to nitrite induced SCC and subsequent component leakage in the VEGP
 
ACCW system components. This program is a pl ant-specific program. On the basis of its review, the staff finds that because these components will be inspected periodically, the 3-400 aging effect of cracking for carbon steel piping components and valve bodies exposed to an internal environment of closed cycle cooling wa ter from the ACCW system will be effectively managed by the ACCW System Ca rbon Steel Components Program.
 
In LRA Table 3.3.2-10, the applicant proposed to manage change in material properties, for
 
which the applicant includes cracking, for PVC pump casings of zinc addition injection
 
pumps exposed to an external environment of indoor air using the External Surfaces Monitoring Program.
 
The staff verified that the VEGP External Surfaces Monitoring Program is a new program
 
that inspects external surfaces of mechanical system components requiring aging
 
management for license renewal in external ai r environments. Surfaces constructed from materials susceptible to aging in these environments are inspected at frequencies that
 
assure the effects of aging are managed such that system components will perform their intended function during the period of extended operation. The program will be a monitoring
 
program, which manages aging effects through periodic visual inspections of external
 
surfaces of components such as piping, piping components, ducting, and other components
 
for evidence of material loss. The staff's evaluation of the External Surfaces Monitoring
 
Program is documented in SER Section 3.0.3.3.5. On the basis of its review, the staff finds
 
that because these components will be inspected periodically, the aging effect of change in
 
material properties for PVC pump casings of zinc addition injection pumps exposed to an
 
external environment of indoor air will be e ffectively managed by the External Surfaces Monitoring Program.
 
In LRA Table 3.3.2-10, the applicant stated that PVC pump casings of zinc addition
 
injection pumps exposed to an interior treat ed water environment do not exhibit any aging effects requiring management. There is no corresponding GALL Report Table 1 line item or
 
GALL Report Volume 2 Chapter VII line item for this material/environment combination. The
 
staff finds this acceptable because there is no indication in the industry that PVC or
 
thermoplastics exposed to a treated water in ternal environment have any aging effects requiring management. The generally low operating temperatures and historical good
 
chemical resistance data for PVC components, combined with a lack of historic negative
 
operating experience, indicate that PVC is not likely to experience any degradation from the
 
treatment chemicals used in the water. PVC materials do not display corrosion rates as
 
metals do, but rather rely on chemical resi stance to the environments to which they are exposed. Therefore, based on industry experience and the assumption of proper design
 
and application of the material, the staff finds that PVC pump casings of zinc addition
 
injection pumps exposed to an interior treat ed water environment exhibit no aging effects requiring management for the period of extended operation.
 
On the basis of its review, the staff finds that the applicant has appropriately evaluated the
 
AMR results of material, environment, AERM, and AMP combinations not 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  Ventilation Systems - Control Building (CB): Summary of Aging Management Review - LRA Table 3.3.2-11 
 
The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations
 
for the ventilation systems - control building (CB) component groups.
3-401  In LRA Table 3.3.2-11, the applicant proposed to manage the loss of material for carbon
 
steel damper housings, duct silencer housi ngs, fan housings, and heater housings exposed to an interior air-ventilation environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the control building ventilation system within the
 
scope of the One-Time Inspection Program to confirm that the aging effect of loss of
 
material in an interior air-ventilation environment is either not present or is proceeding very
 
slowly. In addition, the staff confirmed that the aging management of loss material for
 
carbon steel exposed to an air/gas environment in a control room ventilation system by the One-Time Inspection Program has been previous ly accepted by the staff in other LRA reviews. The air/gas environment for the Far ley control room ventilation system is analogous to the interior air-ventilation environment. On the basis of its review, the staff
 
finds that the aging effect of loss of material for carbon steel damper housings, duct
 
silencer housings, fan housings, and heater housings exposed to an interior air-ventilation
 
environment will be effectively managed by the One-Time Inspection Program.
 
In LRA Table 3.3.2-11, the applicant proposed to manage loss of preload for stainless steel
 
closure bolting exposed to an external air (indoor) environment using the Bolting Integrity
 
Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload of stainless steel closure bolting
 
exposed to an external air (indoor) environment will be effectively managed by the Bolting Integrity Program.
 
In LRA Table 3.3.2-11, the applicant stated that stainless steel control room filter, fan unit
 
housings, and ductwork, fittings in the control building ventilation system exposed to an
 
internal air-ventilation environment do not ex hibit any aging effects requiring management.
The staff finds this acceptable because stainless steel is highly resistant to corrosion in dry
 
air in the absence of corrosive species, as cited in the Metals Handbook, Volume 3 (p. 65)
 
and Volume 13 (p. 555) (Ninth Edition, American Society for Metals International, 1980 and
 
1987). Therefore, stainless steel in an inter nal air-ventilation environment exhibits no aging effect, and the component or structure will remain capable of performing intended functions
 
consistent with the CLB for the period of extended operation.
 
In LRA Table 3.3.2-11, the applicant stated that fiber, foam and ceramic control room filter
 
and fan unit moisture eliminators exposed to an exterior ventilation-air environment do not 3-402 exhibit aging effects requiring management. The applicant stated that there has never been any plant-specific aging effect noted for these components. The staff's review of site
 
operating experience did not identify any aging effects for these components at VEGP. On
 
the basis of its review of current industry research and current plant operating experience, the staff concludes that fiber, foam and ceramic control room filter and fan unit moisture
 
eliminators exposed to an exterior ventilati on-air environment at VEGP do not exhibit aging effects requiring management.
 
In LRA Table 3.3.2-11, the applicant proposed to manage change in material properties, for
 
which the applicant includes hardening, loss of strength and cracking; for elastomer flexible
 
connectors exposed to an interior air-ventilation environment using the Piping and Duct
 
Internal Inspection Program.
 
The staff verified that the applicant's Piping and Duct Internal Inspection Program is a new
 
program and has been identified as an AMP that is consistent with program elements in GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components", with exceptions. The staff also verified that like GALL AMP XI.M20, "Open-
 
Cycle Cooling Water System", the scope of the applicant's program, in part, credits visual
 
examinations to manage corrosion in the internal surfaces of stainless steel piping
 
components that are exposed internally to raw water. The staff also verified that the
 
applicant has addressed the need to implement this AMP in accordance with LRA
 
Commitment No. 19, which was placed on UFSAR Supplement Section A.2.22 and
 
provided in the applicant's letter of March 20, 2008. The staff's evaluation of the Piping and
 
Duct Internal Inspection Program is documented in SER Section 3.0.3.2.13. On the basis of
 
its review, the staff finds that the aging effect change in material properties, for which the
 
applicant includes hardening, loss of strength and cracking for elastomer flexible
 
connectors exposed to an interior air-ventila tion environment will be effectively managed by the Piping and Duct Internal Inspection Program.
 
In LRA Table 3.3.2-11, the applicant proposed to manage the loss of material for carbon
 
steel piping components exposed to an interi or clean drainage environment using the One-Time Inspection Program.
The staff's evaluation of the One-Time Inspection Program is documented in SER Section 3.0.3.1.2. The staff's evaluation described in SER Section 3.0.3.2.13 includes the staff's
 
basis why the Piping and Duct Internal Inspection Program may be used to manage the
 
aging effects that are applicable to elastome ric components in the auxiliary systems. The One-Time Inspection Program description states that one-time inspections are to be used
 
to confirm the slow progression or the absence of an aging effect. The staff confirmed that
 
the applicant has included the control building ventilation system within the scope of the
 
One-Time Inspection Program to confirm that the aging effect of loss of material in an
 
interior clean drainage environment is either not present or is proceeding very slowly. On the basis of its review, the staff finds that the aging effect of loss of material for carbon steel
 
piping components exposed to an interior cl ean drainage environment will be effectively managed by the One-Time Inspection Program.
In LRA Table 3.3.2-11, the applicant stated that copper alloy piping components exposed to an internal air-ventilation environment do not exhibit any aging effects requiring management. The staff finds this acceptable because the GALL Report does not identify
 
any aging effects requiring management for copper alloy less than 15 percent Zn
 
component types exposed to air with borated water leakage which is a more aggressive 3-403 environment than the air (exterior) environment in these line items. Therefore, copper alloy in an internal air-ventilation environment ex hibits no aging effect, and the component or structure will remain capable of performing intended functions consistent with the CLB for
 
the period of extended operation.
 
On the basis of its review, the staff finds that the applicant has appropriately evaluated the
 
AMR results of material, environment, AERM, and AMP combinations not 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  Ventilation Systems - Auxiliary Building (AB): Summary of Aging Management Review - LRA Table 3.3.2-12 
 
The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations
 
for the ventilation systems - auxilia ry building (AB) component groups.
 
In LRA Table 3.3.2-12, the applicant proposed to manage loss of preload for stainless steel
 
closure bolting exposed to an external environment of indoor air using the Bolting Integrity
 
Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload of stainless steel closure bolting
 
exposed to an external environment of indoor air will be effectively managed by the Bolting Integrity Program.
 
In LRA Table 3.3.2-12, the applicant proposed to manage the loss of material for carbon
 
steel damper housings, fan housings, piping penetration area cooler housings, piping
 
penetration filter and fan unit housings, and room cooler housings exposed to an interior
 
air-ventilation environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the aux iliary building ventilation system within the scope of the One-Time Inspection Program to confirm that the aging effect of loss of
 
material in an interior air-ventilation environment is either not present or is proceeding very
 
slowly. In addition, the staff confirmed that the declaration that stainless steel components
 
exposed to an inside environment in a control room ventilation system experience no aging effects has been previously accepted by the staff in the Farley Nuclear Plant license
 
renewal application SER (NUREG-1825). The air/gas environment for the Farley control 3-404 room ventilation system is analogous to the interior air-ventilation environment. On the basis of its review, the staff finds that the aging effect of loss of material for carbon steel
 
damper housings, fan housings, piping penetration area cooler housings, piping penetration
 
filter and fan unit housings, and room cooler housings exposed to an interior air-ventilation
 
environment will be effectively managed by the One-Time Inspection Program.
 
In LRA Table 3.3.2-12, the applicant stated that stainless steel ductwork and fittings and
 
piping penetration filter and fan unit housings exposed to an interior air-ventilation
 
environment do not exhibit any aging e ffects requiring management. There is no corresponding GALL Report Table 1 line item or GALL Report Volume 2 Chapter VII line
 
item for this material/environment combination. However, GALL Report Volume 2 does
 
contain line item AP-17 for auxiliary systems wh ich applies to stainless steel piping, piping components, and piping elements in an exter nal indoor uncontrolled air environment. This GALL Report Volume 2 line item documents that there are no aging effects for this
 
material/environment combination. Because the GALL Report does not identify any aging
 
effects requiring management for stainless steel piping, piping components, and piping
 
elements exposed externally to indoor uncontrolled air which is either the same or a more
 
aggressive environment than the interior ai r-ventilation environment for these stainless steel line items, the staff finds it acceptable that there are no aging effects. In addition, the
 
staff confirmed that the declaration that stainless steel components exposed to an inside
 
environment in a control room ventilation system experience no aging effects has been previously accepted by the staff in the Farley Nuclear Plant license renewal application
 
SER (NUREG-1825). The inside environment for the Farley control room ventilation system is analogous to the interior air-ventilation environment for the stainless steel ductwork and
 
fittings and piping penetration filter and fan unit housings components at VEGP. Therefore, the staff concludes that stainless steel ductwork and fittings and piping penetration filter and
 
fan unit housings exposed to an interior air-ventilation environment do not exhibit aging
 
effects requiring management. 
 
In LRA Table 3.3.2-12, the applicant proposed to manage change in material properties, for
 
which the applicant includes hardening, loss of strength and cracking; for elastomer flexible
 
connectors exposed to an interior air-ventilation environment using the Piping and Duct
 
Internal Inspection Program.
 
The staff verified that the applicant's Piping and Duct Internal Inspection Program is a new
 
program and has been identified as an AMP that is consistent with program elements in GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components", with exceptions. The staff also verified that like GALL AMP XI.M20, "Open-
 
Cycle Cooling Water System", the scope of the applicant's program, in part, credits visual
 
examinations to manage corrosion in the internal surfaces of stainless steel piping
 
components that are exposed internally to raw water. The staff also verified that the
 
applicant has addressed the need to implement this AMP in accordance with LRA
 
Commitment No. 19, which was placed on UFSAR Supplement Section A.2.22 and
 
provided in the applicant's letter of March 20, 2008. The staff's evaluation of the Piping and
 
Duct Internal Inspection Program is documented in SER Section 3.0.3.2.13. On the basis of
 
its review, the staff finds that the aging effect change in material properties, for which the
 
applicant includes hardening, loss of strength and cracking; for elastomer flexible
 
connectors exposed to an interior air-ventila tion environment will be effectively managed by the Piping and Duct Internal Inspection Program.
 
3-405 In LRA Table 3.3.2-12, the applicant proposed to manage the loss of material for carbon steel piping components exposed to an interi or clean drainage environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The staff's evaluation described in SER Section 3.0.3.2.13 includes the staff's
 
basis why the Piping and Duct Internal Inspection Program may be used to manage the
 
aging effects that are applicable to elastome ric components in the auxiliary systems. The One-Time Inspection Program description states that one-time inspections are to be used
 
to confirm the slow progression or the absence of an aging effect. The staff confirmed that
 
the applicant has included the control building ventilation system within the scope of the
 
One-Time Inspection Program to confirm that the aging effect of loss of material in an
 
interior clean drainage environment is either not present or is proceeding very slowly. On the basis of its review, the staff finds that the aging effect of loss of material for carbon steel
 
piping components exposed to an interior cl ean drainage environment will be effectively managed by the One-Time Inspection Program.
In LRA Table 3.3.2-12, the applicant stated that copper alloy piping components exposed to an interior air-ventilation environment do not exhibit any aging effects requiring management. There is no corresponding GALL Report Table 1 line item or GALL Report
 
Volume 2 Chapter VII line item for this material/environment combination. However, GALL
 
Report Volume 2 does contain line item SP-6 for steam and power conversion systems which applies to copper alloy piping, piping components, and piping elements in an external
 
indoor uncontrolled air environment. This GALL Report Volume 2 line item documents that
 
there are no aging effects for this material/environment combination. Because the GALL
 
Report does not identify any aging effects requiring management for copper alloy piping, piping components, and piping elements exposed to indoor uncontrolled air which is either
 
the same or a more aggressive environment than the interior air-ventilation environment for
 
this copper alloy line item, the staff finds it acceptable that there are no aging effects.
 
Therefore, the staff concludes that copper alloy piping components exposed to an interior
 
air-ventilation environment do not exhibi t aging effects requiring management. 
 
In LRA Table 3.3.2-12, the applicant stated that fiber, foam and ceramic piping penetration
 
filter and fan unit moisture eliminators expos ed to an exterior ventilation-air environment do not exhibit aging effects requiring management. The applicant stated that there has never
 
been any plant-specific aging effect noted for these components. The staff's review of site
 
operating experience did not identify any aging effects for these components at VEGP. On
 
the basis of its review of current industry research and current plant operating experience, the staff concludes that fiber, foam and ceramic piping penetration filter and fan unit
 
moisture eliminators exposed to an exterior ventilation-air environment at VEGP do not exhibit aging effects requiring management.
.
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).
 
3-406 3.3.2.3.13  Ventilation Systems - Containment Building (CTB): Summary of Aging Management Review - LRA Table 3.3.2-13 
 
The staff reviewed LRA Table 3.3.2-13, which summarizes the results of AMR evaluations
 
for the ventilation systems - contai nment building (CTB) component groups.
 
In LRA Table 3.3.2-13, the applicant proposed to manage the loss of material for carbon
 
steel containment building auxiliary cooling unit housings, damper housings, duct silencer
 
housings, fan housings, and heater housings exposed to an interior air-ventilation
 
environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the c ontainment building ventilation system within the scope of the One-Time Inspection Program to confirm that the aging effect of loss of
 
material in an interior air-ventilation environment is either not present or is proceeding very
 
slowly. In addition, the staff confirmed that the declaration that stainless steel components
 
exposed to an inside environment in a control room ventilation system experience no aging effects has been previously accepted by the staff in the Farley Nuclear Plant license
 
renewal application SER (NUREG-1825). The air/gas environment for the Farley control
 
room ventilation system is analogous to the interior air-ventilation environment. On the basis of its review, the staff finds that the aging effect of loss of material for carbon steel
 
containment building auxiliary cooling unit housings, damper housings, duct silencer
 
housings, fan housings, and heater housings exposed to an interior air-ventilation
 
environment will be effectively managed by the One-Time Inspection Program.
 
In LRA Table 3.3.2-13, the applicant stated that stainless steel fan housings, flexible
 
connectors, flow orifice/element, piping components, and valve bodies in the containment
 
building ventilation system exposed to an inte rnal air-ventilation environment do not exhibit any aging effects requiring management. The staff finds this acceptable because stainless
 
steel is highly resistant to corrosion in dry air in the absence of corrosive species, as cited
 
in the Metals Handbook, Volume 3 (p. 65) and Volume 13 (p. 555) (Ninth Edition, American
 
Society for Metals International, 1980 and 1987). 
 
Therefore, stainless steel in an internal air-ventilation environment exhibits no aging effect, and the component or structure will remain capable of performing intended functions
 
consistent with the CLB for the period of extended operation.
 
In LRA Table 3.3.2-13, the applicant proposed to manage change in material properties, for
 
which the applicant includes hardening, loss of strength and cracking; for elastomer flexible
 
connectors exposed to an interior air-ventilation environment using the Piping and Duct
 
Internal Inspection Program.
The staff's evaluation of the One-Time Inspection Program is documented in SER Section 3.0.3.1.2. The staff's evaluation described in SER Section 3.0.3.2.13 includes the staff's
 
basis why the Piping and Duct Internal Inspection Program may be used to manage the
 
aging effects that are applicable to elastome ric components in the auxiliary systems. The One-Time Inspection Program description states that one-time inspections are to be used
 
to confirm the slow progression or the absence of an aging effect. The staff confirmed that
 
the applicant has included the control building ventilation system within the scope of the 3-407 One-Time Inspection Program to confirm that the aging effect of loss of material in an interior clean drainage environment is either not present or is proceeding very slowly. On the basis of its review, the staff finds that the aging effect of loss of material for carbon steel
 
piping components exposed to an interior cl ean drainage environment will be effectively managed by the One-Time Inspection Program.
In LRA Table 3.3.2-13, the applicant proposed to manage the loss of material for carbon steel piping components exposed to an interi or clean drainage environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the c ontainment building ventilation system within the scope of the One-Time Inspection Program to confirm that the aging effect of loss of
 
material in an interior clean drainage environment is either not present or is proceeding
 
very slowly. On the basis of its review, the staff finds that the aging effect of loss of material
 
for carbon steel piping components exposed to an interior clean drainage environment will be effectively managed by the One-Time Inspection 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).
 
3.3.2.3.14  Ventilation Systems - Fuel Handling Building (FHB): Summary of Aging
 
Management Review - LRA Table 3.3.2-14 
 
The staff reviewed LRA Table 3.3.2-14, which summarizes the results of AMR evaluations
 
for the ventilation systems - fuel handling building (FHB) component groups.
 
In LRA Table 3.3.2-14, the applicant proposed to manage loss of preload for stainless steel
 
closure bolting exposed to an external environment of indoor air using the Bolting Integrity
 
Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload of stainless steel closure bolting
 
exposed to an external environment of indoor air will be effectively managed by the Bolting Integrity Program.
 
3-408 In LRA Table 3.3.2-14, the applicant proposed to manage the loss of material for carbon steel damper housings, fan housings, and FHB post accident filter and fan unit housings
 
exposed to an interior air-ventilation environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The staff's evaluation described in SER Section 3.0.3.2.13 includes the staff's
 
basis why the Piping and Duct Internal Inspection Program may be used to manage the
 
aging effects that are applicable to elastome ric components in the auxiliary systems. The One-Time Inspection Program description states that one-time inspections are to be used
 
to confirm the slow progression or the absence of an aging effect. The staff confirmed that
 
the applicant has included the control building ventilation system within the scope of the
 
One-Time Inspection Program to confirm that the aging effect of loss of material in an
 
interior clean drainage environment is either not present or is proceeding very slowly. On the basis of its review, the staff finds that the aging effect of loss of material for carbon steel
 
piping components exposed to an interior cl ean drainage environment will be effectively managed by the One-Time Inspection Program.
In LRA Table 3.3.2-14, the applicant stated that stainless steel ductwork and fittings, FHB post accident filter and fan unit housings, and valve bodies exposed to an interior air-
 
ventilation environment do not exhibit any aging effects requiring management. There is no corresponding GALL Report Table 1 line item or GALL Report Volume 2 Chapter VII line
 
item for this material/environment combination. However, GALL Report Volume 2 does
 
contain line item AP-17 for auxiliary systems wh ich applies to stainless steel piping, piping components, and piping elements in an exter nal indoor uncontrolled air environment. This GALL Report Volume 2 line item documents that there are no aging effects for this
 
material/environment combination. Because the GALL Report does not identify any aging
 
effects requiring management for stainless steel piping, piping components, and piping
 
elements exposed externally to indoor uncontrolled air which is either the same or a more
 
aggressive environment than the interior ai r-ventilation environment for these stainless steel line items, the staff finds the applicant's conclusion that there are no aging effects
 
acceptable. In addition, the staff confirmed that the declaration that stainless steel
 
components exposed to an inside environment in a control room ventilation system experience no aging effects has been previously accepted by the staff in the Farley Nuclear
 
Plant license renewal application SER (NUREG-1825). The inside environment for the
 
Farley control room ventilation system is simila r to the interior air-ventilation environment for the stainless steel ductwork and fittings, FHB post accident filter and fan unit housings, and
 
valve bodies components at VEGP. Therefore, the staff concludes that stainless steel
 
ductwork and fittings, FHB post accident filter and fan unit housings and valve bodies
 
exposed to an interior air-ventilation environm ent do not exhibit aging effects requiring management. 
 
In LRA Table 3.3.2-14, the applicant stated that fiber, foam and ceramic FHB post accident
 
filter and fan unit moisture eliminators expos ed to an exterior air-ventilation environment do not exhibit aging effects requiring management. The applicant stated that there has never
 
been any plant-specific aging effect noted for this component. The staff's review of site
 
operating experience did not identify any aging effects for these components at VEGP. On
 
the basis of its review of current industry research and current plant operating experience, the staff concludes that fiber, foam and ceramic FHB post accident filter and fan unit
 
moisture eliminators exposed to an exteri or air-ventilation environment at VEGP do not exhibit aging effects requiring management.
 
3-409 In LRA Table 3.3.2-14, the applicant proposed to manage change in material properties, for which the applicant includes hardening, loss of strength and cracking, for elastomer flexible
 
connectors exposed to an interior air-ventilation environment using the Piping and Duct
 
Internal Inspection Program.
 
The staff verified that the applicant's Piping and Duct Internal Inspection Program is a new
 
program and has been identified as an AMP that is consistent with program elements in GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components", with exceptions. The staff also verified that like GALL AMP XI.M20, "Open-
 
Cycle Cooling Water System," the scope of t he applicant's program, in part, credits visual examinations to manage corrosion in the internal surfaces of stainless steel piping
 
components that are exposed internally to raw water. The staff also verified that the
 
applicant has addressed the need to implement this AMP in accordance with LRA
 
Commitment No. 19, which was placed on UFSAR Supplement Section A.2.22 and
 
provided in the applicant's letter of March 20, 2008. The staff's evaluation of the Piping and
 
Duct Internal Inspection Program is documented in SER Section 3.0.3.2.13. On the basis of
 
its review, the staff finds that the aging effect of change in material properties, for which the
 
applicant includes hardening, loss of strength and cracking, for elastomer flexible
 
connectors exposed to an interior air-vent ilation environment, will be effectively managed by the Piping and Duct Internal Inspection Program.
 
In LRA Table 3.3.2-14, the applicant proposed to manage the loss of material for carbon
 
steel piping components exposed to an interi or clean drainage environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the fuel handling building ventilation system
 
within the scope of the One-Time Inspection Program to confirm that the aging effect of loss
 
of material in an interior clean drainage environment is either not present or is proceeding
 
very slowly. On the basis of its review, the staff finds that the aging effect of loss of material
 
for carbon steel piping components exposed to an interior clean drainage environment will be effectively managed by the One-Time Inspection Program.
 
In LRA Table 3.3.2-14, the applicant stated that copper alloy piping components exposed to
 
an interior air-ventilation environment do not exhibit any aging effects requiring management. There is no corresponding GALL Report Table 1 line item or GALL Report
 
Volume 2 Chapter VII line item for this material/environment combination. However, GALL
 
Report Volume 2 does contain line item SP-6 for steam and power conversion systems which applies to copper alloy piping, piping components, and piping elements in an external
 
indoor uncontrolled air environment. This GALL Report Volume 2 line item documents that
 
there are no aging effects for this material/environment combination. Because the GALL
 
Report does not identify any aging effects requiring management for copper alloy piping, piping components, and piping elements exposed to indoor uncontrolled air which is either
 
the same or a more aggressive environment than the interior air-ventilation environment for
 
this copper alloy line item, the staff finds it acceptable that there are no aging effects.
 
Therefore, the staff concludes that copper alloy piping components exposed to an interior
 
air-ventilation environment do not exhibi t aging effects requiring management. 
 
3-410 In LRA Table 3.3.2-14, the applicant stated that stainless steel piping components exposed to an interior indoor air environment do not exhibit any aging effects requiring management.
There is no corresponding GALL Report Table 1 line item or GALL Report Volume 2
 
Chapter VII line item for this material/environment combination. However, GALL Report
 
Volume 2 does contain line item AP-17 for auxilia ry systems which applies to stainless steel piping, piping components, and piping elements in an external indoor uncontrolled air
 
environment. This GALL Report Volume 2 line item documents that there are no aging
 
effects for this material/environment combination. Because the GALL Report does not
 
identify any aging effects requiring management for stainless steel piping, piping
 
components, and piping elements exposed externa lly to indoor uncontrolled air which is either the same or a more aggressive environment than the interior indoor air environment
 
for these stainless steel line items, the staff finds it acceptable that there are no aging
 
effects. Therefore, the staff concludes that stainless steel piping components exposed to an
 
interior indoor air environment do not ex hibit aging effects requiring management. 
 
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  Ventilation Systems - Diesel Generator Building: Summary of Aging
 
Management Review - LRA Table 3.3.2-15 
 
The staff reviewed LRA Table 3.3.2-15, which summarizes the results of AMR evaluations
 
for the ventilation systems - diesel generator building component groups.
 
In LRA Table 3.3.2-15, the applicant proposed to manage the loss of material for carbon
 
steel diesel generator building ventilation syst em damper housings, fan housings, and filter housings, exposed to an interior air-ventilation environment using the One-Time Inspection
 
Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the diesel generator building ventilation system within the scope of the One-Time Inspection Program to confirm that the aging effect of loss
 
of material in an interior air-ventilation environment is either not present or is proceeding
 
very slowly. In addition, the staff confirmed that the declaration that stainless steel
 
components exposed to an inside environment in a control room ventilation system experience no aging effects has been previously accepted by the staff in the Farley Nuclear
 
Plant license renewal application SER (NUREG-1825). The air/gas environment for the
 
Farley control room ventilation system is analogous to the interior air-ventilation environment. On the basis of its review, the staff finds that the aging effect of loss of
 
material for carbon steel diesel generator building ventilation system damper housings, fan
 
housings, and filter housings exposed to an interior air-ventilation environment will be effectively managed by the One-Time Inspection Program.
 
In LRA Table 3.3.2-15, the applicant proposed to manage change in material properties, for
 
which the applicant includes hardening, loss of strength and cracking; for elastomer flexible 3-411 connectors exposed to an interior air-ventilation environment using the Piping and Duct Internal Inspection Program.
 
The staff verified that the applicant's Piping and Duct Internal Inspection Program is a new
 
program and has been identified as an AMP that is consistent with program elements in GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting
 
Components", with exceptions. Suggest we say something specific about how the Piping
 
and Duct Internal Inspection Program relates to and manages elastomer flexible connectors. The staff also verified that like GALL AMP XI.M20, "Open-Cycle Cooling Water
 
System," the scope of the applicant's program, in part, credits visual examinations to manage corrosion in the internal surfaces of stainless steel piping components that are
 
exposed internally to raw water. The staff also verified that the applicant has addressed the
 
need to implement this AMP in accordance with LRA Commitment No. 19, which was
 
placed on UFSAR Supplement Section A.2.22 and provided in the applicant's letter of
 
March 20, 2008. 
 
The staff's evaluation of the Piping and Duct Internal Inspection Program is documented in
 
SER Section 3.0.3.2.13. The staff's evaluation described in SER Section 3.0.3.2.13
 
includes the staff's basis why the Piping and Duct Internal Inspection Program may be used
 
to manage the aging effects that are applicable to elastomeric components in the auxiliary
 
systems. On the basis of its review, the staff finds that the aging effect of change in material
 
properties, for which the applicant includes hardening, loss of strength and cracking; for
 
elastomer flexible connectors exposed to an interior air-ventilation environment will be effectively managed by the Piping and Duct Internal Inspection 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).
 
3.3.2.3.16  Ventilation Systems - Auxiliary Feedwater Pumphouse: Summary of Aging Management Review - LRA Table 3.3.2-16 
 
The staff reviewed LRA Table 3.3.2-16, which summarizes the results of AMR evaluations
 
for the ventilation systems - auxiliary feedwater pumphouse component groups.
 
In LRA Table 3.3.2-16, the applicant proposed to manage the loss of material for carbon
 
steel damper housings and fan housings exposed to an interior air-ventilation environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the auxiliary feedwater pumphouse ventilation system within the scope of the One-Time Inspection Program to confirm that the aging
 
effect of loss of material in an interior air-ventilation environment is either not present or is
 
proceeding very slowly. In addition, the staff confirmed that the declaration that stainless
 
steel components exposed to an inside environment in a control room ventilation system experience no aging effects has been previously accepted by the staff in the Farley Nuclear
 
Plant license renewal application SER (NUREG-1825). The air/gas environment for the 3-412 Farley control room ventilation system is analogous to the interior air-ventilation environment. On the basis of its review, the staff finds that the aging effect of loss of
 
material for carbon steel damper housings and fan housings exposed to an interior air-
 
ventilation environment will be effectively m anaged by the One-Time Inspection Program.
 
In LRA Table 3.3.2-16, the applicant stated that stainless steel ductwork and fittings
 
exposed to an interior air-ventilation environment do not exhibit any aging effects requiring management. There is no corresponding GALL Report Table 1 line item or GALL Report
 
Volume 2 Chapter VII line item for this material/environment combination. However, GALL
 
Report Volume 2 does contain line item AP-17 for auxiliary systems which applies to stainless steel piping, piping components, and piping elements in an external indoor
 
uncontrolled air environment. This GALL Report Volume 2 line item documents that there
 
are no aging effects for this material/environment combination. Because the GALL Report
 
does not identify any aging effects requiring management for stainless steel piping, piping
 
components, and piping elements exposed externa lly to indoor uncontrolled air which is either the same or a more aggressive environment than the interior air-ventilation
 
environment for this stainless steel line item, the staff finds it acceptable that there are no
 
aging effects. In addition, the staff confirmed that the declaration that stainless steel
 
components exposed to an inside environment in a control room ventilation system experience no aging effects has been previously accepted by the staff in the Farley Nuclear
 
Plant license renewal application SER (NUREG-1825). The inside environment for the
 
Farley control room ventilation system is analogous to the interior. Therefore, the staff
 
concludes that stainless steel ductwork and fittings exposed to an interior air-ventilation
 
environment do not exhibit aging effects requiring management. 
 
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  Ventilation Systems - Miscellaneous: Summary of Aging Management Review -
 
LRA Table 3.3.2-17 
 
The staff reviewed LRA Table 3.3.2-17, which summarizes the results of AMR evaluations
 
for the ventilation systems - miscellaneous component groups.
 
In LRA Table 3.3.2-17, the applicant proposed to manage the loss of material for carbon
 
steel miscellaneous ventilation system damper housings, fan housings, and filter housings, exposed to an interior air-ventilation environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the miscellaneous ventilation systems within the
 
scope of the One-Time Inspection Program to confirm that the aging effect of loss of
 
material in an interior air-ventilation environment is either not present or is proceeding very
 
slowly. In addition, the staff confirmed that the aging management of loss of material for
 
carbon steel exposed to an air/gas environment in a diesel ventilation system by the One-Time Inspection Program has been previously accepted by the staff. In addition, the staff
 
confirmed that the declaration that stainless steel components exposed to an inside 3-413 environment in a control room ventilation system experience no aging effects has been previously accepted by the staff in the Farley Nuclear Plant license renewal application
 
SER (NUREG-1825). The air/gas environment for the Farley control room ventilation
 
system is analogous to the interior air-ventila tion environment. On the basis of its review, the staff finds that the aging effect of loss of material for carbon steel miscellaneous
 
ventilation system damper housings, fan hous ings, and filter housings exposed to an interior air-ventilation environment will be effe ctively managed by the One-Time Inspection Program.
 
In LRA Table 3.3.2-17, the applicant proposed to manage change in material properties, for
 
which the applicant includes hardening, loss of strength and cracking; for elastomer flexible
 
connectors exposed to an interior air-ventilation environment using the Piping and Duct
 
Internal Inspection Program.
 
The staff verified that the applicant's Piping and Duct Internal Inspection Program is a new
 
program and has been identified as an AMP that is consistent with program elements in GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components", with exceptions. The staff also verified that like GALL AMP XI.M20, "Open-
 
Cycle Cooling Water System," the scope of t he applicant's program, in part, credits visual examinations to manage corrosion in the internal surfaces of stainless steel piping
 
components that are exposed internally to raw water. The staff also verified that the
 
applicant has addressed the need to implement this AMP in accordance with LRA
 
Commitment No. 19, which was placed on UFSAR Supplement Section A.2.22 and
 
provided in the applicant's letter of March 20, 2008. The staff's evaluation of the Piping and
 
Duct Internal Inspection Program is documented in SER Section 3.0.3.2.13. On the basis of
 
its review, the staff finds that the aging effect of change in material properties, for which the
 
applicant includes hardening, loss of strength and cracking; for elastomer flexible
 
connectors exposed to an interior air-ventila tion environment will be effectively managed by the Piping and Duct Internal Inspection 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).
 
3.3.2.3.18  Ventilation Systems - Radwaste Buildings: Summary of Aging Management Review - LRA Table 3.3.2-18 
 
The staff reviewed LRA Table 3.3.2-18, which summarizes the results of AMR evaluations
 
for the ventilation systems - radwaste buildings component groups.
 
In LRA Table 3.3.2-18, the applicant proposed to manage the loss of material for carbon
 
steel damper housings exposed to an interior air-ventilation environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the radwaste buildings ventilation system within
 
the scope of the One-Time Inspection Program to confirm that the aging effect of loss of 3-414 material in an interior air-ventilation environment is either not present or is proceeding very slowly. In addition, the staff confirmed that the aging management of loss material for
 
carbon steel exposed to an air/gas environment in a control room ventilation system by the One-Time Inspection Program has been previously accepted by the staff in the Farley
 
Nuclear Plant license renewal application SER (NUREG-1825). The air/gas environment for
 
the Farley control room ventilation system is analogous to the interior air-ventilation environment for the carbon steel damper housing components at VEGP. On the basis of its
 
review, the staff finds that the aging effect of loss of material for carbon steel damper
 
housings exposed to an interior air-ventilati on environment will be effectively managed by the One-Time Inspection 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).
 
3.3.2.3.19  Fire Protection Systems: Summary of Aging Management Review -
 
LRA Table 3.3.2-19 
 
The staff reviewed LRA Table 3.3.2-19, which summarizes the results of AMR evaluations
 
for the fire protection systems component groups.
 
In LRA Table 3.3.2-19, the applicant proposed to manage loss of preload either for carbon
 
steel closure bolting or stainless steel closure bolting exposed either to an external air (outdoor) environment or an external soil envir onment using the Bolting Integrity Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload for either carbon steel closure
 
bolting or stainless steel closure bolting exposed either to an external air (outdoor)
 
environment or an external soil environment will be effectively managed by the Bolting Integrity Program.
 
In LRA Table 3.3.2-19, the applicant proposed to manage loss of material for cast iron fire
 
hydrants exposed to an external environment of outdoor air (wetted) using the External Surfaces Monitoring Program.
 
The staff verified that the VEGP External Surfaces Monitoring Program is a new program
 
that inspects external surfaces of mechanical system components requiring aging
 
management for license renewal in external ai r environments. Surfaces constructed from materials susceptible to aging in these environments are inspected at frequencies that 3-415 assure the effects of aging are managed such that system components will perform their intended function during the period of extended operation. The program will be a monitoring
 
program, which manages aging effects through periodic visual inspections of external
 
surfaces of components such as piping, piping components, ducting, and other components
 
for evidence of material loss. The staff's evaluation of the External Surfaces Monitoring
 
Program is documented in SER Section 3.0.3.3.5. On the basis of its review, the staff finds
 
that because these components will be inspected periodically, the aging effect of loss of
 
material for cast iron fire hydrants expos ed to an external environment of outdoor air (wetted) will be effectively managed by the External Surfaces Monitoring Program.
 
In LRA Table 3.3.2-19, the applicant proposed to manage the loss of material for aluminum
 
alloy flame elements and flame arrestor housings exposed to an internal air (outdoor)
 
environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the fire protection system within the scope of the
 
One-Time Inspection Program to confirm that the aging effect of loss of material for
 
aluminum alloy in an interior outdoor air environment is either not present or is proceeding
 
very slowly. 
 
On the basis of its review, the staff finds that the aging effect of loss of material for flame
 
arrestor elements and flame arrestor housings exposed to an internal air (outdoor)
 
environment will be effectively managed by the One-Time Inspection Program.
 
In LRA Table 3.5.2-19, the applicant stated that stainless steel flame arrestor housings
 
exposed to an interior outdoor air environment and stainless steel flame arrestor housings, flow orifice/elements, and valve bodies, expos ed to an exterior outdoor air environment do not exhibit aging effects requiring managemen
: t. The outdoor air environment at VEGP is subject to normal periodic wetting but is not exposed to an aggressive environment from
 
any nearby industrial facilities or to a salt water environment which could have the potential to concentrate contaminates and cause aging effects for stainless steel. In addition, there is
 
no VEGP operating experience which indicates aging effects for stainless steel in the
 
outdoor air environment has occurred. The GALL Report Volume 2 does contain line item
 
AP-18 for auxiliary systems which does not identify any aging effects requiring
 
management for stainless steel component types exposed to air with borated water leakage
 
which is a more aggressive environment than the interior outdoor air environment and
 
exterior outdoor air environment for these AMR items. On the basis of its review of the
 
current plant operating experience and other more aggressive GALL Report environments
 
for stainless steel, the staff concludes that stainless steel flame arrestor housings exposed
 
to an interior outdoor air environment and stainless steel flame arrestor housings, flow
 
orifice/elements, and valve bodies, exposed to an exterior outdoor air environment at VEGP do not exhibit aging effects requiring management.
 
In LRA Table 3.3.2-19, the applicant stated that copper alloy flow orifice/elements, hose
 
station nozzles, and hose connections, exposed to an external air (indoor) environment do
 
not exhibit any aging effects requiring management. The staff finds this acceptable because
 
the GALL Report does not identify any aging effects requiring management for copper alloy
 
less than 15 percent Zn component types exposed to air with borated water leakage which
 
is a more aggressive environment than the air (exterior) environment in these line items.
3-416 Therefore, copper alloy in an external air (indoor) environment exhibits no aging effect, and the component or structure will remain capable of performing intended functions consistent
 
with the CLB for the period of extended operation.
 
In LRA Table 3.3.2-19, the applicant proposed to manage cracking of aluminum alloy
 
(>6 percent Mg) piping components exposed to an internal raw water environment using
 
the Fire Protection Program.
 
The staff's evaluation of the Fire Protection Program is documented in SER Section
 
3.0.3.2.6. The Fire Protection Program is an existing program which describes
 
enhancements to perform wall thickness evaluat ions on water suppression piping systems using non-intrusive volumetric testing or visual inspections to ensure that wall thicknesses are within acceptable limits, as specified by GALL AMP XI.M27. Further, the staff noted that
 
initial wall thickness evaluations will be performed before the end of the current operating
 
term and that subsequent evaluations are performed at plant-specific intervals during the
 
period of extended operation. The plant-specific inspection intervals will be determined
 
based on previous evaluations and site operating experience. On the basis of its review, the staff finds that, because these components will be inspected periodically, the aging
 
effect of aluminum alloy (>6 percent Mg) piping components exposed to an internal raw
 
water environment will be effectively m anaged by the Fire Protection Program.
 
In LRA Table 3.3.2-19, the applicant proposed to manage loss of material due to selective
 
leaching for gray cast iron piping components exposed to an external air (indoor)
 
environment using the One-Time Inspection Program for Selective Leaching.
 
The staff's evaluation of the One-Time Inspection Program for Selective Leaching is
 
documented in SER Section 3.0.3.2.12. The One-Time Inspection Program for Selective
 
Leaching description states that the program will be a one-time inspection program to
 
assess selective leaching in susceptible cast iron and copper alloy components. The
 
program includes a one-time examination of a sample population of components most likely
 
to exhibit selective leaching. The new VEGP progr am is to provide objective evidence that the aging effect is not occurring, or that the aging effect is occurring slowly enough not to
 
affect the SSCs intended function during the period of extended operation, and thus not
 
require additional aging management. The inspections will be performed within a window of
 
ten years immediately preceding the period of extended operation. If degradation due to
 
selective leaching is identified, additional exam inations will be performed. This program is a new program consistent with GALL AMP XI.M33, "Selective Leaching of Materials" with an
 
exception that the program may use other detection techniques instead of, or in addition to, visual examination and hardness measurement. For some component locations, visual
 
examination and hardness measurement ma y not be feasible due to geometry and configuration issues. Other examination methods which are equally effective in detecting
 
and assessing the extent of selective leaching may be used. Examination techniques may
 
include hardness measurement (where feasible based on form and configuration), visual
 
examination, metallurgical evaluation, or other proven techniques determined to be
 
effective in identifying and assessing the extent of selective leaching. If any conditions do
 
not meet the acceptance criteria, the applicant will take appropriate actions to prevent the
 
component from being returned to service until required corrective actions have been completed. On the basis of its review, the staff finds that the aging effect of loss of material
 
due to selective leaching for gray cast ir on piping components exposed to an external air (indoor) environment will be effectively managed by the One-Time Inspection Program for Selective Leaching.
3-417  In LRA Table 3.3.2-19, the applicant stated that copper alloy piping components, sprinkler
 
heads, spray nozzles and valve bodies exposed to either an internal air (indoor)
 
environment external air (outdoor) environment do not exhibit any aging effects requiring management. The staff finds this acceptable because the GALL Report does not identify
 
any aging effects requiring management for copper alloy less than 15 percent Zn
 
component types exposed to air with borated water leakage which is a more aggressive
 
environment than the air (exterior) environment in these line items. Therefore, copper alloy
 
in either an internal air (indoor) environment or external air (outdoor) environment exhibits no aging effect, and the component or structure will remain capable of performing intended
 
functions consistent with the CLB for the period of extended operation.
 
In LRA Table 3.3.2-19, the applicant stated that stainless steel piping components, silencers, sprinkler heads, and spray nozzles exposed to an external air (outdoor)
 
environment an internal air (indoor) environment do not exhibit any aging effects requiring management. The staff finds this acceptable because stainless steel is highly resistant to
 
corrosion in dry air in the absence of corrosive species, as cited in the Metals Handbook, Volume 3 (p. 65) and Volume 13 (p. 555) (Ninth Edition, American Society for Metals
 
International, 1980 and 1987). Therefore, stainless steel in either an external air (outdoor)
 
environment or an internal air (indoor) environment exhibits no aging effect, and the
 
component or structure will remain capable of performing intended functions consistent with
 
the CLB for the period of extended operation.
 
In LRA Table 3.3.2-19, the applicant stated that aluminum valve bodies exposed to an
 
internal dry gas (halon) environment do not exhibit any aging effects requiring
 
management. Aluminum has an excellent resist ance to corrosion when exposed to a humid air (outdoor or moist air/gas environment). The aluminum oxide film bonds strongly to its surface and 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 highly
 
effective in protecting the aluminum from corro sion. Therefore, the staff finds that aluminum alloy valves bodies exposed to an internal air/gas (halon) environment exhibit no aging effects, and the component or structure will remain capable of performing intended
 
functions consistent with the CLB for the period of extended operation.
 
In LRA Table 3.3.2-19, the applicant proposed to manage loss of material due to selective
 
leaching either for gray cast iron piping components and valve bodies or copper alloy (Zn
 
>15 percent) piping components exposed to an inte rnal fuel oil environment using the One-Time Inspection Program for Selective Leaching.
 
The staff's evaluation of the One-Time Inspection Program for Selective Leaching is
 
documented in SER Section 3.0.3.2.12. The One-Time Inspection Program for Selective
 
Leaching description states that the program will be a one-time inspection program to
 
assess selective leaching in susceptible cast iron and copper alloy components. The
 
program includes a one-time examination of a sample population of components most likely
 
to exhibit selective leaching. The new VEGP progr am is to provide objective evidence that the aging effect is not occurring, or that the aging effect is occurring slowly enough not to
 
affect the SSCs intended function during the period of extended operation, and thus not
 
require additional aging management. The inspections will be performed within a window of
 
ten years immediately preceding the period of extended operation. If degradation due to
 
selective leaching is identified, additional exam inations will be performed. This program is a new program consistent with GALL AMP XI.M33, "Selective Leaching of Materials" with an 3-418 exception that the program may use other detection techniques instead of, or in addition to, visual examination and hardness measurement. For some component locations, visual
 
examination and hardness measurement ma y not be feasible due to geometry and configuration issues. Other examination methods which are equally effective in detecting
 
and assessing the extent of selective leaching may be used. Examination techniques may
 
include hardness measurement (where feasible based on form and configuration), visual
 
examination, metallurgical evaluation, or other proven techniques determined to be
 
effective in identifying and assessing the extent of selective leaching. Any conditions which
 
do not meet the acceptance criteria, the applicant will take appropriate actions to prevent
 
the component from being returned to servic e until required corrective actions have been completed. On the basis of its review, the staff finds that the aging effect of loss of material
 
due to selective leaching either for gray cast iron piping components and valve bodies or
 
copper alloy (Zn >15 percent) piping components exposed to an internal fuel oil
 
environment will be effectively managed by the O ne-Time Inspection Program for Selective Leaching.
 
In LRA Table 3.3.2-19, the applicant proposed to manage loss of material due to selective
 
leaching for gray cast iron valve bodies exposed to an external wetted (outdoor)
 
environment using the One-Time Inspection Program for Selective Leaching.
 
The staff's evaluation of the One-Time Inspection Program for Selective Leaching is
 
documented in SER Section 3.0.3.2.12. The One-Time Inspection Program for Selective
 
Leaching description states that the program will be a one-time inspection program to
 
assess selective leaching in susceptible cast iron and copper alloy components. The
 
program includes a one-time examination of a sample population of components most likely
 
to exhibit selective leaching. The new VEGP progr am is to provide objective evidence that the aging effect is not occurring, or that the aging effect is occurring slowly enough not to
 
affect the SSCs intended function during the period of extended operation, and thus not
 
require additional aging management. The inspections will be performed within a window of
 
ten years immediately preceding the period of extended operation. If degradation due to
 
selective leaching is identified, additional exam inations will be performed. This program is a new program consistent with GALL AMP XI.M33, "Selective Leaching of Materials" with an
 
exception that the program may use other detection techniques instead of, or in addition to, visual examination and hardness measurement. For some component locations, visual
 
examination and hardness measurement ma y not be feasible due to geometry and configuration issues. Other examination methods which are equally effective in detecting
 
and assessing the extent of selective leaching may be used. Examination techniques may
 
include hardness measurement (where feasible based on form and configuration), visual
 
examination, metallurgical evaluation, or other proven techniques determined to be
 
effective in identifying and assessing the extent of selective leaching. For any conditions
 
which do not meet the acceptance criteria, the applicant will take appropriate actions to
 
prevent the component from being returned to service until required corrective actions have been completed. On the basis of its review, the staff finds that the aging effect of loss of
 
material due to selective leaching for gray cast iron valve bodies exposed to an external wetted (outdoor) environment will be effectiv ely managed by the One-Time Inspection Program for Selective Leaching.
 
In LRA Table 3.3.2-19, the applicant stated that copper alloy valve bodies exposed to an
 
internal air (indoor) environment do not ex hibit any aging effects requiring management.
The staff finds this acceptable because the GALL Report does not identify any aging effects
 
requiring management for copper alloy less than 15 percent Zn component types exposed 3-419 to air with borated water leakage which is a more aggressive environment than the air (exterior) environment in these line items. Therefore, copper alloy in an internal air (indoor)
 
environment exhibits no aging effect, and the component or structure will remain capable of
 
performing intended functions consistent with the CLB for the period of extended operation.
 
On the basis of its review, the staff finds that the applicant has appropriately evaluated the
 
AMR results of material, environment, AERM, and AMP combinations not 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).
 
3.3.2.3.20  Emergency Diesel Generator System: Summary of Aging Management Review - LRA Table 3.3.2-20 
 
The staff reviewed LRA Table 3.3.2-20, which summarizes the results of AMR evaluations
 
for the emergency diesel generator system component groups.
 
In LRA Table 3.3.2-20, the applicant proposed to manage loss of preload for carbon steel
 
closure bolting exposed to an external environment of outdoor air using the Bolting Integrity
 
Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload of carbon steel closure bolting
 
exposed to an external environment of out door air will be effectively managed by the Bolting Integrity Program.
 
In LRA Table 3.3.2-20, the applicant proposed to manage the loss of material for aluminum
 
alloy flame arrestor elements and flame arrestor housings exposed to an interior outdoor air
 
environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the emergency diesel generator system within the
 
scope of the One-Time Inspection Program to confirm that the aging effect of loss of
 
material for aluminum alloy in an interior outdoor air environment is either not present or is
 
proceeding very slowly. On the basis of its review, the staff finds that the aging effect of
 
loss of material for aluminum alloy flame arrestor elements and flame arrestor housings
 
exposed to an interior outdoor air environment will be effectively managed by the One-Time Inspection Program.
 
3-420 In LRA Table 3.5.2-20, the applicant stated that stainless steel flame arrestor elements exposed to an interior outdoor air environment and stainless steel flame arrestor elements, flexible connectors, pipe components and valve bodies exposed to an exterior outdoor air
 
environment do not exhibit aging effe cts requiring management. The outdoor air environment at VEGP is subject to normal periodic wetting but is not exposed to an
 
aggressive environment from any nearby industria l facilities or to a salt water environment which could have the potential to concentrate contaminates and cause aging effects for
 
stainless steel. In addition, there is no VEGP operating experience which indicates aging
 
effects for stainless steel in the outdoor air environment has occurred. The GALL Report
 
Volume 2 does contain line item AP-18 for aux iliary systems which does not identify any aging effects requiring management for stainless steel component types exposed to air with
 
borated water leakage which is a more aggressive environment than the interior outdoor air
 
environment and exterior outdoor air environment fo r these AMR items. On the basis of its review of the current plant operating experience and other more aggressive GALL Report
 
environments for stainless steel, the staff concludes that stainless steel flame arrestor
 
elements exposed to an interior outdoor air env ironment and stainless steel flame arrestor elements, flexible connectors, pipe component s and valve bodies exposed to an exterior outdoor air environment at VEGP do not ex hibit aging effects requiring management.
 
In LRA Table 3.3.2-20, the applicant proposed to manage change in material properties, for
 
which the applicant includes hardening, loss of strength and cracking; for elastomer flexible
 
connectors exposed to an interior diesel exhaust environment using the Piping and Duct
 
Internal Inspection Program.
 
The staff verified that the applicant's Piping and Duct Internal Inspection Program is a new
 
program and has been identified as an AMP that is consistent with program elements in GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components", with exceptions. The staff also verified that like GALL AMP XI.M20, "Open-
 
Cycle Cooling Water System," the scope of t he applicant's program, in part, credits visual examinations to manage corrosion in the internal surfaces of stainless steel piping
 
components that are exposed internally to raw water. The staff also verified that the
 
applicant has addressed the need to implement this AMP in accordance with LRA
 
Commitment No. 19, which was placed on UFSAR Supplement Section A.2.22 and
 
provided in the applicant's letter of March 20, 2008. The staff's evaluation of the Piping and
 
Duct Internal Inspection Program is documented in SER Section 3.0.3.2.13. On the basis of
 
its review, the staff finds that the aging effect change in material properties, for which the
 
applicant includes hardening, loss of strength and cracking; for elastomer flexible
 
connectors exposed to an interior diesel exhaust environment will be effectively managed by the Piping and Duct Internal Inspection Program.
 
In LRA Table 3.3.2-20, the applicant proposed to manage change in material properties, for
 
which the applicant includes hardening, loss of strength and cracking, for elastomer flexible
 
connectors exposed to an external environment of outdoor air using the "External Surfaces
 
Monitoring Program."
 
The staff verified that the VEGP External Surfaces Monitoring Program is a new program
 
that inspects external surfaces of mechanical system components requiring aging
 
management for license renewal in external ai r environments. Surfaces constructed from materials susceptible to aging in these environments are inspected at frequencies that
 
assure the effects of aging are managed such that system components will perform their intended function during the period of extended operation. The program will be a monitoring 3-421 program, which manages aging effects through periodic visual inspections of external surfaces of components such as piping, piping components, ducting, and other components
 
for evidence of material loss. The staff's evaluation of the External Surfaces Monitoring
 
Program is documented in SER Section 3.0.3.3.5. On the basis of its review, the staff finds
 
that because these components will be inspected periodically, the aging effect of change in
 
material properties for elastomer flexible c onnectors exposed to an external environment of outdoor air will be effectively managed by the External Surfaces Monitoring Program.
 
In LRA Table 3.3.2-20, the applicant proposed to manage cracking for carbon steel flow
 
orifice elements, EDG jacket water heat exchanger shells, EDG lube oil heat exchanger
 
channel heads, piping components, EDG jacket water keep warm pump casings, EDG
 
jacket water chemical addition tanks and valv e bodies exposed to an internal environment of closed cycle cooling water from the Aux iliary Component Cooling Water System (ACCW) using the ACCW System Carbon Steel Components Program.
 
The staff's evaluation of the ACCW Syst em Carbon Steel Components Program is documented in SER Section 3.0.3.3.1. The ACCW System Carbon Steel Components
 
Program description states cracking of carbon steel components exposed to auxiliary component cooling water is managed through a combination of leakage monitoring, routine
 
walkdowns and periodic visual inspections. The program is in response to operating
 
experience related to nitrite induced stress corrosion cracking (SCC) and subsequent
 
component leakage in the VEGP ACCW System components. This program is a plant-specific program. On the basis of its review, the staff finds that because these components
 
will be inspected periodically, the aging effect of cracking for carbon steel flow orifice
 
elements, EDG jacket water heat exchanger shells, EDG lube oil heat exchanger channel
 
heads, piping components, EDG jacket water keep warm pump casings, EDG jacket water
 
chemical addition tanks and valve bodies expos ed to an internal environment of closed cycle cooling water from the ACCW System will be effectively managed by using the ACCW System Carbon Steel Components Program.
 
In LRA Table 3.3.2-20, the applicant proposed to manage loss of material due to selective
 
leaching either for copper alloy (Zn >15 percent) EDG lube oil heat exchanger tubesheets
 
or gray cast iron EDG lube oil pump casi ngs exposed to an internal environment of lubricating oil using the One-Time Inspection Program for Selective Leaching.
 
The staff's evaluation of the One-Time Inspection Program for Selective Leaching is
 
documented in SER Section 3.0.3.2.12. The One-Time Inspection Program for Selective
 
Leaching description states that the program will be a one-time inspection program to
 
assess selective leaching in susceptible cast iron and copper alloy components. The
 
program includes a one-time examination of a sample population of components most likely
 
to exhibit selective leaching. The new VEGP Progr am is to provide objective evidence that the aging effect is not occurring, or that the aging effect is occurring slowly enough not to
 
affect the SSCs intended function during the period of extended operation, and thus not
 
require additional aging management. The inspections will be performed within a window of
 
ten years immediately preceding the period of extended operation. If degradation due to
 
selective leaching is identified, additional exam inations will be performed. This program is a new program consistent with GALL AMP XI.M33, "Selective Leaching of Materials" with an
 
exception that the program may use other detection techniques instead of, or in addition to, visual examination and hardness measurement. For some component locations, visual
 
examination and hardness measurement ma y not be feasible due to geometry and configuration issues. Other examination methods which are equally effective in detecting 3-422 and assessing the extent of selective leaching may be used. Examination techniques may include hardness measurement (where feasible based on form and configuration), visual
 
examination, metallurgical evaluation, or other proven techniques determined to be
 
effective in identifying and assessing the extent of selective leaching. Should any conditions
 
be observed which do not meet the acceptance criteria, appropriate actions will be taken to
 
prevent the component from being returned to service until required corrective actions have been completed. On the basis of its review, the staff finds that the aging effect of loss of
 
material due to selective leaching either for copper alloy (Zn >15 percent) EDG lube oil heat
 
exchanger tubesheets or gray cast iron EDG l ube oil pump casings exposed to an internal environment of lubricating oil will be effe ctively managed by the One-Time Inspection Program for Selective Leaching.
 
In LRA Table 3.3.2-20, the applicant proposed to manage cracking for copper alloy (Zn >15 percent) EDG lube oil heat exchanger tubesheets exposed to an external closed
 
cycle cooling water environment using the Closed Cooling Water Program.
 
The staff's evaluation of the Closed Cooling Water Program is documented in SER Section
 
3.0.3.2.4. The Closed Cooling Water Program description states that the program manages
 
loss of material, cracking, and reduction in heat transfer in closed-cycle cooling water
 
systems and the components cooled by these systems. The program includes maintenance of corrosion inhibitor, pH buffering agent, and biocide concentrations. Concentrations of
 
detrimental ionic species are monitored and reduced if necessary. Important diagnostic
 
parameters are monitored and evaluated for si gnificant trends. The program also uses corrosion-monitoring activities including trending of iron and copper concentrations and
 
component inspections. Corrosion rate monitoring methods may also be used. The
 
program will indicate the components in each system that is most susceptible to various
 
corrosion mechanisms and to ensure that corrosion monitoring is appropriately
 
implemented. On the basis of its review, the staff finds that the aging effect cracking for
 
copper alloy (Zn >15 percent) EDG lube oil heat exchanger tubesheets exposed to an 
 
external closed cycle cooling water environm ent will be effectively managed by the Closed Cooling Water Program.
 
In LRA Table 3.3.2-20, the applicant proposed to manage loss of material for carbon steel
 
piping components and valve bodies exposed to an interior dirty drainage environment
 
using the Piping and Duct Internal Inspection Program.
The staff verified that the applicant's Piping and Duct Internal Inspection Program is a new program and has been identified as an AMP that is consistent with program elements in GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components", with exceptions. The staff also verified that like GALL AMP XI.M20, "Open-
 
Cycle Cooling Water System," the scope of t he applicant's program, in part, credits visual examinations to manage corrosion in the internal surfaces of stainless steel piping
 
components that are exposed internally to raw water. The staff also verified that the
 
applicant has addressed the need to implement this AMP in accordance with LRA
 
Commitment No. 19, which was placed on UFSAR Supplement Section A.2.22 and
 
provided in the applicant's letter of March 20, 2008. The staff's evaluation of the Piping and
 
Duct Internal Inspection Program is documented in SER Section 3.0.3.2.13. The staff's
 
evaluation described in SER Section 3.0.3.2.13 includes that staff's basis why the Piping
 
and Duct Internal Inspection Program may be used to manage the aging effects that are
 
applicable to steel components in the auxiliary syst ems. On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, 3-423 environment, AERM, and AMP combinations not evaluated in the GALL Report.
On the basis of its review, the staff finds that the aging effect of loss of material for carbon
 
steel piping components and valve bodies exposed to an interior dirty drainage
 
environment will be effectively managed by t he Piping and Duct Internal Inspection Program. 
 
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  Demineralized Water System: Summary of Aging Management Review -
 
LRA Table 3.3.2-21 
 
The staff reviewed LRA Table 3.3.2-21, which summarizes the results of AMR evaluations
 
for the demineralized water system component groups.
 
In LRA Table 3.3.2-21, the applicant proposed to manage loss of preload for stainless steel
 
closure bolting exposed to an external environment of indoor air using the Bolting Integrity
 
Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload of stainless steel closure bolting
 
exposed to an external environment of indoor air will be effectively managed by the Bolting Integrity 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).
 
3.3.2.3.22  Hydrogen Recombiner and Monito ring System: Summary of Aging Management Review - LRA Table 3.3.2-22 
 
The staff reviewed LRA Table 3.3.2-22, which summarizes the results of AMR evaluations
 
for the hydrogen recombiner and monitoring system component groups.
 
In LRA Table 3.3.2-22, the applicant proposed to manage loss of preload for stainless steel
 
closure bolting exposed to an external environment of indoor air using the Bolting Integrity
 
Program.
 
3-424 The staff verified that the applicant's Bolting Integrity Program is a new plant-specific program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload of stainless steel closure bolting
 
exposed to an external environment of indoor air will be effectively managed by the Bolting Integrity Program.
 
In LRA Table 3.3.2-22, the applicant stated that stainless steel hydrogen recombiner
 
containment housings, piping components and valve bodies exposed to an interior indoor
 
air environment do not exhibit any aging effects requiring management. There is no corresponding GALL Report Table 1 line item or GALL Report Volume 2 Chapter VII line
 
item for this material/environment combination. However, GALL Report Volume 2 does
 
contain line item AP-17 for auxiliary systems wh ich applies to stainless steel piping, piping components, and piping elements in an exter nal indoor uncontrolled air environment. This GALL Report Volume 2 line item documents that there are no aging effects for this
 
material/environment combination. Because the GALL Report does not identify any aging
 
effects requiring management for stainless steel piping, piping components, and piping
 
elements exposed externally to indoor uncontrolled air which is either the same or a more
 
aggressive environment than the interior indoor air environment for these stainless steel
 
line items, the staff finds it acceptable that there are no aging effects. Therefore, the staff
 
concludes that stainless steel hydrogen recombiner containment housings, piping
 
components and valve bodies exposed to an interi or indoor air environment do not exhibit aging effects requiring management. 
 
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  Drain Systems: Summary of Aging Management Review - LRA Table 3.3.2-23 
 
The staff reviewed LRA Table 3.3.2-23, which summarizes the results of AMR evaluations
 
for the drain systems component groups.
 
In LRA Table 3.3.2-23, the applicant proposed to manage loss of preload either for carbon
 
steel, copper alloy or stainless steel closure bolting exposed to an external environment of
 
outdoor or indoor air using the Bolting Integrity Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor 3-425 vessel head studs which are managed in accordance with the applicant's Reactor Vessel Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload either for carbon steel carbon
 
steel, copper alloy or stainless steel closure bolting exposed to an external environment of
 
outdoor or indoor air will be effectively managed by the Bolting Integrity Program.
In LRA Table 3.3.2-23, the applicant proposed to manage the loss of material for cast iron drain bodies exposed to an interior indoor air environment using the One-Time Inspection
 
Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the drain system within the scope of the One-
 
Time Inspection Program to confirm that the aging effect of loss of material in an interior
 
indoor air environment is either not present or is proceeding very slowly. On the basis of its review, the staff finds that the aging effect of loss of material for cast iron drain bodies
 
exposed to an interior indoor air environment will be effectively managed by the One-Time Inspection Program.
 
In LRA Table 3.3.2-23, the applicant stated that lead alloy floor drain plugs exposed to an
 
interior indoor air environment do not ex hibit any aging effects requiring management.
There is no corresponding GALL Report Table 1 line item or GALL Report Volume 2
 
Chapter VII line item for this material/environment combination. The staff finds this
 
acceptable because there is no indication in the industry that lead alloys exposed to an
 
interior air indoor environment have any aging effects requiring management. The lack of historic negative operating experience indicates that lead alloy is not likely to experience
 
any degradation from indoor air. Therefore, based on industry experience and the
 
assumption of proper design and application of the material, the staff finds that lead alloy
 
floor drain plugs exposed to an interior indoor air environment exhibit no aging effects
 
requiring management for the period of extended operation.
 
In LRA Table 3.3.2-23, the applicant proposed to verify the material and that no significant
 
aging has occurred for lead alloy floor drain plugs exposed to an exterior indoor air
 
environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the drain system within the scope of the One-
 
Time Inspection Program. The program will confirm the lead alloy material and that aging of
 
lead alloy floor drain plugs in an exterior indoor air environment is either not present or is
 
proceeding very slowly. On the basis of its review, the staff finds that the verification of the
 
material and that no significant aging has occurred for lead alloy floor drain plugs exposed
 
to an exterior indoor air environment w ill be effectively managed by the One-Time Inspection Program.
3-426  In LRA Table 3.3.2-23, the applicant proposed to manage loss of material either for carbon
 
steel piping components and valve bodies or copper alloy piping components exposed to
 
an interior dirty drainage environment using the Piping and Duct Internal Inspection
 
Program. The staff verified that the applicant's Piping and Duct Internal Inspection Program is a new program and has been identified as an AMP that is consistent with program elements in GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components", with exceptions. The staff also verified that like GALL AMP XI.M20, "Open-
 
Cycle Cooling Water System," the scope of t he applicant's program, in part, credits visual examinations to manage corrosion in the internal surfaces of stainless steel piping
 
components that are exposed internally to raw water. The staff also verified that the
 
applicant has addressed the need to implement this AMP in accordance with LRA
 
Commitment No. 19, which was placed on UFSAR Supplement Section A.2.22 and
 
provided in the applicant's letter of March 20, 2008. The staff's evaluation of the Piping and
 
Duct Internal Inspection Program is documented in SER Section 3.0.3.2.13. The staff's
 
evaluation in SER Section 3.0.3.2.13 includes that staff's basis why the Piping and Duct
 
Internal Inspection Program may be used to manage the aging effects that are applicable to
 
carbon steel or stainless steel piping components and valve bodies or copper alloy piping
 
components in the auxiliary systems. On the basis of its review, the staff finds that the aging effect of loss of material either for carbon steel or stainless steel piping components
 
and valve bodies or copper alloy piping components exposed to either an interior or exterior
 
dirty drainage environment will be effectivel y managed by the Piping and Duct Internal Inspection Program.
 
In LRA Table 3.3.2-23, the applicant proposed to manage loss of material for carbon steel
 
piping components exposed to an external envir onment of outdoor air (wetted) using the External Surfaces Monitoring Program.
 
The staff verified that the VEGP External Surfaces Monitoring Program is a new program
 
that inspects external surfaces of mechanical system components requiring aging
 
management for license renewal in external ai r environments. Surfaces constructed from materials susceptible to aging in these environments are inspected at frequencies that
 
assure the effects of aging are managed such that system components will perform their intended function during the period of extended operation. The program will be a monitoring
 
program, which manages aging effects through periodic visual inspections of external
 
surfaces of components such as piping, piping components, ducting, and other components
 
for evidence of material loss. The staff's evaluation of the External Surfaces Monitoring
 
Program is documented in SER Section 3.0.3.3.5. On the basis of its review, the staff finds
 
that because these components will be inspected periodically, the aging effect of loss of
 
material for carbon steel piping components ex posed to an external environment of outdoor air (wetted) will be effectively managed by t he External Surfaces Monitoring Program.
 
In LRA Table 3.3.2-23, the applicant stated that copper alloy piping components exposed to
 
an interior indoor air environment do not ex hibit any aging effects requiring management.
There is no corresponding GALL Report Table 1 line item or GALL Report Volume 2
 
Chapter VII line item for this material/environment combination. However, GALL Report
 
Volume 2 does contain line item SP-6 for steam and power conversion systems which applies to copper alloy piping, piping components, and piping elements in an external
 
indoor uncontrolled air environment. This GALL Report Volume 2 line item documents that 3-427 there are no aging effects for this material/environment combination. Because the GALL Report does not identify any aging effects requiring management for copper alloy piping, piping components, and piping elements exposed to indoor uncontrolled air which is either
 
the same or a more aggressive environment than the interior indoor air environment for this
 
copper alloy line item, the staff finds it acceptable that there are no aging effects. Therefore, the staff concludes that copper alloy piping components exposed to an interior indoor air
 
environment do not exhibit aging effects requiring management. 
 
In LRA Table 3.3.2-23, the applicant stated that PVC piping components exposed to an
 
interior indoor air environment do not ex hibit any aging effects requiring management.
There is no corresponding GALL Report Table 1 line item or GALL Report Volume 2
 
Chapter VII line item for this material/environment combination. The staff finds this
 
acceptable because there is no indication in the industry that PVC or thermoplastics
 
exposed to an internal indoor air envir onment have any aging effects requiring management. The generally low operating temper atures and historical good chemical resistance data for PVC components, combined with a lack of historic negative operating
 
experience, indicate that PVC is not likely to experience any degradation from the non-
 
aggressive indoor air. PVC materials do not display corrosion rates as metals do, but rather
 
rely on chemical resistance to the environm ents to which they are exposed. Therefore, based on industry experience and the assumption of proper design and application of the
 
material, the staff finds that PVC piping components exposed to an interior indoor air
 
environment exhibit no aging effects requi ring management for the period of extended operation.
 
In LRA Table 3.3.2-23, the applicant proposed to manage change in material properties, for
 
which the applicant includes cracking, for PVC piping components exposed to an external
 
environment of indoor air using the Ex ternal Surfaces Monitoring Program.
 
The staff verified that the VEGP External Surfaces Monitoring Program is a new program
 
that inspects external surfaces of mechanical system components requiring aging
 
management for license renewal in external ai r environments. Surfaces constructed from materials susceptible to aging in these environments are inspected at frequencies that
 
assure the effects of aging are managed such that system components will perform their intended function during the period of extended operation. The program will be a monitoring
 
program, which manages aging effects through periodic visual inspections of external
 
surfaces of components such as piping, piping components, ducting, and other components
 
for evidence of material loss. The staff's evaluation of the External Surfaces Monitoring
 
Program is documented in SER Section 3.0.3.3.5. On the basis of its review, the staff finds
 
that because these components will be inspected periodically, the aging effect of change in
 
material properties for PVC piping component s exposed to an external environment of indoor air will be effectively managed by the External Surfaces Monitoring Program.
 
In LRA Table 3.3.2-23, the applicant stated that stainless steel piping components and
 
valve bodies exposed to an interior indoor ai r environment do not exhibit any aging effects requiring management. There is no corresponding GALL Report Table 1 line item or GALL
 
Report Volume 2 Chapter VII line item for this material/environment combination. However, GALL Report Volume 2 does contain line item AP-17 for auxiliary systems which applies to stainless steel piping, piping components, and piping elements in an external indoor
 
uncontrolled air environment. This GALL Report Volume 2 line item documents that there
 
are no aging effects for this material/environment combination. Because the GALL Report
 
does not identify any aging effects requiring management for stainless steel piping, piping 3-428 components, and piping elements exposed externa lly to indoor uncontrolled air which is either the same or a more aggressive environment than the interior indoor air environment
 
for these stainless steel line items, the staff finds it acceptable that there are no aging
 
effects. Therefore, the staff concludes that stainless steel piping components and valve
 
bodies exposed to an interior indoor air environment do not exhibit aging effects requiring
 
management. 
 
In LRA Table 3.3.2-23, the applicant proposed to manage the loss of material for stainless
 
steel piping components and valve bodies exposed to an interior clean drainage
 
environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included t he waste management system within the scope of the One-Time Inspection Program to confirm that the aging effect of loss of material in an
 
interior clean drainage environment is either not present or is proceeding very slowly. On the basis of its review, the staff finds that the aging effect of loss of material for stainless
 
steel piping components and valve bodies exposed to an interior clean drainage
 
environment will be effectively managed by the One-Time Inspection Program.
 
In LRA Table 3.3.2-23, the applicant stated that polypropylene acid neutralizing sump tanks
 
exposed to an interior indoor air environment do not exhibit any aging effects requiring management. There is no corresponding GALL Report Table 1 line item or GALL Report
 
Volume 2 Chapter VII line item for this material/environment combination. The staff finds
 
this acceptable because there is no indication in the industry that thermoplastics exposed to
 
an internal indoor air environment have any aging effects requiring management. The generally low operating temperatures and historical good chemical resistance data for
 
thermoplastic components, combined with a la ck of historic negative operating experience, indicate that polypropylene is not likely to experience any degradation from the non-
 
aggressive indoor air. Thermoplastic materials do not display corrosion rates as metals do, but rather rely on chemical resistance to the environments to which they are exposed.
Therefore, based on industry experience and the assumption of proper design and
 
application of the material, the staff finds that the polypropylene acid neutralizing sump
 
tanks exposed to an interior indoor air environment exhibit no aging effects requiring
 
management for the period of extended operation.
 
In LRA Table 3.3.2-23, the applicant proposed to manage change in material properties, for
 
which the applicant includes cracking, for polypropylene acid neutralizing sump tanks
 
exposed to an external environment of indoor ai r using the External Surfaces Monitoring Program.
 
The staff verified that the VEGP External Surfaces Monitoring Program is a new program
 
that inspects external surfaces of mechanical system components requiring aging
 
management for license renewal in external ai r environments. Surfaces constructed from materials susceptible to aging in these environments are inspected at frequencies that
 
assure the effects of aging are managed such that system components will perform their intended function during the period of extended operation. The program will be a monitoring
 
program, which manages aging effects through periodic visual inspections of external
 
surfaces of components such as piping, piping components, ducting, and other components
 
for evidence of material loss. The staff's evaluation of the External Surfaces Monitoring 3-429 Program is documented in SER Section 3.0.3.3.5. On the basis of its review, the staff finds that because these components will be inspected periodically, the aging effect of change in
 
material properties for polypropylene acid neutralizing sump tanks exposed to an external
 
environment of indoor air will be effectively managed by the External Surfaces Monitoring Program.
 
In LRA Table 3.3.2-23, the applicant proposed to manage the loss of material for carbon
 
steel valve bodies exposed to an interior indoor air environment using the One-Time
 
Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the drain system within the scope of the One-
 
Time Inspection Program to confirm that the aging effect of loss of material in an interior
 
indoor air environment is either not present or is proceeding very slowly. On the basis of its review, the staff finds that the aging effect of loss of material for carbon steel valve bodies
 
exposed to an interior indoor air environment will be effectively managed by the One-Time Inspection 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).
 
3.3.2.3.24  Potable and Utility Water Systems: Summary of Aging Management Review -
 
LRA Table 3.3.2-24 
 
The staff reviewed LRA Table 3.3.2-24, which summarizes the results of AMR evaluations
 
for the potable and utility water systems component groups.
 
In LRA Table 3.3.2-24, the applicant proposed to manage the loss of material for copper
 
alloy water hammer arrestors, piping components, hot water recirculation pump casings, strainer housings, and valve bodies exposed to an interior domestic water environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the potable and utility water system within the
 
scope of the One-Time Inspection Program to confirm that the aging effect of loss of
 
material in an interior domestic water environment is either not present or is proceeding
 
very slowly. 
 
On the basis of its review, the staff finds that the aging effect of loss of material for copper
 
alloy water hammer arrestors, piping components, hot water recirculation pump casings, strainer housings, and valve bodies exposed to an interior domestic water environment will be effectively managed by the One-Time Inspection Program.
 
3-430 In LRA Table 3.3.2-24, the applicant proposed to manage loss of preload for copper alloy closure bolting exposed to an external environment of indoor air using the Bolting Integrity
 
Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload of copper alloy closure bolting 
 
exposed to an external environment of indoor air will be effectively managed by the Bolting Integrity Program.
 
In LRA Table 3.3.2-24, the applicant proposed to manage loss of material for carbon steel
 
water heater housings and jackets exposed to an internal environment of domestic water
 
using the Periodic Surveillance and Preventive Maintenance Activities Program.
 
The staff's evaluation of the Periodic Surveillance and Preventive Maintenance Activities
 
Program is documented in SER Section 3.0.3.3.6. The Periodic Surveillance and
 
Preventive Maintenance Activities Program descrip tion states that the program provides for periodic component inspections and testing to detect aging effects. The extent and
 
schedule of inspections and testing assure detection of component degradation prior to loss
 
of intended functions. Inspection and testing intervals are established to provide timely
 
detection of degradation and are dependent on the component, material, and environment, and take into consideration industry and plant-specific operating experience and
 
manufacturer's recommendations. Inspection and testing activities monitor various
 
parameters such as surface condition, loss of material, presence of corrosion products or
 
fluid leakage, signs of cracking, or reduction of wall thickness. Inspection techniques such
 
as visual are used. The staff verified that visual inspection of the within scope potable water
 
system water heater housings has been added to this program as a preventive maintenance task that will manage loss of material by inspecting for evidence of leakage
 
and loss of material on the housing. This program is a plant-specific program. On the basis
 
of its review, the staff finds that because this component will be inspected periodically, the
 
aging effect of loss of material for carbon steel water heater housings and jackets exposed
 
to an internal environment of domestic wate r will be effectively managed by the Periodic Surveillance and Preventive Maintenance Activities 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).
 
3-431 3.3.2.3.25  Radiation Monitoring System
: Summary of Aging Management Review -
LRA Table 3.3.2-25 
 
The staff reviewed LRA Table 3.3.2-25, which summarizes the results of AMR evaluations
 
for the radiation monitoring system component groups.
 
In LRA Table 3.3.2-25, the applicant proposed to manage loss of preload for stainless steel
 
closure bolting exposed to an external environment of indoor air using the Bolting Integrity
 
Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload of stainless steel closure bolting
 
exposed to an external environment of indoor air will be effectively managed by the Bolting Integrity Program.
 
In LRA Table 3.3.2-25, the applicant proposed to manage cracking for carbon steel piping
 
components and valve bodies exposed to an inter nal environment of closed cycle cooling water from the ACCW using the ACCW System Carbon Steel Components Program.
 
The staff's evaluation of the ACCW Syst em Carbon Steel Components Program is documented in SER Section 3.0.3.3.1. On the basis of its review, the staff finds that
 
because these components will be inspected periodically, the aging effect of cracking for
 
carbon steel piping components and valve bodies exposed to an internal environment of closed cycle cooling water from the ACCW system will be effectively managed by the ACCW System Carbon Steel Components Program.
 
In LRA Table 3.3.2-25, the applicant proposed to manage loss of material for carbon steel
 
piping components exposed to an interior dirty drainage environment using the Piping and
 
Duct Internal Inspection Program.
The staff verified that the applicant's Piping and Duct Internal Inspection Program is a new program and has been identified as an AMP that is consistent with program elements in GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components", with exceptions. The staff also verified that like GALL AMP XI.M20, "Open-
 
Cycle Cooling Water System," the scope of t he applicant's program, in part, credits visual examinations to manage corrosion in the internal surfaces of stainless steel piping
 
components that are exposed internally to raw water. The staff also verified that the
 
applicant has addressed the need to implement this AMP in accordance with LRA
 
Commitment No. 19, which was placed on UFSAR Supplement Section A.2.22 and
 
provided in the applicant's letter of March 20, 2008. The staff's evaluation of the Piping and
 
Duct Internal Inspection Program is documented in SER Section 3.0.3.2.13. The staff's 3-432 evaluation described in SER Section 3.0.3.2.13 includes that staff's basis why the Piping and Duct Internal Inspection Program may be used to manage the aging effects that are
 
applicable to carbon steel piping components in t he auxiliary systems. On the basis of its review, the staff finds that the aging effect of loss of material for carbon steel piping
 
components exposed to an interior dirty dr ainage environment will be effectively managed by the Piping and Duct Internal Inspection Program.
 
In LRA Table 3.3.2-25, the applicant proposed to manage loss of material for carbon steel
 
piping components exposed to an interior treated water (aggressive chemistry) environment using the Flow-Accelerated Corrosion Program.
 
The staff's evaluation of the Flow-Accelerated Corrosion Program is documented in SER
 
Section 3.0.3.2.7. The Flow-Accelerated Corrosion Program description states that the
 
program manages loss of material (wall thinning) due to FAC in susceptible plant piping
 
and other components. The program includes analysis to determine susceptible locations, predictive modeling techniques, baseline inspections of wall thickness, follow-up
 
inspections, and repair or replacement of degraded components as necessary. This program is consistent with GALL AMP XI.M17, "Flow-Accelerated Corrosion Program," with
 
exceptions. One exception is that the VEGP Flow-Accelerated Corrosion Program will encompass wall thinning resulting from FAC and will also be used to manage similar
 
phenomena such as cavitation, impingement, and erosion, for piping or components whose
 
failure could result in personnel injuries or detrimental operation effects in systems
 
determined to be susceptible to FAC. Due to this exception, VEGP also uses the Flow-
 
Accelerated Corrosion Program and its inspection techniques to manage wall thinning that
 
is occurring in piping components downstream of the steam generator blowdown
 
demineralizers that is not attributed to FAC. The wall thinning has been attributed to the
 
acidic conditions of the demineralizer effluent. The environment is low temperature and low
 
pressure, so FAC has been eliminated as a cause for this thinning. Ultrasonic testing (UT)
 
is the primary technique used for FAC inspections. Radiographic testing (RT) is also
 
permissible where practical. In addition to UT and RT the VEGP Flow-Accelerated
 
Corrosion Program permits the use of other industry-accepted inspection techniques when
 
practical. Visual inspection (VT) from inside the piping may be performed in certain large-
 
bore systems. On the basis that the VEGP Flow-Accelerated Corrosion Program includes
 
inspections for loss of material in piping components not susceptible to FAC by the same
 
FAC inspection techniques, the staff finds that the aging effect of loss of material for carbon
 
steel piping components exposed to an interior treated water (aggressive chemistry)
 
environment will be effectively managed by the Flow-Accelerated Corrosion Program.
 
In LRA Table 3.3.2-25, the applicant stated that stainless steel piping components and
 
valve bodies exposed to either an interior i ndoor air environment or interior air-ventilation environment do not exhibit any aging e ffects requiring management. There is no corresponding GALL Report Table 1 line item or GALL Report Volume 2 Chapter VII line
 
item for this material/environment combination. However, GALL Report Volume 2 does
 
contain line item AP-17 for auxiliary systems wh ich applies to stainless steel piping, piping components, and piping elements in an exter nal indoor uncontrolled air environment. This GALL Report Volume 2 line item documents that there are no aging effects for this
 
material/environment combination. Because the GALL Report does not identify any aging
 
effects requiring management for stainless steel piping, piping components, and piping
 
elements exposed externally to indoor uncontrolled air which is either the same or a more
 
aggressive environment than the interior indoor air environment for these stainless steel
 
line items, the staff finds it acceptable that there are no aging effects. In addition, the staff 3-433 confirmed that the declaration that stainless steel components exposed to an inside environment in a control room ventilation system experience no aging effects has been previously accepted by the staff in the Farley Nuclear Plant license renewal application
 
SER (NUREG-1825). The inside environment for the Farley control room ventilation system is analogous to the interior air-ventilation environment for the stainless steel piping
 
components and valve bodies at VEGP. Therefore, the staff concludes that stainless steel
 
piping components and valve bodies exposed either to an interior indoor air environment or interior air-ventilation environment do not exhibit aging effects requiring management. 
 
In LRA Table 3.3.2-25, the applicant stated that stainless steel pipe components exposed
 
to an exterior outdoor air environment do not exhibit aging effects requiring management.
The outdoor air environment at VEGP is subject to normal periodic wetting but is not
 
exposed to an aggressive environment from any nearby industrial facilities or to a salt water environment which could have the potential to concentrate contaminates and cause aging
 
effects for stainless steel. In addition, there is no VEGP operating experience which
 
indicates aging effects for stainless steel in the outdoor air environment has occurred. The
 
GALL Report Volume 2 does contain line item AP-18 for auxiliary systems which does not identify any aging effects requiring management for stainless steel component types
 
exposed to air with borated water leakage which is a more aggressive environment than the
 
exterior outdoor air environment for this line item. On the basis of its review of the current
 
plant operating experience and other more aggressive GALL environments for stainless
 
steel, the staff concludes that stainless steel pipe components exposed to an exterior
 
outdoor air environment at VEGP do not ex hibit aging effects requiring management.
 
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).
 
3.3.2.3.26  Reactor Makeup Water Storage Tank and Degasifier System: Summary of
 
Aging Management Review - LRA Table 3.3.2-26 
 
The staff reviewed LRA Table 3.3.2-26, which summarizes the results of AMR evaluations
 
for the reactor makeup water storage tank and degasifier system component groups.
 
In LRA Table 3.3.2-26, the applicant proposed to manage loss of preload either for carbon
 
steel or stainless steel closure bolting expos ed to an external environment of outdoor or indoor air using the Bolting Integrity Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be 3-434 inspected periodically, the aging effect of loss of preload either for carbon steel or stainless steel closure bolting exposed to an external environment of outdoor or indoor air will be effectively managed by the Bolting Integrity Program.
 
In LRA Table 3.5.2-26, the applicant stated that stainless steel pipe components and valve
 
bodies exposed to an exterior outdoor air environment and stainless steel tank liners (and
 
internals) for reactor makeup water storage tanks exposed to an interior outdoor air
 
environment do not exhibit aging effe cts requiring management. The outdoor air environment at VEGP is subject to normal periodic wetting but is not exposed to an
 
aggressive environment from any nearby industria l facilities or to a salt water environment which could have the potential to concentrate contaminates and cause aging effects for
 
stainless steel. In addition, there is no VEGP operating experience which indicates aging
 
effects for stainless steel in the outdoor air environment has occurred. The GALL Report
 
Volume 2 does contain line item AP-18 for aux iliary systems which does not identify any aging effects requiring management for stainless steel component types exposed to air with
 
borated water leakage which is a more aggressive environment than the exterior outdoor
 
air environment and interior outdoor air environment for these AMR items. On the basis of its review of the current plant operating experience and other more aggressive GALL
 
Report environments for stainless steel, the staff concludes that stainless steel pipe
 
components and valve bodies exposed to an exte rior outdoor air environment and stainless steel tank liners (and internals) for reactor makeup water storage tanks exposed to an
 
interior outdoor air environment at VEGP do not exhibit aging effects requiring
 
management.
 
In LRA Table 3.3.2-26, the applicant proposed to manage change in material properties, for
 
which the applicant includes cracking, for elastomer tank diaphragms of reactor makeup
 
water storage tanks exposed either to an internal environment of treated water or external
 
environment of outdoor air using the Periodic Surveillance and Preventive Maintenance
 
Activities Program.
 
The staff's evaluation of the Periodic Surveillance and Preventive Maintenance Activities
 
Program is documented in SER Section 3.0.3.3.6. The Periodic Surveillance and
 
Preventive Maintenance Activities Program descrip tion states that the program provides for periodic component inspections and testing to detect aging effects. The extent and
 
schedule of inspections and testing assure detection of component degradation prior to loss
 
of intended functions. Inspection and testing intervals are established to provide timely
 
detection of degradation and are dependent on the component, material, and environment, and take into consideration industry and plant-specific operating experience and
 
manufacturer's recommendations. Inspection and testing activities monitor various
 
parameters such as surface condition, loss of material, presence of corrosion products or
 
fluid leakage, signs of cracking, or reduction of wall thickness. Inspection techniques such
 
as visual are used. The staff verified that visual inspections of the Boric Acid Storage Tank (BAST), Condensate Storage Tank (CST), and Reactor Make-up Water Storage Tank (RMWST) diaphragms are existing preventiv e maintenance tasks that manage change in material properties (including cracking) and loss of material on the internal elastomer
 
diaphragms in these tanks. This program is a plant-specific program. On the basis of its
 
review, the staff finds that because this component will be inspected periodically, the aging
 
effect of change in material properties, for which the applicant includes cracking, for
 
elastomer tank diaphragms of reactor makeup water storage tanks exposed either to an
 
internal environment of treated water or external environment of outdoor air will be 3-435 effectively managed by the Periodic Surveill ance and Preventive Maintenance Activities 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).
 
3.3.2.3.27  Sampling Systems: Summary of Aging Management Review - LRA 
 
Table 3.3.2-27 
 
The staff reviewed LRA Table 3.3.2-27, which summarizes the results of AMR evaluations
 
for the sampling systems component groups.
 
In LRA Table 3.3.2-27, the applicant proposed to manage loss of preload either for
 
aluminum alloy or stainless closure bolting ex posed to an external environment of indoor air using the Bolting Integrity Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload either for aluminum alloy or
 
stainless steel closure bolting exposed to an external environment of indoor air will be effectively managed by the Bolting Integrity Program.
In LRA Table 3.3.2-27, the applicant proposed to manage cracking for carbon steel piping components, shells and end plates of the primary and secondary side of sample coolers, and valve bodies exposed to an internal environment of closed cycle cooling water from the ACCW using the ACCW System Carbon Steel Components Program.
 
The staff's evaluation of the ACCW Syst em Carbon Steel Components Program is documented in SER Section 3.0.3.3.1. The ACCW System Carbon Steel Components
 
Program description states cracking of carbon steel components exposed to auxiliary component cooling water is managed through a combination of leakage monitoring, routine
 
walkdowns and periodic visual inspections. The program is in response to operating
 
experience related to nitrite induced SCC and subsequent component leakage in the VEGP
 
ACCW system components. This program is a pl ant-specific program. On the basis of its review, the staff finds that because these components will be inspected periodically, the
 
aging effect of cracking for carbon steel piping components, shells and end plates of the
 
primary and secondary side of sample coolers, and valve bodies exposed to an internal
 
environment of closed cycle cooling water fr om the ACCW system will be effectively managed by the ACCW System Ca rbon Steel Components Program.
3-436  In LRA Table 3.3.2-27, the applicant proposed to manage the loss of material for carbon
 
steel piping components and valve bodies exposed to an interior miscellaneous gas
 
environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections
 
are to be used to confirm the slow progression or the absence of an aging effect. The staff
 
confirmed that the applicant has included the sampling system within the scope of the One-
 
Time Inspection Program to confirm that the aging effect of loss of material in an interior
 
miscellaneous gas environment is either not pres ent or is proceeding very slowly. On the basis of its review, the staff finds that the aging effect of loss of material for carbon steel
 
piping components and valve bodies exposed to an interior miscellaneous gas environment will be effectively managed by the One-Time Inspection Program.
In LRA Table 3.3.2-27, the applicant proposed to manage the loss of material for galvanized steel piping components exposed to an interior treated water environment using the Water Chemistry Control and the One-Time Inspection Programs.
 
The staff evaluations of the Water Chemistry Control and One-Time Inspection Programs
 
are documented in SER Sections 3.0.3.1.4 and 3.0.3.1.2, respectively. The Water
 
Chemistry Control description states that the program mitigates loss of material, cracking, and reduction in heat transfer in system components and structures through the control of
 
water chemistry. The program includes control of detrimental chemical species and the
 
addition of chemical agents. The Water Chemistry Control Program is consistent with GALL AMP XI.M2, "Water Chemistry." The staff verified that the scope of secondary water
 
chemistry control includes sampling of condensate, feedwater, blowdown, the steam
 
generators, and the condensate storage tanks. The One-Time Inspection Program
 
description states that one-time inspections are to be used to confirm the slow progression
 
or the absence of an aging effect. The staff confirmed that the applicant has included the
 
sampling system within the scope of the One-Time Inspection Program to confirm that the
 
aging effect of loss of material for galvanized steel in an interior treated water environment
 
is either not present or is proceeding very slowly. On the basis of its review, the staff finds
 
that the aging effect of loss of material for galvanized steel piping components exposed to
 
an interior treated water environment will be effectively managed by the Water Chemistry Control and One-Time Inspection Programs.
In LRA Table 3.3.2-27, the applicant proposed to manage cracking for nickel alloy piping components exposed to an interior steam envir onment using the Water Chemistry Control Program.
 
The staff evaluation of the Water Chemistry Control Program is documented in SER
 
Section 3.0.3.1.4. The Water Chemistry Control Program description states that the
 
program mitigates loss of material, cracking, and reduction in heat transfer in system
 
components and structures through the control of water chemistry. The program includes
 
control of detrimental chemical species and the addition of chemical agents. The Water
 
Chemistry Control Program is consistent with GALL AMP XI.M2, "Water Chemistry." The staff verified that the scope of secondary water chemistry control includes sampling of
 
condensate, feedwater, blowdown, the steam generators, and the condensate storage
 
tanks. There is no corresponding GALL Report Table 1 line item or GALL Report Volume 2
 
Chapter VII line item for this material/environment combination. However, GALL Report 3-437 Volume 2 does contain line item R-36 under reactor vessel, internals, and reactor coolant systems for once through steam generators which applies to nickel alloy steam generator
 
components (such as secondary side nozzles for vents, drains, and instrumentation) in a
 
secondary feedwater/steam environment. This GALL Report Volume 2 line item documents that for this material/environment combination there is the aging effect cracking for which the GALL Report recommends GALL AMP XI.M2, "Water Chemistry" to manage. Because the GALL Report identifies cracking as an aging effect requiring management for nickel
 
alloy steam generator components such as secondary side vent, drain, and instrumentation
 
nozzles exposed to secondary feedwater/steam using the Water Chemistry Program, the
 
staff finds it acceptable to manage cracking for nickel alloy piping components exposed to
 
an interior steam environment using t he Water Chemistry Control Program.
In LRA Table 3.3.2-27, the applicant stated that stainless steel piping components and valve bodies exposed to an interior misce llaneous gas environment do not exhibit any aging effects requiring management. There is no corresponding GALL Report Table 1 line
 
item or GALL Report Volume 2 Chapter VII line item for this material/environment
 
combination. However, GALL Report Volume 2 does contain line item AP-22 for auxiliary
 
systems which applies to stainless steel piping, piping components, and piping elements in
 
a gas (internal gas environments from dry air, inert or nonreactive gases). This GALL
 
Report Volume 2 line item documents that there are no aging effects for this
 
material/environment combination. Because the GALL Report does not identify any aging
 
effects requiring management for stainless steel piping, piping components, and piping
 
elements exposed to gas which is either the same or very similar to the interior
 
miscellaneous gas environment for these stainless steel line items, the staff finds it
 
acceptable that there are no aging effects. Therefore, the staff concludes that stainless
 
steel piping components and valve bodies exposed to an interior miscellaneous gas
 
environment do not exhibit aging effects requiring management. 
 
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).
 
3.3.2.3.28  Auxiliary Gas Systems:
Summary of Aging Management Review -
LRA Table 3.3.2-28 
 
The staff reviewed LRA Table 3.3.2-28, which summarizes the results of AMR evaluations
 
for the auxiliary gas systems component groups.
 
In LRA Table 3.3.2-28, the applicant proposed to manage loss of preload for stainless steel
 
closure bolting exposed to an external environment of indoor air using the Bolting Integrity
 
Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity 3-438 includes an assessment of ability of the program elements to manage aging consistent with the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload of stainless steel closure bolting
 
exposed to an external environment of indoor air will be effectively managed by the Bolting Integrity 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).
 
3.3.2.3.29  Chilled Water Systems: Summary of Aging Management Review -
 
LRA Table 3.3.2-29 
 
The staff reviewed LRA Table 3.3.2-29, which summarizes the results of AMR evaluations
 
for the chilled water systems component groups.
 
In LRA Table 3.3.2-29, the applicant stated that carbon steel condenser shells for essential
 
chillers, evaporator shells for essential chillers, and chiller economizer tanks exposed to an
 
interior freon environment do not exhibit any aging effects requiring management. There is no corresponding GALL Report Table 1 line item or GALL Report Volume 2 Chapter VII line
 
item for this material/environment combination. However, GALL Report Volume 2 does
 
contain line item AP-6 for auxiliary system s which applies to steel piping, piping components, and piping elements in a gas environment (defined in the GALL Report as
 
internal gas environments from dry air, inert or nonreactive gases). This GALL Report
 
Volume 2 line item documents that there are no aging effects for this material/environment
 
combination. Because the GALL Report does not identify any aging effects requiring
 
management for steel piping, piping components, and piping elements exposed to gas
 
which is either the same or very similar to the interior Freon environment for these carbon
 
steel line items, the staff finds it acceptable that there are no aging effects. Therefore, the
 
staff concludes that carbon steel condenser shells for essential chillers, evaporator shells
 
for essential chillers, and chiller economizer tanks exposed to an interior Freon
 
environment do not exhibit aging effects requiring management. 
 
In LRA Table 3.3.2-29, the applicant stated that copper alloy condenser tubes for essential
 
chillers and evaporator tubes for essential chillers and copper alloy condenser tubesheets
 
for essential chillers and evaporator tubesheets for essential chillers exposed to an exterior
 
Freon environment do not exhibit any aging effects requiring management. There is no corresponding GALL Report Table 1 line item or GALL Report Volume 2 Chapter VII line
 
item for this material/environment combination. However, GALL Report Volume 2 does
 
contain line item AP-9 for auxiliary systems which applies to copper alloy piping, piping
 
components, and piping elements in a gas environment (defined in the GALL Report as
 
internal gas environments from dry air, inert or nonreactive gases). This GALL Report
 
Volume 2 line item documents that there are no aging effects for this material/environment
 
combination. Because the GALL Report does not identify any aging effects requiring
 
management for copper alloy piping, piping components, and piping elements exposed to
 
gas which is either the same or very sim ilar to the exterior Freon environment for these copper alloy line items, the staff finds it acceptable that there are no aging effects.
3-439 Therefore, the staff concludes that copper alloy condenser tubes for essential chillers and evaporator tubes for essential chillers and copper alloy condenser tubesheets for essential
 
chillers and evaporator tubesheets for essential chillers exposed to an exterior Freon
 
environment do not exhibit aging effects requiring management.
In LRA Table 3.3.2-29, the applicant stated that glass sight glasses exposed to an interior closed-cycle cooling water environment do not exhibit any aging effects requiring management. There is no corresponding GALL Report Table 1 line item or GALL Report
 
Volume 2 Chapter VII line item for this material/environment combination. However, GALL
 
Report Volume 2 does contain line item AP-51 for auxiliary systems which applies to glass piping elements in a treated water environment (defined in the GALL Report as
 
demineralized water, which is the base water for all clean systems. Depending on the
 
system, this demineralized water may require additional processing. Treated water could be
 
deaerated and include corrosion inhibitors, biocides, or some combination of these
 
treatments). This GALL Report Volume 2 line item documents that there are no aging
 
effects for this material/environment combination. Because the GALL Report does not
 
identify any aging effects requiring management for glass piping elements exposed to
 
treated water which is either the same or very similar to the closed-cycle cooling water
 
environment for this glass line item, the staff finds it acceptable that there are no aging
 
effects. Therefore, the staff concludes that glass sight glasses exposed to an interior
 
closed-cycle cooling water environment do not exhibit aging effects requiring management. 
 
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  Waste Management Systems:
Summary of Aging Management Review -
LRA Table 3.3.2-30 
 
The staff reviewed LRA Table 3.3.2-30, which summarizes the results of AMR evaluations
 
for the waste management systems component groups.
 
In LRA Table 3.3.2-30, the applicant proposed to manage loss of preload for stainless steel
 
closure bolting exposed to an external environment of indoor air using the Bolting Integrity
 
Program.
 
The staff verified that the applicant's Bolting Integrity Program is a new plant-specific
 
program and that the scope of the program is credited to manage cracking, loss of material, and loss of preload both safety-related and nonsafety-related closure bolting for pressure-
 
retaining components within the scope of license renewal, with the exception of the reactor
 
vessel head studs which are managed in accordance with the applicant's Reactor Vessel
 
Head Closure Stud Program. The staff's evaluation of the Bolting Integrity Program is
 
documented in SER Section 3.0.3.3.2. The staff's evaluation of the Bolting Integrity
 
includes an assessment of ability of the program elements to manage aging consistent with
 
the staff's recommended criteria for AMP program elements in Section A.2.1.3 of NRC
 
Branch Position No. RLSB-1 (i.e., in Appendix A of the SRP-LR [NUREG-1800, Revision
 
1]). On the basis of its review, the staff finds that, because these components will be
 
inspected periodically, the aging effect of loss of preload of stainless steel closure bolting 3-440  exposed to an external environment of indoor air will be effectively managed by the Bolting Integrity Program.
 
In LRA Table 3.3.2-30, the applicant proposed to manage the loss of material for stainless
 
steel filter housings, flow orifice elements, piping components, pipe spools for startup
 
strainers, gas decay drain pump casings, backflushable filter crud tanks, and valve bodies
 
exposed to an interior clean drainage environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The staff confirmed that the applicant has included the waste management
 
system within the scope of the One-Time Inspection Program to confirm that the aging
 
effect of loss of material in an interior clean drainage environment is either not present or is
 
proceeding very slowly. On the basis of its review, the staff finds that the aging effect of
 
loss of material for stainless steel filter housings, flow orifice elements, piping components, pipe spools for startup strainers, gas decay drain pump casings, backflushable filter crud
 
tanks, and valve bodies exposed to an interior clean drainage environment will be
 
effectively managed by the One-Time Inspection Program.
 
In LRA Table 3.3.2-30, the applicant proposed to manage loss of material either for
 
stainless steel filter housings, piping components, and valve bodies or carbon steel gas
 
traps exposed either to an interior dirty drainage environment or interior indoor air (wetted)
 
environment using the Piping and Duct Internal Inspection Program.
 
The staff verified that the applicant's Piping and Duct Internal Inspection Program is a new
 
program and has been identified as an AMP that is consistent with program elements in GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," with exceptions. The staff also verified that like GALL AMP XI.M20, "Open-
 
Cycle Cooling Water System," the scope of t he applicant's program, in part, credits visual examinations to manage corrosion in the internal surfaces of stainless steel piping
 
components that are exposed internally to raw water. The staff also verified that the
 
applicant has addressed the need to implement this AMP in accordance with LRA
 
Commitment No. 19, which was placed on UFSAR Supplement Section A.2.22 and
 
provided in the applicant's letter of March 20, 2008. The staff's evaluation of the Piping and
 
Duct Internal Inspection Program is documented in SER Section 3.0.3.2.13. The staff's
 
evaluation of the Piping and Duct Internal Inspection Program is documented in SER
 
Section 3.0.3.2.13. The staff's evaluation described in SER Section 3.0.3.2.13 includes that
 
staff's basis why the Piping and Duct Internal Inspection Program may be used to manage
 
the aging effects that are applicable to stainless steel and carbon steel components in the
 
auxiliary systems. On the basis of its review, the staff finds that the aging effect of loss of
 
material either for stainless steel filter housings, piping components, and valve bodies or
 
carbon steel gas traps exposed either to an interior dirty drainage environment or interior
 
indoor air (wetted) environment will be effect ively managed by the Piping and Duct Internal Inspection Program.
 
In LRA Table 3.3.2-30, the applicant proposed to manage the loss of material for carbon
 
steel gas traps, piping components, and valve bodies exposed to an interior clean drainage
 
environment using the One-Time Inspection Program.
 
The staff's evaluation of the One-Time Inspection Program is documented in SER Section
 
3.0.3.1.2. The One-Time Inspection Program description states that one-time inspections 3-441 are to be used to confirm the slow progression or the absence of an aging effect. The staff confirmed that the applicant has included t he waste management system within the scope of the One-Time Inspection Program to confirm that the aging effect of loss of material in an
 
interior clean drainage environment is either not present or is proceeding very slowly. On the basis of its review, the staff finds that the aging effect of loss of material for carbon steel
 
gas traps, piping components, and valve bodies exposed to an interior clean drainage
 
environment will be effectively managed by the One-Time Inspection 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).
 
3.3.2.3.31  Thermal Insulation: Summary of Aging Management Review - 
 
LRA Table 3.3.2-31 
 
The staff reviewed LRA Table 3.3.2-31, which summarizes the results of AMR evaluations
 
for the thermal insulation component groups.
 
In LRA Table 3.3.2-31, the applicant stated that stainless steel jacketing and supports for
 
insulation exposed to an exterior exposed to weather environment do not exhibit aging effects requiring management. The exposed to weat her environment at VEGP is subject to normal periodic wetting but is not exposed to an aggressive environment from any nearby industrial facilities or to a salt water environment which could have the potential to
 
concentrate contaminates and cause aging effects for stainless steel. In addition, there is
 
no VEGP operating experience which indicates aging effects for stainless steel in the
 
exposed to weather environment has occurred. The GALL Report Volume 2 does contain
 
line item AP-18 for auxiliary systems which does not identify any aging effects requiring management for stainless steel component types exposed to air with borated water leakage
 
which is a more aggressive environment than the exterior exposed to weather environment for this line item. On the basis of its review of the current plant operating experience and
 
other more aggressive GALL Report environments for stainless steel, the staff concludes
 
that stainless steel jacketing and supports for insulation exposed to an exterior exposed to
 
weather environment at VEGP do not ex hibit aging effects requiring management.
 
In LRA Table 3.3.2-31, the applicant stated that fiber, foam and ceramic thermal insulation
 
exposed to a protected from weather envir onment do not exhibit aging effects requiring management. The applicant stated that there has never been any plant-specific aging effect
 
noted for these components. The staff's review of site operating experience did not identify
 
any aging effects for these components at VEGP. On the basis of its review of current
 
industry research and current plant operating experience, the staff concludes that fiber, foam and ceramic thermal insulation exposed to a protected from weather environment at VEGP do not exhibit aging effects requiring management.
 
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).
 
3-442 3.3.2.3.32  Miscellaneous Leak Detection System: Summary of Aging Management Review
- LRA Table 3.3.2-32 
 
The staff reviewed LRA Table 3.3.2-32, which summarizes the results of AMR evaluations
 
for the miscellaneous leak detection system component groups.
 
In LRA Table 3.3.2-32, the applicant stated that stainless steel piping components exposed
 
to an interior indoor air environment do not exhibit any aging effects requiring management.
There is no corresponding GALL Report Table 1 line item or GALL Report Volume 2
 
Chapter VII line item for this material/environment combination. However, GALL Report
 
Volume 2 does contain line item AP-17 for auxilia ry systems which applies to stainless steel piping, piping components, and piping elements in an external indoor uncontrolled air
 
environment. This GALL Report Volume 2 line item documents that there are no aging
 
effects for this material/environment combination. Because the GALL Report does not
 
identify any aging effects requiring management for stainless steel piping, piping
 
components, and piping elements exposed externa lly to indoor uncontrolled air which is either the same or a more aggressive environment than the interior indoor air environment
 
for these stainless steel line items, the staff finds it acceptable that there are no aging
 
effects. Therefore, the staff concludes that stainless steel piping components exposed to an
 
interior indoor air environment do not ex hibit aging effects requiring management. 
 
On the basis of its review, the staff finds that the applicant has appropriately evaluated the
 
AMR results of material, environment, AERM, and AMP combinations not evaluated in the
 
GALL Report. The staff finds that the applicant has demonstrated that the effects of aging
 
will be adequately managed so that the intended function(s) will be maintained consistent
 
with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.3.3  Conclusion The staff concludes that the applicant has provided sufficient information to demonstrate
 
that the effects of aging for the auxiliary systems components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.4  Aging Management of Steam and Power Conversion Systems This section of the SER documents the staff's review of the applicant's AMR results for the
 
steam and power conversion system s components and component groups of:
* main steam system
* feedwater system
* SG blowdown processing system
* auxiliary feedwater system
* auxiliary steam system 3.4.1  Summary of Technical Information in the Application LRA Section 3.4 provides AMR results fo r the steam and power conversion systems components and component groups. LRA Table 3.4.1, "Summary of Aging Management
 
Reviews for Steam and Power Conversion Syst ems in Chapter VIII of NUREG-1801," is a 3-443 summary comparison of the applicant's AMRs with those evaluated in the GALL Report for the steam and power conversion sy stems components and component groups.
 
The applicant's AMRs evaluated and incorporated applicable plant-specific and industry
 
operating experience in the determination of AERMs. The plant-specific evaluation included
 
condition reports and discussions with appropriate site personnel to identify AERMs. The
 
applicant's review of industry operating experience included a review of the GALL Report
 
and operating experience issues identified since the issuance of the GALL Report.
 
3.4.2  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 licens e 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 audit of AMRs to verify the applicant's claim that certain AMRs were
 
consistent with the GALL Report. The staff did not repeat its review of the matters
 
described in the GALL Report; however, the staff did verify that the material presented in
 
the LRA was applicable and that the applicant identified the appropriate GALL Report
 
AMRs. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details
 
of the staff's audit evaluation are documented in SER Section 3.4.2.1.
 
In the audit, the staff also selected AMRs consistent with the GALL Report and for which
 
further evaluation is recommended. The staff confirmed that the applicant's further
 
evaluations were consistent with the SRP-LR Section 3.4.2.2 acceptance criteria. The
 
staff's audit evaluations are documented in SER Section 3.4.2.2.
 
The staff also conducted a technical review of the remaining AMRs not consistent with or
 
not addressed in the GALL Report. The technical review evaluated whether all plausible
 
aging effects have been identified and whether the aging effects listed were appropriate for
 
the material-environment combinations specified. The staff's evaluations are documented in
 
SER Section 3.4.2.3.
 
For SSCs which the applicant claimed were not applicable or required no aging
 
management, the staff reviewed the AMR line items and the plant's operating experience to
 
verify the applicant's claims.
 
Table 3.4-1 summarizes the staff's evaluation of components, aging effects or mechanisms, and AMPs listed in LRA Section 3.4 and addressed in the GALL Report.
 
Table 3.4-1  Staff Evaluation for Steam and Power Conversion Systems Components in the GALL Report Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation
 
3-444 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel piping, piping components, and
 
piping elements
 
exposed to steam or treated water
 
(3.4.1-1)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes TLAA Fatigue is a TLAA (See SER
 
Section 3.4.2.2.1)
Steel piping, piping components, and
 
piping elements
 
exposed to steam
 
(3.4.1-2)
Loss of material due to general, pitting and
 
crevice corrosion Water Chemistry and One-Time InspectionYes Water Chemistry Control Program (B.3.28) and One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.4.2.2.2(1))
Steel heat exchanger
 
components exposed to treated water
 
(3.4.1-3)
Loss of material due to general, pitting and
 
crevice corrosion Water Chemistry and One-Time InspectionYes Water Chemistry Control Program (B.3.28) and One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.4.2.2.2(1))
Steel piping, piping
 
components, and
 
piping elements
 
exposed to treated water (3.4.1-4)
Loss of material due to general, pitting and
 
crevice corrosion Water Chemistry and One-Time InspectionYes Water Chemistry Control Program (B.3.28) and One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.4.2.2.2(1))
Steel heat exchanger
 
components exposed to treated water
 
(3.4.1-5)
Loss of material due to general, pitting, crevice, and galvanic
 
corrosion Water Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.4.2.2.2(2))
Steel and stainless
 
steel tanks exposed to treated water
 
(3.4.1-6)
Loss of material due to general (steel only)
 
pitting and
 
crevice corrosion Water Chemistry and One-Time InspectionYes Water Chemistry Control Program (B.3.28) and One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Sections
 
3.4.2.2.2(1))and
 
3.4.2.2.7(1))
3-445 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel piping, piping components, and
 
piping elements
 
exposed to
 
lubricating oil
 
(3.4.1-7)
Loss of material due to general, pitting and
 
crevice corrosion Lubricating Oil Analysis and One-Time InspectionYes Oil Analysis Program (B.3.16) and One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.4.2.2.2(2))
Steel piping, piping
 
components, and
 
piping elements exposed to raw water
 
(3.4.1-8)
Loss of material due to general, pitting, crevice, and microbiologically
-influenced
 
corrosion, and
 
fouling Plant specific Yes Not applicable Not applicable to VEGP (See SER
 
Section 3.4.2.2.3)
Stainless steel and copper alloy heat
 
exchanger tubes
 
exposed to treated water (3.4.1-9)
Reduction of heat transfer
 
due to fouling Water Chemistry and One-Time InspectionYes Water Chemistry Control Program (B.3.28) and One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.4.2.2.4(1))
Steel, stainless steel, and copper alloy heat
 
exchanger tubes
 
exposed to
 
lubricating oil
 
(3.4.1-10)
Reduction of heat transfer
 
due to fouling Lubricating Oil Analysis and One-Time InspectionYes Oil Analysis Program (B.3.16) and One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.4.2.2.4(2))
Buried steel piping, piping components, piping elements, and tanks (with or without coating or wrapping)
 
exposed to soil
 
(3.4.1-11)
Loss of material due to general, pitting, crevice, and microbiologically
-influenced
 
corrosion Buried Piping and Tanks Surveillance 
 
or
 
Buried Piping and Tanks Inspection Yes Not applicable Not applicable to VEGP (See SER
 
Section 3.4.2.2.5(1))
Steel heat exchanger
 
components exposed
 
to lubricating oil
 
(3.4.1-12)
Loss of material due to general, pitting, crevice, and microbiologically
-influenced
 
corrosion Lubricating Oil Analysis and One-Time InspectionYes Not applicable Not applicable to VEGP (See SER
 
Section 3.4.2.2.5(2))
3-446 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel piping, piping
 
components, piping
 
elements exposed to
 
steam (3.4.1-13)
Cracking due to stress corrosion
 
cracking Water Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (See
 
SER Section
 
3.4.2.2.6)
Stainless steel
 
piping, piping
 
components, piping
 
elements, tanks, and
 
heat exchanger
 
components exposed to treated water
> 60&deg;C (> 140&deg;F)
 
(3.4.1-14)
Cracking due to stress corrosion
 
cracking Water Chemistry and One-Time InspectionYes Water Chemistry Control Program (B.3.28) and One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.4.2.2.6)
Aluminum and copper alloy piping, piping components, and piping elements
 
exposed to treated water (3.4.1-15)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time InspectionYes Water Chemistry Control Program (B.3.28) and One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section 3.4.2.2.7(1))
Stainless steel
 
piping, piping
 
components, and
 
piping elements;
 
tanks, and heat
 
exchanger
 
components exposed to treated water
 
(3.4.1-16)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time InspectionYes Water Chemistry Control Program (B.3.28) and One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section 3.4.2.2.7(1))
Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to soil
 
(3.4.1-17)
Loss of material due to pitting
 
and crevice
 
corrosion Plant specific Yes Buried Piping and Tanks
 
Inspection
 
Program (B.3.4) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section 3.4.2.2.7(2)) Copper alloy piping, piping components, and piping elements
 
exposed to
 
lubricating oil
 
(3.4.1-18)
Loss of material due to pitting
 
and crevice
 
corrosion Lubricating Oil Analysis and One-Time InspectionYes Not applicable Not applicable to VEGP (See SER
 
Section 3.4.2.2.7(3))
3-447 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel piping, piping
 
components, piping
 
elements, and heat
 
exchanger
 
components exposed
 
to lubricating oil
 
(3.4.1-19)
Loss of material due to pitting, crevice, and
 
microbiologically
-influenced
 
corrosion Lubricating Oil Analysis and One-Time InspectionYes Oil Analysis Program (B.3.16) and One-Time Inspection
 
Program (B.3.17) Consistent with the GALL Report, which
 
recommends
 
further evaluation (See
 
SER Section
 
3.4.2.2.8)
Steel tanks exposed
 
to air - outdoor (external)
 
(3.4.1-20)
Loss of material, general, pitting, and crevice
 
corrosion Aboveground Steel Tanks No External Surfaces Monitoring
 
Program (B.3.8) Consistent with the GALL Report (See SER Section 3.4.2.1.6)
High-strength steel
 
closure bolting exposed to air with steam or water
 
leakage (3.4.1-21)
Cracking due to cyclic loading, stress corrosion
 
cracking Bolting Integrity No Not applicable Not applicable to VEGP Steel bolting and
 
closure bolting exposed to air with steam or water
 
leakage, air - outdoor (external), or air -
 
indoor uncontrolled (external);
 
(3.4.1-22)
Loss of material due to general, pitting and
 
crevice corrosion; loss
 
of preload due to
 
thermal effects, gasket creep, and self-loosening Bolting Integrity No Bolting Integrity Program (B.3.2) Consistent with the GALL Report (See SER Sections 3.4.2.1.1 and
 
3.4.2.1.2)
Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to closed-cycle cooling water
> 60&deg;C (> 140&deg;F)
 
(3.4.1-23)
Cracking due to stress corrosion
 
cracking Closed-Cycle Cooling Water System No Not applicable Not applicable to VEGP Steel heat exchanger
 
components exposed to closed cycle cooling water
 
(3.4.1-24)
Loss of material due to general, pitting, crevice, and galvanic
 
corrosion Closed-Cycle Cooling Water System No Not applicable Not applicable to VEGP Stainless steel
 
piping, piping
 
components, piping
 
elements, and heat
 
exchanger
 
components exposed to closed cycle cooling water
 
(3.4.1-25)
Loss of material due to pitting
 
and crevice
 
corrosion Closed-Cycle Cooling Water System No Not applicable Not applicable to VEGP 3-448 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Copper alloy piping, piping components, and piping elements
 
exposed to closed cycle cooling water
 
(3.4.1-26)
Loss of material due to pitting, crevice, and
 
galvanic corrosion Closed-Cycle Cooling Water System No Not applicable Not applicable to VEGP Steel, stainless steel, and copper alloy heat
 
exchanger tubes
 
exposed to closed cycle cooling water
 
(3.4.1-27)
Reduction of heat transfer
 
due to fouling Closed-Cycle Cooling Water System No Not applicable Not applicable to VEGP Steel external
 
surfaces exposed to
 
air - indoor
 
uncontrolled (external),
condensation (external), or air
 
outdoor (external)
 
(3.4.1-28)
Loss of material due to general
 
corrosion External Surfaces Monitoring No External Surfaces Monitoring
 
Program (B.3.8) Consistent with the GALL Report Steel piping, piping
 
components, and
 
piping elements
 
exposed to steam or treated water
 
(3.4.1-29) Wall thinning due to flow-
 
accelerated
 
corrosion Flow-Accelerated Corrosion No Flow Accelerated
 
Corrosion
 
Program (B.3.10) Consistent with the GALL Report Steel piping, piping
 
components, and
 
piping elements
 
exposed to air
 
outdoor (internal) or
 
condensation (internal)
 
(3.4.1-30)
Loss of material due to general, pitting, and
 
crevice corrosion Inspection of Internal Surfaces in
 
Miscellaneous Piping
 
and Ducting
 
Components No Piping and Duct Internal Inspection
 
Program (B.3.22) Consistent with the GALL Report Steel heat exchanger
 
components exposed to raw water
 
(3.4.1-31)
Loss of material due to general, pitting, crevice, galvanic, and
 
microbiologically
-influenced
 
corrosion, and
 
fouling Open-Cycle Cooling Water System No Periodic Surveillance and
 
Preventive
 
Maintenance
 
Activities (B.3.21) Consistent with the GALL Report (See SER Section 3.4.2.1.5)
Stainless steel and copper alloy piping, piping components, and piping elements exposed to raw water
 
(3.4.1-32)
Loss of material due to pitting, crevice, and
 
microbiologically
-influenced
 
corrosion Open-Cycle Cooling Water System No Not applicable Not applicable to VEGP 3-449 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel heat exchanger
 
components exposed to raw water
 
(3.4.1-33)
Loss of material due to pitting, crevice, and
 
microbiologically
-influenced
 
corrosion, and
 
fouling Open-Cycle Cooling Water System No Not applicable Not applicable to VEGP Steel, stainless steel, and copper alloy heat
 
exchanger tubes exposed to raw water
 
(3.4.1-34)
Reduction of heat transfer
 
due to fouling Open-Cycle Cooling Water System No Not applicable Not applicable to VEGP Copper alloy
> 15% Zn piping, piping components, and piping elements
 
exposed to closed cycle cooling water, raw water, or treated water (3.4.1-35)
Loss of material due to selective
 
leaching Selective Leaching of Materials No Not applicable Not applicable to VEGP Gray cast iron piping, piping components, and piping elements
 
exposed to soil, treated water, or raw water (3.4.1-36)
Loss of material due to selective
 
leaching Selective Leaching of Materials No Not applicable Not applicable to VEGP Steel, stainless steel, and nickel-based alloy piping, piping
 
components, and
 
piping elements
 
exposed to steam
 
(3.4.1-37)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry No Water Chemistry Control Program (B.3.28) Consistent with GALL Report Steel bolting and
 
external surfaces exposed to air with borated water
 
leakage (3.4.1-38)
Loss of material due to boric acid
 
corrosion Boric Acid Corrosion No Boric Acid Corrosion
 
Control Program (B.3.3) Consistent with GALL Report Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to steam
 
(3.4.1-39)
Cracking due to stress corrosion
 
cracking Water Chemistry No Water Chemistry Control Program (B.3.28) Consistent with GALL Report 3-450 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Glass piping elements exposed to
 
air, lubricating oil, raw water, and treated water
 
(3.4.1-40) None None No Not applicable Not applicable to VEGP Stainless steel, copper alloy, and nickel alloy piping, piping components, and piping elements
 
exposed to air -
 
indoor uncontrolled (external)
 
(3.4.1-41) None None No None Consistent with GALL Report Steel piping, piping
 
components, and
 
piping elements
 
exposed to air -
 
indoor controlled (external)
 
(3.4.1-42) None None No Not applicable Not applicable to VEGP Steel and stainless
 
steel piping, piping
 
components, and
 
piping elements in
 
concrete (3.4.1-43) None None No None Consistent with GALL Report Steel, stainless steel, aluminum, and copper alloy piping, piping components, and piping elements
 
exposed to gas
 
(3.4.1-44) None None No None Consistent with GALL Report The staff's review of the steam and power conversion systems component groups followed any one of several approaches. One approach, documented in SER Section 3.4.2.1, reviewed AMR results for components that the applicant indicated are consistent with the
 
GALL Report and require no further evaluation. Another approach, documented in SER
 
Section 3.4.2.2, reviewed AMR results for components that the applicant indicated are
 
consistent with the GALL Report and for which further evaluation is recommended. A third
 
approach, documented in SER Section 3.4.2.3, reviewed AMR results for components that
 
the applicant indicated are not consistent with, or not addressed in, the GALL Report. The
 
staff's review of AMPs credited to manage or monitor aging effects of the steam and power conversion systems components is doc umented in SER Section 3.0.3.
3.4.2.1  AMR Results Consistent with the GALL Report LRA Section 3.4.2.1 identifies the materials, environments, AERMs, and the following 3-451 programs that manage aging effects for t he steam and power conversion systems components:
* Bolting Integrity Program
* Boric Acid Corrosion Control Program
* Buried Piping and Tanks Inspection Program
* External Surfaces Monitoring Program
* Flow-Accelerated Corrosion Program
* Oil Analysis Program
* One-Time Inspection Program
* Periodic Surveillance and Preventive Maintenance Activities
* Piping and Duct Internal Inspection Program
* Water Chemistry Control Program
 
LRA Tables 3.4.2-1 through 3.4.2-5 summarize AMRs for the steam and power conversion
 
systems components and indicate AMRs claim ed 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
 
staff's audit and review determined whether the plant-specific components of these GALL
 
Report component groups were bounded by the GALL Report evaluation.
 
The applicant noted for each AMR line item how the information in the tables aligns with the
 
information in the GALL Report. The staff audited those AMRs with notes A 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
 
Report AMP. The staff audited these line items to verify consistency with the GALL Report
 
and validity of the AMR for the site-specific conditions.
 
Note B indicates that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the
 
GALL Report AMP. The staff audited these line items to verify consistency with the GALL
 
Report and verified that the identified exceptions to the GALL Report AMPs have been
 
reviewed and accepted. 
 
The staff also determined whether the applicant's AMP was consistent with the GALL
 
Report AMP and whether the AMR was valid for the site-specific conditions.
 
Note C indicates that the component for the AMR line item, although different from, is
 
consistent with the GALL Report for material, environment, and aging effect. In addition, the
 
AMP is consistent with the GALL Report 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 determined 
 
whether the AMR line item of the different component was applicable to the component
 
under review and whether the AMR was valid for the site-specific conditions.
 
3-452 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 Report AMP. The staff audited these line items to
 
verify consistency with the GALL Report. The staff verified whether the AMR line item of the
 
different component was applicable to the component under review and whether the
 
identified exceptions to the GALL Report AMPs have been reviewed and accepted. The
 
staff also determined whether the applicant's AMP was consistent with the GALL Report
 
AMP and whether the AMR was valid for the site-specific conditions.
 
Note E indicates that the AMR line item is consistent with the GALL Report for material, environment, and aging effect, but credits a different AMP or NUREG-1801 identifies a
 
plant specific aging management program. The staff audited these line items to verify
 
consistency with the GALL Report. The staff also determined whether the credited AMP
 
would manage the aging effect consistently with the GALL Report AMP and whether the
 
AMR was valid for the site-specific conditions.
 
The staff audited and reviewed the information in the LRA. The staff did not repeat its
 
review of the matters described in the GALL Report; however, the staff did verify that the
 
material presented in the LRA was applicable and that the applicant identified the
 
appropriate GALL Report AMRs. The staff's evaluation follows.
 
3.4.2.1.1  Loss of Material Due to General, Pitting and Crevice Corrosion (Item 1)
 
During the audit and review, the staff noted that for VEGP AMR items 1a and 1d of LRA
 
Table 3.4.2-1; 1a and 1c of LRA Table 3.4.2-2; 1a of LRA Table 3.4.2-3; 1a and 1d of LRA
 
Table 3.4.2-4; and 1a and 1d of LRA Table 3.4.2-5, the applicant provides its AMRs on loss
 
of material due to general, pitting and crevice corrosion in carbon S&PC bolting under
 
exposure to either an air indoor (exterior) environment or an air outdoor (exterior)
 
environment. The applicant uses a standard Note E for these AMR line items that roll up to
 
the LRA Table 3.4.1, Item 22. Note E states (LRA Table 3.0-4) that the AMR line item is
 
consistent with the GALL Report for material, environment, and aging effect, but a different
 
aging management program is credited or the GALL Report identifies a plant-specific aging
 
management program. The applicant has credited its Bolting Integrity Program to manage loss of material in surfaces of these bolting components that are exposed to either the air
 
indoor (exterior) environment or the air outdoor (exterior) environment. 
 
The GALL AMR items (VIII.H-1 and VIII.H-4) that per tain to these VEGP AMR items that roll up to the LRA Table 3.4.1, Item 22, recommend GALL AMP XI.M18, "Bolting Integrity" for
 
managing these aging effects while the LRA uses the Bolting Integrity Program, which is a
 
plant specific program. The staff reviewed the applicant's Bolting Integrity Program, and the
 
staff's evaluation is documented in SER Section 3.0.3.3.2. During the audit and review, the
 
staff agreed with the applicant's determination that these LRA line items are consistent with
 
the GALL Report, except using a plant specific AMP. On the basis of the staff's evaluation
 
of the AMP and the staff's determination that the applicant's AMR results are consistent
 
with the GALL Report, the staff finds the applicant's AMR results to be acceptable.
3.4.2.1.2  Loss of Preload Due to Stress Relaxation, Gasket Creep, or Self Loosening
 
During the audit and review, the staff noted that for VEGP AMR items 1c of LRA Table
 
3.4.2-1; 1b of LRA Tables 3.4.2-2, 3.4.2-3, and 3.4.2-4; and 1c of LRA Table 3.4.2-5, the
 
applicant provides its AMRs on management of loss of preload due to stress relaxation, 3-453 gasket creep, or self loosening in carbon steel S&PC bolting under exposure to an air indoor (exterior) environment. The applicant has credited its Bolting Integrity Program to
 
manage loss of material in surfaces of the bolting components that are exposed to the air
 
indoor (exterior) environment. The applicant uses a standard Note E for these AMR line
 
items that roll up to the LRA Table 3.4.1, Item 22. Note E states (LRA Table 3.0-4) that the
 
AMR line item is consistent with the GALL Report for material, environment, and aging
 
effect, but a different aging management program is credited or the GALL Report identifies
 
a plant-specific aging management program.
 
The GALL AMR Item (VIII.H-5) that pertains to these VEGP AMR items that roll up to the LRA Table 3.4.1, Item 22, recommends GALL AMP XI.M18, "Bolting Integrity," for
 
managing these aging effects while the LRA uses the Bolting Integrity Program, which is a
 
plant specific program. The staff reviewed the applicant's Bolting Integrity Program, and the
 
staff's evaluation is documented in SER Section 3.0.3.3.2. During the audit and review, the
 
staff agreed with the applicant's determination that these LRA line items are consistent with
 
the GALL Report, except using a plant specific AMP. On the basis of the staff's evaluation
 
of the AMP and the staff's determination that the applicant's AMR results are consistent
 
with the GALL Report, the staff finds the applicant's AMR results to be acceptable. 
 
3.4.2.1.3  Loss of Material Due to General, Pitting, and Crevice Corrosion (Item 2)
 
During the audit and review, the staff noted that for VEGP AMR items 2b, 7b, and 12b of
 
LRA Table 3.4.2-1, the applicant provides its AMRs for managing loss of material due to
 
general, pitting, and crevice corrosion in surfaces of aluminum alloy oil reservoir actuators, filter housing actuators, and valve bodies in t he main steam system that are exposed to an air - outdoor (exterior) environment. The applicant credits its External Surfaces Monitoring
 
Program to manage loss of material in the component surfaces that are exposed to the air
 
- outdoor (exterior) environment. The applicant uses a standard Note E for these AMR line
 
items that roll up to the LRA Table 3.5.1, Item 50. 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 or NUREG-1801 identifies a plant specific aging management program.
 
The GALL AMR Item (III.B2-7) that pertains to these VEGP AMR items recommends that
 
the Structures Monitoring Program (GALL AMP XI.S6) be used to manage loss of preload due to thermal effects, gasket creep, and self loosening in steel (including carbon steel) 
 
bolting surfaces that are exposed to uncontrolled indoor air environment while the LRA
 
uses the External Surfaces Monitoring Program.
 
The staff asked the applicant to clarify whether or not any exceptions taken in its External
 
Surfaces Monitoring Program against the recommended program elements in GALL AMP XI.M36, "External Surfaces Monitoring," are applicable to the AMRs for these components, and if so, justify why these exceptions are acceptable to manage loss of material in these
 
components.
 
In its response, the applicant stated: 
 
LRA Table 3.4.2-1, Items 2b, 7b, and 12b, align to GALL Report III.B2-7 because
 
there are no items in GALL section IV, V, VII, or VIII for this material and
 
environment combination. Plant specific note 402 was applied to Item 2b to address
 
this issue, and should have also been applied to Items 7b and 12b. In addition, 3-454 Table 3.5.1, Item 3.5.1-50, does not discuss the mechanical components which refer to that item.
As described in Note E for Items 2b, 7b, and 12b (LRA Table 3.4.2-1), consistency
 
with GALL Report III.B2-7 and Table 3.5.1-50 is maintained for the material, environment, and aging effect. However, a different aging management program is
 
credited, the External Surfaces Monitoring Program in lieu of the Structures
 
Monitoring Program.
The literature indicates that aluminum resists corrosion due to the presence of a thin
 
aluminum oxide film covering the surface. Therefore, according to the EPRI
 
Mechanical Tools (TR-1010639), an aggressive environment consisting of a wetted
 
surface or pooled liquid, oxygen, and contaminants must be present for corrosion to
 
occur in aluminum. The ARV local actuator filter housing exterior surfaces are
 
subjected to an air - outdoor (exterior) environment in which the potential for
 
atmospheric moisture exists. However, atmospheric moisture does not provide a significant source of contaminants. There is also no operating experience at VEGP
 
which presents a case for significant loss of material for aluminum in an air - outdoor (exterior) environment. However, SNC has taken a conservative position to manage
 
any effects of loss of material on the aluminum filter housings with the External
 
Surfaces Monitoring Program. The External Surfaces Monitoring Program is a
 
program especially designed to inspect exte rnal surfaces of mechanical system components in external air environments su ch as the aluminum alloy ARV local actuator filter housings. The Structural Monitoring Program is designed to inspect
 
structural components, not mechanical components. Therefore, the External
 
Surfaces Monitoring Program is the appropriate program to manage the
 
components listed in LRA Table 3.4.2-1, Items 2b, 7b, and 12b.
The VEGP External Surfaces Monitoring Program takes exception to GALL AMP XI.M36 in that additional materials such as aluminum used for the components in
 
question will be included within the scope of inspections. 
 
This is considered an exception since the GALL AMP is described as being
 
applicable to steel components only.
A License Renewal Application amendment is required to add plant specific note
 
402 where it was omitted, and to revise Table 3.5.1, Item 3.5.1-50, to discuss the
 
mechanical components.
 
The staff confirmed that in its letter dated March 20, 2008, the applicant amended the LRA
 
as stated above to add plant specific note 402 in LRA Table 3.4.2-1, for Items 7b, and 12b, and to revise Table 3.5.1, Item 3.5.1-50, to discuss the mechanical components. The staff
 
finds the applicant's response and the amended aging management basis is acceptable
 
because it stated that VEGP External Surfaces Monitoring Program is designed to inspect
 
external surfaces of mechanical system co mponents made of aluminum in external air environments such as the aluminum alloy ARV local actuator filter housings and this
 
provides an acceptable basis for crediting the Ex ternal Surfaces Monitoring activities as an alternate aging management basis.
 
The staff has evaluated the ability of the applicant's External Surfaces Monitoring Program (LRA AMP B.3.8) to manage loss of material in aluminum alloy components and its 3-455 evaluation is described in SER Section 3.0.3.2.5. Based on the review, the staff finds the applicant's AMR results to be acceptable. 
 
3.4.2.1.4  Loss of Material Due to General, Pitting, and Crevice Corrosion (Item 3)
 
During the audit and review, the staff noted that for VEGP AMR Item 5a of LRA Table 3.4.2-
 
2 and AMR items 3a and 5a of LRA Table 3.4.2-5, the applicant provides its AMRs for
 
managing loss of material due to general, pitting, and crevice corrosion in surfaces of
 
carbon steel piping components and valve co mponents in the main steam and auxiliary steam systems that are exposed to an air
- indoor (interior) environment. For these components, the applicant credits its One-Time Inspection Program to manage loss of
 
material in the component surfaces that are exposed to the air - indoor (interior)
 
environment. The applicant uses a standard Note E for these AMR line items that roll up to
 
the LRA Table 1 Item 3.2.1-32. Note E states (LRA Table 3.0-4) that the AMR line item is
 
consistent with the GALL Report for material, environment, and aging effect, but a different
 
aging management program is credited or the GALL Report identifies a plant-specific aging
 
management program.
 
The GALL AMR Item (V.A-19) that pertains to these AMR items recommends that GALL AMP XI.M38, "Inspection of Internal Surfaces of Miscellaneous Piping and Ducting
 
Components," be used to manage loss of material due to general, pitting, and crevice
 
corrosion in steel components surfaces that are exposed to the air - indoor (interior)
 
environment. 
 
The staff asked the applicant to clarify whether or not any exceptions taken in its One-Time
 
Inspection Program against the recommended program elements in GALL AMP XI.M32, "One-Time Inspection," are applicable to this AMR, and if so, justify why these exceptions
 
are acceptable to manage loss of material in carbon steel piping and valve body
 
components.
 
In its response, the applicant stated that: 
 
VEGP LRA Table 3.4.2-5, items 3a and 5a, for Steam and Power Conversion
 
System "Auxiliary Steam System" were a ligned to GALL Table V.A, Item V.A-19, for Engineered Safety Features System "Cont ainment Spray System," because there are no GALL AMR lines in either Chapter VIII, "Steam and Power Conversion
 
System," or Chapter VII, "Auxiliary Syst ems," which evaluate the combination of carbon steel piping exposed to an "Air - Indoor (Interior)" environment. GALL Table
 
V.A, Item V.A-19, is a match to VEGP LRA Table 3.4.2-5, items 3a and 5a, for 
 
component, material, environment, and aging effect requiring management. VEGP
 
chose to credit a different aging management program than GALL for these
 
components.
For carbon steel piping components and valve bodies exposed to an Air - Indoor (Internal) environment where condensation or wetting are not present, some loss of
 
material due to general corrosion is expected. However, VEGP expects the degree
 
of corrosion for this material and environment combination to be minor and to
 
progress slowly. VEGP believes that a one-time inspection will confirm this
 
expectation, and that additional inspections will not be warranted. If the one-time
 
inspection indicates that corrosion of this material and environment combination has
 
progressed such that the intended function of a component could be affected during 3-456 the period of extended operation, then the impacted components will be included in the Piping and Duct Internal Inspection Program, or other program as appropriate.
 
Carbon steel components exposed to condensation, wetting, or Air - Outdoor (Internal) are managed by the Piping and Duct Internal Inspection Program because
 
the potential for exposure to water negates the expectation that corrosion would
 
progress slowly.
The VEGP One-Time Inspection Program does not contain any exceptions to the
 
recommended program elements in GALL AMP XI.M32, "One-Time Inspection."  The staff finds the applicant's response and that the amended aging management basis is acceptable because the applicant has provided clarification that loss of material due to
 
general corrosion for carbon steel piping components and valve bodies when exposed to
 
an air - indoor (internal) environment where condensation or wetting are not present is
 
expected to be minor and to progress slowly. The absence of any loss of material is verified
 
by the applicant's One-Time Inspection Program. The staff evaluated the ability of One-
 
Time Inspection Program (LRA AMP B.3.17), to manage loss of material due to general, pitting and crevice corrosion in carbon steel components that are exposed to an indoor air (interior) environments and its evaluation is provided in SER Section 3.0.3.1.2.
3.4.2.1.5  Loss of Material Due to General, Pitting, and Crevice Corrosion (Item 4)
 
During the audit and review, the staff noted that for VEGP AMR Item 7a of LRA Table 3.4.2-
 
3, the applicant provides its AMRs for managing loss of material due to general, pitting, and
 
crevice corrosion in the carbon steel heat exchanger components in the steam generator
 
blowdown processing system that are exposed to a raw water - river water (interior)
 
environment. For these components, the applicant credits its Periodic Surveillance and
 
Preventative Maintenance Program to manage loss of material in the component surfaces
 
that are exposed to the raw water - river water (interior) environment. 
 
The applicant uses a standard Note E for this AMR line item that roll up to the LRA Table 1
 
Item 3.4.1-31. Note E states (LRA Table 3.0-4) that the AMR line item is consistent with the
 
GALL Report for material, environment, and aging effect, but a different aging management
 
program is credited or the GALL Report identifies a plant-specific aging management
 
program.
 
The GALL AMR Item (VIII.F-5) that pertains to this AMR item recommends that GALL AMP XI.M20, "Open-Cycle Coolant Water System,"
be used to manage loss of material due to general, pitting, and crevice corrosion in steel components surfaces that are exposed to the
 
air - indoor (interior) environment.
 
The staff asked the applicant to provide the basis why the Periodic Surveillance and
 
Preventative Maintenance Activities are valid, sufficient, and capable of managing loss of
 
material in these components in lieu of crediting the inspections that would be performed in
 
accordance with the program elements for the VEGP Generic Letter 89-13 Program.
 
In its response, the applicant stated: 
 
NRC Generic Letter 89-13 is applicable to "the system or systems that transfer heat
 
from safety-related structures, systems, or components to the UHS."  For VEGP, Generic Letter 89-13 only applies to the Nuclear Service Cooling Water (NSCW) 3-457 System. The environment in the NSCW System is "raw water - NSCW."  The steam generator blow down (SGBD) trim heat exchanger is not part of, nor is it cooled by, the NSCW System. Therefore this component is not in the scope of the VEGP
 
Generic Letter 89-13 Program.
The SGBD trim heat exchanger is a non-safe ty related component which is cooled by the non-safety related Turbine Plant Cooling Water (TPCW) System. The
 
environment in the TPCW System is "raw water - river water."  Since the Generic
 
Letter 89-13 Program is not applicable to this component, VEGP credited Periodic
 
Surveillance and Preventive Maintenance Activities for aging management. As
 
noted in Appendix B to the LRA, section B.3.21, a program for periodic inspection of
 
the SGBD trim heat exchanger on each uni t already exists. These components are visually inspected in accordance with procedure 83321-C for fouling, corrosion, coating failure, and structural/mechanical damage. These inspections are similar to
 
inspections that would be performed under the Generic Letter 89-13 Program.
 
VEGP operating experience with these inspections indicates that they are sufficient
 
and capable to manage loss of material of the SGBD trim heat exchangers.
The staff finds the applicant's response and the amended aging management basis to be acceptable because the applicant provided clarification that the inspections performed
 
under the Periodic Surveillance and Preventative Maintenance Activities Program are the
 
type of inspections that would be performed under the Generic Letter 89-13 Program, and
 
this provides an acceptable basis for crediting the Periodic Surveillance and Preventative
 
Maintenance Activities as an alternate aging management basis. The staff evaluated the
 
ability of the Periodic Surveillance and Preventative Maintenance Activities Program (LRA
 
AMP B.3.21) to manage loss of material due to general, pitting and crevice corrosion in
 
carbon steel heat exchanger component surfaces that are exposed to raw water - river
 
water environment and its evaluation is provided in SER Section 3.0.3.3.6.
3.4.2.1.6  Loss of Material Due to General, Pitting, and Crevice Corrosion (Item 5)
 
During the audit and review, the staff noted that for VEGP AMR Item 15b of LRA Table
 
3.4.2-4, the applicant provides its AMRs for managing loss of material due to general, pitting, and crevice corrosion in the carbon steel tanks in the auxiliary feedwater system that are exposed to an air - outdoor (exterior) environment. For these components, the
 
applicant's credits its External Surfaces Monitoring Program to manage loss of material in
 
the tank surfaces that are exposed to the air - outdoor (exterior) environment. The
 
applicant uses a standard Note E for this AMR line item that roll up to the LRA Table 1 Item
 
3.4.1-20. Note E states (LRA Table 3.0-4) that the AMR line item is consistent with the
 
GALL Report for material, environment, and aging effect, but a different aging management
 
program is credited or the GALL Report identifies a plant-specific aging management
 
program.
 
The GALL AMR Item (VIII.G-40) that pertains to these AMR items recommends that GALL AMP XI.M29, "Aboveground Steel Tanks," be used to manage loss of material due to
 
general, pitting, and crevice corrosion in steel components surfaces that are exposed to the
 
air - outdoor (external) environment. 
 
The staff asked the applicant to discuss how the program elements for the External
 
Surfaces Monitoring Program compare to the NRC's recommended program elements in 3-458 GALL AMP XI.M29 and identify any differences and justify the use of the External Surfaces Monitoring Program to manage the loss of material aging effect.
 
In its response, the applicant stated: 
 
GALL AMP XI.M29, "Aboveground Steel Tanks," uses a combination of coating of
 
the external surfaces of a tank, sealing of the tank to foundation interface, external
 
visual inspections of accessible portions of a tank and of the tank to foundation
 
interface, and thickness measurements to identify any external corrosion of the
 
inaccessible portions of a tank bottom.
VEGP has taken the conservative position of not crediting coatings for aging
 
management. However, VEGP agrees that observation of the condition of the paint
 
or coating is an effective method for identifying degradation of the underlying
 
material. Therefore, monitoring of the condition of coatings will be included in the
 
inspection criteria of the External Surfaces Monitoring Program along with the
 
inspection criteria to monitor for degradation of the component materials. Refer to
 
the response to question B.3.8-02 for additional discussion.
The CST degasifier tank addressed in LRA Table 3.4.2-4, Item 15b, is a vertical
 
cylindrical tank supported by a skirt. This tank is insulated. There is no tank to
 
foundation interface. The bottom of the tank is accessible for visual inspection, so
 
the GALL program elements related to sealing of the tank to foundation interface, external visual inspections of the tank to foundation interface, and thickness
 
measurements of the tank bottom to identify external degradation are not applicable
 
to this tank.
The remaining elements of the GALL Aboveground Steel Tanks program consist of
 
external visual inspections of the accessible portions of the tank. These elements
 
are included in the VEGP External Surfaces Monitoring Program, therefore VEGP
 
believes that this program will adequately manage loss of material from the CST
 
degasifier tank during the period of extended operation.
 
The staff finds the applicant's response and that the amended aging management basis is
 
acceptable because it provided clarification that the inspection attributes for managing the aging effects of CST degasifier tank is consistent with GALL AMP XI.M29. The staff has
 
evaluated the ability of the applicant's External Surfaces Monitoring Program (LRA AMP
 
B.3.8) to manage loss of material due to general, pitting and crevice corrosion in carbon
 
steel tank component surfaces that are exposed to an air - outdoor (exterior) environment
 
and its evaluation is provided in SER Section 3.0.3.2.5.
 
Conclusion
: The staff evaluated the applicant's claim of consistency with the GALL Report.
The staff also reviewed information pertaining to the applicant's consideration of recent
 
operating experience and proposals for managing aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with
 
the GALL Report, are indeed consistent with 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 their intended function(s) will be maintained consistent with
 
the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3-459 3.4.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended In LRA Section 3.4.2.2, the applicant further evaluated aging management, as
 
recommended by the GALL Report, for the st eam and power conversion (S&PC) systems components and provides information concer ning 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-influenced corrosion, and fouling  reduction of heat transfer due to fouling  loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion  cracking due to SCC  loss of material due to pitting and crevice corrosion  loss of material due to pitting, crevice, and microbiologically-influenced corrosion  loss of material due to general, pitting, crevice, and galvanic corrosion  QA for aging management of nonsafety-related components For component groups evaluated in the GALL Report, for which the applicant claimed
 
consistency with the report and for which the report recommends further evaluation, the
 
staff audited and reviewed the applicant's evaluation to determine whether it adequately
 
addressed the issues further evaluated. In addition, the staff reviewed the applicant's
 
further evaluations against the criteria contained in SRP-LR Section 3.4.2.2. The staff's
 
review of the applicant's further evaluation follows.
 
3.4.2.2.1  Cumulative Fatigue Damage 
 
LRA Section 3.4.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants
 
must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). 
 
The applicant identified that for those S&PC components requiring metal fatigue analyses, the fatigue analyses are addressed in Section 4.3.2 of the LRA. The staff verified that Table
 
3.4.1 includes applicable line item on metal fatigue of Non-Class 1 S&PC components, as
 
stated in LRA AMR Item 3.4.1-1 and that LRA Section 4.3.2 contains the TLAA and metal
 
fatigue analysis section for Non-Class 1 S&PC components at VEGP. Thus, the staff noted
 
that the applicant's further evaluation assessment in LRA Section 3.4.2.2.1 conforms to the
 
staff's recommendations in SRP-LR Section 3.4.2.2.1 and that the LRA includes AMR Item
 
3.4.1-1 that corresponds to this further evaluation item. The staff verified that AMR Item 3-460 3.4.1-1 is consistent with and conforms to the staff recommended AMR evaluation in AMR Item 1 in Table 4 of the GALL Report, Revision 1, Volume 1. Based on this review, the staff
 
concludes that the applicant's further evaluation discussion in LRA Section 3.4.2.2.1 is
 
consistent with and conforms to the staff's corresponding evaluation recommendations in
 
SRP-LR Section 3.4.2.2.1 and is acceptable. The staff also determined that the LRA
 
includes AMR Item 3.4.1-1 on metal fatigue of S&PC components, and that this AMR is
 
consistent with the recommendations in Table 4 of the GALL Report, Revision 1, Volume 1.
 
The staff reviewed the applicant's TLAA on metal fatigue and its evaluation of the TLAA on
 
metal fatigue is provided in SER Section 4.3 and its subsections.
 
3.4.2.2.2  Loss of Material Due to General, Pitting, and Crevice Corrosion 
 
The staff reviewed LRA Section 3.4.2.2.2 against the criteria in SRP-LR Section 3.4.2.2.2:
 
  (1) LRA Section 3.4.2.2.2 addresses loss of material due to general, pitting, and crevice corrosion in steel piping and components, tanks, and heat exchangers exposed to
 
treated water and steel piping and components exposed to steam as an aging effect
 
for which the GALL Report recommends a one-time inspection to verify the
 
effectiveness of the water chemistry control program. Consistent with GALL Report AMPs XI.M2 and XI.M32, the Water Chemis try Control Program and the One-Time Inspection Program will manage such loss of material for carbon steel components
 
exposed to treated water.
SRP-LR Section 3.4.2.2.2, Item (1) 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
 
selected 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.
 
SRP-LR Item 3.4.2.2.2, Item (1) invokes Items 2, 3, 4, and 6 in Table 4 of the GALL
 
Report, Revision 1, Volume 1. Collectively, AMR Items 2, 3, 4, and 6 in Table 4 of
 
the GALL Report, Revision Volume 1, reference that AMR items VIII.B1-11, VIII.C-
 
7, VIII.D1-8, VIII.E-34, VIII.E-37, VIII.E-40, VIII.F-25, VIII.F-28, VIII.G-38, and
 
VIII.G-41 of the GALL Report, Revision 1, Volume 2, are generic AMR items that
 
may be applicable to the steel PWR piping, piping component, piping elements, tanks, and heat exchanger components in PWR main steam, extraction steam, feedwater, condensate, steam generator blowdown, and auxiliary feedwater systems under exposure to a treated wa ter environment, and that AMR Items VIII.A-16 and VIII.C-4 of the GALL Report, Revision 1, Volume 2, are generic AMR
 
items for steel piping, piping component, and piping elements in PWR steam
 
turbine and extraction steam systems under exposure to a steam environment. For 3-461 these component-material-environment combinations, the GALL Report (like the SRP-LR) recommends that the Water Chemistry Program be credited to prevent or
 
mitigate loss of material in the components and that a plant-specific program be
 
credited to verify the effectiveness of the Water Chemistry Program in achieving its preventative or mitigative function. 
 
Like the SRP-LR, the GALL AMRs identify that the One-time Inspection Program is
 
an acceptable program to credit to verify the effectiveness of the applicant's Water
 
Chemistry Program.
The staff noted that the applicant did not include any Type 2 AMR items in LRA for steel piping, piping components, piping elements, tanks and heat exchanger components in the extraction steam system s that are exposed to treated water or steel piping, piping components, and piping elements in the extraction steam systems that are exposed to steam because the applicant does not include these systems within the scope of license renewal. The staff has evaluated the applicant's basis for omitting these systems from the scope of the LRA and has provided its basis for concluding that the extraction steam and condensate systems do not need to be within the scope of license renewal in SER Section 2.4. Based on this finding, the staff concludes that the scope of the LRA does not need to include any AMR items aligning to GALL AMR items VIII.C-4 and VIII.C-7 for these extraction steam system components because the extraction st eam systems are not within the scope of license renewal. 
 
For the remaining steel piping, piping components, piping elements, tanks, and
 
heat exchanger components in main steam , steam generator blowdown, auxiliary feedwater, and auxiliary steam systems that are exposed to treated water or steam, the staff reviewed LRA Tables 3.4.2-1, 3.4.2.-3, 3.4.2-4, and 3.4.2-5 verified that
 
the applicant's LRA includes applicable AMR line items that align to GALL AMR
 
Items VIII.B1-11, VIII.F-25, VIII.F-28, VIII.G-38, and VIII.G-41. The staff also verified
 
that the applicant has credited the Water Chemistry Program and One-Time
 
Inspection to manage loss of material in these components. This is in conformance
 
with the AMPs recommended for use in SRP-LR Section 3.4.2.2.2, Item (1) and in
 
GALL AMR Items VIII.B1-11, VIII.F-25, VIII.F-28, VIII.G-38, and VIII.G-41. Based
 
on this review, the staff concludes that the AMPs credited to manage loss of
 
material in these components are in conformance with the staff's recommendations
 
in SRP-LR Section 3.4.2.2.2, Item (1) and the GALL Report. Based on this
 
assessment, the staff concludes that the applicant's AMRs on loss of material for
 
the steel piping, piping components, piping elements, tanks, and heat exchanger
 
components in main steam, steam generat or blowdown, auxiliary feedwater, and auxiliary steam systems that are exposed to treated water or steam is acceptable because they are in conformance with the staff recommendations in SRP-LR
 
Section 3.4.2.2.2, Item (1) and the GALL Report.
 
For the feedwater system, the staff reviewed Section 2.3.4 of the LRA and
 
determined that the scope of the applicant's feedwater system is treated as one
 
system at VEGP and which includes the following subsystems: (1) feedwater and
 
condensate system, (2) condensate chemical injection system, and (3) moisture
 
separator and reheater drain system. However, the LRA system drawings for the
 
feedwater system demonstrate the condensat e portions of this system are not within the scope of license renewal. The staff reviewed LRA Section 2.3.4 and the 3-462 LRA boundary drawings for the feedwater system and determined that the scope of the LRA does not include any condensate sy stem heat exchangers or tanks that are within the scope of license renewal but does include applicable piping, piping
 
components, and piping elements (including flow orifices/elements, various piping
 
components, and valve bodies) for these systems that are within the scope of
 
license renewal. Therefore, based on this assessment, staff concludes that it is
 
valid to conclude that the LRA does not need to include any AMR items that align to
 
the staff recommendations in GALL AMRs VIII.E-37 and VIII.E-40 for management
 
of loss of material in steel condensate system heat exchangers and tanks. 
 
The staff verified that the applicant has aligned its AMR for the steel feedwater
 
system piping, piping components, and pipi ng elements that are exposed to treated water to the recommendations in GALL AMR VIII.D1-8 and has credited the Water
 
Chemistry Program to manage loss of material in the components and the One-time
 
Inspection Program to verify the effectiv eness of the Water Chemistry Program to manage loss of material in the components. This is in conformance with the AMPs
 
recommended for use in SRP-LR Section 3.4.2.2.2, Item (1) and in GALL AMR Item
 
VIII.D1-8. Based on this review, the staff concludes that the AMPs credited to
 
manage loss of material in these feedwater system components are the same as
 
those recommended for aging management in the staff's recommendations of SRP-
 
LR Section 3.4.2.2.2, Item (1) and the GALL Report. 
 
Based on this assessment, the staff concludes that the applicant's AMRs for
 
managing loss of material for the steel feedwater system piping, piping
 
components, and piping elements that are exposed to treated water is acceptable
 
because they are in conformance with the staff recommendations in SRP-LR
 
Section 3.4.2.2.2, Item (1) and the GALL Report.
 
The staff reviewed the ability of the Water Chemistry Program to manage loss of
 
material due to general, pitting, and crevice corrosion and its evaluation is
 
described in SER Section 3.0.3.1.4. The staff reviewed the ability of the One-Time
 
Inspection Program to verify the effectiv eness of the Water Chemistry Program in managing loss of material due to general, pitting, and crevice corrosion and its
 
evaluation of the One-Time Inspection Program is described in SER Section
 
3.0.3.1.2.
 
  (2) LRA Section 3.4.2.2.2, Item (2) addresses loss of material due to general, pitting, and crevice corrosion in steel piping, piping components, and piping elements
 
exposed to lubricating oil as an aging effect for which the GALL Report
 
recommends a one-time inspection to verify the effectiveness of lubricating oil
 
controls in managing corrosion. Consistent with GALL Report AMPs with
 
exceptions, the Oil Analysis Program and the One-Time Inspection Program will manage loss of material for cast iron and carbon steel components exposed to
 
lubricating oil.
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, 3-463 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 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.
SRP-LR Item 3.4.2.2.2, Item (2) identifies AMR Item 7 in Table 4 of the GALL
 
Report, Revision 1, Volume 1, and AMR items VIII.D1-6, VIII.E-32, and VIII.G-35 as
 
generic AMR items that may be applicable to steel piping, piping components, and
 
piping elements in the feedwater, c ondensate and auxiliary steam systems under exposure to a lubricating oil environment. Like SRP-LR Section 3.4.2.2.2, Item (2),
GALL AMRs VIII.D1-6, VIII.E-32, and VIII.G
-35 recommend that the Lubricating Oil Analysis Program be credited to manage loss of material that may occur in the
 
surfaces of these components that are exposed to the lubricating oil environment
 
and that a plant-specific program be credited to verify the effectiveness of the
 
Lubricating Oil Analysis Program to manage loss of material due to general, pitting, and crevice corrosion. 
 
Like SRP-LR Section 3.4.2.2.2, Item (2), GALL AMRs VIII.D1-6, VIII.E-32, and
 
VIII.G-35 identify that the One-Time Inspection Program is an acceptable program
 
to verify the effectiveness of the Lubricating Oil Analysis Program.
 
The staff reviewed LRA Section 2.3.4 and determined that, for the LRA, the scope
 
of the feedwater system bounds the following systems: (1) condensate and
 
feedwater system, (2) condensate chemical injection system, and (3) moisture separator and reheater drain system. However, the LRA system drawings for the
 
feedwater system demonstrate the condensat e portions of this system are not within the scope of license renewal. The staff reviewed LRA Section 2.3.4 and the
 
LRA boundary drawings for the feedwater system and determined that the scope of the LRA does not include any condensate system piping, piping components, and
 
piping elements (including flow orifices/elements, various piping components, and
 
valve bodies) that are within the scope of license renewal or any feedwater piping, piping components, or piping elements that are exposed to a lubricating oil
 
environment. Therefore, based on this review, the staff concludes that this is a valid
 
basis for not including AMRs in LRA Table 3.4.2-2, "Feedwater System - Summary 
 
of Aging Management Reviews," that corresponds to GALL AMR Item VIII.D1-6 or
 
VIII.E-32.
 
The staff also verified that the VEGP design includes the following auxiliary
 
feedwater system components or commodity groups that are fabricated from steel materials and are exposed to a lubricating oil environment:
 
filter housings  piping components  turbine driven auxiliary feedwater pump lubricating oil reservoirs  turbine driven auxiliary feedwater lubricating oil pump casings  valve bodies
 
3-464 For these components or commodity groups, the staff verified that the applicant has aligned its AMRs for these components or commodity groups to GALL AMR VIII.G-35 and credited the Oil Analysis Program to manage loss of material due to
 
general, pitting, or, crevice corrosion in the surfaces that are exposed to the
 
lubricating oil environment. The staff also verified that the applicant has credited the
 
One-Time Inspection Program to verify t he effectiveness the Oil Analysis Program to manage loss of material due to general, pitting, and crevice corrosion in the
 
component surfaces that are exposed to lubricating oil. These are the same AMPs
 
that are recommended for management in SRP-LR Section 3.4.2.2.2, Item (2) and
 
in GALL AMR Item VIII.G-35. 
 
Based on this review, the staff concludes that the applicant's AMRs on loss of
 
material due to general, pitting, and crevice corrosion for the components surfaces
 
of the piping, piping components, and piping elements that are exposed to
 
lubricating oil is in conformance with the staff's recommendation in the SRP-LR and
 
in the GALL Report. Based on this assessment, the staff concludes that the
 
applicant's AMR for the turbine driven auxilia ry feedwater pump lube oil cooler heat exchanger tubes is acceptable because it is in conformance with the
 
recommendations of SRP-LR Section 3.4.2.2.2, Item (2) and GALL AMR Item
 
VIII.G-35.
 
The staff reviewed the ability of Oil Analysis Program to manage loss of material
 
due to general, pitting, and crevice corrosion and its evaluation is described in SER
 
Section 3.0.3.2.10. The staff reviewed the ability of the One-Time Inspection
 
Program to verify the effectiveness of t he Oil Analysis Program in managing loss of material due to general, pitting, and crevice corrosion and its evaluation of the One-
 
Time Inspection Program is described in SER Section 3.0.3.1.2.
 
Based on the programs identified above, the staff concludes that the applicant's programs
 
meet SRP-LR Section 3.4.2.2.2 criteria or has provided an acceptable basis for
 
demonstrating the SRP-LR Section 3.4.2.2.2 criteria do not apply to the relevant VEGP
 
system or systems addressed by the specific SRP-LR item. For those line items that apply to LRA Section 3.4.2.2.2, the staff concludes that the LRA is consistent with the SRP-LR
 
and 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 loss of material due to general, pitting, crevice, and
 
microbiologically-influenced corrosion, and fouling in steel piping components exposed to
 
raw water as an aging effect not applicable to VEGP. The AMR methodology predicts loss
 
of material for steel piping components exposed to raw water, but AMR results for S&PC
 
systems do not include steel piping components exposed to raw water. LRA Item 3.4.1-31
 
addresses S&PC system steel heat exchanger components exposed to raw water. LRA Section 3.3 addresses interfacing raw water systems.
 
3-465 SRP-LR Section 3.4.2.2.3 states that loss of material due to general, pitting, and crevice corrosion, and microbiologically-influenced corrosion, and fouling may occur in steel piping, piping components, and piping elements exposed to raw water.
 
SRP-LR Item 3.4.2.2.3 identifies AMR Item 8 in Table 4 of the GALL Report, Revision 1, 
 
Volume 1, and AMR Item VIII.G-36 in the GALL Report, Revision 1, Volume 2, as generic
 
AMRs for the surfaces of steel piping, piping component, piping elements in the auxiliary
 
feedwater system that are exposed to a raw water environment. In these AMR items, the GALL states that loss of material due to general corrosion, pitting corrosion, crevice
 
corrosion, or microbiologically-influenced corrosion may occur in the surfaces of these steel
 
components that are exposed to the raw water environment and recommends that is to be
 
evaluated and credited to manage this aging effect. 
 
The staff reviewed UFSAR Section 10.4.9 of the Vogtle UFSAR, Auxiliary Feedwater
 
System and determined that the normal flow fo r VEGP auxiliary feedwater systems is from the CST to the auxiliary feedwater pumps and that the systems do not include any piping, piping components, or piping elements that are exposed to a raw water environment. 
 
Based on this review, the staff concludes that the applicant has provided an acceptable
 
basis for concluding the recommendations of SRP-LR Section 3.4.2.2.3 and GALL Item
 
VIII.G-36 are not applicable to the VEGP LRA because the scope of the auxiliary feedwater
 
system does not include any piping, pipi ng components or piping elements that are exposed to a raw water environment.
 
Based on the above, the staff concludes that the applicant has provided an acceptable
 
basis for demonstrating the SRP-LR Section 3.4.2.2.3 criteria do not apply to the relevant
 
VEGP system or systems addressed by the specific SRP-LR item. 
 
3.4.2.2.4  Reduction of Heat Transfer Due to Fouling 
 
The staff reviewed LRA Section 3.4.2.2.4 against the criteria in SRP-LR Section 3.4.2.2.4:
 
  (1) LRA Section 3.4.2.2.4 addresses reduction of heat transfer due to fouling in stainless steel and copper alloy heat exchanger tubes exposed to treated water as
 
an aging effect for which the GALL Report recommends a one-time inspection to
 
verify the effectiveness of the water chemistry control program. Consistent with
 
GALL Report AMPs, the Water Chemistry Control Program and the One-Time
 
Inspection Program will manage reduction of heat transfer for heat exchanger tubes
 
so exposed.
SRP-LR Section 3.4.2.2.4, Item (1) 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.
 
3-466 SRP-LR Item 3.4.2.2.4, Item (1) identifies that AMR Item 9 in Table 4 in the GALL Report, Revision 1, Volume 1, and AMR Items VIII.E-10, VIII.E-13, VIII.F-7, VIII.F-
 
10, and VIII.G-10 in the GALL Report, Revision 1, Volume 2, are generic AMR items
 
for stainless steel and copper heat exchanger tubes in the condensate, steam
 
generator blowdown, and auxiliary feedwater systems that are exposed to a treated water environment. In these AMRs, the GALL states that reduction of heat transfer
 
as a result of fouling may occur in the surfaces of stainless steel or copper heat
 
exchanger tubes under exposure to the tr eated water environment. Like SRP-LR Section 3.4.2.2.4, Item (1), these GALL AMRs recommend that Water Chemistry
 
Program be credited to manage this aging effect and that a plant-specific AMP be
 
evaluated and credited to verify that the effectiveness of the Water Chemistry
 
Program to manage reduction or heat transfer due to fouling of these stainless steel
 
and copper heat exchanger tubes. Like SRP-LR Section 3.4.2.2.4, Item (1), these
 
GALL AMRs identify that the One-Time Inspection Program is an acceptable AMP
 
to credit for the verification of the effectiveness of the Water Chemistry Program.
 
To assess whether the LRA needed to address any relevant heat exchanger tubes
 
in the feedwater system, the staff reviewed LRA Section 2.3.4 and determined that
 
the feedwater system is within the scope of license renewal and that scope of the
 
feedwater system bounds the following systems: (1) condensate and feedwater system, (2) condensate chemical injection system, and (3) moisture separator and
 
reheater drain system. The staff concludes that Section 2.3.4 of the LRA indicates
 
that these systems do not include any pa ssive heat exchanger components that are within the scope of license renewal and are subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1). Based on this finding, the staff concludes
 
that the scope of the LRA does not need to include any AMR items aligning to
 
GALL AMR Item VIII.E-10 (as applicable copper heat exchanger tubes in the
 
condensate system) and VIII.E-13 (as applicable to stainless steel heat exchanger
 
tubes in the condensate system) because the feedwater systems (including its subsystems identified above) do not include any heat exchangers that are with the
 
scope of license renewal and are subject to an AMR. 
 
The staff reviewed LRA Section 3.4.2.1.3 and the AMR items in LRA Table 3.4.2-3, "Steam Generator Blowdown Processing System - Summary of Aging Management Review," to assess whether the LRA needed to address any relevant heat
 
exchanger tubes in the steam generator blowdown processing system under this SRP-LR item. Based on its review, the staff concludes that, while the steam
 
generator blowdown processing system is within the scope of license renewal and
 
does include steam generator blowdown heat exchangers and trim heat
 
exchangers, the shells, and channel heads in the heat exchangers are made from
 
carbon steel. The tubes and tubesheets are not in scope. Thus, none of the in
 
scope components in these heat exchangers are made from copper alloy or
 
stainless steel materials. Therefore, based on this assessment, the staff finds that it
 
is valid to conclude that the application does not need to include any AMRs
 
corresponding to either GALL AMR Item VIII.F-7 (as applicable to copper heat
 
exchanger tubes in the steam generator blowdown system) and VIII.F-10 (as applicable to stainless steel heat exchanger tubes in the steam generator blowdown 
 
system) because the steam generator blowdown processing heat exchangers and trim heat exchangers tubes and tubesheets are not in scope. 
 
3-467 The staff has verified that the applicant does include appropriate AMR items on loss of material of the steel shells and channel heads for the steam generator blowdown
 
processing system heat exchangers and trim heat exchangers, and that the applicant has aligned these AMR items to GALL AMR VIII.F-28. In these AMRs, the
 
applicant credits the Water Chemistry Program to manage loss of material of the
 
steel heat exchanger shells and channel heads and the One-Time Inspection
 
Program to verify the effectiveness of the Water Chemistry Program in managing this aging effect. These AMPs are the same AMPs as those recommended for aging
 
management in GALL AMR VIII.F-28. Based on this review, the staff concludes that
 
the AMPs credited to manage loss of material in these components are acceptable
 
because they are in conformance with the staff's AMPs recommended for aging
 
management in GALL AMR Item VIII.F-28. The staff reviewed the ability of the
 
Water Chemistry Program to manage loss of material due to general, pitting, and
 
crevice corrosion and its evaluation is described in SER Section 3.0.3.1.4. The staff
 
reviewed the ability of the One-Time Inspection Program to verify the effectiveness
 
of the Water Chemistry Program in managing loss of material due to general, pitting, and crevice corrosion and its evaluation of the One-Time Inspection Program is
 
described in SER Section 3.0.3.1.2.
 
The staff also reviewed LRA Section 3.4.4 and the AMR items in LRA Table 3.4.2-4, "Auxiliary Feedwater System - Summary of Aging Management Review," to assess whether the LRA needed to address any relevant heat exchanger tubes in the
 
auxiliary feedwater system under this SR P-LR item, as invoking GALL AMR Item VIII.G-10 for copper heat exchanger tubes in the auxiliary feedwater system that are exposed to a treated water environment. Based on its review of LRA Section Table
 
3.4.2-4, the staff concludes that the VEGP auxiliary feedwater systems do not
 
include any heat exchangers whose tubes are fabricated from copper or copper
 
alloy materials. Based on this assessment, the staff finds that it is valid to conclude
 
that the application does not need to include any AMRs corresponding to GALL
 
AMR Item VIII.G-10 (as applicable to reduction of heat transfer function in copper
 
heat exchanger tubes of the auxiliary feedw ater system under exposure to treated water) because the design of the auxiliary feedwater system does not include any heat exchangers whose tubes are fabricated from copper or copper alloy materials. 
 
(2) LRA Section 3.4.2.2.4 addresses reduction of heat transfer due to fouling in stainless steel and copper alloy heat exchanger tubes exposed to lubricating oil, stating that GALL Report recommends lube oil chemistry control and a confirmatory
 
one-time inspection. Consistent with GALL Report AMPs with exceptions, the Oil
 
Analysis Program and the One-Time Inspection Program will manage fouling of
 
lubricating oil cooler heat-transfer surfaces.
SRP-LR Section 3.4.2.2.4, Item (2) 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 selected components at susceptible locations is an acceptable
 
method to determine whether an aging effect is occurring or is slowly progressing 3-468 such that the component's intended functions will be maintained during the period of extended operation.
 
SRP-LR Item 3.4.2.2.4, Item (2) identifies that AMR Item 10 in Table 4 of the GALL
 
Report, Revision 1, Volume 1, and AMR Items VIII.G-8, VIII.G-12, and VIII.G-15 of
 
the GALL Report, Revision 1, Volume 2, are generic AMR items for copper, stainless steel and steel heat exchanger tubes in the auxiliary feedwater system that are exposed to a lubricating oil environment. In these AMRs, the GALL Report
 
states that reduction of heat transfer as a result of fouling may occur in the surfaces
 
of the copper, stainless steel, or steel heat exchanger tubes that are exposed to the
 
lubricating oil environment. Like SRP-LR Section 3.4.2.2.4, Item 2, these GALL
 
AMRs recommend that Lubricating Oil Analysis Program be}}

Latest revision as of 12:53, 14 January 2025

Final Safety Evaluation Report Related to the License Renewal of Vogtle Electric Generating Plant, Units 1 and 2
ML090710010
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Issue date: 03/31/2009
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