ML090630309: Difference between revisions

From kanterella
Jump to navigation Jump to search
(Created page by program invented by StriderTol)
(StriderTol Bot change)
 
(One intermediate revision by the same user not shown)
Line 19: Line 19:


=Text=
=Text=
{{#Wiki_filter:Safety Evaluation Report With Open Items Related to the License Renewal of Susquehanna Steam Electric Station, Units 1 and 2 Docket Nos. 50-387 and 50-388
{{#Wiki_filter:}}
 
PPL Susquehanna, LLC
 
United States Nuclear Regulatory Commission Office of Nuclear Reactor Regulation March 2009
 
THIS PAGE INTENTIONALLY LEFT BLANK.
iii  ABSTRACT This safety evaluation report (SER) documents the technical review of the Susquehanna Steam Electric Station (SSES), Units 1 and 2, license renewal application (LRA) by the United States (US) Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated September 13, 2006, PPL Susquehanna, LLC (PPL 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." PPL requests renewal of the Units 1 and 2 operating
 
licenses (Facility Operating License Numbers NPF-14 and NPF-22, respectively) for a period of
 
20 years beyond the current expirations at midnight July 17, 2022, for Unit 1, and at midnight
 
March 23, 2024, for Unit 2.
 
SSES is located approximately 5 miles northeast of Berwick, PA. The NRC issued the
 
construction permits for Unit 1 on November 2, 1973, and on November 2, 1973, for Unit 2. The
 
NRC issued the operating licenses for Unit 1 on November 12, 1982, and on June 27, 1984, for
 
Unit 2. Units 1 and 2 are of Mark 2 BWR design. General Electric supplied the nuclear steam
 
supply system and Bechtel originally designed and constructed the balance of the plant. The
 
licensed power output of each unit is 3489 megawatt thermal with a gross electrical output of
 
approximately 1190 megawatt electric.
 
This SER presents the status of the staff's review of information submitted through December
 
2008, the cutoff date for consideration in the SER. The staff identified no open or confirmatory
 
items that would require a formal response fr om the applicant. SER Section 6 provides the staff's final conclusion of its LRA review. The staff will present its final conclusion on the LRA
 
review in an update to this SER.
iv 
 
THIS PAGE INTENTIONALLY LEFT BLANK.
 
v TABLE OF CONTENTS ABSTRACT..................................................................................................................................iii TABLE OF CONTENTS................................................................................................................v ABBREVIATIONS.......................................................................................................................xiii INTRODUCTION AND GENERAL DISCUSSION.....................................................................1-1 1.1  Introduction.............................................................................................................1-1 1.2  License Renewal Background.................................................................................1-2 1.2.1  Safety Review...........................................................................................1-3 1.2.2  Environmental Review..............................................................................1-4 1.3  Principal Review Matters.........................................................................................1-5 1.4  Interim Staff Guidance............................................................................................1-6 1.5  Summary of Proposed License Conditions.............................................................1-7 STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW.........2-1 2.1  Scoping and Screening Methodology.....................................................................2-1 2.1.1  Introduction...............................................................................................2-1 2.1.2  Summary of Technical Information in the Application..............................2-1 2.1.3  Scoping and Screening Program Review.................................................2-2 2.1.3.1  Implementation Procedures and Documentation Sources for Scoping and Screening..........................................................................2-3 2.1.3.2  Quality Controls Applied to LRA Development..........................2-5 2.1.3.3  Training......................................................................................2-6 2.1.3.4  Conclusion of Scoping and Screening Program Review...........2-6 2.1.4  Plant Systems, Structures, and Components Scoping Methodology.......2-6 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).........2-16 2.1.4.4  Plant-Level Scoping of Systems and Structures......................2-19 2.1.4.5  Mechanical Component Scoping.............................................2-21 2.1.4.6  Structural Component Scoping................................................2-22 2.1.4.7  Electrical Component Scoping.................................................2-23 2.1.4.8  Conclusion for Scoping Methodology......................................2-24 2.1.5  Screening Methodology..........................................................................2-24 2.1.5.1  General Screening Methodology.............................................2-24 2.1.5.2  Mechanical Component Screening..........................................2-26 2.1.5.3  Structural Component Screening.............................................2-27 2.1.5.4  Electrical Component Screening.............................................2-28 2.1.5.5  Conclusion for Screening Methodology...................................2-29 2.1.6  Summary of Evaluation Findings............................................................2-29 2.2  Plant-Level Scoping Results.................................................................................2-30 2.2.1  Introduction.............................................................................................2-30 2.2.2  Summary of Technical Information in the Application............................2-36 2.3  Scoping and Screening Results: Mechanical Systems.........................................2-36 2.3.1  Reactor Vessel, Reactor Vessel Internals, and Reactor  Coolant System......................................................................................2-37 2.3.1.1  Reactor Pressure Vessel.........................................................2-37
 
vi 2.3.1.2  Reactor Vessel Internals.........................................................2-38 2.3.1.3  Reactor Coolant System Pressure Boundary..........................2-39 2.3.2  Engineered Safety Features...................................................................2-40 2.3.2.1  Residual Heat Removal System..............................................2-41 2.3.2.2  Reactor Core Isolation Cooling System...................................2-41 2.3.2.3  Core Spray System..................................................................2-43 2.3.2.4  High Pressure Coolant Injection System.................................2-43 2.3.2.5  Containment and Suppression System...................................2-45 2.3.2.6  Containment Atmosphere Control System..............................2-47 2.3.2.7  Standby Gas Treatment System..............................................2-51 2.3.3  Auxiliary Systems...................................................................................2-52 2.3.3.1  Building Drains Nonradioactive System...................................2-53 2.3.3.2  Containment Instrument Gas System......................................2-53 2.3.3.3  Control Rod Drive Hydraulics System.....................................2-54 2.3.3.4  Control Structure Chilled Water System..................................2-54 2.3.3.5  Control Structure Heating, Ventilation, and Air  Conditioning (HVAC) Systems..............................................................2-56 2.3.3.6  Cooling Tower System.............................................................2-56 2.3.3.7  Diesel Fuel Oil System............................................................2-59 2.3.3.8  Diesel Generator Building HVAC Systems..............................2-64 2.3.3.9  Diesel Generator System.........................................................2-64 2.3.3.10  Domestic Water System........................................................2-64 2.3.3.11  Emergency Service Water System........................................2-65 2.3.3.12  Engineered Safeguards (ES) Service Water (SW)
Pumphouse HVAC System...................................................................2-66 2.3.3.13  Fire Protection System..........................................................2-67 2.3.3.14  Fuel Pool Cooling and Cleanup System and Fuel Pools and Auxiliaries............................................................................2-83 2.3.3.15  Neutron Monitoring System...................................................2-91 2.3.3.16  Nitrogen and Hydrogen System.............................................2-91 2.3.3.17  Primary Containment Atmosphere Circulation System..........2-92 2.3.3.18  Process and Area Radiation Monitoring System...................2-92 2.3.3.19  Radwaste Liquid System.......................................................2-94 2.3.3.20  Radwaste Solids Handling System........................................2-97 2.3.3.21  Raw Water Treatment System...............................................2-97 2.3.3.22  Reactor Building Chilled Water System.................................2-98 2.3.3.23  Reactor Building Closed Cooling Water System.................2-100 2.3.3.24  Reactor Building HVAC System..........................................2-107 2.3.3.25  Reactor Nonnuclear Instrumentation System......................2-108 2.3.3.26  Reactor Water Cleanup System..........................................2-109 2.3.3.27  Residual Heat Removal Service Water System..................2-109 2.3.3.28  Sampling System.................................................................2-111 2.3.3.29  Sanitary Drainage System...................................................2-111 2.3.3.30  Service Air System..............................................................2-112 2.3.3.31  Service Water System.........................................................2-112 2.3.3.32  Standby Liquid Control System...........................................2-114 2.3.3.33  Turbine Building Closed Cooling Water System..................2-116 2.3.4  Steam and Power Conversion Systems...............................................2-117
 
vii 2.3.4.1  Auxiliary Boiler System..........................................................2-117 2.3.4.2  Bypass Steam System...........................................................2-118 2.3.4.3  Condensate Transfer and Storage System...........................2-118 2.3.4.4  Condenser and Air Removal System.....................................2-121 2.3.4.5  Feedwater System.................................................................2-122 2.3.4.6  Main Steam System...............................................................2-122 2.3.4.7  Main Turbine System.............................................................2-128 2.3.4.8  Makeup Demineralizer System..............................................2-129 2.3.4.9  Makeup Transfer and Storage System..................................2-129 2.3.4.10 Reactor Feed Pump Turbines System..................................2-130 2.3.4.11  Refueling Water Transfer and Stoarge System...................2-130 2.4  Scoping and Screening Results: Structures........................................................2-131 2.4.1  Primary Containment............................................................................2-134 2.4.1.1  Summary of Technical Information in the Application............2-134 2.4.1.2  Staff Evaluation......................................................................2-135 2.4.1.3  Conclusion.............................................................................2-139 2.4.2  Reactor Building...................................................................................2-140 2.4.2.1  Summary of Technical Information in the Application............2-140 2.4.2.2  Staff Evaluation......................................................................2-141 2.4.2.3  Conclusion.............................................................................2-145 2.4.3  Engineered Safeguards Service Water Pumphouse and  Spray Pond..........................................................................................2-145 2.4.3.1  Summary of Technical Information in the Application............2-145 2.4.3.2  Staff Evaluation......................................................................2-147 2.4.3.3  Conclusion.............................................................................2-147 2.4.4  Circulating Water Pumphouse and Water Treatment Building.............2-147 2.4.4.1  Summary of Technical Information in the Application............2-147 2.4.4.2  Staff Evaluation......................................................................2-148 2.4.4.3  Conclusion.............................................................................2-148 2.4.5  Control Structure..................................................................................2-149 2.4.5.1  Summary of Technical Information in the Application............2-149 2.4.5.2  Staff Evaluation......................................................................2-150 2.4.5.3  Conclusion.............................................................................2-150 2.4.6  Diesel Generator A, B, C, and D Building.............................................2-150 2.4.6.1  Summary of Technical Information in the Application............2-150 2.4.6.2  Staff Evaluation......................................................................2-151 2.4.6.3  Conclusion.............................................................................2-152 2.4.7  Diesel Generator E Building.................................................................2-152 2.4.7.1  Summary of Technical Information in the Application............2-152 2.4.7.2  Staff Evaluation......................................................................2-153 2.4.7.3  Conclusion.............................................................................2-153 2.4.8  Turbine Building...................................................................................2-154 2.4.8.1  Summary of Technical Information in the Application............2-154 2.4.8.2  Staff Evaluation......................................................................2-155 2.4.8.3  Conclusion.............................................................................2-156 2.4.9  Yard Structures....................................................................................2-156 2.4.9.1  Summary of Technical Information in the Application............2-156 2.4.9.2  Staff Evaluation......................................................................2-159
 
viii 2.4.9.3  Conclusion.............................................................................2-160 2.4.10  Bulk Commodities..............................................................................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...........................................................................2-166 2.5  Scoping and Screening Results: Electrical and Instrumentation and Controls...2-166 2.5.1  Electrical and Instrumentation and Controls Component  Commodity Groups..............................................................................2-167 2.5.1.1  Summary of Technical Information in the Application............2-167 2.5.1.2  Staff Evaluation......................................................................2-169 2.5.1.3  Conclusion.............................................................................2-171 2.6  Conclusion for Scoping and Screening...............................................................2-171 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 3.0.2  Staff's Review Process.............................................................................3-4 3.0.2.1  Review of AMPs........................................................................3-4 3.0.2.2  Review of AMR Results.............................................................3-5 3.0.2.3  FSAR Supplement.....................................................................3-5 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..................................3-10 3.0.3.2  AMPs Consistent with the GALL Report with  Exceptions or Enhancements...............................................................3-93 3.0.3.3  AMPs Not Consistent with or Not Addressed in the GALL Report............................................................................................................3-180 3.0.4  QA Program Attributes Integral to Aging Management Programs........3-197 3.0.4.1  Summary of Technical Information in the Application............3-197 3.0.4.2  Staff Evaluation......................................................................3-197 3.0.4.3  Conclusion.............................................................................3-198 3.1  Aging Management of Reactor Vessel, Reactor Vessel Internals,  and Reactor Coolant System..............................................................................3-198 3.1.1  Summary of Technical Information in the Application..........................3-199 3.1.2  Staff Evaluation....................................................................................3-199 3.1.2.1  AMR Results Consistent with the GALL Report....................3-217 3.1.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended......................................3-223 3.1.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report.................................................................................................3-241 3.1.3  Conclusion............................................................................................3-252 3.2  Aging Management of Engineered Safety Features...........................................3-252 3.2.1  Summary of Technical Information in the Application..........................3-253 3.2.2  Staff Evaluation....................................................................................3-253 3.2.2.1  AMR Results Consistent with the GALL Report....................3-263
 
ix 3.2.2.2  AMR Results Consistent with the GALL Report for  Which Further Evaluation is Recommended......................................3-274 3.2.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report.............................................................................3-287 3.2.3  Conclusion............................................................................................3-294 3.3  Aging Management of Auxiliary Systems............................................................3-295 3.3.1  Summary of Technical Information in the Application..........................3-295 3.3.2  Staff Evaluation....................................................................................3-296 3.3.2.1  AMR Results Consistent with the GALL Report....................3-313 3.3.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended......................................3-324 3.3.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report.............................................................................3-366 3.3.3  Conclusion............................................................................................3-416 3.4  Aging Management of Steam and Power Conversion Systems..........................3-416 3.4.1  Summary of Technical Information in the Application..........................3-417 3.4.2  Staff Evaluation....................................................................................3-417 3.4.2.1  AMR Results Consistent with the GALL Report....................3-425 3.4.2.2  AMR Results Consistent with the GALL Report for  Which Further Evaluation is Recommended......................................3-430 3.4.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report.............................................................................3-440 3.4.3  Conclusion............................................................................................3-448 3.5  Aging Management of Containments, Structures, and Component Supports.....3-448 3.5.1  Summary of Technical Information in the Application..........................3-449 3.5.2  Staff Evaluation....................................................................................3-449 3.5.2.1  AMR Results Consistent with the GALL Report....................3-461 3.5.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended......................................3-465 3.5.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report.............................................................................3-487 3.5.3  Conclusion............................................................................................3-494 3.6  Aging Management of Electrical and Instrumentation and Controls...................3-494 3.6.1  Summary of Technical Information in the Application..........................3-494 3.6.2  Staff Evaluation....................................................................................3-495 3.6.2.1  AMR Results Consistent with the GALL Report....................3-498 3.6.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended......................................3-500 3.6.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report.............................................................................3-507 3.6.3  Conclusion............................................................................................3-510 3.7  Conclusion for Aging Management Review Results...........................................3-510 TIME-LIMITED AGING ANALYSES...........................................................................................4-1 4.1  Identification of Time-Limited Aging Analyses........................................................4-1 4.1.1  Summary of Technical Information in the Application..............................4-1 4.1.2  Staff Evaluation........................................................................................4-1 4.1.3  Conclusion................................................................................................4-4
 
x 4.2  Reactor Vessel Neutron Embrittlement...................................................................4-4 4.2.1  Neutron Fluence.......................................................................................4-5 4.2.1.1  Summary of Technical Information in the Application................4-5 4.2.1.2  Staff Evaluation..........................................................................4-5 4.2.1.3  UFSAR Supplement..................................................................4-6 4.2.1.4  Conclusion.................................................................................4-6 4.2.2  Upper Shelf Energy Evaluation................................................................4-6 4.2.2.1  Summary of Technical Information in the Application................4-6 4.2.2.2  Staff Evaluation..........................................................................4-6 4.2.2.3  UFSAR Supplement..................................................................4-8 4.2.2.4  Conclusion.................................................................................4-8 4.2.3  Adjusted Reference Temperature Analysis..............................................4-8 4.2.3.1  Summary of Technical Information in the Application................4-8 4.2.3.2  Staff Evaluation..........................................................................4-8 4.2.3.3  UFSAR Supplement..................................................................4-9 4.2.3.4  Conclusion.................................................................................4-9 4.2.4  Pressure-Temperature (P-T) Limits..........................................................4-9 4.2.4.1  Summary of Technical Information in the Application................4-9 4.2.4.2  Staff Evaluation........................................................................4-10 4.2.4.3  UFSAR Supplement................................................................4-11 4.2.4.4  Conclusion...............................................................................4-11 4.2.5  Reactor Vessel Circumferential Weld Examination Relief......................4-11 4.2.5.1  Summary of Technical Information in the Application..............4-11 4.2.5.2  Staff Evaluation........................................................................4-11 4.2.5.3  UFSAR Supplement................................................................4-13 4.2.5.4  Conclusion...............................................................................4-13 4.2.6  Reactor Vessel Axial Weld Failure Probability.......................................4-13 4.2.6.1  Summary of Technical Information in the Application..............4-14 4.2.6.2  Staff Evaluation........................................................................4-14 4.2.6.3  UFSAR Supplement................................................................4-14 4.2.6.4  Conclusion...............................................................................4-14 4.2.7  Reflood Thermal Shock..........................................................................4-15 4.2.7.1  Summary of Technical Information in the Application..............4-15 4.2.7.2  Staff Evaluation........................................................................4-15 4.2.7.3  UFSAR Supplement................................................................4-16 4.2.7.4  Conclusion...............................................................................4-17 4.3  Metal Fatigue........................................................................................................4-17 4.3.1  Reactor Pressure Vessel Fatigue Analyses...........................................4-17 4.3.1.1  Summary of Technical Information in the Application..............4-17 4.3.1.2  Staff Evaluation........................................................................4-17 4.3.1.3  FSAR Supplement...................................................................4-20 4.3.1.4  Conclusion...............................................................................4-20 4.3.2  Reactor Vessel Internals Fatigue Analyses............................................4-20 4.3.2.1  Summary of Technical Information in the Application..............4-20 4.3.2.2  Staff Evaluation........................................................................4-20 4.3.2.3  FSAR Supplement...................................................................4-21 4.3.2.4  Conclusion...............................................................................4-21
 
xi 4.3.3  Effects of Reactor Coolant Environment on  Fatigue Life of Components and Piping.................................................4-21 4.3.3.1  Summary of Technical Information in the Application..............4-22 4.3.3.2  Staff Evaluation........................................................................4-22 4.3.3.3  FSAR Supplement...................................................................4-25 4.3.3.4  Conclusion...............................................................................4-25 4.3.4  Reactor Coolant Pressure Boundary Piping and  Component Fatigue Analyses................................................................4-25 4.3.4.1  Summary of Technical Information in the Application..............4-25 4.3.4.2  Staff Evaluation........................................................................4-25 4.3.4.3  UFSAR Supplement................................................................4-26 4.3.4.4  Conclusion...............................................................................4-27 4.3.5  Non-Class 1 Component Fatigue Analyses............................................4-27 4.3.5.1  Summary of Technical Information in the Application..............4-27 4.3.5.2  Staff Evaluation........................................................................4-27 4.3.5.3  UFSAR Supplement................................................................4-27 4.3.5.4  Conclusion...............................................................................4-28 4.4  Environmental Qualification of Electrical Equipment.............................................4-28 4.4.1  Summary of Technical Information in the Application............................4-28 4.4.2  Staff Evaluation......................................................................................4-28 4.4.3  UFSAR Supplement...............................................................................4-29 4.4.4  Conclusion..............................................................................................4-30 4.5  Concrete Containment Tendon Prestress.............................................................4-30 4.5.1  Summary of Technical Information in the Application............................4-30 4.5.2  Staff Evaluation......................................................................................4-30 4.5.3  UFSAR Supplement...............................................................................4-30 4.5.4  Conclusion..............................................................................................4-30 4.6  Containment Liner Plate, Metal Containments, and Penetrations Fatigue Analyses.............................................................................4-30 4.6.1  ASME Class MC Components...............................................................4-30 4.6.1.1  Summary of Technical Information in the Application..............4-30 4.6.1.2  Staff Evaluation........................................................................4-31 4.6.1.3  UFSAR Supplement................................................................4-31 4.6.1.4  Conclusion...............................................................................4-31 4.6.2  Downcomer Vents and Safety Relief Valve Discharge Piping................4-31 4.6.2.1  Summary of Technical Information in the Application..............4-31 4.6.2.2  Staff Evaluation........................................................................4-32 4.6.2.3  UFSAR Supplement................................................................4-32 4.6.2.4  Conclusion...............................................................................4-33 4.6.3  Safety Relief Valve Quenchers...............................................................4-33 4.6.3.1  Summary of Technical Information in the Application..............4-33 4.6.3.2  Staff Evaluation........................................................................4-33 4.6.3.3  UFSAR Supplement................................................................4-34 4.6.3.4  Conclusion...............................................................................4-34 4.7  Other Plant-Specific Time-Limited Aging Analyses...............................................4-34 4.7.1  Main Steam Line Flow Restrictor Erosion Analyses...............................4-34 4.7.1.1  Summary of Technical Information in the Application..............4-34 4.7.1.2  Staff Evaluation........................................................................4-35
 
xii 4.7.1.3  UFSAR Supplement................................................................4-36 4.7.1.4  Conclusion...............................................................................4-36 4.7.2  High Energy Line Break Cumulative Fatigue Usage Factors.................4-37 4.7.2.1  Summary of Technical Information in the Application..............4-37 4.7.2.2  Staff Evaluation........................................................................4-37 4.7.2.3  UFSAR Supplement................................................................4-37 4.7.2.4  Conclusion...............................................................................4-38 4.7.3  Core Plate Rim Hold-Down Bolts...........................................................4-38 4.7.3.1  Summary of Technical Information in the Application..............4-38 4.7.3.2  Staff Evaluation........................................................................4-38 4.7.3.3  UFSAR Supplement................................................................4-40 4.7.3.4  Conclusion...............................................................................4-40 4.7.4  Irradiation Assisted Stress Corrosion Cracking (IASCC)........................4-40 4.7.4.1  Summary of Technical Information in the Application..............4-40 4.7.4.2  Staff Evaluation........................................................................4-40 4.7.4.3  UFSAR Supplement................................................................4-41 4.7.4.4  Conclusion...............................................................................4-42 4.8  Conclusion for Time-Limited Aging Analyses........................................................4-42 REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS..........................5-1 CONCLUSION...........................................................................................................................6-1  SSES UNITS 1 AND 2 LICENSE RENEWAL COMMITMENTS...............................................A-1 CHRONOLOGY........................................................................................................................B-1  PRINCIPAL CONTRIBUTORS.................................................................................................C-1
 
REFERENCES.........................................................................................................................D-1 xiii ABBREVIATIONS
 
AAI  applicant action item AC  alternating current ACI  American Concrete Institute ACRS  Advisory Committee on Reactor Safeguards ACSR  Aluminum Conductor Steel Reinforced ADAMS Agencywide Document Access and Management System ADS  automatic depressurization system AEM  aging effect / mechanism AERM  aging effect requiring management AFW  auxiliary feedwater AHU  air handling unit AISC  American Institute of Steel Construction aka  also known as AMP  aging management program AMR  aging management review ANSI  American National Standards Institute APRM  average power range monitor AR  action request ARI  alternate rod injection / alternate rod insertion ART  adjusted reference temperature ASCE  American Society of Civil Engineers ASME  American Society of Mechanical Engineers AST  alternate source term ASTM  American Society for Testing and Materials ATWS  anticipated transient without scram
 
B&PV  boiler and pressure vessel BTP APCSB Branch Technical Position Auxilia ry Power Conversion Systems Branch BWR  boiling water reactor BWRVIP Boiling Water Reactor Vessel and Internals Program
 
CASS  cast austenitic stainless steel CF  chemistry factor
 
CFR  Code of Federal Regulations CI  confirmatory item CIG  containment instrument gas CIV  combined intermediate valve CLB  current licensing basis CM  condition monitoring CMAA  Crane Manufacturers Association of America CPX  Component Maintenance System CR  condition report CRD  control rod drive CRDH  control rod drive hydraulics CRDRL control rod drive return line xiv CREOASS Control Room Emergency Outside Air Supply System CS  carbon steel CSS  core support structures CSCW  control structure chilled water CST  condensate storage tank CWST  clarified water storage tank CUF  cumulative usage factor
 
DAR  design assessment report DBA  design basis accident DBD  design basis document DBE  design basis event DC  direct current DG  diesel generator DOR  Division of Operating Reactors DOT  Department of Transportation DP  differential pressure
 
ECCS  emergency core cooling system EDG  emergency diesel generator EFPY  effective full-power year EHL  emergency heat load EOL  end of life EPRI  Electric Power Research Institute EPRI-MRP Electric Power Research Institute Materials Reliability Program EPU  extended power uprate EQ  environmental qualification ESF  engineered safety feature ESS  Engineered Safeguard System ESSW  engineered safeguards service water ESW  emergency service water
 
FAC  flow-accelerated corrosion
 
F en  environmental fatigue life correction factor FERC  Federal Energy Regulatory Commission FP  fire protection FPCCU Fuel Pool Cooling and Cleanup System FPRR  fire protection review report FR  Federal Register FSAR  final safety analysis report FW  feedwater
 
GALL  Generic Aging Lessons Learned Report GDC  general design criteria or general design criterion GE  General Electric GEIS  Generic Environmental Impact Statement GL  generic letter GRRCCW Gaseous Radwaste Recombiner Closed Cooling Water System xv GSI  generic safety issue
 
HAZ  heat-affected zone HCI  hydraulic control unit HELB  high-energy line break HEPA  high efficiency particulate air HP  high pressure HPCI  high pressure coolant injection HVAC  heating, ventilation, and air conditioning HWC  hydrogen water chemistry HX  heat exchanger
 
I&C  instrumentation and controls IASCC  irradiation assisted stress corrosion cracking ICTM  isolated condenser treatment method ID  inside diameter IEEE  Institute of Electrical and Electronics Engineers IGA  intergranular attack IGSCC  intergranular stress corrosion cracking IN  information notice INPO  Institute of Nuclear Power Operations IP  intermediate pressure IPA  integrated plant assessment IPE  individual plant evaluation IPEEE  individual plant evaluation of external events IR  insulation resistance IRM  intermediate range monitor ISFSI  independent spent fuel storage installation ISG  interim staff guidance ISI  inservice inspection ISO  independent system operator ISP  Integrated Surveillance Program
 
kV  kilo-volt
 
LLRWHF low level radwaste holding facility LOCA  loss of coolant accident LP  low pressure LPCI  low pressure coolant injection LPCS  low pressure core spray LPRM  local power range monitor LR  license renewal LRA  license renewal application LTOP  low-temperature overpressure protection
 
MEB  metal-enclosed bus MeV  million electron volts MIC  microbiologically influenced corrosion xvi MOAB  motor operated air break MRDB  maintenance rule database MS  main steam MSIV/LCS main steam isolation valve / leakage control system MWt  megawatts-thermal MWe  megawatts-electric
 
N/A  not applicable NCR  Non-conformance Report NDE  nondestructive examination NEI  Nuclear Energy Institute NFPA  National Fire Protection Association Ni  nickel NIMS  Nuclear Information Management System NLDAE new loads design adequacy evaluation NMS  Neutron Monitoring System NPS  nominal pipe size NRC  US Nuclear Regulatory Commission NSAS  non-safety affecting safety NSE  nuclear system engineering NSSS  nuclear steam supply system
 
ODCM  offsite dose calculation manual ODSCC outside-diameter stress corrosion cracking OE  operating experience OI  open item OL  operating license OQA  operational quality assurance
 
P&ID  piping and instrumentation diagrams PASS  Post-Accident Sampling System PGCC  Power Generation Control Complex pH  Concentration of Hydrogen Ions PM  preventive maintenance / performance monitoring PPB  parts per billion PPL  PPL Susquehanna, LLC PPM  parts per million P-T  pressure-temperature PTS  pressurized thermal shock PVC  polyvinyl chloride PWR  pressurized water reactor PWSCC primary water stress corrosion cracking
 
QA  quality assurance QAPD  quality assurance program description
 
RAI  request for additional information RB  reactor building xvii RBCCW reactor building closed cooling water RBCW  reactor building chilled water RBM  rod block monitor RCIC  reactor core isolation cooling RCPB  reactor coolant pressure boundary RCS  reactor coolant system RCSPB reactor coolant system pressure boundary RFP  reactor feedwater pump RG  regulatory guide RHR  residual heat removal RHRSW residual heat removal service water RI  reactor internals RIS  regulatory issue summary ROFT  reduction of fracture toughness RPT  recirculation pump trip RPV  reactor pressure vessel RR  reactor recirculation RT  radiographic testing
 
RT NDT  reference temperature nil ductility transition RVID  reactor vessel integrity database RWCU  Reactor Water Cleanup System RWST  refueling water storage tank
 
SBO  station blackout SC  structure and component SCC  stress-corrosion cracking SCW  source of cooling water SDV  scram discharge volume SE  safety evaluation SER  safety evaluation report SHE  Standard Hydrogen Electrode SGTS  Standby Gas Treatment System SJAE  steam jet air ejector SLC  standby liquid control SOC  statement of consideration SOMS  Shift Operations Management System SPE  steam packing exhauster SPLEX  Susquehanna Plant Lifetime Excellence Program SRM  source range monitoring SRP  Standard Review Plan SRP-LR Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants SRV  safety relief valve SS  stainless steel SSC  system, structure, and component SSE  safe-shutdown earthquake SSES  Susquehanna Steam Electric Station SW  service water xviii  TBCCW turbine building closed cooling water TEMA  Tubular Exchanger Manufacturers Association TIP  traversing incore probe TLAA  time-limited aging analysis TRM  technical requirements manual TS  technical specifications
 
USE  upper-shelf energy UT  ultrasonic testing UV  ultraviolet
 
VDC  volts direct current VFLD  vessel flange leak detection VHP  reactor vessel head penetration
 
XLPE  cross-linked polyethylene XLPO  cross-linked polyolefin
 
WA  work authorization
 
Zn  zinc 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
 
Susquehanna Steam Electric Station (SSES), Units 1 and 2, as filed by the PPL Susquehanna, LLC (PPL or the applicant). By letter dated September 13, 2006, PPL submitted its application
 
to the US Nuclear Regulatory Commission (NRC) for renewal of the SSES operating licenses
 
for an additional 20 years. The NRC staff (the staff) prepared this report to summarize
 
summarizes 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 Evelyn Gettys. Ms Gettys may be contacted by telephone at 301-415-4029or by electronic mail at Evelyn.Gettys@nrc.gov. Alternatively, written correspondence may be sent to the
 
following address:
 
Division of License Renewal
 
US Nuclear Regulatory Commission
 
Washington, DC 20555-0001
 
Attention: Evelyn Gettys Mail Stop 011-F1
 
In its September 13, 2006, submission letter, the applicant requested renewal of the operating
 
licenses issued under Section 103 (Operating License Nos. NPF-14 and NPF-22) of the Atomic
 
Energy Act of 1954, as amended, for Units 1 and 2 for a period of 20 years beyond the current
 
expirations at midnight July 17, 2022, for Unit 1, and at midnight March 23, 2024, for Unit 2.
 
SSES is located approximately 5 miles northeast of Berwick, PA. The NRC issued the
 
construction permits for Unit 1 on November 2, 1973, and on November 2, 1973, for Unit 2. The
 
NRC issued the operating licenses for Unit 1 on November 12, 1982, and on June 27, 1984, for
 
Unit 2. Units 1 and 2 are of Mark 2 BWR design. General Electric supplied the nuclear steam
 
supply system and Bechtel originally designed and constructed the balance of the plant. The
 
licensed power output of each unit is 3489 megawatt thermal with a gross electrical output of
 
approximately 1190 megawatt electric. The updated fi nal 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 SSES license renewal is based on the applicant's LRA and on its responses to the staff's
 
requests for additional information. 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 December 2008. The staff reviewed information received after that date
 
depending on the stage of the safety review and the volume and complexity of the information.
 
The public may view the LRA and all pertinent information and materials, including the UFSAR, at the NRC Public Document Room, located on the first floor of One White Flint North, 11555 1-2 Rockville Pike, Rockville, MD 20852-2738 (301-415-4737 / 800-397-4209). 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 35 "Generic Environmental Impact Statement for License Renewal of Nuclear Plants Regarding
 
Susquehanna Steam Electric Station, Units 1 and 2, Draft Report for Comment," on April 2008.
 
The final, plant-specific GEIS Supplement 35, "Generic Environmental Impact Statement for License Renewal of Nuclear Plants Regarding Susquehanna Steam Electric Station, Units 1
 
and 2, Final Report," is scheduled to be issued in April 2009.
 
1.2  License Renewal Background Pursuant to the Atomic Energy Act of 1954, as amended, and NRC regulations, operating
 
licenses for commercial power reactors are issued for 40 years and can be renewed for up to
 
20 additional years. The original 40-year license term was selected based on economic and
 
antitrust considerations rather than on technical limitations; however, some individual plant and
 
equipment designs may have been engineered for an expected 40-year service life.
 
In 1982, the staff anticipated interest in license renewal and held a workshop on nuclear power
 
plant aging. This workshop led the NRC to establish a comprehensive program plan for nuclear
 
plant aging research. From the results of that research, a technical review group concluded that
 
many aging phenomena are readily manageable and pos e no technical issues precluding life extension for nuclear power plants. In 1986, the staff published a request for comment on a
 
policy statement that would address major policy, technical, and procedural issues related to
 
license renewal for nuclear power plants.
 
In 1991, the staff published 10 CFR Part 54, the License Renewal Rule (Volume 56, page 64943, of the Federal Register (56 FR 64943), dated December 13, 1991). The staff participated in an industry-sponsored demonstration program to apply 10 CFR Part 54 to a pilot
 
plant and to gain the experience necessary to develop implementation guidance. To establish a scope of review for license renewal, 10 CFR Part 54 defined age-related degradation unique to 1-3 license renewal; however, during the demonstrati on program, the staff found that adverse aging effects on plant systems and components are managed during the period of initial license and
 
that the scope of the review did not allow sufficient credit for management programs, 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 staff 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 staff made these
 
rule changes to ensure that important syst ems, structures, and components (SSCs) will continue to perform their intended functions during the period of extended operation. In addition, the amended 10 CFR Part 54 clarifies and simplifies the integrated plant assessment process to
 
be consistent with the revised focus on passive, long-lived structures and components (SCs).
 
Concurrent with these initiatives, the staff pursued a separate rulemaking effort (61 FR 28467, June 5, 1996) and amended 10 CFR Part 51 to focus the scope of the review of environmental
 
impacts of license renewal in order to fulfill NRC responsibilities under the National
 
Environmental Policy Act of 1969.
 
1.2.1  Safety Review License renewal requirements for power reactors are based on two key principles:
 
(1) The regulatory process is adequate to ensure that the licensing bases of all currently operating plants maintain an acceptable level of safety with the possible exceptions of
 
the detrimental aging effects on the functions of certain SSCs, as well as a few other
 
safety-related issues, during the period of extended operation.    (2) The plant-specific licensing basis must be maintained during the renewal term in the same manner and to the same extent as during the original licensing term.
 
In implementing these two principles, 10 CFR 54.4, "Scope," defines the scope of license
 
renewal as including those SSCs 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 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.
1-4  Pursuant to 10 CFR 54.21(d), the LRA is required to include a FSAR supplement with a
 
summary description of the applicant's programs and activities for managing aging effects and
 
an evaluation of time-limited aging analyses (TLAAs) for the period of extended operation.
 
License renewal also requires TLAA identification and updating. During the plant design phase, certain assumptions about the length of time the plant can operate are incorporated into design
 
calculations for several plant SSCs. In accordance with 10 CFR 54.21(c)(1), the applicant must
 
either show that these calculations will remain valid for the period of extended operation, project
 
the analyses to the end of the period of extended operation, or demonstrate that the aging
 
effects on these SSCs will be adequately managed for the period of extended operation.
 
In 2005, the NRC revised Regulatory Guide (RG) 1.188, "Standard Format and Content for
 
Applications to Renew Nuclear Power Plant Operating Licenses." This RG endorses Nuclear
 
Energy Institute (NEI) 95-10, Revision 6, "Industry Guideline for Implementing the Requirements
 
of 10 CFR Part 54 - The License Renewal Rule," issued in June 2005. NEI 95-10 details an
 
acceptable method of implementing 10 CFR Part 54. The staff also used the SRP-LR to review
 
the LRA.
 
In the LRA, the applicant fully utilized the process defined in NUREG-1801, Revision 1, "Generic
 
Aging Lessons Learned (GALL) Report," dated September 2005. The GALL Report summarizes
 
staff-approved aging management programs (AMPs) for many SCs subject to an AMR. If an applicant commits to implementing these staff-approved AMPs, the time, effort, and resources
 
for LRA review can be greatly reduced, improvi ng the efficiency and effectiveness of the license renewal review process. The GALL Report summarizes the aging management evaluations, programs, and activities credited for managing aging for most of the SCs used throughout the
 
industry. The report is also a quick reference for both applicants and staff reviewers to AMPs
 
and activities that can manage aging adequately during the period of extended operation.
 
1.2.2  Environmental Review Part 51 of 10 CFR contains regulations on environmental protection regulations. In
 
December 1996, the staff revised the environmental protection regulations to facilitate the
 
environmental review for license renewal. The staff prepared the GEIS to document its
 
evaluation of possible environmental impacts associated with nuclear power plant license renewals. For certain types of environmental im pacts, the GEIS contains generic findings that apply to all nuclear power plants and are codified in Appendix B, "Environmental Effect of
 
Renewing the Operating License of a Nuclear Power Plant," to Subpart A, "National
 
Environmental Policy Act - Regulations Implementing Section 102(2)," of 10 CFR Part 51.
 
Pursuant to 10 CFR 51.53(c)(3)(i), a license renewal applicant may incorporate these generic
 
findings in its environmental report. In accor dance 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 November 15, 2006, in Berwick, PA, to identify plant-specific
 
environmental issues. The draft, plant-specific GEIS Supplement 35 documents the results of the environmental review and makes a preliminary recommendation as to the license renewal
 
action. The staff held another public meeting on May 28, 2008, in Berwick, PA, to discuss draft, 1-5 plant-specific GEIS Supplement 35. After considering comments on the draft, the staff will published the final, plant-specific GEIS Supplement 35 separately from this report.
 
1.3  Principal Review Matters Part 54 of 10 CFR 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, "Standards for Issuance of a Renewed
 
License," of 10 CFR sets forth the license renewal standards. This SER describes the results of
 
the staff's safety review.
 
Pursuant to 10 CFR 54.19(a), the NRC requires a license renewal applicant to submit general
 
information, which the applicant provided in LRA Section 1. The staff reviewed LRA Section 1
 
and finds that the applicant has submitted the required information.
 
Pursuant to 10 CFR 54.19(b), the NRC requires that the LRA include "conforming changes to
 
the standard indemnity agreement, 10 CFR 140.92, Appendix B, to account for the expiration
 
term of the proposed renewed license." On this issue, the applicant stated in the LRA:
 
The current indemnity agreement (No. B-90) for SSES states, in Article VII, that
 
the agreement shall terminate at the time of expiration of the license specified in
 
Item 3 of the Attachment to the agreement, which is the last to expire. Item 3 of
 
the Attachment to the indemnity agreem ent, as revised by Amendment No. 3, lists SSES operating licenses NPF-14 and NPF-22. PPL Susquehanna, LLC
 
requests that conforming changes be made to Article VII of the indemnity
 
agreement, and Item 3 of the Attachment to that agreement, specifying the
 
extension of agreement to the expiration date of the renewed SSES facility
 
operating licenses sought in this application. In addition, should the license
 
numbers be changed upon issuance of the renewal license, PPL Susquehanna, LLC requests that conforming changes be made to Item 3 of the Attachment to
 
the indemnity agreement, and to other sections of the agreement as deemed
 
appropriate.
 
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 FSAR supplement.
 
LRA Sections 3 and 4 and Appendix B address the license renewal requirements of
 
10 CFR 54.21(a), (b), and (c). LRA Appendix A 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 letters dated September 12, 2007 and
 
September 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.
 
1-6  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 SSES 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," 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 main taining safety, improving effectiveness and efficiency, reducing regulatory burden, and increasing public confidence. Interim staff guidance (ISG) is documented for use by the staff, industry, and other interested stakeholders until
 
incorporated into such license renewal guidance documents as the SRP-LR and GALL Report.
 
Table 1.4-1 shows the current set of ISGs, as well as the SER sections in which the staff
 
addresses them.
 
Table 1.4-1  Current Interim Staff Guidance ISG Issue (Approved ISG Number)
Purpose SER Section Nickel-alloy components in the reactor coolant pressure boundary (LR-ISG-19B) 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. Not applicable (PWRs only) 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 
 
1-7 ISG Issue (Approved ISG Number)
Purpose SER Section Staff Guidance Regarding the Station Blackout Rule (10 CFR 50.63) Associated with License Renewal Applications (LR-ISG-2008-01)
To clarify the scoping boundary of the offsite recovery paths that must be included within the scope of license renewal for station blackout.
The staff has issued the proposed
 
ISG for public comments. A final ISG has not yet been issued.
2.5.1.2 Changes to Generic Aging Lesson
 
Learned (GALL) Report Aging
 
Management Program (AMP) XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49
 
Environmental Qualification
 
Requirements" (LR-ISG-2007-02)
To address the frequency of
 
inspection of electrical cable connections not subject to 10 CFR
 
50.49 prior to the period of extended
 
operation.
The staff has issued the proposed
 
ISG for public comments. A final ISG has not yet been issued.
3.0.3.1.27 1.5  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 FSAR update required by 10 CFR 50.71(e) following the issuance
 
of the renewed licenses.
 
The second license condition requires future activities described in the UFSAR supplement to
 
be completed prior to the period of extended operation.
 
The third license condition requires that all capsules in the reactor vessel that are removed and
 
tested meet the requirements of American Society for Testing and Materials (ASTM) E 185-82
 
to the extent practicable for the configuration of the specimens in the capsule. Any changes to the capsule withdrawal schedule, including spare capsules, must be approved by the staff prior
 
to implementation. All capsules placed in storage must be maintained for future insertion. Any
 
changes to storage requirements must be approved by the staff, as required by 10 CFR Part 50, Appendix H.
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 Part 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) for systems, structures, and components (SSCs) that are within the scope of license renewal in accordance
 
with 10 CFR 54.4.
 
In license renewal application (LRA) Section 2.1, A Scoping and Screening Methodology,@ the applicant described the scoping and screening methodology used to identify the SSCs at the Susquehanna Steam Electric Station (SSES) that are within the scope of license renewal and
 
the SCs subject to an AMR. The staff reviewed the Pennsylvania Power and Light (PPL)
 
Susquehanna, LLC (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 Part 54 - The License Renewal Rule,@ Revision 6. Additionally, in developing this methodology, the applicant considered the correspondence between the United States (U.S.) Nuclear Regulatory Commission (NRC) and other applicants, and NEI.
 
2.1.2  Summary of Technical Information in the Application In LRA Sections 2.0 and 3.0, the applicant provided the technical information required by
 
10 CFR 54.21(a). In LRA Section 2.1, the applicant described the process used to identify the
 
SSCs that meet the license renewal scoping criteria pursuant to 10 CFR 54.4(a), and the
 
process used to identify the SCs that are subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1). The applicant provided the results of the process used for identifying the
 
SCs subject to an AMR in the following LRA Sections:
* Section 2.2, A Plant Level Scoping Results
@
* Section 2.3, A Scoping and Screening Results: Mechanical Systems
@
* Section 2.4, A Scoping and Screening Results: Structures
@
2-2
* Section 2.5, A Scoping and Screening Results: Electrical and Instrumentation and Control Systems@
In LRA Section 3.0, A Aging Management Review Results,@ the applicant described its aging management results as follows:
* Section 3.1, A Aging Management of Reactor Vessel, Internals and Reactor Coolant System@
* Section 3.2, A Aging Management of Engineered Safety Features
@
* Section 3.3, A Aging 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
@
* Section 3.6, A Aging Management of Electrical and Instrumentation and Controls
@  In LRA Section 4.0, A Time-Limited Aging Analyses,@ the applicant described its identification and evaluation of time-limited aging analyses.
2.1.3  Scoping and Screening Program Review The staff evaluated the LRA scoping and screening methodology in accordance with the
 
guidance contained in NUREG-1800, A Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants,@ Revision 1, Section 2.1, A Scoping and Screening Methodology
@ (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 identification of plant SSCs within the scope of the Rule
* 10 CFR 54.4(b), as it relates to identification of 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 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 has described a process for identifying SSCs that are within the scope of license renewal, as required by 10 CFR 54.4(a)
* Section 2.2, to ensure that the applicant has described a process for determining the SCs that are subject to an AMR as required by 10 CFR 54.21(a)(1) and (a)(2)
In addition, the staff conducted a scoping and screening methodology audit at SSES, located outside Berwick, Pennsylvania, during the week December 11-15, 2006. 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. Also, the staff conducted detailed discussions with the applicant on the implementation and control of the 2-3 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 also reviewed training for personnel that developed the LRA and quality practices used by
 
the applicant to develop the LRA. Further, the staff evaluated the quality attributes of the
 
applicant=s Aging Management Program (AMP) activities described in LRA Appendix A, A Final Safety Analysis Report Supplement,@ and Appendix B, A Aging Management Programs.
@ The staff also reviewed the training and qualification of the applicant's LRA development team. The staff reviewed scoping and screening results reports for the main steam (MS) system and the
 
turbine building (TB) to ensure that the applicant had appropriately implemented the
 
methodology outlined in the administrative controls and that the results were consistent with the
 
current licensing basis (CLB) documentation. 
 
2.1.3.1  Implementation Procedures and Documentation Sources for Scoping and Screening  The staff reviewed the applicant's scoping and screening implementing procedures as
 
documented in the audit report, dated May 24, 2007, to verify that the process used to identify
 
structure and component (SC)s subject to an AMR was consistent with the in information
 
contained in 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 adequately implemented the procedural
 
guidance during the scoping and screening process.
 
2.1.3.1.1  Summary of Technical Information in the Application 
 
In LRA Section 2.1, A Scoping and Screening Methodology,@ the applicant reviewed the following information sources during the license renewal scoping and screening process:
* Maintenance Rule Data Base
* Updated Final Safety Analysis Report (UFSAR)
* Design basis references
* Piping & Instrumentation Diagrams (P&IDs)
* Electrical drawings
* Docketed correspondence
* Technical Specifications (TSs) and Bases
* Technical Requirements Manual
* Individual Plant Examination (IPE)
* Individual Plant Examination of External Events (IPEEE)
 
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(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 structures
 
and components subject to an AMR.
 
2.1.3.1.2  Staff Evaluation 
 
Scoping and Screening Implementing Procedures. The staff reviewed the applicant
=s scoping and screening methodology implementing procedures, including license renewal guidelines, documents, reports, and AMR reports, as documented in the audit report, to ensure the 2-4 guidance was consistent with the requirements of the Rule, the SRP-LR, and NEI 95-10, A Industry Guidelines for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule,@ Revision 6. The staff found the overall process to implement the 10 CFR Part 54 requirements described in the implementing documents and AMRs was consistent with the Rule, SRP-LR and industry guidance. Guidance for determining plant SSCs
 
within the scope of the Rule, including determining which component types of the SCs within the
 
scope of license renewal were subject to an AMR, were contained in the 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 staff positions documented in the SRP-LR, and information in the staff's request for addition information (RAI) responses dated April 17, 2007.
 
After reviewing the LRA and supporting documentation, the staff found that the scoping and
 
screening methodology instructions were consistent with the applicant's description of the
 
methodology contained in LRA Section 2.1. 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 staff requirements applicable to a specific plant
 
and a licensee's written commitments for ensuring compliance with, and operation within, applicable staff requirements and the plant-specific design bases that are docketed and in
 
effect. The CLB includes certain NRC regulations, orders, license conditions, exemptions, TSs, design-basis information documented in the most recent UFSAR, and licensee commitments
 
remaining in effect and made in docketed licensing correspondence such as licensee responses
 
to NRC bulletins, generic letters, and enforcement actions, as well as licensee 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 basis references, P&IDs, electrical drawings, docketed correspondence, TSs and bases, the fire hazards
 
analysis, safety evaluations, and design documentation such as engineering calculations and
 
design specifications. The staff verified that the applicant
=s detailed license renewal program guidelines required use of the CLB source information in developing scoping evaluations. 
 
The SSES component database is the applicant
=s primary repository for component safety classification information. During the audit, the staff reviewed the applicant
=s administrative controls for SSES component database safety classification data. These controls are described and implementation is governed by plant administr ative procedures. Based on a review of the administrative controls, and a sample of the SSES component database safety classifications, the staff concluded that the applicant has established adequate measures to control the integrity
 
and reliability of SSES component database safety classification data and; therefore, concluded
 
that the SSES component database provided a sufficiently controlled source of component data
 
to support scoping and screening evaluations.
 
During the staff
=s review of the applicant
=s CLB evaluation process, the applicant explained the 2-5 incorporation of updates to the CLB and the process used to ensure those updates are adequately incorporated into the license renewal process. The staff determined that LRA
 
Section 2.1 provided a description of the CLB and related documents used during the scoping
 
and screening process that is consistent with the guidance contained in the SRP-LR. In
 
addition, the staff reviewed technical reports the applicant used to support identification of SSCs
 
relied upon to demonstrate compliance with the safety-related criteria, nonsafety-related criteria, as well as the five regulated events pursuant to 10 CFR 54.4(a)(1-3). The applicant's license
 
renewal program guidelines provided a comp rehensive listing of documents used to support scoping and screening evaluations. The staff found these design documentation sources 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 its review of information in LRA Section 2.1, a review of the applicant's detailed
 
scoping and screening implementing 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 guidance contained in the SRP-LR and
 
NEI 95-10, and met the requirements of 10 CFR 54.4, 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 applicant's quality controls to ensure that scoping and screening
 
methodologies used in the LRA were adequately implemented. The staff found that the
 
applicant applied the following quality assurance (QA) processes during LRA development:
* The applicant developed a project plan which was the QA guide implemented for preparation of the LRA.
* Implementation of the scoping and screening methodology was governed by written procedures. A tracking system was implemented to account for the dates that
 
procedures were originally issued and for subsequent revisions.
* The applicant reviewed previous staff RAIs to ensure that applicable issues were addressed in the LRA.
* The SSES QA Committee performed an independent assessment of the LRA to verify that it was developed in accordance with the requirements of 10 CFR Part 54.
* The LRA was subjected to a peer review prior to submittal to the staff.
* The LRA was reviewed by the Off-Site Review Committees prior to submittal to the staff.
 
2.1.3.2.2  Conclusion 
 
On the basis of its review of information in LRA Section 2.1 and discussion with the applicant
=s license renewal staff, and a review of quality assessment documents, the staff concludes that the QA activities meet current regulatory requirements and provide assurance that LRA
 
development activities were consistently performed with the applicant
=s license renewal program requirements.
2-6  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 were applied in a consistent and appropriate manner. The license renewal project plan included the training requirements for the personnel who developed
 
the LRA and indicated the level of training appropriate to the license renewal task being
 
performed.
 
Training was required for the license renewal project personnel that included the contract
 
personnel who prepared the application and the applicant
=s personnel who reviewed the application. The training was designed to vary depending on the level of the person
=s involvement and responsibility. As described above, the applicant
=s training guidelines specified the level of training required for the various groups participating in development of the LRA. The training consisted of a combination of reading and attending training sessions and was
 
documented on a qualification card. All license renewal personnel were required to review
 
applicable license renewal regulations, NEI 95-10 and associated procedures. The training also
 
included initial training for the applicant
=s personnel and the contract personnel for project definition activities, process training for production of documents, subsequent training to the applicant=s personnel to review the deliverables, and general training for the applicant
=s management and plant operations review committ ee and others involved in the development of the LRA. In addition, the applicant held periodic production meetings in which the license
 
renewal project team members shared their k nowledge and experience of a given subject with the team. Training material was developed to include lessons learned during the development of
 
the SSES LRA and previous license renewal projects. The staff reviewed completed
 
qualification and training records of several of the applicant's license renewal personnel and
 
also reviewed completed check lists. 
 
2.1.3.3.2  Conclusion 
 
On the basis of its discussions with the applicant
=s license renewal project personnel responsible for the scoping and screening process, and a review of selected design documentation in support of the process, the staff concludes that the applicant
=s staff and contractor personnel understand the requirements and has adequately implemented the scoping and screening methodology established in the applicant
=s renewal application. The staff did not identify any concerns regarding the training of the applicant
=s license renewal project personnel.
2.1.3.4  Conclusion of Scoping and Screening Program Review On the basis of its review of information provided by the applicant in LRA Section 2.1, a review
 
of the applicant
=s detailed scoping and screening implementing procedures, discussions with the applicant
=s license renewal personnel and the results from the scoping and screening audit, the staff concludes that the applicant
=s scoping and screening program is consistent with the guidance contained in the SRP-LR and; therefore, is acceptable.
2.1.4  Plant Systems, Structures, and Components Scoping Methodology
 
2-7 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 systems 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 from the SSES Maintenance Rule Database
 
and confirmed using the Nuclear Informat ion Management System database and the FSAR.
The structures list was reviewed against site civil/structural and plant layout drawings. The
 
license renewal evaluation boundaries include those portions of the SSCs that are necessary to
 
ensure that the intended functions will be performed. Structures and components needed to
 
support each of the system and/or structure-level intended functions identified in the scoping
 
process are included within the evaluation boundary. The applicant
=s scoping methodology, as described in the LRA, is discussed in the sections below.
2.1.4.1  Application of the Scoping Criteria in 10 CFR 54.4(a)(1) 2.1.4.1.1  Summary of Technical Information in the Application 
 
LRA Section 2.1.1.1, A Safety-Related Scoping,@ describes the scoping methodology as it relates to the safety-related requirements of 54.4(a)(1). With respect to the safety-related criterion, the applicant stated that the safety-related systems and structures are initially identified based on a review of the Maintenance Rule Database, then confirmed using Nuclear Information
 
Management System and the FSAR, system design-basis documents (DBDs), P&IDs, and SSES design standards. Systems and structures whose intended functions met one or more of
 
the requirements of 10 CFR 54.4(a)(1) were included within the scope of license renewal. The
 
staff confirmed that all plant conditions, including conditions of normal operation, design-basis
 
accidents (DBAs), external events, and natural phenomena for which the plant must be
 
designed, were considered for license renewal scoping in accordance with 10 CFR 54.4(a)(1)
 
criteria. 
 
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: (a) the integrity of the reactor coolant pressure boundary; (b) the ability to shut down
 
the reactor and maintain it in a safe-shutdown condition; or (c) the 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), 50.67(b)(2), or 100.11.
 
With regard to identification of DBEs, SRP-LR Section 2.1.3 states:
 
The set of DBEs as defined in the Rule is not limited to Chapter 15 (or
 
equivalent) of the UFSAR. Examples of DBEs that may not be described in this
 
chapter include external events, such as floods, storms, earthquakes, tornadoes, or hurricanes, and internal events, such as a high energy line break. Information
 
regarding DBEs as defined in 10 CFR 50.49(b)(1) may be found in any chapter
 
of the facility UFSAR, the Commission's regulations, NRC orders, exemptions, or license conditions within the CLB. These sources should also be reviewed to
 
identify SSCs relied upon to remain functional during and following DBEs (as 2-8 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, DBAs, external events and natural phenomena) that were applicable to SSES. The applicant identified the documents that described the events, all
 
of which are contained in the UFSAR, with the exception of fire, which is contained in separate
 
documentation. The applicant also reviewed the IPE and the IPEEE, as well as licensing
 
correspondence and DBDs. The applicant stated that as a result of this review, no additional
 
systems were identified and included within the scope license renewal. The staff concludes that
 
the applicant
=s evaluation of DBEs was consistent with the guidance contained in the SRP-LR.
The applicant performed scoping of SSCs pursuant to 10 CFR 54.4(a)(1) criterion in accordance
 
with the license renewal procedure guidelines which provide guidance for the preparation, review, verification, and approval of the scoping evaluations to assure the adequacy of the
 
results of the scoping process. The staff reviewed these guidance documents governing the
 
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.
 
Specifically, the staff reviewed a sample of the license renewal scoping results for the MS
 
system, the engineered safeguards (ES) servic e water pumphouse, and the TB to provide additional assurance that the applicant adequately implemented its scoping methodology in
 
accordance with 10 CFR 54.4(a)(1). The staff verified that the 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
 
within scope, in accordance with 10 CFR 54.4(a)(1).
 
The staff reviewed the applicant
=s evaluation of the Rule and CLB definitions pertaining to 10 CFR 54.4(a)(1). The SSES CLB definition of safety-related is not identical to the definition provided in the Rule. The applicant
=s definition of safety-related and exceptions to the definition in the Rule are documented in LRA Section 2.1.1.1. Based on its review, the staff confirms that 10 CFR 50.34(a)(1) is not applicable to SSES as this regulation pertains to applications for a
 
construction permit and 10 CFR 50. 67(b)(2) is applicable to plants using an alternate source
 
term. The staff noted that SSES has submitted a license amendment request, to the staff, (which was issued by letter dated January 31, 2007) to allow the use of an alternative source
 
term for accident analyses in accordance with the requirements of 10 CFR 50.67(b)(2) and has
 
conservatively included all SSCs which would be affected by the license amendment within the
 
scope of license renewal. In addition, the applicant stated that certain components located in
 
the TB do not have an intended function but are classified by SSES as safety-related and
 
included within the scope of license renewal, in accordance with 10 CFR 54.4(a)(1). However, the staff notes that this process is not articulated by the applicant in the LRA nor is it
 
documented in the license renewal procedures or guidelines. The staff
=s review of LRA Section 2.1.1 identified areas in which additional information was necessary to complete the review of the applicant
=s scoping and screening methodology.
In RAI 2.1-1, dated March 9, 2007, the staff requested that the applicant provide a written 2-9 evaluation that addresses the impact, if any, of the use of differing definitions of safety-related and of not having explicitly considered in its scoping methodology for SSES, those structures, systems, or components that are relied upon to ensure "the capability to prevent or mitigate the
 
consequences of accidents that could result in potential offsite exposures comparable to the
 
guidelines in 10 CFR 50.34(a)(1), 50.67(b)(2), or 100.11 of this chapter, as applicable,"
consistent with the CLB for SSES.
 
In the response to RAI 2.1-1, dated April 17, 2007, the applicant stated that the SSES source
 
documents used for 10 CFR 54.4(a)(1) scoping include differing definitions of safety-related
 
pertaining to the offsite exposure limits of 10 CFR 50.34(a)(1), 50.67(b)(2), and 100.11. The
 
offsite exposure criterion is included in the safety-related definition used in each of the source
 
documents, but refers only to the limits of 10 CFR Part 100. The applicant stated that
 
10 CFR 50.34(a)(1) is associated with facilities seeking a construction permit and therefore is
 
not applicable to SSES license renewal and the dose guidelines of 10 CFR 50.67(b) are
 
associated with accident source term limits which were not applicable to SSES, when the LRA
 
was submitted. The applicant evaluated the variations in the safety-related definitions and
 
concluded that there is no impact on the 10 CFR 54.4(a)(1) scoping performed for the LRA. 
 
Based on its review, the staff finds the applicant
=s response to RAI 2.1-1 acceptable because the applicant has adequately evaluated the differing definitions of safety-related contained in its scoping source documents pertaining to the offsite exposure criterion. The staff concludes that
 
there was no impact on the applicant's ability to accurately identify SSCs within the scope of
 
license renewal, in accordance with the requirements of 10 CFR 54.4(a)(1). Therefore, the
 
staff=s concern described in RAI 2.1-1 is resolved.
In RAI 2.1-2, dated March 9, 2007, the staff requested that the applicant discuss the process
 
and rationale by which it determined that certain nonsafety-related components were within the
 
scope of license renewal in accordance with 10 CFR 54.4(a)(1). In addition, the staff requested
 
that the applicant discuss how it reviewed other nonsafety-related SSCS for potential interaction
 
(10 CFR 54.4(a)(2)) with the nonsafety-related components located within the TB, which have
 
been included within the scope of license renewal pursuant to 10 CFR 54.4(a)(1).
 
In the response to RAI 2.2-2, dated April 17, 2007, the applicant stated that the SSES design
 
bases states that not all equipment designated as "Q"-class, performs a safety-related function.
 
PPL Design Standard GDS-06 states that "Q" items are either safety-related or are to be "treated as safety-related" under the Operati onal QA Program, even though they do not perform or prevent the performance of the safety-related function. To maintain consistency with normal
 
plant practices, the set of SSCs that satisfy the 10 CFR 54.4(a)(1) criteria conservatively
 
includes those components designated as "Q" that are "treated as safety-related", without
 
performing a safety-related function. Although, certain pressure switches located in the TB are
 
designated "Q" in accordance with normal plant operations and were included within the scope
 
of license renewal in accordance with 10 CFR 54.4(a)(1), the component
=s do not have a safety-related function. The SSES CLB indicates that there are no components that perform a safety-related function located in the TB. Because the CLB establishes that there is no
 
safety-related equipment in the TB, there would be no potential interaction (10 CFR 54.4(a)(2))
 
with the nonsafety-related components located within the TB.
 
Based on its review, the staff finds the applicant
=s response to RAI 2.1-1 acceptable because the applicant has provided a rationale for including the nonsafety-related SCs within the scope of license renewal in accordance with 10 CFR 54.4(a)(1), as consistent with normal plant 2-10 operations. The staff determines that there are no safety-related SSCs within the TB such that there can be no potential nonsafety-related affecting safety-related interactions. Therefore, the
 
staff=s concern described in RAI 2.1-2 is resolved.
2.1.4.1.3  Conclusion 
 
On the basis of its review of sample systems, discussions with the applicant, and review of the
 
applicant's scoping process, the staff concludes that the applicant's methodology for identifying
 
systems and structures is consistent with the scoping criteria pursuant to 10 CFR 54.4(a)(1)
 
and; therefore, is acceptable.
2.1.4.2  Application of the Scoping Criteria in 10 CFR 54.4(a)(2) 2.1.4.2.1  Summary of Technical Information in the Application 
 
In LRA Section 2.1.1.2, A Nonsafety-Related SSCs Affecting Safety-Related SSCs Scoping,@ 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 (a)(2) scoping methodology was based on guidance provided in Appendix F of NEI 95-10, Revision 6. The applicant evaluated the impacts of nonsafety-related SSCs that met 10 CFR 54.4(a)(2) criteria by using two major
 
categories: 1) functional failure, and 2) physical failure. A summary description of these two
 
categories is provided below.
 
Functional Failure of Nonsafety-Related SSCs. LRA Section 2.1.1.2.1, A Functional Failures of Nonsafety-Related SSC,@ stated that SSCs required to perform a function in support of safety-related components are classified as safety-related and are included in the scope of license renewal in accordance with 10CFR 54.4(a)(1). SSCs required to remain functional in
 
support of safety-related components were included within the scope of license renewal in
 
accordance with the requirements of 10 CFR 54.4(a)(2). Engineering and licensing documents
 
were reviewed to determine the appropriate systems and structures in this category. The
 
applicable sections of the FSAR, Maintenance Rule Database, and design basis references
 
provide the system and structure functional in formation to address these considerations.
Systems, structures, and components that per form nonsafety-related intended functions credited in the current licensing basis and are subject to an AMR are identified in Sections 2.3, 2.4, and 2.5 of the LRA. In addition, nonsafety-related SSCs identified in the SSES alternate
 
source term analyses have been included within the scope of license renewal in accordance
 
with 10 CFR 54.4(a)(2).
 
Nonsafety-Related SSCs with the potential for spatial Interaction with Safety-Related SSCs. LRA Section 2.1.1.2.2, A Spatial Failures of Nonsafety-Related SSCs,@ states that nonsafety-related systems and nonsafety-relat ed 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 are defined as failures of nonsafety-related SSCs that
 
are connected to or located in the vicinity (same building) of safety-related SSCs creating the
 
potential for interaction between the SSCs due to physical impact, harsh environment, flooding, spray or leakage that could impede or prevent the accomplishment of the safety-related
 
functions of a safety-related SSC. 
 
Certain mitigative features, such as missile barriers, flood barriers, and spray shields, are
 
credited in the current licensing basis for the protection of safety-related SSCs from spatial 2-11 interaction. These protective features are included within the scope of license renewal and evaluated as structural components. 
 
In addition, SSES used the preventive option described in Appendix F of NEI 95-10 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 current licensing basis. This scoping
 
process required an evaluation based on equipment location and the related SSCs and whether
 
fluid-filled system components are located in t he same building or miscellaneous area as safety-related equipment, unless justification is prov ided that failures would not impact a safety function. Consistent with the related industry discussions in NEI 95-10, Appendix F, failure of
 
nonsafety-related components that do not contain a fluid would not result in spatial interaction
 
as there is no fluid to leak or spray onto safety-related SSCs and system pressure is such that
 
there is no force that could cause significant movement of the failed component. This
 
conclusion is confirmed by review of SSES and industry operating experience.
 
Nonsafety-Related SSCs directly connected to Safety-Related SSCs. The LRA stated that for nonsafety-related piping that is directly connected to safety-related piping, the seismic Category
 
I design requirements are extended to the first seismic restraint beyond the defined boundaries (the nonsafety-related and safety-related interface). The seismic design is extended to the first
 
point in the system which can be treated as an anchor to the plant structure. An anchor support
 
is defined in SSES piping design specifications as a rigid support that restrains all 6 degrees of
 
motion of the piping system. Anchors can include large fixed equipment such as pumps, tanks, heat exchangers, and in some cases, larger piping. The nonsafety-related structural
 
components in the scope of license renewal include those that comprise seismic anchors. All
 
seismic anchors and the associated piping and components for nonsafety-related to
 
safety-related interfaces are within the scope of license renewal under 10 CFR 54.4(a)(2) using
 
the base-mounted equipment and flexible connection options from NEI 95-10 (Reference 2.1-1), Appendix F, as well as including the entire length of piping that is connected on both ends to
 
safety-related piping.
 
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 accomplishment of safety-related SSCs relied upon to remain
 
functional during and following a DBE to ensure the following functions: (a) the integrity of the
 
reactor coolant pressure boundary; (b) the ability to shut down the reactor and maintain it in a
 
safe-shutdown condition; or (c) the 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), 50.67(b)(2), or 100.11.
 
Regulatory Guide (RG) 1.188, A Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses,@ Revision 1, dated September 2005, provided staff endorsement on the use of NEI 95-10, A Industry Guidelines for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule,@ Revision 6, dated June 2005. RG 1.188 states that NEI 95 -10, Revision 6, provides methods that the staff considers acceptable for compliance with 10 CFR Part 54, when preparing a license renewal application. NEI 95 -10, Revision 6, discusses the staff position on 10 CFR 54.4(a)(2) scoping criteria; nonsafety-related
 
SSCs, typically identified in the CLB; consideration of missiles, cranes, flooding, high-energy
 
line breaks (HELBs); nonsafety-related SSCs connected to safety-related SSCs; nonsafety-
 
related SSCs in proximity of safety-related SSCs; and the mitigative and preventative options 2-12 related to nonsafety-related and safety-related SSCs interactions. 
 
In addition, the staff position on NEI 95-10, Revision 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. The paper further describes operating experience as all documented plant-specific and industry-wide experience
 
that can be used to determine the plausibility of a failure. Documentation would include NRC
 
generic communications and event reports, plant-s pecific condition reports, industry reports such as safety operational event reports, and engineering evaluations.
 
The staff reviewed LRA Section 2.1.1.2, where the applicant described its scoping methodology
 
as it related to the nonsafety-related criteria in accordance with 10 CFR 54.4(a)(2). In addition, the staff reviewed the applicant's 10 CFR 54(a)(2) AMR report. The staff noted that the
 
applicant=s evaluations were performed in accordance with the guidance contained in NEI 95-10, Revision 6, for identification and treatment of SSCs which meet 10 CFR 54.4(a)(2) criteria. Also, as described in LRA Section 2.1.4.2.1, the applicant
=s evaluation of the nonsafety-related SSCs to meet 10 CFR 54.4(a)(2) criteria is based on categories of functional failure and physical failure. 
 
Based on its review of the information provided by the applicant in the LRA, 10 CFR 54.4(a)(2)
 
AMR report criteria, and the discussions with the applicant during the audit, the staff
=s evaluation pertaining to the categories described in paragraph two of this subsection immediately follows.
 
Nonsafety-Related SSCs Required to Perform a Function that Supports a Safety-Related SSC. 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)(2). This evaluating criteria was discussed in the applicant
=s 10 CFR 54.4(a)(2) AMR report. The staff finds that the applicant has 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 SSC
: s. In order to identify the nonsafety-related SSCs directly connected to safety-related SSCs and required to be
 
structurally sound to maintain the integrity of the safety-related SSCs, the applicant used a
 
bounding approach as described in NEI 95-10, Appendix F and the SSES seismic analysis. The
 
applicant reviewed each mechanical system safety-related to nonsafety-related interface to
 
identify the components located between the interface and the structural boundary or equivalent
 
anchor, if used. The applicant included all nonsafety-related SSCs within the analyzed structural
 
boundary and within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2). If the
 
structural boundary was not indicated on the applicable drawing, the applicant identified the
 
portion of the nonsafety-related SSCs beyond the safety-related SSCs, to the first equivalent
 
anchor or seismic anchor, and included this portion of the nonsafety-related SSCs within the
 
scope of license renewal.
 
The applicant also indicated in the LRA that if the structural boundary could not be identified for
 
the applicable nonsafety-related/safety-related interface, the nonsafety-related SSCs were
 
included to a point beyond the nonsafety-related/safety-related interface to a base-mounted
 
component, flexible connection, or the end of the piping run. The applicant based its actions on
 
the guidance of NEI 95-10, Appendix F, which describes the use of A bounding criteria
@ as a 2-13 method of determining the portion of nonsafety-related SSCs to be included within the scope of license renewal.
This provided assurance that the nonsafety-related piping systems included in the design-basis seismic analysis are included in the scope of license renewal. The applicant
=s identification of these nonsafety-related sy stems and components at nonsafety-related to safety-related boundary is depicted in its 10 CFR 54.4(a)(2) AMR report. Also listed in this
 
report are the AMR results of the component types with the corresponding intended function, material, environment, and aging effects and associated programs. In addition, the staff noted
 
that the applicant stated in LRA Sections 2.3.3.2, 2.3.3.5, 2.3.3.9, 2.3.3.23, and 2.3.3.31, certain
 
components (e.g., accumulator, tank, heating and ventilation units) perform an anchor function, but are not subject to an AMR based on evaluation of their construction, mounting and support
 
function.
 
The staff=s review of LRA Section 2.1.1.2.2 identified that the applicant had not included nonsafety-related piping attached to safety-related SSCs located within containment or nonsafety-related piping attached to safety-related piping at containment penetrations within the
 
scope of license renewal. In addition, the applicant used an analysis, in lieu of it
=s documented screening process, to determine whether nonsafety-related components affecting safety-related components, as discussed in LRA Sections 2.3.3.2, 2.3.3.5, 2.3.3.9, 2.3.3.23 and 2.3.3.31, were
 
subject to an AMR. The staff determined that additional information would be required to
 
complete the review of the applicant
=s scoping methodology.
In RAI 2.1-3, dated March 9, 2007, the staff requested that the applicant explain the following: 
 
(a) The rationale and basis for not including nonsafety-related piping attached to safety-related piping at containment penetrations and extending outside of
 
containment, within the scope of license renewal (b) The rationale and basis for not including nonsafety-related piping attached to safety-related SCs inside containment, within the scope of license renewal (c) The rationale for the use of an analysis to determine that nonsafety-related SCs within the scope of license renewal were not subject to an AMR, the details and
 
results of the analysis, and to indicate how the applicant's analysis met the
 
criteria of the screening process used for other nonsafety-related SCs and the
 
requirements of 10 CFR 54.21
 
In its response to RAI 2.1-3, dated April 17, 2007, the applicant stated: 
 
(a) The applicant had performed a re-evaluation and determined that certain nonsafety-related components attached to safety-related piping at containment
 
penetrations and extending outside of containment, had not been included within
 
the scope of license renewal. The applicant indicated that the nonsafety-related
 
components are connected to, and provide support for, the attached safety-
 
related equipment and have subsequently been included within the scope of
 
license renewal as required by 10 CFR 54.4(a)(2). The applicant provided a list
 
of the nonsafety related equipment which had been included within the scope of
 
license renewal and the results of the aging management reviews.
(b) The applicant had performed a re-evaluation which identified nonsafety-related equipment, inside primary containment, that is connected to safety-related 2-14 equipment and provides the anchor for the safety-related equipment, that had not been included within the scope of license renewal. The applicant indicated that
 
the nonsafety-related equipment has subsequently been included within the
 
scope of license renewal as required by 10 CFR 54.4(a)(2). The applicant
 
provided a list of the nonsafety-related equipment which had been included
 
within the scope of license renewal and the results of the aging management
 
reviews.  (c) The applicant had determined that certain nonsafety-related components attached to safety-related SSCs and which had been included within the scope of
 
license renewal, had not been subject to an aging management review. The
 
applicant performed an evaluation to determine the extent of condition and
 
subsequently performed the required aging management reviews. The applicant
 
provided a list of the components determined to be subject to an aging
 
management review and the results of the aging management reviews.
 
Based on its review, the staff finds the applicant=s response to RAI 2.1-3 acceptable because
 
the applicant had performed evaluations to determine if nonsafety-related SCs should be
 
included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2) and if aging
 
management reviews were required. The applicant's evaluations, as documented in the RAI
 
response, resulted in (1) the inclusion of nonsafety-related components, attached to safety-
 
related piping at containment penetrations and extending outside of containment within the
 
scope of license renewal; (2) the inclusion of  nonsafety-related equipment, inside primary
 
containment, that is connected to safety-related equipment and provides the anchor for the
 
safety-related equipment within the scope of license renewal; and (3) the performance of aging
 
management reviews of nonsafety-related co mponents attached to safety-related SSCs and which had been included within the scope of license renewal, but which had not been previously
 
subject to an aging management review. The staff determined that the nonsafety-related
 
components, discussed in RAI 2.1-3, has been appropriately evaluated for inclusion within the
 
scope of license renewal and subjected to aging management review and that the staff's
 
concern in RAI 2.1-3 is resolved.
 
Nonsafety-Related SSCs with the Potential for Spatial Interaction with Safety-Related SSCs. The applicant considered physical impact (i.e , pipe whip, jet impingement), harsh environments, flooding, spray, and leakage when evaluating the potential for spatial interactions between
 
nonsafety-related systems and safety-related SSCs. The applicant used a spaces approach for
 
scoping of nonsafety-related systems with potential spatial interaction with safety-related SSCs.
 
The spaces approach focused on the interaction between nonsafety-related and safety-related
 
SSCs that are located in the same space, which was defined as a building which contains
 
safety-related SSCs. The space was defined such that any potential interaction between
 
nonsafety-related and safety-related SSCs is limited to the space.
 
Physical Impact or Flooding. The applicant considered situations where nonsafety-related supports for non-seismic (including seismic II/I) piping systems and electrical conduit and cable
 
trays with potential for spatial interaction with safety-related SSCs are included in the scope of
 
license renewal per the Rule and subject to an AMR. These supports and components are
 
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 2-15 to flow accelerated corrosion. Furthermore, the piping section itself was determined not to be in-scope for 10 CFR 54.4(a)(2), due to a physical impact hazard. The applicant evaluated
 
whether missiles could be generated from internal or external events such as failure of rotating
 
equipment or overhead-handling systems. The nonsafet y-related design features which protect safety-related SSCs from such missiles were included within the scope of license renewal. 
 
Pipe Whip, Jet Impingement, and Harsh Environment. The applicant evaluated nonsafety-related portions of high energy lines against the 10 CFR 54.4(a)(2) criteria. The
 
applicant=s evaluation was based on a review of the FSAR and relevant site documentation. The applicant evaluated the high energy systems to ens ure proper identification 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 (i.e., piping, equipment and supports) was included within the scope of license renewal pursuant to 10 CFR 54.4(a)(2)
 
criteria and subject to and AMR, in order to provide reasonable assurance that those
 
assumptions remain valid through the period of extended operation. Also, as discussed in the
 
SSES AMR report for 10 CFR 54.4(a)(2) review, the applicant reviewed the reference
 
documents that contained HELB analysis for inside as well as outside containment and
 
identified high energy lines. Many of the ident ified systems were safety-related 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 potential interaction with
 
safety-related SSCs, were included within the scope of license renewal.
 
Spray and Leakage. The applicant evaluated moderate and lo w-energy systems which have the potential for spatial interactions of spray and leakage. Nonsafety-related systems and
 
nonsafety-related portions of safety-related systems with the potential for spray or leakage that
 
could prevent safety-related SSCs from perfo rming their required safety function were considered within the scope of license renewal. The applicant used a spaces approach to
 
identify the nonsafety-related SSCs which were located within the same space as safety-related
 
SSCs. As described by the applicant in the LRA, a space is defined as a building containing
 
safety-related SSCs. The space is defined such that any potential interaction between
 
nonsafety-related and safety-related SSCs is limited to the space. The applicant documented its
 
review of each mechanical system for potential spatial interaction with safety-related SSCs in
 
applicant=s scoping results AMR review report, which also is documented in the audit report.
Following identification of the applicable mechanical systems, the applicant reviewed the system functions to determine whether the system contained fluid, air or gas. Based on the
 
spray or leakage and also operating experience, the applicant excluded the nonsafety-related
 
SSCs containing air or gas from the scope of license renewal. The applicant then reviewed the
 
mechanical systems to determine whether the system had any components located within a structure containing safety-related SSCs. Those nonsafety-related SSCs determined to contain
 
fluid and located within a space containing safety-related SSCs, were included within the scope
 
license renewal. 
 
Protective Features. The applicant evaluated protective features such as whip restraints, spray shields, supports, and 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.
 
2.1.4.2.3  Conclusion 2-16  On the basis of its review of sample systems, discussions with the applicant, and review of the
 
applicant's scoping process, the staff concludes that the applicant's methodology for identifying
 
systems and structures is consistent with the scoping criteria of 10 CFR 54.4(a)(2) and;
 
therefore, is acceptable.
 
2.1.4.3  Application of the Scoping Criteria in 10 CFR 54.4(a)(3) 2.1.4.3.1  Summary of Technical Information in the Application 
 
In LRA Section 2.1.1.3, A Regulated Events Scoping,@ the applicant described the methodology for identifying systems and structures that are in the scope of license renewal based on the regulated events criteria. The SSCs that perform intended functions required for compliance
 
with a regulated event and subject to an AMR are identified in LRA Sections 2.3, 2.4, and 2.5.
 
Mechanical and structural systems that perform a fire protection, anticipated transients without
 
scram (ATWS), and/or station blackout (SBO) intended function are included in the scope of
 
license renewal. All plant electrical and instrum entation and control (I&C) systems and electrical equipment in mechanical systems were included in-scope of license renewal.
Fire Protection. In LRA Section 2.1.1.3.1, A Fire Protection (10 CFR 50.48),@ the applicant described the scoping of mechanical systems and structures required to demonstrate compliance with the fire protection requirements. In the LRA, the applicant stated that the SSES
 
was licensed after January 1, 1979 and is therefore not bound to the provisions of
 
10 CFR 50.48(b). However, as a result of licensing commitments and standard fire protection
 
licensing condition for plants licensed after January 1, 1979, the SSES generated a Fire
 
Protection Review Report which addresses compliance with pertinent regulations. The
 
applicant=s CLB includes the Fire Protection Review Report, which contains a safe-shutdown analysis (to demonstrate compliance with Appendix R), description of the fire protection system, the fire hazard analysis (to demonstrate that a single postulated fire will not affect the ability of
 
both units to be brought to and maintained in cold shutdown condition), and any deviation
 
requirements. Section 2.1.1.3.1 further states, based on its review of its CLB for fire protection, the applicant identified systems and structures and determined the corresponding intended
 
functions that meet the requirements of 10 CFR 50.48 in addition to 10 Part 50, Appendix R.
 
This determination included both the features required for fire protection of safety-related
 
equipment and any system function that was incl uded in, or provides necessary support for, one or more of the three safe-shutdown paths credited for compliance with 10 CFR Part 50, Appendix R. Mechanical systems and structures credited with fire prevention, detection, mitigation in areas containing equipment important to safe operation of the plant, and equipment
 
credited with safe-shutdown in the event of a fire were included within the scope of license
 
renewal. 
 
Environmental Qualification (EQ). The applicant described the EQ requirements of 10 CFR 50.49 in LRA Section 2.1.1.3.2, A Environmental Qualification (10 CFR 50.49).
@ The electrical equipment at SSES, which is required to be environmentally qualified for a A harsh@ environment by 10 CFR 50.49, is identified in the SSES - Nuclear Information Management System database. In the LRA, the applicant stated that EQ at SSES applies to electrical
 
equipment installed in mechanical systems, inst ruments or valve operators in a fluid system, and also the electrical equipment installed in elec trical systems. Electrical equipment that is required to be environmentally qualified is identified to be within the scope of license renewal.
 
2-17 Pressurized Thermal Shock. These requirements are not applicable because SSES units are of boiling-water reactor (BWR) design.
 
Anticipated Transient Without Scram. The applicant described the scoping of mechanical systems and structures required to demonstrate compliance with the ATWS requirements of 10 CFR 50.62 in LRA Section 2.1.1.3.4, A Anticipated Transients without Scram (10 CFR 50.62).
@ Mechanical systems and structures that perform a 10 CFR 50.62 intended function were included within the scope of license renewal. 
 
Station Blackout. The applicant described the scoping criteria in LRA Section 2.1.1.3.5, A Station Blackout (10 CFR 50.63).
@ The applicant
=s licensing basis requires an SBO coping duration of four hours, and therefore the mechanical systems and structures required to support the four-hour coping duration are included within the scope of license renewal. The applicant stated
 
that, at SSES, all plant equipment which includes systems and instrumentation necessary to
 
cope with the SBO was identified and investigated to assure that all items necessary for the
 
equipment to function would be available for at least four-hours. This is the equipment relied
 
upon for compliance with 10 CFR 50.63 requirements. Also, the applicant stated that based on
 
its CLB for SBO, the intended functions for each system and structure supporting the
 
10 CFR 50.63 requirements were determined, and the SSCs that perform an intended function
 
for SBO were included in the scope of license renewal.
 
2.1.4.3.2  Staff Evaluation 
 
The staff reviewed the applicant
=s approach to identifying the mechanical systems and structures relied upon to perform functions related to regulated events applicable to BWRs in accordance with 10 CFR 54.4(a)(3). As part of this review and during its scoping and screening
 
audit at SSES, the staff discussed the methodology with the applicant, reviewed the
 
documentation developed to support the license renewal, and evaluated a sample of the
 
resultant mechanical systems and structures identified as within scope pursuant to
 
10 CFR 54.4(a)(3) criteria. The staff
=s review of the applicant
=s documentation included, but was not limited to: (a) license renewal project guidelines, (b) license renewal project documents, (c) plant drawings, (d) UFSAR, (e) maintenance rule design basis documentation, and (f) the
 
applicant's Fire Protection Review Report. 
 
The license renewal project guidelines described the applicant
=s process for identifying systems and structures that are within the scope of license renewal. As described in the license renewal project guidelines, all mechanical systems and structures that perform an intended function
 
pursuant to 10 CFR 54.4(a)(3), were included within the scope of license renewal, and the
 
results of scoping are documented in the applicant
=s license renewal project document scoping results reports. The license renewal project documents stated that the scope of license renewal includes all SSCs relied on in safety analyses or plant evaluations to perform a function that
 
demonstrates compliance with the 10 CFR 54.4(a)(3) regulated events. The staff reviewed the
 
applicant=s evaluation of mechanical systems and structures for compliance with the scoping criteria of 10 CFR 54.4(a)(3) and discussed the results of applicant
=s evaluation with the applicant's license renewal project team members. The staff
=s review of the applicant
=s evaluation and results of scoping requirements pursuant to 10 CFR 54.4(a)(3), for each regulated event, is described below.
 
Fire Protection. As described in the LRA and the license renewal project documents, based on a review of the Fire Protection Review Report for SSES, fire hazards analysis, topical design 2-18 basis documents, and other CLB documents, the applicant identified systems and structures and determined the corresponding intended functions that meet the requirements of fire
 
protection license renewal scoping requirements of 10 CFR 54.4(a)(3). In a sample review of
 
the applicant
=s methodology for meeting 10 CFR 54.4(a)(3) regulation for fire protection, the staff verified that the license renewal project document report identified the mechanical systems that are within the scope of license renewal because they perform intended functions pursuant
 
to 10 CFR 50.48. The license renewal project documents summarized the scoping results for
 
mechanical systems and identified several mec hanical systems that have one or more intended functions pursuant to 10 CFR 50.48. The staff performed a sample review of the residual heat
 
removal service water (RHRSW) system, core spray system (CSS), and circulating water pump house (CWPH) systems and structure for their inclusion as in-scope for fire protection. Based
 
on its review of the applicant
=s documentation and discussions with the applicant's license renewal project team members, the staff finds that the applicant has implemented an acceptable method for identifying systems and structures that perform a function that meets the fire
 
protection requirements of 10 CFR 54.4(a)(3) and has included those systems and structures
 
within the scope of license renewal.
 
Environmental Qualification. During the scoping and screening audit, the staff reviewed the LRA and the applicant=s implementing procedures and results reports (license renewal project
 
documents) for the EQ regulated event. Also, the staff discussed with the applicant's license
 
renewal project team, the details of the applicant's EQ scoping process and the information
 
sources used, to determine compliance with 10 CFR 50.49. The staff confirmed that the
 
applicant=s primary sources of information for scoping electrical components for license
 
renewal was the Nuclear Information Management System database and the CLB, which
 
identified electrical equipment required by 10 CFR 50.49 to be environmentally qualified for harsh environments, and the intended functions of those systems. The staff reviewed selected portions of  Nuclear Management System database and the SSCs identified within the scope of
 
license renewal in accordance with 10 CFR 54.4(a)(3). The staff determined that the applicant
 
had appropriately identified SSCs supporting env ironmental qualification and had accurately identified the intended functions.
 
Anticipated Transient Without Scram. The three primary systems at SSES, that perform intended functions pursuant to 10 CFR 50.62 to mitigate an ATWS event, are: standby liquid
 
control (SLC), alternate rod insertion, and reactor recirculation pump trip systems. Also, several
 
other SSCs support these systems in performing intended functions in accordance with
 
10 CFR 50.62. The applicant=s scoping results report identified these mechanical systems as
 
included within the scope of license renewal, because they perform a 10 CFR 50.62 intended
 
function. During the audit, the staff reviewed the applicant=s license renewal implementing
 
procedures and results documents. The staff performed a sample review of the above three
 
systems that perform 10 CFR 50.62 intended functions. The staff also reviewed the primary
 
sources of information that the applicant used for identifying these intended functions. Sources
 
the applicant reviewed for scoping the systems and structures pursuant to 10 CFR 50.62
 
included topical design basis documents for ATWS, Maintenance Rule Database
 
documentation, the UFSAR, and SERs related to compliance with 10 CFR 50.62. Based on its
 
review of the source documentation and the system functions, the applicant included those
 
SSCs that perform an intended function for ATWS within the scope of license renewal.
 
Station Blackout. In accordance with the CLB, the coping period for SSES is four hours, during which time, all systems and structures relied on in safety analyses or plant evaluations to
 
perform a function that demonstrates compliance with 10 CFR 50.63 for SBO, be included 2-19 within the scope of license renewal. The staff reviewed the LRA, as well as the applicant=s implementing procedures and the results reports in accordance with the criteria found in
 
10 CFR 50.63 and the applicant=s results report which identified mechanical systems and
 
structures that are included within the scope of license renewal because they perform an
 
intended function pursuant to 10 CFR 50.63. The staff reviewed selected portions of the
 
sources of information used by the applicant for the scoping of systems and structures in
 
compliance with 10 CFR 50.63 including the UFSAR, site technical report for coping
 
assessment for the SSES during an SBO, and site calculations (UFSAR Section 15.8). Based
 
on review of these information sources and the CLB, the staff determined that the applicant had
 
correctly identified the intended functions for each system and structure meeting the
 
requirements of 10 CFR 50.63, had identified the SSCs that perform an intended function for a
 
SBO and included them within the scope of license renewal.  .
 
2.1.4.3.3  Conclusion 
 
On the basis of the sample review, discussions with the applicant, and review of the applicant's
 
scoping process, the staff concludes that the applicant's methodology for identifying systems
 
and structures meets the scoping criteria pursuant to 10 CFR 54.4(a)(3) and; therefore, is
 
acceptable.
 
2.1.4.4  Plant-Level Scoping of Systems and Structures 2.1.4.4.1  Summary of Technical Information in the Application 
 
System and Structure Level Scoping. The applicant documented its methodology for scoping of SSCs in accordance with 10 CFR 54.4(a) in the license renewal project guidelines and license
 
renewal project documents, as documented in the audit report. The applicant's approach to
 
system and structure scoping provided in the site guidance was consistent with the
 
methodology described in LRA Section 2.1. Specifically, the license renewal project guidelines
 
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 regarding the CLB for systems included the
 
Maintenance Rule Database, FSAR, DBDs, P&IDs, electrical drawings, and docketed
 
correspondence. The applicant then compared identified system or structures function lists to
 
the scoping criteria to determine whether the functions met the scoping criteria of
 
10 CFR 54.4(a). The applicant documented the results of the plant-level scoping process in
 
accordance with the license renewal project guidelines. These results were provided in the
 
systems and structures license renewal proj ect documents. The license renewal project documents contained information including a descripti on 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 license renewal project document reports and concluded that the applicant's
 
scoping results in the license renewal project documents contained an appropriate level of detail
 
to document the scoping process.
 
Component Level Scoping. After the applicant identified the intended functions of systems or structures within the scope of license renewal, a review determined which components of each
 
in-scope system and structure support license renewal intended functions. The components that
 
support intended functions were considered within the scope of license renewal and screened 2-20 to determine whether an AMR was required. The applicant considered three component/commodity groups during this stage of the scoping methodology: (1) mechanical, (2)
 
structural commodity, and (3) electrical commodity.
 
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 2.1.2.6, A Treatment of Insulation,@ stated that at SSES, piping and equipment insulation is classified as nonsafety-related and is required to maintain its structural integrity for nonsafety affecting safety considerations. Insulating materials that function to limit
 
heat transfer, serve as fire barriers, or are required to maintain their structural integrity are
 
included within the scope of license renewal and are addressed as structural commodities in
 
Section 2.4 of the LRA.
 
Consumables. LRA Section 2.1.2.4, A Treatment of Consumables,@ states that the guidance in Section 4.1 of NEI 95-10 was used to categorize and evaluate consumables. Consumables were divided into the following five categories for the purpose of license renewal: (a) packing, gaskets, component seals, and O-rings; (b) structural sealants; (c) oil, grease, and component
 
filters; (d) system filters, fire extinguishers, fire hoses, and air packs; and, (e) mechanical
 
sealants. 
 
Group (a) subcomponents are not relied upon to form a pressure-retaining function and, therefore, are not subject to an AMR. Group (b) subcomponents are structural sealants for
 
structures within the scope of license renewal that require an AMR. Group (c) subcomponents
 
are periodically replaced according to plant procedures and, therefore, are not subject to an
 
AMR. Group (d) consumables are subject to replacement based on National Fire Protection Association standards and Department of Transportation standards according to plant
 
procedures and, therefore, are not subject to an AMR. Group (e) mechanical sealants in the
 
heating, ventilation, and air conditioning (HVAC) system include duct tape, and gaskets. Upon
 
evaluation, the applicant determined that these consumables did not have an intended function
 
for license renewal and; therefore, 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 compliance with 10 CFR 54.4(a). The methodology used to determine the mechanical systems and components within the scope of license renewal was documented
 
in license renewal project documents, and plant level scoping results for mechanical systems
 
were identified in LRA Table 2.2-1. The scoping process defined the plant in terms of systems
 
and structures. Specifically, the license renewal project guidelines (a) identified the systems and structures that are subject to review in accordance with 10 CFR 54.4, (b) described the
 
processes for capturing the results of the review, and (c) were used to determine whether the
 
system or structure performed intended functions consistent with the requirements 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
=s personnel performed initial reviews on systems and structures identified in the CLB. 
 
2.1.4.4.3  Conclusion 
 
Based on its review of the LRA, scoping and screening implementing procedures, and a 2-21 sampling of system scoping results during the audit, the staff concludes that the applicant
=s methodology reasonably identifies SSCs and commodity groups within the scope of license renewal and their intended functions. The staff also concludes that the applicant
=s scoping methodology for plant SSCs, commodity groups , insulation, and consumables meets the scoping criteria pursuant to 10 CFR 54.4(a)(3) and; therefore, is acceptable.
 
2.1.4.5  Mechanical Component Scoping 2.1.4.5.1  Summary of Technical Information in the Application 
 
LRA Section 2.1 describes the methodology for identifying license renewal evaluation
 
boundaries. For mechanical systems, the mechanical components include those portions of the
 
system that are necessary to ensure that t he intended functions will be performed. Structures and components needed to support each of the system/structure-level intended functions
 
identified in the scoping process are included within the evaluation boundary. 
 
The evaluation boundaries for mechanical sy stems are documented on license renewal boundary drawings created by marking mechanical piping and instrumentation diagrams
 
to indicate the components within the scope of license renewal. Components within the
 
evaluation boundary are reviewed to determine whether they perform an intended function.
 
Typically, components in mechanical systems perform a pressure boundary function. Some components may perform other functions such as heat transfer, filtration, or flow control.
 
Intended functions are established based on whether a particular function of a component is
 
necessary to support the system functions that meet the scoping criteria.
 
2.1.4.5.2  Staff Evaluation 
 
The staff evaluated LRA Section 2.1 and the guidance in license renewal project documents, license renewal project guidelines, and AMR reports to complete the review of mechanical
 
scoping process. The project document and guidelines provided instructions for identifying the
 
evaluation boundary. Determination of the mechanical system evaluation boundary requires an
 
understanding of system operations in support of intended functions. This process was based
 
on review of P&IDs, DBDs, Maintenance Rule basis documents, component databases, and
 
CLB documents such as the Environmental Protection Plan, the UFSAR, the Fire Protection
 
Review Report, the Offsite Dose Calculation Manual, the QA Program Description, the
 
Technical Requirements Manual, and the TSs and Bases. The evaluation boundaries for
 
mechanical systems are documented on licens e renewal boundary drawings created by marking mechanical piping and instrumentation diagrams to indicate the components within the
 
scope of license renewal. 
 
Components within the evaluation boundary were reviewed to determine whether they perform
 
an intended function. Intended functions are established based on whether a particular function
 
of a component is necessary to support the syst em functions that meet the scoping criteria.
Mechanical components were grouped, where practical, by component type.
 
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 2-22 documentation pertinent to the scoping process. The staff assessed whether the applicant had appropriately applied the scoping methodology outlined in the LRA and implementing
 
procedures and whether the scoping results were consistent with CLB requirements. The staff
 
determined that the applicant's procedural methodology was consistent with the description
 
provided in LRA Section 2.1 and the guidance contained in SRP-LR Section 2.1, and was
 
adequately implemented. 
 
The staff reviewed the applicant's methodology for identifying main steam (MS) 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 has identified and used pertinent
 
engineering and licensing information in order to determine the MS 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 fo r the MS system, 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 has identified and highlighted system P&IDs to develop the
 
license renewal evaluation 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 implementing procedures. Additionally, the staff verified that the
 
applicant's results are 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 implementing procedures, and the system sample and
 
discussions with the applicant, the staff concludes that the applicant
=s methodology for identifying mechanical systems meets the scoping criteria pursuant to 10 CFR 54.4(a) and; therefore, is acceptable.
 
2.1.4.6  Structural Component Scoping 2.1.4.6.1  Summary of Technical Information in the Application 
 
In LRA Section 2.1, the applicant described the methodology for identifying structures that are in
 
the scope of license renewal. Initially, all plant structures were reviewed to determine whether
 
they were in-scope for license renewal. The list of structures was identified using CLB
 
documents such as the FSAR, the Maintenance Rule document for structures, the Fire
 
Protection Review Report, topical design basis documents, and plant drawings. Structures that
 
have an intended function for 10 CFR 54.4(a) were included in the scope of license renewal and
 
listed in LRA Table 2.2-3. LRA Section 2.4 described the scoping results for the individual
 
structures that are in-scope of license renewal. 
 
2.1.4.6.2  Staff Evaluation
 
The staff reviewed the applicant
=s approach for identifying structures relied upon to perform the functions pursuant to 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, 2-23 and evaluated the scoping results for several structures that were identified as within the scope of license renewal. 
 
The license renewal project guidelines described the applicant
=s process for identifying structures that are within the scope of license renewal and stated that all structures that perform an intended function are to be included within the scope of license renewal and that the scoping
 
results are to be documented in the scoping results report. The scoping results report listed all
 
the structures that were evaluated, and also described the procedures the applicant used to
 
identify structures.
 
The staff reviewed the applicants implementing procedures and scoping results reports. The
 
applicant performed structural scoping in a manner to ensure that all plant buildings, yard
 
structures, and SBO related non-plant structures were considered. The scoping results report
 
identified the intended functions for each structure required for compliance with one or more
 
criteria pursuant to 10 CFR 54.4(a). The structural component intended functions were identified
 
based on the guidance provided in NEI 95-10, and the SRP-LR. For structures, the applicant
 
determined the evaluation boundaries by developing a complete description of each structure
 
with respect to the intended functions performed by the structure. The results of the review were
 
documented in the scoping results report which contained a list of structures, evaluation results
 
for each structure pursuant to 10 CFR 54.4(a) criteria, a description of structural intended
 
functions, and source reference information for the functions. The applicant identified 16
 
structures and or buildings as within the scope of license renewal.
 
The staff conducted detailed discussions with the applicant
=s license renewal team and reviewed documentation pertinent to the scoping process. The staff assessed whether the scoping methodology outlined in the LRA and procedures were appropriately implemented and
 
whether the scoping results were consistent with CLB requirements. The staff also reviewed
 
structural scoping evaluation results for the ES service water (SW) pump-house and the TB to
 
verify proper implementation of the scoping process. Based on these audit activities, the staff
 
did not identify any discrepancies between the methodology documented and the
 
implementation results. 
 
2.1.4.6.3  Conclusion
 
On the basis of the staff's review of information in the LRA, the applicant's detailed scoping
 
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
 
meets the scoping criteria pursuant to 10 CFR 54.4(a) and; therefore, is acceptable.
2.1.4.7  Electrical Scoping 2.1.4.7.1  Summary of Technical Information in the Application 
 
LRA Section 2.1.1.4.3, A Electrical and Instrumentation and Control Systems
@ and Section 2.5, A Scoping and Screening Results: Electrical and Instrumentation and Control Systems,@ describes the scoping process associated with electrical systems and components. A bounding scoping approach was used for electrical equipment. All electrical components were determined
 
to be within the scope of license renewal and subject to an AMR unless they were scoped out at
 
the system level or are screened out at the co mponent level by commodity group. Therefore, detailed evaluation boundaries were not depicted for electrical scoping.
2-24  2.1.4.7.2  Staff Evaluation
 
The staff evaluated LRA sections 2.1.1.4.3 and 2.5 and the applicant's implementing
 
procedures and AMR reports, as documented in the audit report governing the electrical
 
scoping methodology. The applicant 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. The applicant used the Maintenance Rule Data Base, the FSAR
 
and systems DBDs to determine whether systems met the requirements for inclusion pursuant to 10 CFR 54.4(a)(1), (2) or (3). All electrical components contained in plant systems within the
 
scope of license renewal and non-plant electrical systems, including switchyard components
 
required to support SBO, were included within the scope of license renewal. In addition, the
 
applicant identified 20 fuse boxes as included within the scope of license renewal. The staff
 
reviewed selected portions of the data sources and selected several examples of components
 
including switchyard components required to support SBO and fuse boxes, for which the
 
applicant demonstrated the process used to determine whether electrical components were
 
within the scope of license renewal. 
 
2.1.4.7.3  Conclusion
 
On the basis of its review of information contained in the LRA, the applicant
=s scoping implementing 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 meets the scoping criteria pursuant to 10 CFR 54.4(a) and; therefore, is acceptable.
 
2.1.4.8  Conclusion for Scoping Methodology On the basis of its review of the LRA and the scoping implementing procedures, the staff
 
determines that the applicant's scoping methodology is consistent with the guidance contained
 
in the SRP-LR. The staff further determines that the applicant has identified those SSCs that are
 
safety-related, whose failure could affect safety-related functions, and are necessary to
 
demonstrate compliance with staff regulations for fire protection, EQ, ATWS, and SBO. The
 
staff concludes that the applicant
=s methodology is consistent with the requirements of 10 CFR 54.4(a) and; therefore, is acceptable.
2.1.5  Screening Methodology 2.1.5.1  General Screening Methodology After determining the systems and structures within the scope of license renewal, the applicant
 
implemented a process for determining which SSCs were subject to an AMR, in accordance
 
10 CFR 54.21.
 
2.1.5.1.1  Summary of Technical Information in the Application 
 
In LRA Section 2.1.2, A Screening Methodology,@ the applicant discussed the method of identifying components from in-scope systems and st ructures that are subject to an AMR. The screening process consisted of the following steps:
 
2-25
* Identification of components, long-lived or passive, for each in-scope mechanical system, structure and electrical commodity group
* Identification of the license renewal intended function(s) for all mechanical and structural component types and electrical commodity groups
 
Active components were screened out and therefore, did not require AMR. The screening
 
process also identified short lived com ponents and consumables. The short lived components are not subject to an AMR. Consumables are a special class of items that include packing, gaskets, component seals, O-rings, oil, grease, component filters, system filters, fire extinguishers, fire hoses, and air packs. Sealants for structures were the only consumables
 
within the scope of license renewal that require an AMR
 
2.1.5.1.2  Staff Evaluation
 
Pursuant to 10 CFR 54.21, the staff requires that each LRA contain an integrated plant
 
assessment (IPA)  that identifies SCs within the scope of license renewal and 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 whether mechanical and
 
structural component types, 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 2.1.2, the applicant discussed these screening activities as they related to
 
component types and commodity groups within the scope of license renewal.
 
The screening process evaluated these in-scope component types and commodity groups to determine which ones were long-lived and passive and therefore, subject to an AMR. The staff
 
reviewed LRA Sections 2.3, 2.4, and 2.5, which documented the results of the process the
 
applicant used to identify component types and commodity groups subject to an AMR. The staff
 
also reviewed the screening results reports for the MS system and the TB.
 
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 its review of the LRA, the screening implementing procedures and a sampling of
 
screening results, the staff concludes that the applicant
=s screening methodology is consistent with the guidance contained in the SRP-LR and is capable of identifying passive, long-lived components within the scope of license renewal and subject to an AMR. The staff concludes
 
that the applicant
=s process for determining which component types and commodity groups are 2-26 subject to an AMR is consistent with the requirements of 10 CFR 54.21 and; therefore, is acceptable.
 
2.1.5.2  Mechanical Component Screening 2.1.5.2.1  Summary of Technical Information in the Application 
 
LRA Section 2.1.2.1, 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 (with the exception
 
of those systems in-scope for 10 CFR 54.4(a)(2) for physical interactions, as discussed below). 
 
2.1.5.2.2  Staff Evaluation
 
The staff evaluated the mechanical screening methodology in LRA 2.1.2.1, the license renewal
 
project documents, license renewal project guidelines, and the AMR reports. The mechanical
 
system screening process began with the results from the scoping process. The applicant
 
reviewed each system evaluation boundary, 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 are subject to an AMR. To streamline
 
the AMR process, the applicant grouped components into component types. The component
 
types were then reviewed against the list contained in NEI 95-10, Appendix B. The results of the
 
review are documented in the AMR reports. The AMR reports contain system intended functions, system evaluation boundaries, co mponent materials and environments, component intended functions, and AMR results.
 
The staff reviewed the results of the boundary evaluations and further discussed the process
 
with the applicant. The staff confirmed that mechanical system evaluation boundaries were
 
established for each system within the scope of license renewal. These boundaries were
 
determined by mapping the pressure boundary asso ciated with system-level license renewal intended functions onto the P&IDs. A preparer and an independent reviewer performed a
 
comprehensive evaluation of the boundary drawings to ensure the completeness and accuracy
 
of the review results.
 
Additionally, the staff reviewed the screening activities associated with the MS system. The staff
 
reviewed the system intended functions and associated source documents identified for the
 
system, the MS flow diagrams, and the asso ciated results documented in the AMR report. The staff did not identify any discrepancies with the evaluation, and determined that the applicant
 
has adequately followed the process documented in the license renewal project documents, and adequately documented the results in the AMR reports.
 
2.1.5.2.3  Conclusion
 
Based on its review of the LRA, the screening implementing procedures, and a sample of MS
 
system screening results, the staff concludes that the applicant
=s mechanical component screening methodology is consistent with SRP-LR guidance. The staff further concludes that the applicant=s methodology for identifying passive, long lived mechanical components within the scope of license renewal and subject to an AMR meets the requirements of 10 CFR 54.21(a)(1) and; therefore, is acceptable.
2-27  2.1.5.3  Structural Component Screening 2.1.5.3.1  Summary of Technical Information in the Application 
 
LRA Section 2.1.2.2, A Screening of Structures,@ states that for each structure within the scope of license renewal, the screening process identified those structural components that were subject to an AMR. LRA Section 2.4, A Scoping and Screening Results: Structures,@ presents the results for structures. The screening process for structural components involved a review of design documents (UFSAR, drawings) to identify the specific structural components that make up the
 
structure. Structural components typically do not have unique identifiers similar to those provided for mechanical components. Therefore, grouping structural components and
 
commodities were first based on materials of construction and then subdivided based on
 
component design and function which provided a means of categorizing them for an AMR.
 
Commodity groups were based on materials of construction, such as steel, concrete, elastomers, or earthen. Once the structural commodity groups were identified within an in-scope
 
structure or building, the commodity groups were subdivided into discrete structural component
 
types based on design, such as walls, floors, fire doors, and equipment supports. Structures
 
contain inherently passive, long-lived structural components and therefore the structural
 
components within the scope of license renewal that perform an intended function were
 
identified as 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 as within
 
the scope of license renewal. 
 
The applicant
=s AMR reports, as described in the audit report, provided detailed implementation guidance on the applicant
=s process for identifying and screening structural components that are subject to an AMR. The report stated that all structural components that perform an intended function and are passive and long-lived are subject to an AMR. In addition, the applicant
 
described the screening results for each system in separate AMR reports for each system. 
 
The staff reviewed the applicant's methodology used for structural screening described in
 
LRA sections noted above, and in the applicants implementing guidance and AMR reports. The
 
applicant performed the screening review in accordance with the implementation guidance and
 
captured pertinent structure design information, component, materials, environments, and aging
 
effects. The staff confirmed that the applicant used the lists of passive SCs embodied in the
 
regulatory guidance as an initial starting point and supplemented that list with additional items
 
unique to the site or for which a direct match to the generic lists did not exist (i.e., material and/or environment combinations). The boundary for a structure was the entire building
 
including base slabs, foundations, walls, beams, slabs, and steel superstructure. 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 conducted detailed discussions with the applicant
=s license renewal team and reviewed documentation pertinent to the screening process. The staff assessed whether the 2-28 screening methodology outlined in the LRA and procedures was appropriately implemented and whether the scoping results were consistent with CLB requirements. The staff also reviewed
 
structural screening results for SCs contained in the ES SW pump-house and the TB 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 its review of information contained in the LRA, the applicant's detailed screening
 
implementing procedures, and a sampling review of structural screening results, the staff
 
concludes that the applicant's methodology for identification of structural components subject to
 
an AMR met the requirements of 10 CFR 54.21(a)(1) and; therefore, is acceptable.
 
2.1.5.4  Electrical Component Screening 2.1.5.4.1  Summary of Technical Information in the Application 
 
In the LRA section 2.1.2.3, A Screening of Electrical and Instrumentation and Control Systems,@ the applicant discussed the screening of electrical and instrumentation and control system components. For each electrical system within the scope of license renewal, the screening
 
process identified those electrical components and commodities that are subject to an AMR.
 
Electrical components in mechanical systems were included in the scope of license renewal and
 
were addressed under the electrical screening process. 
 
The process of electrical screening differed from the mechanical and structural processes
 
because the electrical components were addressed completely within their respective
 
commodity groups. Each electrical component within the scope of license renewal is assigned
 
to an electrical component commodity group for the screening evaluation. The screening of
 
electrical components for license renewal was performed utilizing a commodity group basis. An
 
electrical commodity group is a group of el ectrical components grouped by type of equipment and/or function. The listing of electrical component commodity groups included in Appendix B to
 
NEI 95-10 is used as the starting point for establishing commodity groups. Review of SSES
 
documents (FSAR, single-line drawings, and electrical layout drawings) was used to validate the
 
listing as complete. 
 
For the electrical equipment within the scope of license renewal, the passive, long-lived
 
components that perform or support an intended function are subject to an AMR. NEI 95-10, Appendix B, identifies the electrical commodities considered to be passive and potentially
 
requiring an AMR. For SSES, electrical commodity groups were identified and cross-referenced
 
to the appropriate NEI 95-10 commodity, which identifies the passive commodity groups.
 
Electrical commodities determined to be active were not subject to an AMR. Electrical commodities that are not subject to replacement based on a qualified life or specified time
 
period were considered long-lived. Components that are subject to replacement are addressed
 
in replacement programs, such as the Environm ental Qualification Program, or other controlled programs that establish a specific service life, qualified life, or replacement frequency.
 
Components that are not long-lived are not subject to an AMR.
 
2.1.5.4.2  Staff Evaluation
 
2-29 The staff reviewed the applicant
=s methodology used for electrical screening in LRA Section 2.1.2.3 and the applicant's implementation procedures and AMR reports. Based on a review of the LRA, applicant's implementing procedures and screening reports, the staff
 
determined that the applicant used the screening process described in these documents to
 
identify the electrical commodity groups subject to AMR and that the applicant used the
 
component database, the stations single-line drawings, and cable procurement specifications as
 
data sources to identify the electrical and I&C components, including fuses-holders. The
 
applicant determined there were 20 fuse-holders located outside of active devices and subject
 
to an AMR. 
 
The staff determined that the applicant assembled a table of four commodities which were
 
determined to meet the passive criteria which were grouped in accordance with NEI 95-10 as (a) non-insulated cables and connections, (b) non-insulated metal enclosed (phase) bus, (c)
 
high-voltage insulators, and (d) transmission conductors and connections. Based on the review
 
of the applicant's screening reports, the staff determined that the applicant evaluated the
 
identified, passive commodities to determine 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 or specified time period (long-lived). The remaining passive, long lived components
 
were determined to be subject to an AMR. The staff reviewed the applicant's screening of
 
selected components including switchyard components required to support SBO and fuse
 
boxes, 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 and concludes that the applicant
=s methodology is consistent with the description provided in LRA and the applicant
=s implementing procedures. On the basis of its review of information contained in the LRA, the applicant
=s screening implementing procedures, and a sampling review of electrical screening results, the staff further concludes that the applicant=s methodology for identification of electrical commodity groups subject to an AMR is consistent with the requirements of 10 CFR 54.21(a)(1) and; therefore, is acceptable.
2.1.5.5  Conclusion for Screening Methodology On the basis of its review of the LRA, the screening implementing procedures, discussions with
 
the applicant
=s staff, and a sample review of screening results, the staff determines that the applicant's screening methodology is consistent with the guidance contained in the SRP-LR and that the applicant has 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; therefore, is 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 implementing procedures and reports, the information presented
 
during the scoping and screening methodology audit, and the applicant
=s responses to the staff=s RAIs dated March 9, 2007, formed the basis of the staff
=s determination. The staff confirmed that the applicant
=s scoping and screening methodology is consistent with the requirements of the Rule. From this review, the staff concludes that the applicant
=s methodology 2-30 for identifying SSCs within the scope of license renewal and SCs requiring an AMR is consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1) and; therefore, is acceptable.
 
2.2  Plant-Level Scoping Results 2.2.1  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 verified that the
 
applicant properly implemented its methodology, the staff's review focused on the
 
implementation results shown in LRA Tables 2.2-1, 2.2-2, and 2.2-3, to confirm that there were
 
no omissions of plant-level systems and stru ctures within the scope of license renewal.
 
The staff determined whether the applicant properly identified the systems and structures within
 
the scope of license renewal in accordance with 10 CFR 54.4. The staff reviewed selected
 
systems and structures that the applicant did not identify as within the scope of license renewal
 
to verify whether the systems and structur es 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 where 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 August 27, 2007, the staff noted that LRA Table 2.2-1 defines the
 
electro-hydraulic control and logic system and t he electro-hydraulic control hydraulic power system as not within the scope of license renewal. Electro-hydraulic control systems assist to provide holdup and plate-out of fission products that may leak through the closed main steam
 
isolation valves (MSIVs). This is a function performed by components located in the main
 
condenser and MSIV leakage pathway. In doing so, they fulfill intended functions pursuant to
 
10 CFR 54.4(a)(2). The staff requested that the applicant provide additional information to justify
 
exclusion of the electro-hydraulic control and logic system and the electro-hydraulic control hydraulic power system from the scope of license renewal.
 
In its response to RAI 2.2-1, dated October 18, 2007, the applicant stated:
 
The Electro-Hydraulic Control and Logic System, and the Electro-Hydraulic Control Hydraulic Power System are not within the scope of license
 
renewal and are not subject to Aging Management Review (AMR). Control
 
of fission products that may leak through a closed MSIV is provided by
 
directing the leakage to the condenser prior to release to atmosphere. This
 
function is performed by the Main Steam System, as discussed in LRA
 
Section 2.3.4.6. The Susquehanna FSAR, Section 6.7 states: "The MSIV
 
leakage Isolated Condenser Treatment Method (ICTM) controls and
 
minimizes the release of fission products which could leak through the
 
closed main steam isolation valves (MSIVs) after a LOCA. The treatment
 
method provides this control by processing MSIV leakage prior to release
 
to the atmosphere. This is accomplished by directing the leakage through
 
the main steam drain line to the condenser." The primary path for the ICTM 2-31 method as used at Susquehanna depends on the drain line pathway to the condenser. The primary path is in-scope and subject to AMR and is
 
depicted on LR-M-141/2141-1 and LR-M-205/2105-1. The secondary path
 
depends on the Main Steam line drip legs, is in-scope and subject to AMR, and is depicted on LR-M-101/2101-1. The ICTM does not depend on either
 
the Electro-Hydraulic Control and Logic System, or the Electro-Hydraulic Control Hydraulic Power System to ma intain any valves open to provide the pathway from the MSIVs to the condenser for either the primary or the
 
secondary paths.
Per FSAR Section 6.7.2.1.1, the primary pathway to the condenser is the main steam drain line through the HV-1(2)41F020 and HV-1(2)41F021
 
motor-operated valves. The HV-1(2)41F020 valve is normally open and will
 
not need to be operated. The HV-1(2)41F021 valve is normally closed and
 
will need to be opened by an operator by means of a hand switch in the
 
control room. There are three normally open motor-operated valves that will
 
need to be closed by an operator to prevent leakage to other areas of the
 
TB. These boundary valves are HV-1(2)0107 to steam jet air ejector, HV-1(2)0109 to steam seal evaporator, and HV-1(2)0111, to reactor feed
 
pump turbines. The hand switches for these valves are in the control room.
Per FSAR Section 6.7.2.1.2, alternate orificed pathways (which do not
 
require the opening of any valves) exist as a backup to direct MSIV leakage
 
to the condenser should the HV-1(2)41F021 valve not open as expected.
 
These pathways include: the orificed bypass line around the
 
HV-1(2)041F021 valve; the four orificed drain lines from the main steam
 
line eight inch drip legs; and the one orificed drain line from the main steam
 
line twelve inch drip leg.
 
The Electro-Hydraulic Control and Logic System and the Electro-Hydraulic Control Hydraulic Power System do not perform any safety-related functions and therefore do not meet the criteria of 10 CFR 54.4(a)(1).
The Electro-Hydraulic Control and Logic System and the Electro-Hydraulic Control Hydraulic Power System do not have the potential to adversely affect safety-related systems or components through spatial interaction and
 
therefore do not meet the criteria of 10 CFR 54.4(a)(2). As stated in LRA
 
Section 2.1.1.2.2, there are no components located in the TB that either
 
perform or would prevent a safety-related function from occurring.
The Electro-Hydraulic Control and Logic System and the Electro-Hydraulic Control Hydraulic Power System are not relied upon to demonstrate
 
compliance with, nor satisfy the 10 CFR 54.4(a)(3) scoping criteria for, any
 
regulated event.
 
Based on its review, the staff finds the applicant's response to RAI 2.2-1 acceptable because
 
the applicant clarified why the electro-hydraulic control and logic system and the electro-
 
hydraulic control hydraulic power system are not within the scope of license renewal. Therefore, the staff's concern described in RAI 2.2-1 is resolved. 
 
2-32 In RAI 2.2-2, dated August 27, 2007, the staff noted that LRA Table 2.2-1 defines the circulating water system (CWS) as not within the scope of license renewal. Applicants with similar plant
 
designs have included the CWS within the scope of license renewal in accordance with
 
10 CFR 54.4(a)(2). The staff requested that the applicant provide additional information to justify
 
exclusion of the CWS from scope with respect to the applicable requirements pursuant to
 
10 CFR 54.4(a). 
 
In its response to RAI 2.2-2, dated October 18, 2007, the applicant stated:
As described in Section 10.4.5 of the FSAR, the Circulating Water
 
System for SSES has no safety-related functions and is designed to
 
remove the latent heat from the main condenser and sensible heat from
 
the Service Water System and dissipate both in a hyperbolic natural draft
 
cooling tower. Failure of the Circulating Water System will not prevent the
 
satisfactory accomplishment of any safety-related functions and
 
therefore, does not meet the criteria of 10 CFR 54.4(a)(1).
 
In addition, failure of the Circulating Water System will not adversely
 
affect any safety-related syst ems or components through spatial interaction and system piping is not connected to any safety-related
 
piping. There is no potential for spatial interaction of the Circulating Water System with safety-related components, because circulating water piping
 
is not routed in structures or outdoor areas that contain safety-related
 
components. Portions of the Circulating Water System are routed in the
 
Turbine Building. However, as described in Section 2.1.1.2.2 of the LRA (pg. 2.1-6) there are no components located in the Turbine Building that
 
either perform or would prevent a safety-related function from occurring.
 
Therefore, the Circulating Water System does not meet the criteria of
 
10 CFR 54.4(a)(2).
 
As evaluated in FSAR Section 10.4.1.3.3, flooding due to the rupture of a
 
circulating water expansion joint in the Turbine Building will not affect any
 
safety-related equipment. The Circulating Water System is not relied
 
upon to demonstrate compliance with any regulated event and, therefore, does not meet the criteria of 10 CFR 54.4(a)(3).
 
2-33 In a telephone conference call, "Summary of Telephone Conference Call Held December 28, 2007, between the U.S. Nuclear Regulatory Commission and PPL Susquehanna, LLC, Concerning Requests for Additional Information Pertaining to the Susquehanna Steam
 
Electric Station, Unit 1 and 2, License Renewal Application," (see Appendix B) the staff noted
 
that UFSAR Section 10.4.5 identifies the cooling towers and its piping as part of the CWS. The
 
UFSAR identifies the cooling towers and the piping from the cooling towers as a secondary
 
source of fire protection water, making this portion of the CWS within the scope of license
 
renewal, based on criterion pursuant to 10 CFR 54.4(a)(3). Furthermore, boundary drawings
 
LR-M-115, "Unit 1 License Renewal Boundary Drawings Circulating Water," and LR-M-2115, "Unit 2 License Renewal Boundary Drawing Circulating Water," identify the cooling tower basins
 
and a portion of the pipes from the cooling tower basins as within the scope of license renewal, based on criterion in accordance with 10 CFR 54.4(a)(3).
 
The applicant replied as follows: 
 
The 108-inch piping exiting the Unit 1 cooling tower basin and the 78-inch
 
line exiting the Unit 2 cooling tower basin provide water to both the
 
circulating water system and the service water system. Therefore, this
 
piping is functionally part of two systems. Within the SSES maintenance
 
program this piping is considered part of the cooling tower system. The
 
LRA system designation is based on the "functional" purpose of the
 
cooling tower basins and piping rather than the FSAR description.
 
Based on its review, the staff finds the applicant's response to RAI 2.2-2 acceptable because
 
the applicant has clarified that the LRA system designation is based on the functional purpose
 
of the cooling tower basins and piping rather than the UFSAR system designation and that
 
within the SSES maintenance program, this piping is considered part of the cooling tower
 
system, which is within the scope of license renewal. Therefore, the staff's concern described in
 
RAI 2.2-2 is resolved.
 
In RAI 2.2-1, dated July 25, 2007, the staff requested that the applicant provide justification for
 
the exclusion of the miscellaneous HVAC system s (Chlorination Building HVAC, Circulating Water Pump Room HVAC, Intake Works HVAC, Service and Administration Building HVAC, Service Water Pump Room HVAC, Turbine Build ing HVAC, and Water Treatment Room HVAC) and their applicable components and passive functions from the scope of license renewal. If
 
these systems and their applicable components are within the scope of license renewal, in
 
accordance with 10 CFR 54.4(a), and subject to an AMR pursuant to 10 CFR 54.21(a)(1),
update the LRA by providing the applicable information in the appropriate LRA sections, tables, and boundary drawings.
 
In its response to RAI 2.2-1, dated August 23, 2007, the applicant stated:
 
Chlorination Building HVAC - The Chlorination Building is part of the
 
structure that is identified in the LRA as the Chlorination and Acid
 
Storage Building. As stated in LRA Table 2.2-3, the Chlorination and Acid
 
Storage Building is not within the scope of license renewal. There are no
 
safety-related components located in the building. Therefore, the HVAC
 
components located in the building are not in-scope based upon the
 
criteria of 10 CFR 54.4(a)(1) and 10 CFR 54.4(a)(2). In addition, no
 
components located in the building support any regulated events for a 2-34 BWR. Therefore, the HVAC components are also not in-scope based on the criterion of 10 CFR 54.4(a)(3). The Chlorination Building HVAC
 
System does not provide a supporting function applicable to equipment
 
within the scope of license renewal, therefore it is not within the scope of
 
license renewal. 
 
Circulating Water Pump Room HVAC - The Circulating Water Pump
 
Room is part of the structure identified in the LRA as the Circulating
 
Water Pumphouse and Water Treatment Building. As stated in LRA
 
Table 2.2-3, the Circulating Water Pumphouse and Water Treatment
 
Building is within the scope of license renewal. LRA Section 2.4.4 states
 
that the building is relied upon to demonstrate compliance with the
 
regulation 10 CFR 50.48 for Fire Protection by providing physical support
 
and protection to the fire water pumps. There are no safety-related
 
components located in the Circulating Water Pumphouse and Water
 
Treatment Building, which contains the Circulating Water Pump Room.
 
Therefore, the HVAC components located in the Circulating Water Pump
 
Room are not in-scope based upon the criteria of 10 CFR 54.4(a)(1) and
 
10 CFR 54.4(a)(2). While there is fire protection equipment located in
 
Circulating Water Pumphouse and Water Treatment Building that is
 
in-scope, based on criterion of 10 CFR 54.4(a)(3), this equipment does
 
not require support from the Circulating Water Pump Room HVAC.
 
Therefore, the HVAC components located in Circulating Water Pump
 
Room are not in-scope based upon the criterion of 10 CFR 54.4(a)(3).
 
The Circulating Water Pump Room HVAC System does not provide a
 
supporting function for any equipment within the scope of license
 
renewal, therefore, it is not within the scope of license renewal.
 
Intake Works HVAC - The Intake Works is part of the structure identified
 
in the LRA as the River Intake Structure. As stated in LRA Table 2.2-3, the River Intake Structure is not within the scope of license renewal.
 
There are no safety-related components located in the structure.
 
Therefore, the HVAC components located in the structure are not
 
in-scope based upon the criteria of 10 CFR 54.4(a)(1) and
 
10 CFR 54.4(a)(2). In addition, no components located in the structure
 
support any regulated events for a BWR. Therefore, the HVAC
 
components are also not in-scope based on the criterion of
 
10 CFR 54.4(a)(3). The Intake Works HVAC System does not provide a
 
supporting function applicable to equipment within the scope of license
 
renewal, therefore, it is not within the scope of license renewal.
 
Service and Administration Building HVAC - As stated in LRA
 
Table 2.2-3, the Service and Administration Building is not within the
 
scope of license renewal. There are no safety-related components
 
located in the Service and Administration Building. Therefore, the HVAC
 
components located in the Service and Administration Building are not
 
in-scope based upon the criteria of 10 CFR 54.4(a)(1) and
 
10 CFR 54.4(a)(2). In addition, no components located in the Service and
 
Administration Building support any regulated events for a BWR.
 
Therefore, the HVAC components are also not in-scope based on the 2-35 criterion of 10 CFR 54.4(a)(3). The Service and Administration Building HVAC System does not provide a supporting function applicable to
 
equipment within the scope of license renewal, therefore it is not within
 
the scope of license renewal.
 
Service Water Pump Room HVAC - The Service Water Pump Room is
 
part of the structure identified in the LRA as the Circulating Water
 
Pumphouse and Water Treatment Building. As stated in LRA Table 2.2-3, the Circulating Water Pumphouse and Water Treatment Building is within
 
the scope of license renewal. LRA Section 2.4.4 states that the building is
 
relied upon to demonstrate compliance with the regulation 10 CFR 50.48
 
for Fire Protection by providing physical support and protection to the fire
 
water pumps. There are no safety-related components located in the
 
Circulating Water Pumphouse and Water Treatment Building, which
 
contains the Service Water Pump Room. Therefore, the HVAC
 
components located in the Service Water Pump Room are not in-scope
 
based upon the criteria of 10 CFR 54.4(a)(1) and 10 CFR 54.4(a)(2).
 
While there is fire protection equipment located in Circulating Water
 
Pumphouse and Water Treatment Building that is in-scope based on
 
criterion of 10 CFR 54.4(a)(3), this equipment does not require support
 
from the Service Water Pump Room HVAC. Therefore, the HVAC
 
components located in the Service Water Pump Room are not in-scope
 
based upon the criterion of 10 CFR 54.4(a)(3). The Service Water Pump
 
Room HVAC System does not provi de a supporting function applicable to equipment within the scope of license renewal, therefore it is not within
 
the scope of license renewal.
Turbine Building HVAC - As stated in LRA Table 2.2-3, the Turbine
 
Building is within the scope of license renewal. LRA Section 2.4.8
 
provides the reasons for the building being in-scope. There are no
 
safety-related components located in the Turbine Building. Therefore, the
 
HVAC components located in the Turbine Building are not in-scope
 
based upon the criterion of 10 CFR 54.4(a)(1). While there is equipment
 
in the Turbine Building that is in-scope based on the criteria of
 
10 CFR 54.4(a)(2) and 10 CFR 54.4(a)(3), this equipment does not
 
require support from the Turbine Building HVAC. Therefore, the HVAC
 
components located in the Turbine Building are not in-scope based upon
 
the criteria of 10 CFR 54.4(a)(2) and 10 CFR 54.4(a)(3). The Turbine
 
Building HVAC System does not provide a supporting function for the
 
equipment within the scope of license renewal, therefore it is not within
 
the scope of license renewal.
 
2-36 Water Treatment Room HVAC - The Water Treatment Room is part of the structure identified in the LRA as the Circulating Water Pumphouse and
 
Water Treatment Building. As stated in LRA Table 2.2-3, the Circulating
 
Water Pumphouse and Water Treatment Building is within the scope of
 
license renewal. LRA Section 2.4.4 states that the building is relied upon
 
to demonstrate compliance with the regulation 10 CFR 50.48 for Fire
 
Protection by providing physical support and protection to the fire water
 
pumps. There are no safety-related components located in the Circulating
 
Water Pumphouse and Water Treatment Building, which contains the
 
Water Treatment Room. Therefore, the HVAC components located in the
 
Water Treatment Room are not in-scope based upon the criteria of
 
10 CFR 54.4(a)(1) and 10 CFR 54.4(a)(2). While there is fire protection
 
equipment located in the Circulating Water Pumphouse and Water
 
Treatment Building that is in-scope based on criterion of
 
10 CFR 54.4(a)(3), this equipment does not require support from the
 
Water Treatment Room HVAC. Therefore, the HVAC components are
 
also not in-scope based on the criterion of 10 CFR 54.4(a)(3). The Water
 
Treatment Room HVAC System does not provide a supporting function applicable to equipment within the scope of license renewal, therefore it
 
is not within the scope of license renewal.
 
Based on its review, the staff finds the applicant's response to staff's RAI 2.2-1 acceptable
 
because the applicant clarified why the miscellaneous HVAC systems (Chlorination Building
 
HVAC, Circulating Water Pump Room HVAC, Intake Works HVAC, Service and Administration
 
Building HVAC, Service Water Pump Room HVAC, Turbine Building HVAC, and Water
 
Treatment Room HVAC systems) are not with in the scope of license renewal. Therefore, the staff's concern described in RAI 2.2-1 is resolved.
2.2.2  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. On the basis of its review, the staff concludes that the applicant has
 
appropriately identified the systems and structures within the scope of license renewal in
 
accordance with 10 CFR 54.4 and; therefore, is acceptable.
 
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 (RV), RV internals, and reactor coolant system (RCS)
* Engineered safety features (ESF)
* Auxiliary systems
* Steam and power conversion systems
 
Staff Evaluation of Mechanical System Scoping and Screening Results This staff evaluation of the mechanical system scoping and screening results applies to all mechanical systems reviewed. Those systems t hat required requests for additional information 2-37 (RAIs) to be generated (if any) include an additional staff evaluation which specifically addresses the applicant's response to the RAI(s).
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 the applicant has identified
 
the mechanical system structures and component s 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
 
with the exception of those few selected systems described Sections 2.3.3 and 2.3.4 as
 
receiving an alternate review. The staff used was performed using the evaluation methodology
 
described here, in SER Section 2.3 and the guidance in SRP-LR Section 2.3, and took into
 
account (where applicable) the system function(s) described in the UFSAR. The objective was
 
to determine whether the applicant identified, in accordance with 10 CFR 54.4, components and
 
supporting structures for mechanical systems t hat meet the license renewal scoping criteria.
Similarly, the staff evaluated the applicant's screening results to verify that all passive, long-
 
lived components were subject to an AMR in accordance with 10 CFR 54.21(a)(1).
In the scoping evaluation, the staff reviewed the LRA, UFSAR, license renewal boundary drawings, and other licensing basis documents, as appropriate, for each mechanical system
 
within the scope of license renewal. The staff reviewed the licensing basis documents to confirm
 
that the LRA specified all intended functions pursuant to 10 CFR 54.4(a). The review then
 
focused on identifying components with intended functions in accordance with 10 CFR 54.4(a)
 
that had not been identified as within the scope of license renewal.
 
The staff then evaluated the applicant's screening results. For the SCs with intended functions
 
in compliance with 10 CFR 54.4(a), the staff determined whether the functions are performed
 
with moving parts or a change in configuration or properties or the SCs are subject to
 
replacement after a qualified life or specified time period, pursuant to 10 CFR 54.21(a)(1). For
 
SCs not meeting either of these criteria, the staff confirmed that the SCs are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.1  Reactor Vessel, Reactor Vessel Internals, and Reactor Coolant System In LRA Section 2.3.1, the applicant identified the RV, RV internals, and RCS SCs subject to an
 
AMR for license renewal. The applicant described the supporting SCs of the RV, RV internals, and RCS in the following LRA sections:
* 2.3.1.1  Reactor pressure vessel
* 2.3.1.2  Reactor vessel internals
* 2.3.1.3  Reactor coolant system pressure boundary
 
2.3.1.1  Reactor Pressure Vessel 2.3.1.1.1 Summary of Technical Information in the Application
 
LRA Section 2.3.1.1 describes the reactor pressure vessel (RPV), which provides a high
 
integrity barrier against the leakage of radioactive materials, contains and supports the reactor 2-38 core, RV internals, and coolant moderator, and provides a floodable volume in which the core can be adequately cooled in the event of a break in a line external to the vessel. The RPV
 
contains safety-related components relied upon to remain functional during and following DBEs.
 
LRA Table 2.3.1-1 identifies RPV component types within the scope of license renewal and
 
subject to an AMR.
 
2.3.1.1.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the RPV system mechanical components within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the
 
system components subject to an aging managem ent review in accordance with the requirements stated in 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 RV internals, which provide a high integrity barrier against
 
the leakage of radioactive materials, support the reactor core and RV internals, provide a
 
floodable volume in which the core can be adequately cooled in the event of a break in a line
 
external to the vessel, and distribute flow as designed to promote mixing. The RV internals
 
contain safety-related components relied upon to remain functional during and following DBEs.
 
The failure of nonsafety-related SSCs in the RV internals potentially could prevent the
 
satisfactory accomplishment of a safety-related function. In addition, the RV internals performs
 
functions that support ATWS. LRA Table 2.3.1-2 identifies RV internals component types within
 
the scope of license renewal and subject to an AMR.
 
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. The staff's
 
review identified areas requiring additional information 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 2.3.1-1, dated October 24, 2007, the staff noted in LRA Table 2.3.1-1, the nozzle N9 and
 
cap for N9 were listed as in-scope as a pressure boundary. The staff identified boundary
 
drawing LR-M-141-2 as showing nozzle N9 as out of scope. The staff requested that the
 
applicant confirm that N9 nozzle and cap were in-scope. 
 
In its response to RAI 2.3.1-1, dated November 14, 2007, the applicant stated:
 
The highlighting of nozzle N9 and the cap for N9 on boundary drawing
 
LR-M-141-2 was inadvertently omitted. As listed in LRA Table 2.3.1-1, nozzle N9 and the associated cap are within the scope of license renewal
 
and subject to an AMR. The highlighting on LR-M-141-2 has been
 
corrected to highlight nozzle N9 from the vessel wall to and including the
 
associated cap. The highlighting of the Unit 2 N9 nozzle on LR-M-2141-2
 
has also been clarified to clearly show highlighting from the vessel wall to 2-39 and including the cap. These were highlighting omissions on the boundary drawings and no changes to the LRA are required.
 
The staff confirms that the applicant has submitted revised boundary drawings
 
LR-M-141-2 and LR-M-2141-2. Based on its review, the staff finds the
 
applicant's response to RAI 2.3.1-1 acceptable because the applicant has
 
clarified that the highlighting for nozzle N9 and the cap for N9 were inadvertently
 
omitted and appropriate revisions were made to boundary drawings LR-M-141-2
 
and LR-M-2141-2. Therefore, the staff's concern described in RAI 2.3.1-1 is
 
resolved.
 
In RAI 2.3.1-2, dated October 24, 2007, the staff noted boundary drawing LR-M-146 depicted
 
valve 146-F004, and associate piping for a drive water pressure control station as out of scope.
 
However, isolation valves between the out of scope and in-scope piping were not shown. The
 
staff believes that this bypass line and valve should be within the scope of license renewal as a
 
pressure boundary. The staff requested the applicant clarify whether the subject components
 
were in-scope, thus, requiring an AMR and; if excluded, provide a justification.
 
In its response to RAI 2.3.1-2, dated November 14, 2007, the applicant stated:
 
The highlighting of valve 146-F004 and the associated piping on
 
boundary drawing LR-M-146-1 was i nadvertently omitted. Valve 146-F004 and the associated piping are within the scope of license
 
renewal and subject to aging management review. These components
 
meet the scoping criteria for 10 CFR 54.4(a)(2) and are included in LRA
 
Section 2.3.3.3, Table 2.3.3-3 and Table 3.3.2-3. The Unit 2 boundary
 
drawing, LR-M-2146-1 shows the correct highlighting. This was a
 
highlighting error and no changes to the LRA are required.
 
The staff confirmed that the applicant has submitted revised boundary drawing LR-M-146-1. 
 
Based on its review, the staff finds the applicant's response to RAI 2.3.1-2 acceptable because
 
the applicant clarified that valve 146-F004 and associated piping are within the scope of license
 
renewal and the highlighting was inadvertently omitted. The staff confirms that the applicant has
 
made appropriate revisions to boundary drawings LR-M-141-2 and LR-M-2141-2. Therefore, the
 
staff's concern described in RAI 2.3.1-1 is resolved.
 
2.3.1.2.3 Conclusion
 
The staff reviewed the LRA, UFSAR, boundary drawings (original and revised), and
 
RAI responses 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. On the basis of its review, the staff concludes
 
that the applicant has appropriately identified the RPV mechanical components within the scope
 
of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately
 
identified the RPV components subject to an AMR, in accordance with the requirements of
 
10 CFR 54.21(a)(1) and; therefore, is acceptable.
2.3.1.3  Reactor Coolant System Pressure Boundary 2.3.1.3.1  Summary of Technical Information in the Application 2-40  LRA Section 2.3.1.3 describes the RCS pressure boundary, which includes the ASME Code
 
Class 1 portions of these systems:
* Control Rod Drive Hydr aulic System (Class 1 portions only)
* Core Spray System (Class 1 portions only)
* Feedwater System (Class 1 portions only)
* High-Pressure Coolant Injection System (Class 1 portions only)
* Main Steam System (Class 1 portions only)
* Reactor Core Isolation Cooling System (Class 1 portions only)
* Reactor Nonnuclear Instrumentation System (Class 1 portions only)
* Reactor Recirculation System
* Reactor Vessel and Auxiliaries (vent line and flange leak detection line only)
* Residual Heat Removal System (Class 1 portions only)
* Reactor Water Cleanup System (Class 1 portions only)
* Standby Liquid Control System (Class 1 portions only)
* In-scope portions of the reactor recirculation system are included for purposes of license renewal evaluation.
The RCS pressure boundary contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the RCS
 
pressure boundary potentially could prevent the sati sfactory accomplishment of a safety-related function. In addition, the RCS pressure boundary performs functions that support fire protection, ATWS, SBO, and EQ. LRA Table 2.3.1-3 identifies RCS pressure boundary component types
 
within the scope of license renewal and subject to an AMR.
 
2.3.1.3.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the RCS system mechanical components within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the
 
system components subject to an aging managem ent review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.2  Engineered Safety Features In LRA Section 2.3.2, the applicant identified the ESFs SCs subject to an AMR for license
 
renewal. The applicant described the supporting SCs of the ESF in the following LRA sections:
* 2.3.2.1 Residual heat removal (RHR) system
* 2.3.2.2 Reactor core isolation cooling (RCIC) system
* 2.3.2.3 Core spray system (CSS)
* 2.3.2.4 High-pressure coolant injection (HPCI) system
* 2.3.2.5 Containment and suppression system 2-41
* 2.3.2.6 Containment atmosphere control system
* 2.3.2.7 Standby gas treatment system (SGTS)
 
2.3.2.1  Residual Heat Removal System 2.3.2.1.1  Summary of Technical Information in the Application
 
LRA Section 2.3.2.1 describes the RHR system, which is comprised of two independent loops, each with two motor-driven pumps, a heat exchanger, piping, valves, instrumentation, and
 
controls. The RHR system contains safety-related components relied upon to remain functional
 
during and following DBEs. The failure of nonsafety-related SSCs in the RHR system potentially
 
could prevent the satisfactory accomplishment of a safety-related function. In addition, the RHR
 
system performs functions that support fire protection, ATWS, and EQ. LRA Table 2.3.2-1 identifies RHR system component types within the scope of license renewal and subject to an
 
AMR.
 
2.3.2.1.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the RHR system mechanical components within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the
 
system components subject to an aging managem ent review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.2.2  Reactor Core Isolation Cooling System 2.3.2.2.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.2.2 describes the RCIC system, which consists of a steam-driven turbine-pump unit, valves, and piping capable of delivering water from either the CST or the suppression pool
 
to the RV via one of the feedwater lines. The RCIC system contains safety-related components
 
relied upon to remain functional during and following DBEs. The failure of nonsafety-related
 
SSCs in the RCIC system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the RCIC system performs functions that support fire protection, ATWS, SBO, and EQ. LRA Table 2.3.2-2 identifie s RCIC system component types within the scope of license renewal and subject to an AMR.
 
2.3.2.2.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.2.2 and UFSAR Section 5.4.6 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff's
 
review identified areas where 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 2.3.2.2-1, dated October 24, 2007, the staff noted boundary drawings LR-M-150
 
and -2150 of the LRA depicted piping between the RCIC vacuum tank and the barometric
 
condenser vacuum pump as not in-scope. The staff identified that Table 2.3.2-2 listed the piping
 
and piping components function (under the vacuum tank) as structural integrity. Additionally, 2-42 Tanks 1/2 T219 were depicted as in-scope in boundary drawing LR-M-150-1; but they were not listed in Table 2.3.2-2. The staff requested the applicant to confirm the connecting piping was
 
included within the scope of license renewal and subjected to AMR as structural boundary or to
 
justify its exclusion. In addition, the staff requested the applicant to modify Table 2.3.2-2 to
 
reflect the response.
 
In its response dated November 14, 2007, the applicant stated:
 
The piping between the RCIC Barometric Condenser Vacuum Tank air
 
space and the suction of the RCIC Barometric Condenser Vacuum Pump
 
is not in-scope because these lines are not fluid filled. The RCIC
 
Barometric Condenser Vacuum Pump is primarily removing air and non-
 
condensables from the steam that is condensed in the RCIC Barometric
 
Condenser. Therefore, this segment of piping does not contain sufficient
 
liquid that would leak or spray on adjacent equipment. 
 
The RCIC Barometric Condenser Vacuum Pump and associated
 
discharge piping is highlighted in magenta because it provides a
 
structural integrity function for safety-related connected piping as
 
indicated in license renewal note C on the subject drawings. The piping
 
between the RCIC Barometric Condenser Vacuum Tank air space and
 
the suction of the RCIC Barometric Condenser Vacuum Pump does not
 
provide structural integrity for either the RCIC Barometric Condenser or
 
Barometric Condenser Vacuum Pump, which also supports the piping not
 
included in-scope for license renewal. Based on the above, LRA
 
drawings LR-M-150 and LR-M-2150, Sheet 1, H7 are correct and no
 
change is required.
 
Review of LRA Table 2.3.2-2 and Table 3.2.2-2 identified that the RCIC
 
Barometric Condenser Vacuum Pump (1/2P219) was inadvertently
 
omitted from these tables. In addition, it was identified that the piping
 
between the RCIC Barometric Condenser Vacuum Pump discharge and
 
the suppression pool was inadvertently omitted from Table 3.2.2-2. The
 
license renewal application was amended to include the RCIC Barometric
 
Condenser Vacuum Pump and associated discharge piping as subject to
 
aging management review.
 
The applicant submitted revised LRA Tables 2.3.2-2 and 3.2.2-2.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.2.2-1 acceptable
 
because the applicant explained that the piping in question is not fluid filled and the RCIC
 
Barometric Condenser Vacuum Pump removes air and non-condensables from steam. The
 
applicant also explained that the piping in question does not provide structural integrity for any
 
required components. The applicant identified severa l items that were inadvertently omitted from LRA Tables 2.3.2-2, "Reactor Core Isolat ion Cooling System Components Subject to Aging Management Review," and Table 3.2.2-2, "Aging management review Results - Reactor Core
 
Isolation Cooling System." The applicant amended the LRA to include these revised tables.
 
Therefore, the staff's concern described in RAI 2.3.2.2-1 is resolved.
 
2-43  2.3.2.2.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, boundary drawings, RAI responses, and revised LRA
 
tables 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. On the basis of its review, the staff concludes that the
 
applicant has appropriately identified reactor core isolation cooling system mechanical
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the
 
applicant has adequately identified the reactor core isolation cooling system components
 
subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.2.3  Core Spray System
 
2.3.2.3.1  Summary of Technical Information in the Application
 
LRA Section 2.3.2.3 describes the CSS, which, as part of the overall emergency core cooling
 
system, is designed to provide cooling to the reactor core only when the RV pressure is low, as
 
for a large-break loss-of-coolant accident (LOCA). However, when operating with the automatic
 
depressurization system, the effective CSS core cooling capability extends to all break sizes as
 
the automatic depressurization system rapidly reduces the RV pressure to the CSS operating
 
range. The CSS contains safety-related components relied upon to remain functional during and
 
following DBEs. The failure of nonsafety-related SSCs in the CSS potentially could prevent the
 
satisfactory accomplishment of a safety-related function. In addition, the CSS performs
 
functions that support fire protection and EQ. LRA Table 2.3.2-3 identifies CSS component
 
types within the scope of license renewal and subject to an AMR.
 
2.3.2.3.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the CSS system mechanical components within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the
 
system components subject to an aging managem ent review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.2.4  High Pressure Coolant Injection System 2.3.2.4.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.2.4 describes the HPCI system, which consists of a steam-driven turbine-pump unit, valves, and piping that can deliver water from the condensate storage tank (CST) or from
 
the suppression pool to the RV via one of the feedwater lines. The HPCI system contains
 
safety-related components relied upon to remain functional during and following DBEs. The
 
failure of nonsafety-related SSCs in the HPCI sy stem potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the HPCI system performs functions that support fire protection, ATWS, SBO, and EQ. LRA Table 2.3.2-4 identifies HPCI system
 
component types within the scope of license renewal and subject to an AMR.
 
2-44 2.3.2.4.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.2.4 and UFSAR Section 6.3.2.2.1 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff's
 
review identified areas where 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 2.3.2.4-1, dated October 24, 2007, the staff noted that in boundary drawing LR-M-156-1, the drive shaft from the HPCI turbine to the HPCI pump was shown in-scope, however, the drive shaft between the HPCI pump and booster pump was not. The staff requested that the applicant
 
clarify whether the drive shafts were in-scope, thus, requiring an AMR and; if excluded, provide
 
justification.
 
In its response to RAI 2.3.2.4-1, dated November 14, 2007, the applicant stated:
 
The highlighting of the drive shaft between the HPCI pump and booster
 
pump on boundary drawing LR-M-156-1 wa s inadvertently omitted. The entire drive shaft is within the scope of license renewal. The highlighting
 
has been corrected to show this drive shaft highlighted in green. The unit
 
2 boundary drawing, LR-M-2156-1 shows the correct highlighting.
 
The drive shafts and gearbox between the HPCI booster pump and the
 
HPCI pump and the drive shafts between the HPCI pump and the HPCI
 
turbine are within the scope of license renewal. The drive shafts and gear
 
box are considered to be active components and therefore are not
 
subject to aging management review. 
 
This was a highlighting omission on a boundary drawing and no changes
 
to the LRA are required.
 
The staff confirmed that the applicant has submitted revised boundary drawing LR-M-156-1.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.2.4-1 acceptable
 
because the applicant clarified that the highlighting of the drive shaft between the HPCI pump
 
and booster pump was in error and the drive shaft is in-scope. The staff confirms that the
 
applicant has submitted a corrected boundary drawing LR-M-156-1. Therefore, the staff's
 
concern described in RAI 2.3.2.4-1 is resolved.
2.3.2.4.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, boundary drawings (original and revised), and
 
RAI responses 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. On the basis of its review, the staff concludes
 
that the applicant has appropriately identified the HPCI system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has
 
adequately identified the HPCI system components subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1) and; therefore, is acceptable.
 
2-45 2.3.2.5  Containment and Suppression System  2.3.2.5.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.2.5 describes the containment and suppression system, which maintains the
 
structural and functional integrity of the primary containment during and following a design-basis
 
LOCA. The system also monitors suppressi on pool level, pressure, and temperature and provides for suppression pool cleanup. The containment and suppression system contains
 
safety-related components relied upon to remain functional during and following DBEs. The
 
failure of nonsafety-related SSCs in the cont ainment and suppression system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the
 
containment and suppression system performs func tions that support fire protection, ATWS, SBO, and EQ. LRA Table 2.3.2-5 identifies c ontainment and suppression system component types within the scope of license renewal and subject to an AMR.
 
2.3.2.5.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.2.5 and UFSAR Section 6.2.1 using the evaluation
 
methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff's
 
review identified areas where additional information was required to complete the scoping and
 
screening results. The applicant responded to the staff's RAIs as discussed below.
 
In RAI 2.3.2.5-1 dated July 25, 2007, the staff noted that on boundary drawing LR-M-157, Sheet 4, one-inch valve 157011 at penetration X-234A and one-inch valve 157023 at penetration X-232A, which belong to suppression pool level monitoring system, are shown as
 
not within the scope of license renewal. The staff requested that the applicant provide
 
justification for the exclusion of these valves from the scope of license renewal. If these valves are within the scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an
 
AMR in accordance with 10 CFR 54.21(a)(1), the staff requested that the applicant update the
 
LRA by providing the applicable information in the appropriate LRA sections, tables, and
 
boundary drawings.
In its response to RAI 2.3.2.5-1, dated August 23, 2007, the applicant stated:
 
Boundary drawing LR-M-157 Sheet 4 contained an error related to highlighting. Valve 157011 at penetration X-234A and valve 157023 at penetration X-232A are both in-scope and subject to aging management review, but they were inadvertently not highlighted. Both valves have been highlighted in green on the revised boundary drawing LR-M-157 Sheet 4, included as Attachment 1.
 
In the course of addressing this RAI, it was also noticed that the highlighting at penetration X-90D for one-inch line HCB-112 was slightly different from the highlighting for the other pipelines at penetrations X-90A and X-90D. The short length of piping between valve 157077 and the penetration should have been highlighted. This piping is in-scope and subject to aging management review, but was inadvertently not highlighted. This piping has been highlighted in green on the revised boundary drawing LR-M-157 Sheet 4, included as Attachment 1.
 
2-46 No changes to the LRA are required as valves 157011 and 157023 are addressed in Table 2.3.2-5, and the material/environment combinations for the valve bodies are addressed in Table 3.2.2-5. The additional piping component associated with one-inch line HCB-112 belongs to the Containment Atmosphere Control System. No changes to the LRA are required as the piping is included in Table 2.3.2-6 and the material/environment combinations for the piping are addressed in Table 3.2.2-6.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.2.5-1 acceptable because the applicant clarified that the that one-inch valve 157011 at penetration X-234A and one-inch valve 157023 at penetration X-232A are within the scope of license renewal and were
 
inadvertently not highlighted. The staff confirms that the applicant has provided revised
 
boundary drawing LR-M-157, Sheet 4, with correct highlighting. Therefore, the staff's concern
 
described in RAI 2.3.2.5-1 is resolved.
 
In RAI 2.3.2.5-2, dated July 25, 2007, the staff noted that LRA Section 2.3.2.5, "Containment
 
and Suppression System" under "License Renewal Drawings" lists boundary drawings
 
LR-M-151 Sheet 1, and LR-M-155 Sheet 1 for Un it 1, and LR-M-2151 Sheet 1, and LR-M-2155, Sheet 1 for Unit 2. The staff requested that the applicant clarify which functions or items shown
 
in these boundary drawing belong to the containment and suppression system. 
 
In its response to RAI 2.3.2.5-2, dated August 23, 2007, the applicant stated:
 
The evaluation boundaries of the Containment and Suppression System that are shown on drawing LR-M-151 Sheet 1 for Unit 1 (LR-M-2151 Sheet 1 for Unit 2) are within the Non Safety Affecting Safety (NSAS) boundaries highlighted in magenta and extend from valve 151089 in zone B-1 for Unit 1 (valve 251088 in zone B-1 for Unit 2) through four-inch pipeline HBD-173 (4-inch HBD-273 for Unit 2) and continuing on drawing LR-M-157 Sheet 1 for Unit 1 (LR-M2157 Sheet 1 for Unit 2). Components within these boundaries, subject to aging management review, are included as piping and piping components with a structural integrity function, as listed in Table 2.3.2-5 in LRA Section 2.3.2.5.
 
The evaluation boundaries of the Containment and Suppression System that are shown on drawing LR-M-155 Sheet 1 for Unit 1 (LR-M-2155 Sheet 1 for Unit 2) extend from penetrations X-219A and X-219B in zone G-3/H-3 to and including level switches LSH-E41-1N015A & B for Unit 1 (E41-2N015A & B for Unit 2) and continuing to drawing LR-M-157 Sheet 8 for Unit 1 (LR-M-2157 Sheet 8 for Unit 2). Components within these boundaries, subject to aging management review, include condensing pots, piping, tubing, and valve bodies, all of which are listed in Table 2.3.2-5 in LRA Section 2.3.2.5 with a pressure boundary function.
 
Based on the discussion above, no changes to the LRA are required.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.2.5-2 acceptable
 
because the applicant clarified which components are parts of the containment and suppression 2-47 system. Therefore, the staff's concern described in RAI 2.3.2.5-2 is resolved.
 
2.3.2.5.3 Conclusion 
 
The staff reviewed the LRA, UFSAR, boundary drawings (original and revised), and
 
RAI responses 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. On the basis of its review, the staff concludes
 
that the applicant has appropriately identif ied the containment and suppression system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a),
and that the applicant has adequately identified the containment and suppression system
 
components subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1)
 
and; therefore, is acceptable.
 
2.3.2.6  Containment Atmosphere Control System 2.3.2.6.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.2.6 describes the containment atmosphere control (CAC) system, which is
 
designed to control the concentration of hydrogen within the primary containment following a
 
LOCA. The CAC system contains safety-related components relied upon to remain functional
 
during and following DBEs. The failure of nonsafety-related SSCs in the CAC system potentially
 
could prevent the satisfactory accomplishment of a safety-related function. In addition, the CAC
 
system performs functions that support fire protection, SBO, and EQ. LRA Table 2.3.2-6
 
identifies CAC system component types within the scope of license renewal and subject to an
 
AMR.
2.3.2.6.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.2.6 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. The staff's
 
review identified areas where additional information was required to complete the scoping and
 
screening results. The applicant responded to the staff's RAIs as discussed below.
 
In RAI 2.3.2.6-1, dated July 25, 2007, the staff noted that LRA Section 2.3.2.6 identifies the
 
Combustible Gas Control System described in UFSAR Section 6.2.5 as Containment
 
Atmosphere Control System for license renewal. The description and functions of Containment
 
Atmospheric Control System as described in LRA Section 2.3.2.6 is not consistent with the
 
description given in UFSAR Section 6.2.5 for Units 1 and 2. According to UFSAR
 
Section 6.2.5.2, the combustible gas control depends on the following functions and
 
subsystems:
 
(a)    Hydrogen mixing (b)    Hydrogen and oxygen monitoring system (c)    Hydrogen recombiner system (d)    Containment hydrogen purge system (e)    Containment nitrogen inerting system
 
The LRA Section 2.3.2.6 does not mention the Containment Nitrogen Inerting System which
 
maintains the primary containment inerted with nitrogen during power operation, with oxygen 2-48 concentration not to exceed 4% by volume. The staff requested the applicant either add the description of Containment Nitrogen Inerting System in LRA Section 2.3.2.6 or add another
 
section to the LRA describing this system and its license renewal function.
 
In its response to RAI 2.3.2.6-1, dated August 23, 2007, the applicant stated:
While FSAR Section 6.2.5 identifies containment nitrogen inerting as a function of the combustible gas control system, identified as Containment Atmosphere Control in the LRA, nitrogen inerting is not an engineered safety feature (ESF) function.
 
The Nitrogen and Hydrogen System is described in LRA Section 2.3.3.16.
As stated in Section 2.3.3.16, a nonsafety-related portion of this system is identified as in-scope based on the scoping criteria of 10 CFR 54.4(a)(2).
This is illustrated on license renewal drawings LR-M-157 Sheet 1 for Unit 1 and LR-M-2157 Sheet 1 for Unit 2 at zone C-8 by the piping and components shown in magenta.
 
The piping and components related to the function of containment nitrogen inerting and makeup that are highlighted in green on LR-M-157 Sheet 1 and LR-M-2157 Sheet 1 have a safety-related function to provide primary containment isolation and maintain containment integrity. These components are addressed in LRA Section 2.3.2.6 as in-scope based on the scoping criteria of 10 CFR 54.4(a)(1) because they support either the functional or structural integrity of the primary containment. Both LRA Sections 2.3.3.16 and 2.3.2.6 reference drawings LR-M-157 Sheet 1 and LR-M-2157 Sheet 1 which depict the in-scope portions of the Nitrogen and Hydrogen System and the Containm ent Atmosphere Control System.
Based on a teleconference between PPL and the NRC Staff on July 10, 2007, revisions discussed for LRA Sections 2.3.2.5 and 2.3.2.6 are provided in Attachments 2 and 3. The revisions to both attachments consist of added text which is shown in bold italics.
Based on its review, the staff finds the applicant's response to RAI 2.3.2.6-1 acceptable
 
because the applicant clarified what is included in the containment and suppression system.
 
The staff confirms that the applicant has provided revised LRA Sections 2.3.2.5 and 2.3.2.6.
 
Therefore, the staff's concern described in RAI 2.3.2.6-1 is resolved.
 
In RAI 2.3.2.6-2, dated July 25, 2007, the staff noted that UFSAR Table 6.2-12, "Containment Penetration Data," shows the 24-inch butterfly valve HV15722 as a containment isolation safety-related valve located at drywell penetration X-25. This valve
 
located in zone C-5 of boundary drawing LR-M-157 Sheet No. 1 is shown as not within
 
the scope of license renewal. The staff requested that applicant provide justification for
 
the exclusion of this valve from the scope of license renewal. If this valve is within the
 
scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an AMR in
 
accordance with 10 CFR 54.21(a)(1), the staff requested that the applicant update the
 
LRA by providing the applicable information in the appropriate LRA sections, tables, and
 
boundary drawings.
 
2-49 In its response, dated August 23, 2007, the applicant stated:
Boundary drawing LR-M-157 Sheet 1 contained an error related to highlighting. Valve 157022 and the short length of piping between the valve and penetration X-25 are in-scope and subject to aging management review, but they were inadvertently not highlighted. The valve and the piping have been highlighted in green on the revised boundary drawing LR-M-157 Sheet 1, included as Attachment 4
 
No changes to the LRA are required as the valve and piping are included Table 2.3.2-6 and the material/environment combinations for the valve and piping are addressed in Table 3.2.2-6.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.2.6-2 acceptable because the applicant clarified that valve 157022 and the short length of piping between the valve and penetration X-25 are in-scope and subject to an AMR. The staff confirms that the applicant
 
has provided a revised boundary drawing LR-M-157, Sheet 1.
Therefore, the staff's concern described in RAI 2.3.2.6-2 is resolved.
 
In RAI 2.3.2.6-3, dated July 25, 2007, the staff noted that LRA Section 2.3.2.6, "Containment Atmosphere Control System", under the heading "L icense Renewal Drawings", lists LR-M-157, Sheets 6 and 7 for Unit 1, and LR-M-2157, Sheets 6 and 7 for Unit 2. These boundary drawings
 
provide containment radiation monitoring details that appear to not have any item described in LRA Section 2.3.2.6. The staff requested that the applicant provide justification for listing these
 
boundary drawings in LRA Section 2.3.2.6. If any of the system components in these boundary
 
drawings belong to the LRA Section 2.3.2.6, the staff requested that the applicant provide a list
 
of these components and revise LRA Table 2.3.2-6, as required. (Note that suppression pool
 
level and temperature functions are covered in the containment and suppression system in LRA
 
Section 2.3.2.5, which lists these boundary drawings under "License Renewal Drawings" and
 
the containment radiation monitoring system is covered in LRA Section 2.3.3.18, which lists
 
these under the heading "License Renewal Drawing").
 
In its response to RAI 2.3.2.6-3, dated August 23, 2007, the applicant stated:
 
The Containment Radiation Monitoring (CRM) Panels (1C291A/B for Unit 1 and 2C291A/B for Unit 2) and all components within them (shown on drawings LR-M-157 Sheets 6 and 7 for Unit 1 and LR-M-2157 Sheets 6 and 7 for Unit 2) are within the evaluation boundaries of the Process and Area Radiation Monitoring System. In accordance with the guidance provided in NEI 95-10 Appendix B, radiation monitors are considered to be active components and, therefore, not subject to aging management review. This conclusion is presented, along with a description of the Process and Area Radiation Monitoring System and reference to the above mentioned drawings, in LRA Section 2.3.3.18.
 
Drawings LR-M-157 Sheets 6 and 7 for Unit 1 (LR-M-2157 Sheets 6 and 7 for Unit 2) are also included in LRA Section 2.3.2.6 because components that are within the evaluation boundaries of the Containment Atmosphere Control (CAC) System are depicted. The CAC System evaluation boundaries extend from penetrations X-5 and X-91A for Unit 1 2-50 (X-5 and X-31B for Unit 2) to the pipe-to-tubing interface at CRM Panels 1C291A/B for Unit 1 (2C291A/B for Unit 2), and include the piping and valve bodies. The piping and valve bodies are evaluated in LRA Section 2.3.2.6, and the tubing is evaluated with the Process and Area Radiation Monitoring System in LRA Section 2.3.3.18.
Based on the discussion above, no changes to the LRA are required.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.2.6-3 acceptable
 
because the applicant clarified that LR-M-157 Sheets 6 and 7 contain components that are in
 
the CAC system; thus, boundary drawing LR-M-157 Sheets 6 and 7 are listed in LRA
 
Section 2.3.2.6. Therefore, the staff's concern described in RAI 2.3.2.6-3 is resolved.
 
In RAI 2.3.2.6-4, dated July 25, 2007, the staff noted that LRA Section 2.3.2.6, "Containment
 
Atmosphere Control System", under the heading "License Renewal Drawings", lists
 
LR-M-157 Sheet 8 for Unit 1, and LR-M-2157 Sheet 8 for Unit 2. These boundary drawings
 
provide details of suppression pool level and pressure monitoring that appears to not have
 
any items described in LRA Section 2.3.2.6. The staff requested that the applicant provide
 
justification for listing the above boundary drawings in LRA Section 2.3.2.6. If any of the
 
system components in these boundary drawings belong to the LRA Section 2.3.2.6, the staff
 
requested that the applicant provide a list of these components and revise LRA
 
Table 2.3.2-6, as required. (Note that suppression pool level and temperature functions are
 
covered in the containment and suppression system in LRA Section 2.3.2.5, which lists
 
these boundary drawings under the heading "License Renewal Drawings").
 
In its response to RAI 2.3.2.6-4, dated August 23, 2007, the applicant stated:
 
All tubing and valve bodies associated with level transmitters LT-15775A and LT-25775A, as shown on drawings LR-M-157 Sheet 8 and LR-M-2157 Sheet 8, respectively, are within the evaluation boundaries of the Containment and Suppression System and are listed in Table 2.3.2-5 in LRA Section 2.3.2.5. All other components that are shown on drawings LR-M-157 Sheet 8 and LR-M-2157 Sheet 8 are within the evaluation boundaries of the Containment Atmosphere Control (CAC) System and are listed in Table 2.3.2-6 in LRA Section 2.3.2.6 (tubing and valve bodies).
Based on the discussion above, no changes to the LRA are required.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.2.6-4 acceptable
 
because the applicant provided a list of com ponents in LR-M-157, Sheet 8 and LR-M-2157, Sheet 8 that are in the CAC system. Therefore, the staff's concern described in RAI 2.3.2.6-4
 
is resolved.
 
In RAI 2.3.2.6-5, dated July 25, 2007, the staff noted boundary drawing LR-M-157, Sheet 1, zone F-3, at primary containment penetration X-221A, shows the piping component at the
 
upstream side of valve 157201 as not within the scope for license renewal. The staff
 
requested that the applicant provide justification for the exclusion of this piping component
 
from the scope of license renewal. If this component is within the scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an AMR, in accordance with 2-51 10 CFR 54.21(a)(1), the staff requested that the applicant update the LRA by providing the applicable information in the appropriate LRA sections, tables, and boundary drawings.
 
In its response to RAI 2.3.2.6-5, dated August 23, 2007, the applicant stated:
 
Boundary drawing LR-M-157 Sheet 1 contained an error related to highlighting. Valve 157201 at penetration X-221A has a two-inch by one-inch reducer that is in-scope and subject to aging management review, but it was inadvertently not highlighted. The reducer has been highlighted in green on the revised boundary drawing LR-M-157 Sheet 1, included as Attachment 4.
 
No changes to the LRA are required as the reducer is included in Table 2.3.2-6 and the material/environment combinations for the reducer are addressed in Table 3.2.2-6.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.2.6-5 acceptable because the applicant has clarified that boundary drawing LR-M-157, Sheet 1, contained a highlighting error regarding valve 157201 at penetration X-221A. The staff confirms that the
 
applicant has submitted revised boundary drawing LR-M-157 Sheet 1. Therefore, the staff's
 
concern described in RAI 2.3.2.6-5 is resolved.
 
2.3.2.6.3 Conclusion 
 
The staff reviewed the LRA, UFSAR, boundary drawings (original and revised), and
 
RAI responses 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. On the basis of its review, the staff concludes
 
that the applicant has appropriately identified CAC system mechanical components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately
 
identified the CAC system components subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1) and; therefore, is acceptable.
2.3.2.7  Standby Gas Treatment System 2.3.2.7.1  Summary of Technical Information in the Application
 
LRA Section 2.3.2.7 describes the SBGT common to both units. The system is designed for two
 
purposes: (1) to exhaust filtered air from the Reactor Building to maintain a negative pressure in
 
the affected volumes following secondary containment isolation for a spent fuel handling
 
accident or for a LOCA and (2) to filter the exhausted air to remove radioactive particulates and
 
both radioactive and nonradioactive forms of iodine to limit offsite dose. The SGTS contains
 
safety-related components relied upon to remain functional during and following DBEs. In
 
addition, the SGTS performs functions that support EQ. LRA Table 2.3.2-7 identifies SGTS
 
component types within the scope of license renewal and subject to an AMR.
 
2.3.2.7.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has 2-52 appropriately identified the SBGT system mec hanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the
 
system components subject to an aging managem ent review in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3  Auxiliary Systems In LRA Section 2.3.3, the applicant identified the auxiliary systems SCs subject to an AMR for license renewal. The applicant described the suppor ting SCs of the auxiliary systems in the following LRA sections:
* 2.3.3.1 Building drains nonradioactive system
* 2.3.3.2 Containment instrument gas system
* 2.3.3.3 Control rod drive hydraulics system
* 2.3.3.4 Control structure chilled water system
* 2.3.3.5 Control structure HVAC systems
* 2.3.3.6 Cooling tower system
* 2.3.3.7 Diesel fuel oil system
* 2.3.3.8 Diesel generator buildings HVAC systems
* 2.3.3.9 Diesel generator system
* 2.3.3.10 Domestic water system
* 2.3.3.11 Emergency service water system
* 2.3.3.12  Engineered safeguards service water pumphouse HVAC system
* 2.3.3.13  Fire protection system
* 2.3.3.14  Fuel pool cooling and cleanup system and fuel pools and auxiliaries
* 2.3.3.15  Neutron monitoring system
* 2.3.3.16  Nitrogen and hydrogen system
* 2.3.3.17  Primary containment atmosphere circulation system
* 2.3.3.18  Process and area radiation monitoring system
* 2.3.3.19  Radwaste liquid system
* 2.3.3.20  Radwaste solids handling system
* 2.3.3.21  Raw water treatment system
* 2.3.3.22  Reactor building chilled water system
* 2.3.3.23  Reactor building closed cooling water system
* 2.3.3.24  Reactor building HVAC system
* 2.3.3.25  Reactor nonnuclear instrumentation system
* 2.3.3.26  Reactor water cleanup system
* 2.3.3.27  RHR service water system
* 2.3.3.28  Sampling system
* 2.3.3.29  Sanitary drainage system
* 2.3.3.30  Service air system
* 2.3.3.31  Service water system
* 2.3.3.32  Standby liquid control system
* 2.3.3.33  Turbine building closed cooling water system
 
Auxiliary Systems Generic Requests for Additional Information As part of the staff's review, the following RAIs identified instances of boundary drawing errors
 
where the continuation notation for piping from one boundary drawing to another boundary
 
drawing could not be identified or was incorrect:
2-53
* RAI 2.3.3.14-1
* RAI 2.3.3.14-2
* RAI 2.3.3.14-11
* RAI 2.3.3.27-1
* RAI 2.3.3.27-2
* RAI 2.3.3.31-2
 
In its response, dated October 18, 2007, the applicant noted these were typographical errors
 
and submitted revised the boundary drawings.
 
Based on its review, the staff finds the applicant's responses to these RAIs acceptable because
 
the applicant revised the boundary drawings to correct the errors. Therefore, the staff's
 
concerns described in the RAIs noted above are resolved.
2.3.3.1  Building Drains Nonradioactive System 2.3.3.1.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.1 describes the building drains nonradioactive system operating throughout
 
the plant. The failure of nonsafety-related SSCs in the building drains nonradioactive system
 
potentially could prevent the satisfactory acco mplishment of a safety-related function. LRA Table 2.3.3-1 identifies building drains nonradioactive system component types within the scope
 
of license renewal and subject to an AMR.
 
2.3.3.1.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the building drains nonradioactive system mechanical components
 
within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has
 
adequately identified the system components subject to an aging management review in
 
accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.2  Containment Instrument Gas System 2.3.3.2.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.2 describes the containment in strument gas system, which provides filtered, dry, oil-free instrument gas to the pneumatic devices located inside the drywell and suppression
 
chamber. The failure of nonsafety-related SSCs in the containment instrument gas system potentially could prevent the satisfactory acco mplishment of a safety-related function. In addition, the containment instrument gas system performs functions that support fire protection, SBO, and EQ. LRA Table 2.3.3-2 identifies cont ainment instrument gas system component types within the scope of license renewal and subject to an AMR.
 
2.3.3.2.2 Conclusion
 
2-54 Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the containment instru ment gas system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has
 
adequately identified the system components subject to an aging management review in
 
accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.3  Control Rod Drive Hydraulics System 2.3.3.3.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.3 describes the control rod dr ive hydraulic system (CRDHS), which controls gross changes in core reactivity by increment ally positioning neutron-absorbing control rods within the reactor core in response to manual control signals initiated by the reactor manual
 
control system. The CRDHS also must shut down the reactor quickly (scram) in response to
 
manual or automatic signals in emergency situations by rapidly inserting withdrawn control rods
 
into the core. The CRDHS contains safety-related components relied upon to remain functional
 
during and following DBEs. The failure of nonsafety-related SSCs in the CRDHS potentially
 
could prevent the satisfactory accomplishment of a safety-related function. In addition, the
 
CRDHS performs functions that support fire protection, ATWS, and EQ. LRA Table 2.3.3-3
 
identifies CRDHS component types within the scope of license renewal and subject to an AMR.
 
2.3.3.3.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the CRDHS mechanical components within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the
 
system components subject to an aging managem ent review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.4  Control Structure Chilled Water System 2.3.3.4.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.4 describes the control structure chilled-water system, which supplies chilled
 
water to the cooling coils in the control room floor cooling unit, computer room floor cooling unit, and control structure heating and ventilation unit. The control structure chilled-water system
 
contains safety-related components relied upon to remain functional during and following DBEs.
 
The failure of nonsafety-related SSCs in the cont rol structure chilled-water system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the
 
control structure chilled-water system performs functions that support EQ. LRA Table 2.3.3-4
 
identifies control structure chilled-water system component types within the scope of license
 
renewal and subject to an AMR.
 
2.3.3.4.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.4, UFSAR Section 9.2.12.1, and the licensing renewal
 
boundary drawings using the evaluation methodology described in SER Section 2.3 and the
 
guidance in SRP-LR Section 2.3. The staff's review identified areas in which additional 2-55 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 RAIs 2.3.3.4-1, 2.3.3.4-2, and 2.3.3.4-3, dated August 27, 2007, the staff noted instances
 
where boundary drawings identified portions of piping as within the scope of license renewal
 
that are continued on other boundary drawings, where the piping is not shown to be within the
 
scope of license renewal on the continuation boundary drawings. The staff requested that the
 
applicant clarify why the continuations are not within the scope of license renewal.
 
In its response to RAIs 2.3.3.4-1, 2.3.3.4-2, and 2.3.3.4-3, dated October 18, 2007; the
 
applicant stated that the subject piping was within the scope of license renewal. The applicant
 
submitted revised boundary drawings to reflect t he piping as being within the scope of licensing renewal.
 
Based on its review of the applicant's revised boundary drawings, the staff finds the applicant's
 
response to RAIs 2.3.3.4-1, 2.3.3.4-2, and 2.3.3.4-3 acceptable because the applicant has
 
clarified that the piping in question was within the scope of license renewal and has made the
 
appropriate revisions to the subject boundary drawings. Therefore, the staff's concerns
 
described in RAIs 2.3.3.4-1, 2.3.3.4-2, and 2.3.3.4-3 are resolved.
 
In RAI 2.3.3.4-4, dated August 27, 2007, the staff noted that the safety-related control
 
structure H/V unit cooling coils were within the scope of license renewal, pursuant to
 
10 CFR 54.4(a)(1). However, these cooling coils were omitted from LRA Table 2.3.3-4 for
 
components subject to an AMR. The staff requested that the applicant explain why these
 
cooling coils are not included in LRA Table 2.3.3-4.
 
In its response, dated October 18, 2007, the applicant stated:
 
The control structure H/V units 0V103A and 0V103B, including cooling
 
coils 0E146A1 through B2 are within the scope of license renewal and
 
are subject to AMR. Based on PPL's scoping methodology, these cooling
 
coils have been scoped with the control structure HVAC systems and are
 
included in LRA Section 2.3.3.5 and Table 2.3.3-5.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.4-4 acceptable
 
because the applicant adequately explained that the AMR for the cooling coils in question is
 
covered in LRA Section 2.3.3.5 and Table 2.3.3-5. Therefore, the staff's concern described in
 
RAI 2.3.3.4-4 is resolved.
 
In RAIs 2.3.3.4-5 and 2.3.3.4-6, dated August 27, 2007, the staff noted that the safety-related
 
control room floor recirculation unit cooling coils were within the scope of license renewal in
 
accordance with 10 CFR 54.4(a)(1) criterion. However, these cooling coils were omitted from
 
LRA Table 2.3.3-4 for components subject to an AMR. The staff requested that the applicant
 
explain why these cooling coil components are not included in LRA Table 2.3.3-4. 
 
In its response to RAIs 2.3.3.4-5 and 2.3.3.4-6, dated October 18, 2007, the applicant stated:
 
The control room floor recirculation units 0V117A and 0V117B, including cooling coils 0E151A1 through B2, are within the scope of license 2-56 renewal and are subject to AMR. Based on PPL's scoping methodology, these cooling coils have been scoped with the Control Structure HVAC Systems and are included in LRA Section 2.3.3.5 and Table 2.3.3-5.
Based on its review, the staff finds the applicant's response to RAIs 2.3.3.4-5 and 2.3.3.4-6
 
acceptable because the applicant explained that the cooling coils in question are covered in
 
LRA Section 2.3.3.5 and Table 2.3.3-5. Therefore, the staff's concern described in
 
RAIs 2.3.3.4-5 and 2.3.3.4-6 is resolved.
 
2.3.3.4.3 Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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. On the basis of its review, the staff concludes the applicant has
 
appropriately identified the control structure chilled-water system mechanical components within
 
the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has
 
adequately identified the control structure chilled-water system mechanical components subject
 
to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1) and; therefore, is
 
acceptable.
2.3.3.5  Control Structure Heating, Ventilation, and Air Conditioning (HVAC) Systems  2.3.3.5.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.5 describes the control structure HVAC systems. The control structure HVAC
 
systems contain safety-related components relied upon to remain functional during and
 
following DBEs. The failure of nonsafety-related SSCs in the control structure HVAC system
 
potentially could prevent the satisfactory acco mplishment of a safety-related function. In addition, the control structure HVAC system s perform functions that support EQ. LRA Table 2.3.3-5 identifies control structure HVAC systems component types within the scope of license renewal and subject to an AMR.
 
2.3.3.5.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the control structure HVAC systems mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately
 
identified the system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.6  Cooling Tower System 2.3.3.6.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.6 describes the single-loop cooling tower system consisting of a hyperbolic
 
natural draft cooling tower, cooling tower basin, blowdown and makeup water systems, and
 
chemical and blowdown treatment systems. The c ooling tower system dissipates both latent heat from the main condenser and sensible heat from the service water system (SWS). The 2-57 cooling tower system performs functions that support fire protection. LRA Table 2.3.3-6 identifies cooling tower system component types within the scope of license renewal and
 
subject to an AMR.
 
2.3.3.6.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.6, UFSAR Sections 9.2.1 and 10.4.5, and the licensing
 
renewal boundary drawings using the evaluation methodology described in SER Section 2.3
 
and the guidance in SRP-LR Section 2.3. The staff's review identified areas in which additional
 
information was necessary to complete the review of the applicant's scoping and screening
 
results. The applicant responded to the staff's RAIs as discussed below.
 
In RAI 2.3.3.6-1, dated August 27, 2007, the staff noted that one of the stated purposes of the
 
cooling tower system is to supply water to the fire protection system and therefore, complies
 
with the scoping criteria of 10 CFR 54.4(a)(3). Boundary drawings LR-M-115-1, LR-M-2115-1, and LR-M-109-1 show supply lines from the cooling tower basin to the fire pumps within the
 
scope of license renewal, with a pressure boundary intended function. However, connected
 
piping is not within the scope of license renewal up to the first isolation valve, where it connects
 
to the SW and circulating water pumps. The staff requested that the applicant explain why these
 
sections of pipe and components are not within scope for license renewal.
 
In its response to RAI 2.3.3.6-1, dated October 18, 2007, the applicant stated:
 
The highlighted piping depicts the supply path for water from the cooling
 
tower basins to the fire protection pumps. This supply path meets the
 
criteria of 10 CFR 54.4(a)(3) for fire protection. Inclusion of the connected
 
piping up to the service water and circulating water pump isolation valves
 
in the scope of license renewal is not necessary to ensure that the
 
intended function is maintained.
 
As described in Section 2.3.3.6 of the LRA, each cooling tower basin
 
contains 6,000,000 gallons of water, and is capable of meeting the
 
largest expected water demands of the fire protection system. As
 
described in Section 4.1 of the Fire Protection Review Report (FPRR),
the largest single (fire protection) demand can be satisfied by one fire
 
pump, rated at 2500 gpm. Operability of the fire suppression water supply
 
is controlled in accordance with the SSES Technical Requirements
 
Manual (TRM). The TRM ensures at least one flow path capable of taking
 
suction from any two designated water supplies and an available supply
 
of water, from either the Unit 1 or Unit 2 cooling tower basin or the
 
clarified water storage tank, with a minimum volume of 300,000 gallons.
 
Due to the large volume available from a single cooling tower basin, in
 
relation to the fire protection demand, inclusion of the connected piping
 
up to the service water and circulating water pump isolation valves is not
 
necessary to ensure this secondary supply of fire protection water.
 
As the fire suppression water supply is maintained operable the
 
connected sections of piping will not affect the intended function of the
 
Cooling Tower System. Therefore, the subject piping is not included
 
within the scope of license renewal.
2-58  Based on its review, the staff finds the applicant's response to RAI 2.3.3.6-1 acceptable
 
because the applicant has clarified that the highlighted piping depicts the supply path for water
 
from the cooling tower basins to the fire protection pumps and is the total piping required for
 
compliance with 10 CFR 54.4(a)(3) for fire protection. The staff reviewed the UFSAR and the
 
Fire Protection Review Report and confirms the applicant's statement. The staff also confirms
 
that there are no hypothetical failures resulting from system interdependencies that would affect this piping identified in the CLB and none has been previously experienced. Therefore, the
 
staff's concern described in RAI 2.3.3.6-1 is resolved.
 
In RAI 2.3.3.6-2, dated August 27, 2007, the staff noted that one of the stated purposes of the
 
cooling tower system is to supply water to the fire protection system and therefore, complies
 
with the scoping criteria of 10 CFR 54.4(a)(3). Boundary drawings LR-M-115-1, LR-M-2115-1, and LR-M-109-1 show supply lines from the cooling tower basin to the fire pumps as within the
 
scope of license renewal, with a pressure boundary intended function. However, boundary
 
drawing LR-M-2115-1, location A4, and the continuation onto boundary drawing LR-M-2109-1, location D1, shows the supply line to the SWS is not within the scope of license renewal. The
 
staff requested that the applicant explain why these sections of pipe and components are not
 
within scope of license renewal.
 
In its response to RAI 2.3.3.6-2, dated October 18, 2007, the applicant stated:
 
The highlighted piping depicts the supply path for water from the cooling
 
tower basins to the fire protection pumps. This supply path meets the
 
criteria of 10 CFR 54.4(a)(3) for fire protection.
As described in response to RAI 2.3.3.6-1, each cooling tower basin contains a large volume (6,000,000 gallons) of water available for fire
 
protection. This secondary volume is significantly more than is required
 
for fire suppression since the largest single (fire protection) demand can
 
be satisfied by one fire pump, rated at 2500 gpm. As such, the volume
 
contained in the connected piping up to the service water and circulating
 
water pump isolation valves is inconsequential to the fire water supply
 
and only the path from the cooling tower basin to the fire pumps is
 
required for the intended function. Therefore, the path is included in the
 
license renewal evaluation boundary but the connected piping to service
 
water and circulating water pump isolation valves are not.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.6-2 acceptable
 
because the applicant has clarified that the highlighted piping depicts the supply path for water
 
from the cooling tower basins to the fire protection pumps and is the total piping required for
 
compliance with 10 CFR 54.4(a)(3) for fire protection. The staff's review of the UFSAR and Fire
 
Protection Review Report confirms the applicant's clarification. The staff also confirms that there
 
are no hypothetical failures resulting from sy stem interdependencies that would affect this piping identified in the current licensing bases and none has been previously experienced.
 
Therefore, the staff's concern described in RAI 2.3.3.6-2 is resolved.
 
2.3.3.6.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and boundary drawings to determine 2-59 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. On the basis of its review, the staff concludes the applicant has
 
appropriately identified the cooling tower system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified
 
the control cooling tower system mechanical components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1) and; therefore, is acceptable.
 
2.3.3.7  Diesel Fuel Oil System 2.3.3.7.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.7 describes the diesel fuel oil system, which stores onsite and delivers fuel
 
oil to the DGs for at least seven days of operati on. The diesel fuel oil system contains safety-related components relied upon to remain functional during and following DBEs. The failure of
 
nonsafety-related SSCs in the diesel fuel oil sy stem potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the diesel fuel oil system performs functions that support fire protection, ATWS, and SBO. LRA Table 2.3.3-7 identifies diesel fuel
 
oil system component types within the scope of license renewal and subject to an AMR.
2.3.3.7.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.7, UFSAR Section 9.5.4, and the licensing renewal
 
boundary drawings using the evaluation methodology described in SER Section 2.3 and the
 
guidance in SRP-LR Section 2.3. The staff's review identified areas in which additional
 
information was necessary to complete the review of the applicant's scoping and screening
 
results. The applicant responded to the staff's RAIs as discussed below.
 
In RAI 2.3.3.7-1, dated August 27, 2007, the staff noted that the injector housing is a component
 
for the diesel fuel oil system that is usually included within the scope of license renewal and
 
subject to an AMR. The impulse pumps shown on boundary drawings LR-M-134-1, location E5, and LR-M-134-7, location A2, are not shown within the scope of license renewal and the
 
impulse pump housing is not listed in LRA Table 2.3.3-7 for components subject to an AMR.
 
The staff requested that the applicant explain why the impulse pumps and fuel injector housings
 
are not within the scope of license renewal and not included in LRA Table 2.3.3-7 as a
 
component type subject to AMR.
In its response to RAI 2.3.3.7-1, dated October 18, 2007, the applicant stated that a
 
re-evaluation of the fuel injection pumps determined that these pumps are subject to an AMR.
 
LRA Tables 2.3.3-7 and 3.3.2-7 were amended to include the fuel injection pumps. The
 
applicant explained that the fuel injectors are mounted in the engine cylinder and considered
 
active components; therefore, the fuel injectors are not subject to AMR.
 
The staff finds the applicant's response to RAI 2.3.3.7-1 acceptable because the applicant has
 
amended the LRA to add the fuel injection pump housing as a component type subject to AMR
 
and has adequately explained why the fuel injectors are not a component type subject to AMR.
 
Therefore, the staff's concern described in RAI 2.3.3.7-1 is resolved.
2-60  In RAI 2.3.3.7-2, dated August 27, 2007, the staff noted that the DG day tank flame arrestors
 
shown on boundary drawings LR-M-134-1, location F8, and LR-M-134-7, location A8, are within
 
the scope of license renewal, but are not included in LRA Table 2.3.3-7 for component types
 
subject to an AMR. The flame arrestor is ty pically a component type subject to an AMR. The flame arrestors are shown within the scope of license renewal for different reasons on these two
 
boundary drawings. The staff requested that the applicant explain why the flame arrestors are
 
shown within the scope of license renewal, but not included in LRA Table 2.3.3-7, and why the
 
flame arrestors are shown within the scope of license renewal for different reasons.
In its response to RAI 2.3.3.7-2, dated October 18, 2007, the applicant stated in part:
As shown on license renewal drawings LR-M-134-1 and LR-M-134-7-4, the vent line piping for the diesel fuel oil day tanks is within the scope of
 
license renewal.
 
The vent lines for day tanks for diesels A-D on drawing LR-M-134-1 are
 
shown as cross-hatched, which indicates a safety-related process line
 
per the legend drawing LR-M-100-2. This is supported by the HBC line
 
designation which indicates that the piping is classified as ASME
 
Section III Class 3. Therefore, the vent lines are within the scope of
 
license renewal and are highlighted in green per LR-M-100-4 Note A2.
 
The flame arrestors on the A-D diesel day tank vent lines on drawing
 
LR-M-134-1 are not classified as safety-related. Drawing LR-M-134-1 has
 
been revised to include the flame arrestors within the scope of license
 
renewal per the criteria of 10 CFR 54.4(a)(2).
The vent lines for the E diesel day tank on drawing LR-M-134-7 are nonsafety-related but are seismically qualified. This is supported by the
 
HBD line designation which indicates that the piping is classified as ANSI
 
B31.1.0. FSAR Table 3.2-1 supports the determination that the day tank
 
vent lines are not safety-related. Per FSAR Section 9.5.4.3, the diesel
 
generator fuel oil system is Seismic Category I. Therefore, the vent lines
 
are within the scope of license renewal and are highlighted in pink (magenta) per LR-M-100-4 Note A2 up to the point where they exit the
 
diesel generator building as they have the potential for spatial interaction
 
with safety-related components. The boundary is extended through the
 
end of the vent piping for the day tank, including the flame arrestor.
 
The vent piping and flame arrestors perform a structural integrity function
 
and are evaluated under the component type of "piping and piping
 
components." In PPL's response to RAI 2.1-3, LRA Table 2.3.3-7 was
 
amended to include a line item for piping and piping components which
 
perform a structural integrity function. The PPL response to RAI 2.1-3, (Reference 3), also amended LRA Table 3.3.2-7 to include the aging
 
management evaluation for carbon steel piping and piping components
 
subject to an internal ventilation environment and an external outdoor air
 
environment. No further changes to LRA Table 2.3.3-7 or Table 3.3.2-7
 
are required in response to this RAI.
2-61  The staff confirms that the applicant has submitted revised boundary drawings
 
LR-M-134-1 and LR-M-134-7 and also a revision to note 0361 in LRA
 
Section 3.3 to address the response to this RAI.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-2 acceptable
 
because the applicant satisfactorily explained why in-scope flame arrestors are not included in
 
LRA Table 2.3.3-7 and why flame arrestors are shown within the scope of license renewal for
 
different reasons. The staff confirms that the applicant has made appropriate revisions to
 
boundary drawings LR-M-134-1 and LR-M-134-7 and added plant-specific note 0361 to the
 
LRA. Therefore, the staff's concern described in RAI 2.3.3.7-2 is resolved.
 
In RAI 2.3.3.7-3, dated August 27, 2007, the staff noted that DG fuel oil storage tank flame
 
arrestors are shown on boundary drawings LR-M-120-1, locations B3, D3, E3, and G3, and LR-
 
M-120-2, location F3 to C3. The flame arrestors are not shown within the scope of license
 
renewal. Flame arrestors are typically incl uded within the scope of license renewal because they are classified as a component subject to an AMR within the pressure boundary for the
 
diesel fuel oil tanks. The staff requested that the applicant explain why the flame arrestors are
 
not within the scope of license renewal.
 
In its response to RAI 2.3.3.7-3, dated October 18, 2007, the applicant stated:
 
As shown on license renewal drawings LR-M-120-1 and LR-M-120-2, the
 
vent line piping and the associated flame arrestors for the diesel fuel oil
 
storage tanks are not within the scope of license renewal. The vent lines
 
extend from the top of the storage tank within the buried vault to above
 
ground where the piping is goose-necked and provided with flame
 
arrestors. The vent piping is located above the fuel oil level within the
 
storage tanks and therefore does not provide a pressure boundary
 
function.
The vent lines for the diesel fuel oil storage tanks on drawing LR-M-120-1 and LR-M-120-2 are nonsafety-related but are seismically qualified. This
 
is supported by the HBD line designation which indicates that the piping
 
is classified as ANSI B31.1.0. FSAR Table 3.2-1 supports the
 
determination that the storage tank vent lines are not safety-related. Per
 
FSAR Section 9.5.4.3, the diesel generator fuel oil system is Seismic
 
Category I.
The flame arrestors on the diesel storage tank vent lines are not classified as safety-related. FSAR Section 9.5.4.2 states for the fuel oil
 
storage tank vent line that if the above grade section of the vent is
 
damaged, it would not render the fuel oil storage tank inoperable. This
 
determination also applies to the flame arrestors located above grade on
 
the vent piping. The flame arrestors do not perform a license renewal
 
intended function. In addition, the vent line and flame arrestor do not
 
provide any support for the safety-related tank to which they are attached.
 
Therefore, the flame arrestors on the diesel fuel oil storage tank vent
 
lines are not within the scope of license renewal.
2-62  Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-3 acceptable
 
because the applicant satisfactorily explained why these diesel fuel oil tank vent lines and flame
 
arrestors are not within the scope of license renewal. Therefore, the staff's concern described in
 
RAI 2.3.3.7-3 is resolved.
In RAI 2.3.3.7-4, dated August 27, 2007, the staff noted that the DG storage tank manhole
 
covers shown in boundary drawing LR-M-120-1, locations B2, D2, F3, and G3, are not shown
 
within the scope of license renewal. The staff requested that the applicant explain why the
 
manhole covers are not shown within the license renewal scope boundary.
 
In its response to RAI 2.3.3.7-4, dated October 18, 2007, the applicant stated:
 
The diesel generator storage tank manholes and covers shown on
 
drawing LR-M-120-1 are within the scope of license renewal. A
 
highlighting error resulted in the manholes and covers on drawing
 
LR-M-120-1 not being indicated as within the scope of license renewal.
The manholes and covers are considered to be part of the pressure boundary of the storage tanks. This is reflected by the highlighting of the
 
manholes and covers for the E diesel generator storage tank on drawing
 
LR-M-120-2.
No changes are required to Table 2.3.3-7 or Table 3.3.2-7, the manholes are included in the line item for "Tanks (0T527A-E, 0T528A-E)". The
 
component types are therefore subject to aging management review and
 
have been evaluated with the storage tanks.
 
The staff confirms that the applicant has submitted revised boundary drawing LR-M-120-1.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-4 acceptable
 
because the applicant has clarified that the manhole covers are within the scope of license
 
renewal and has made the appropriate revisions to boundary drawing LR-M-120-1. Therefore, the staff's concern described in RAI 2.3.3.7-4 is resolved.
 
In RAI 2.3.3.7-5, dated August 27, 2007, the staff noted that boundary drawing LR-M-120-1, locations B7, D7, E7, and G7, indicate that there are manhole covers on top of the DG day
 
tanks A, B, C, and D. However, boundary drawing LR-M-134-1, location F8, does not show a
 
manhole cover on the top of DG day tanks A, B, C, and D. The staff requested that the applicant
 
explain whether or not there are manhole covers on the four tanks and whether there are
 
manhole covers on these tanks, explain why they are not shown on boundary drawing LR-M-
 
134-1 and why they are not within the scope of license renewal.
 
In its response to RAI 2.3.3.7-5, dated October 18, 2007, the applicant stated:
 
As stated in FSAR Section 9.5.4.2, a manhole is provided on each diesel
 
generator fuel oil day tank for inspection. The manholes are depicted on
 
license renewal drawing LR-M-120-1 due to space limitations on drawing
 
LR-M-134-1. The dashed lines for tanks 0T528A, B, C, and D on drawing
 
LR-M-120-1 indicate that the components are represented on another 2-63 drawing (LR-M-134-1). The manholes and covers associated with the diesel generator fuel oil day tanks on LR-M-120-1 are solid lines
 
indicating that they are represented on drawing LR-M-120-1.
 
It was determined that the diesel generator day tank manholes and
 
covers shown on drawing LR-M-120-1 should be shown as within the
 
scope of license renewal. The manholes and covers are part of the
 
pressure boundary of the storage tanks.
 
No changes are required to Table 2.3.3-7 or Table 3.3.2-7. The manholes
 
and covers for the diesel generator day tank shown in drawing
 
LR-M-134-7 are shown within the license renewal evaluation boundary.
 
The component types are therefore subject to aging management review
 
and have been evaluated with the tanks.
The staff confirms that the applicant has submitted revised boundary drawing LR-M-120-1.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-5 acceptable
 
because the applicant: (a) clarified that the manhole covers are within the scope of license
 
renewal, (b) explained why the manhole covers were not shown on boundary drawing
 
LR-M-134-7, and (c) made the appropriate revisions to boundary drawing LR-M-120-1.
 
Therefore, the staff's concern described in RAI 2.3.3.7-5 is resolved.
 
In RAI 2.3.3.7-6, dated August 27, 2007, the staff noted that boundary drawing LR-M-134-7, location A6, indicates that there is a manhole cover on top of the DG day tank E and that it is
 
within the scope of license renewal. The staff requested that the applicant explain why the
 
manhole cover is not listed in LRA Table 2.3.3-7 for components subject to an AMR.
 
In its response to RAI 2.3.3.7-6, dated October 18, 2007, the applicant stated:
The manhole and cover depicted on license renewal drawing LR-M-134-7
 
is within the scope of license renewal. The manhole and cover are
 
considered to be an integral part of the tank component. Therefore, the
 
"Tanks (0T527A-E, 0T528A-E)" entry in Table 2.3.3-7 includes the
 
associated manholes and covers. The manhole and cover perform the
 
same pressure boundary function as the tank.
 
Based on its review, the staffs finds the applicant's response to RAI 2.3.3.7-6 acceptable
 
because the applicant has explained that the manholes and covers are within the scope of
 
license renewal and are an integral part of the tank component type listed in LRA Table 2.3.3-7.
 
Therefore, the staff's concern described in RAI 2.3.3.7-6 is resolved.
 
2.3.3.7.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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. On the basis of its review, the staff concludes the applicant has
 
appropriately identified the diesel fuel oil system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 2-64 the control diesel fuel oil system mechanical components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1) and; therefore, is acceptable.
2.3.3.8  Diesel Generator Building HVAC Systems 2.3.3.8.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.8 describes the diesel generator (DG) building HVAC systems, which
 
maintain a suitable environment for the DGs during all modes of operation. The DG buildings
 
HVAC systems contain safety-related component s relied upon to remain functional during and following DBEs. In addition, the DG buildings HVAC systems perform functions that support fire protection. LRA Table 2.3.3-8 identifies DG bu ildings HVAC systems component types within the scope of license renewal and subject to an AMR.
 
2.3.3.8.2  Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the DG building HVAC systems mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately
 
identified the system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.9  Diesel Generator System 2.3.3.9.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.9 describes the DGs system consisting of five DGs, only four of which can be
 
aligned to the safety-related load groups. The DG s system contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related
 
SSCs in the DGs system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the DGs system performs functions that support fire protection, ATWS, SBO, and EQ. LRA Table 2.3.3-9 identifie s DGs system component types within the scope of license renewal and subject to an AMR.
 
2.3.3.9.2  Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the DG system mec hanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the
 
system components subject to an aging managem ent review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.10  Domestic Water System 2.3.3.10.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.10 describes the domestic water system, which provides cold and hot water
 
acceptable for human consumption to plumbing fixtures for the entire plant. The failure of 2-65 nonsafety-related SSCs in the domestic water syst em potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-10 identifies domestic water
 
system component types within the scope of license renewal and subject to an AMR. 
 
2.3.3.10.2  Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the domestic water syst em mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified
 
the system components subject to an aging m anagement review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.11  Emergency Service Water System 2.3.3.11.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.11 describes the ESW system consisting of two loops, each designed to
 
supply simultaneously 100 percent of the ESW requirements to both units and to the common
 
emergency DGs. The ESW system contains sa fety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the ESW system
 
potentially could prevent the satisfactory acco mplishment of a safety-related function. In addition, the ESW system performs functions that support fire protection, ATWS, SBO, and EQ.
 
LRA Table 2.3.3-11 identifies ESW system component types within the scope of license renewal and subject to an AMR.
2.3.3.11.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.11, UFSAR Section 9.2.5, and the licensing renewal
 
boundary drawings using the evaluation methodology described in SER Section 2.3 and the
 
guidance in SRP-LR Section 2.3. The staff's review identified areas in which additional
 
information was necessary to complete the review of the applicant's scoping and screening
 
results. The applicant responded to the staff's RAIs as discussed below.
 
In RAI 2.3.3.11-1, dated August 27, 2007, the staff noted that boundary drawings LR-M-186-3
 
and LR-M-186-4 depict ESW piping to and from the ESW bundles (OS117A2 and OS117B2).
 
LRA Section 2.3.3.11, "Emergency Service Water System," paragraph titled "Drawings" does
 
not include LR-M-186-3 or LR-M-186-4 for Unit 1, as applicable boundary drawings. The staff
 
requested that the applicant clarify that ESW piping to and from the ESW bundles (OS117A2
 
and OS117B2) is within the ESW system and whether boundary drawings LR-M-186-3 and LR-M-186-4 are applicable references in LRA Section 2.3.3.11.
In its response to RAI 2.3.3.11-1, dated October 18, 2007, the applicant stated in part:
The ESW piping to and from the ESW bundles (0S117A2 and 0S117B2) shown on LR-M-186-3 and LR-M-186-4, respectively, is within the scope of license renewal and subject to AMR. This ESW piping to and from the ESW bundles is scoped as part of the Control Structure Chilled Water System, rather than as part of ESW, and is included in LRA Section 2.3.3.4 and associated Table 2.3.3-4. Therefore, drawings LR-M-2-66 186-3 and LR-M-186-4 are not applicable references for LRA Section 2.3.3.11.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.11-1 acceptable because the applicant has clarified that the piping in question is within the scope of license renewal as part of the control structure chilled water system rather than the ESW system.
Therefore, the staff's concern described in RAI 2.3.3.11-1 is resolved.
In RAI 2.3.3.11-2, dated August 27, 2007, the staff noted that LRA Table 2.3.3-11, "Emergency Service Water System Components Subject to Aging Management Review," does not contain flexible connectors as a component type subject to AMR. The staff requested that the applicant
 
explain why the flexible connectors are not listed as components subject to an AMR in LRA
 
Table 2.3.3-11. 
 
In its response to RAI 2.3.3.11-2, dated October 18, 2007, the applicant stated in part that the room unit coolers listed in RAI 2.3.3.11-2:
-are in the scope of license renewal and are subject to AMR. The flexible connections associated with each unit cooler are scoped in the same system as the unit cooler itself, not in the ESW system. Based on PPL's scoping methodology, these unit coolers, including the flexible connections associated with them, are all scoped with the Reactor Building HVAC System. The flexible connections are included in LRA Section 2.3.3.24 and the associated Table 2.3.3-23.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.11-2 acceptable because the applicant has clarified that the flexible connections in question are within the scope of license renewal and subject to AMR, but are part of the RB HVAC system rather than the ESW system. Therefore, the staff's concern described in RAI 2.3.3.11-2 is resolved.
2.3.3.11.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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. On the basis of its review, the staff concludes the applicant has
 
appropriately identified the emergency SWS mechanical components within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the
 
emergency SWS mechanical components subject an AMR in accordance with the requirements
 
of 10 CFR 54.21(a)(1) and; therefore, is acceptable.
2.3.3.12  Engineered Safeguards (ES) Service Water (SW) Pumphouse HVAC System 2.3.3.12.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.12 describes the ESSW pumphouse HVAC system, which maintains a
 
suitable environment in the pumphouse for the emergency service water (ESW) and RHRSW
 
system pumps and their appurtenances. The ES SW pumphouse HVAC system contains safety-related components relied upon to remain functional during and following DBEs. In
 
addition, the ES SW pumphouse HVAC system perform s functions that support fire protection.
LRA Table 2.3.3-12 identifies ES SW pumphouse H VAC system component types within the 2-67 scope of license renewal and subject to an AMR.
 
2.3.3.12.2  Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the ESSW pumphouse HVAC system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately
 
identified the system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.13  Fire Protection System 2.3.3.13.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.13 describes the fire protection system, which minimizes both the probability
 
and consequences of postulated fires. The fire protection system contains nonsafety-related
 
components relied upon to remain functional during and following DBEs. The failure of
 
nonsafety-related SSCs in the fire protection syst em potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the fire protection system performs
 
functions that support fire protection. LRA Table 2.3.3-13 identifies fire protection system
 
component types within the scope of license renewal and subject to an AMR. 
 
2.3.3.13.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.13, UFSAR Section 9.5.1, the Fire Protection Review
 
Report and the following fire protection CLB documents, using the evaluation methodology
 
described in SER Section 2.3 and the guidance in SRP-LR Section 2.3:
* NUREG-0776, A Safety Evaluation Report Related to the Operation of Susquehanna Steam Electric Station, Units  1 and 2,@ April 1981
* NUREG-0776, Supplement No. 1, June 1981
* NUREG-0776, Supplement No. 2, September 1981
* NUREG-0776, Supplement No. 3, July 1982
* NUREG-0776, Supplement No. 4, November 1982
* NUREG-0776, Supplement No. 6, March 1984
* Safety Evaluation of Fire Protection Report, August 9, 1989
* Safety Evaluation of Revision 4 to the Fire Protection Review Report, March 29, 1993
* Safety Evaluation of Fire Protection Program Issues, Safe-Shutdown Methodology and Analysis of Associated Circuits dated October 21, 1997
* Safety Evaluation of the Licensees
= Amendment No. 177, June 24, 1989 In conducting its review, the staff evaluated the system functions described in the LRA and
 
UFSAR in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had
 
not omitted from the scope of license renewal any components with intended functions pursuant 2-68 to 10 CFR 54.4(a). The staff then reviewed those components the applicant identified as being within the scope of license renewal to verify that the applicant had not omitted any passive or
 
long-lived components subject to an AMR in accordance with 10 CFR 54.21(a)(1).
 
The staff also reviewed the applicant's commitments to 10 CFR 50.48, A Fire protection" (i.e., approved fire protection program), using the applicant's commitment documents to the Branch Technical Position (BTP) Auxiliary and Power Conversion Systems Branch (APCSB) 9.5-1, ?Guidelines for Fire Protection for Nuclear Power Plants,@ May 1, 1976, and Appendix A to BTP APCSB 9.5-1, August 23, 1976, documented in the Fire Protection Review Report. 
 
The staff=s review of LRA Section 2.3.3.13 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 2.3.3.13-1, dated June 22, 2007, the staff noted the LRA boundary drawing LR-M-122, Sheet No. 1, A Fire Pumphouse, North & South Gatehouse & Security Control Center Buildings,@ shows the jockey pump and associated components as not within the scope of license renewal (i.e., not colored in green). SER Section 9.5.1.1 (NUREG-0776), dated April 1981, states that a
 
separate jockey pump automatically maintains the yard fire main pressure. The jockey pump
 
and its associated components appear to have fire protection intended functions required for
 
compliance with 10 CFR 50.48, pursuant to 10 CFR 54.4(a)(3). The staff requested that the
 
applicant verify whether the jockey pump and its associated components are within the scope of
 
license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1) and; if excluded, provide justification.
 
In its response to RAI 2.3.3.13-1, dated July 24, 2007, the applicant stated in part:
 
The jockey fire pump and associated components, shown on LRA boundary drawing LR-M-122, Sheet 1, are not in the scope of license
 
renewal and, therefore, are not subject to an AMR. The jockey pump
 
does not have fire protection intended functions required for compliance
 
with 10 CFR 50.48.
 
In evaluating the applicant's response to RAI 2.3.3.13-1, the staff found it was incomplete and
 
that review of LRA Section 2.3.3.13 could not be completed. The staff notes the applicant's
 
statement that the jockey pump does not have fire protection intended functions required for the
 
compliance with 10 CFR 50.48. However, the staff finds this statement contrary to the
 
applicant's fire protection commitment to BTP APCSB 9.5-1, Appendix A, documented in SER
 
Section 9.5.1.1 (April 1981), which is used as the CLB. The commitment states in part, "a
 
separate jockey pump automatically maintains yard main pressure from 105 to 125 psi. The fire
 
pumps start automatically on low header pressure."
 
The applicant indicated in its response to RAI 2.3.3.13-1 that the jockey pump in question, was
 
not within the scope of license renewal because the jockey pump is not required to function to
 
suppress a fire or supply required fire protection water. Therefore, the applicant used criteria
 
pursuant to 10 CFR 54.4(a)(2) to exclude the jockey pump. Since there is no adverse effect due
 
to the jockey pump failure, the applicant excludes this component on that basis, and has
 
neglected the fact that this component is relied upon to comply with 10 CFR 50.48 (pursuant to
 
the CLB), as stated in 10 CFR 54.4(a)(3). 
 
2-69 The staff held a telephone conference with the applicant on October 3, 2007, to discuss information necessary to resolve its concern in RAI 2.3.3.13-1. During the teleconference, the
 
staff explained that the scope of SSCs required for compliance with 10 CFR 50.48 and
 
10 CFR Part 50, Appendix A, General Design Criteria (GDC) 3, goes beyond preserving the
 
ability to maintain safe-shutdown in the event of a fire. The staff stated that exclusion of fire
 
protection SSCs, on the basis that the intended function is not required for the protection of
 
safe-shutdown equipment or safety-related equipment, is not acceptable, whether the SSC is
 
required for compliance with 10 CFR 50.48.
 
The applicant's CLB demonstrates that, in accordance with GDC 3, this component was
 
credited to meet the guidance of BTP APCSB 9.5-1, Appendix A. Therefore, the jockey pump in
 
question should not be excluded from the scope of license renewal. In addition, this component
 
should not be excluded on the basis that it is not required to function to suppress a fire, without
 
factoring in the CLB, nor is it required for compliance with 10 CFR 50.48. 
 
By letter dated October 24, 2007, the applicant responded in part that "Based on discussion
 
with the NRC, the jockey fire pump and associated components, shown on LRA boundary
 
drawing LR-M-122, Sheet 1, have been included within the scope of license renewal, and are
 
subject to an AMR."
 
The staff confirms that the applicant has submitted revised boundary drawing LR-M-122-1 and
 
has amended LRA Tables 2.3.3-13 and 3.3.2-13 to include the jockey fire pump and associated
 
components as within the scope of license renewal and subject to an AMR
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.13-1 acceptable
 
because the applicant has committed to meet the CLB based on the guidance of Appendix A of
 
BTP APCSB 9.5-1. The staff is adequately assured that the jockey pump and associated
 
components used for the fire suppression will be appropriately considered during aging
 
management activities. Therefore, the staff's concern described is RAI 2.3.3.13-1 is resolved.
 
In RAI 2.3.3.13-2, dated June 22, 2007, the staff noted the following LRA boundary drawings
 
show fire protection system components as not within the scope of license renewal (i.e., not colored in green):
* LR-M-122 Sheet 1, "Fire Pumphouse, North & South Gatehouse & Security Control Center Buildings,@ shows Diesel Oil Day Tank (0T508) vent line and the fill cap-assembly line, piping, fittings, and drains as out of scope (i.e., not colored in green)
* LR-M-122 Sheet 2, "Turbine Bldg.(TB), Control Structure and Radwaste Building,@ shows several fire suppression systems and components in TB for Units  1 and 2 as out of scope (i.e., not colored in green)
* LR-M-122 Sheet 3, A Reactor Bldg., Standby D G, River Intake Structure Service and Admin. Bldg. & Circ. Water Pumphouse
@ shows several fire suppression systems and components in TB for Units  1 and 2, as out of scope (i.e., not colored in green)
* LR-M-122 Sheet 4, A Carbon Dioxide System,@ shows several components as out of scope (i.e., not colored in green)
The staff requested that the applicant verify whether the above fire suppression systems and components are within the scope of license renewal, in accordance with 10 CFR 54.4(a) and
 
subject to an AMR, in accordance with 10 CFR 54.21(a)(1) and; if not, provide justification for 2-70 the exclusion.
 
In its response to RAI 2.3.3.13-2, dated July 24, 2007, the applicant stated:
 
LR-M-122 Sheet 1 The Diesel Oil Day Tank (0T508) vent line and the fill cap-assembly line, piping, fittings, and drains have no license renewal function, are not in
 
license renewal scope and are not subject to AMR. These vent and fill
 
lines, as well as the return (drain) line from the diesel engine to the tank, are above the tank's normal oil level and the tank is vented to
 
atmosphere. As described in the FPRR, the tank contains enough diesel
 
fuel oil for 8 hours of operation in accordance with NFPA 20. Failure of
 
these components will not create a leakage path that would drain the tank
 
and will not prevent the diesel fire pump from accomplishing its
 
Appendix R function.
 
The components that do have a license renewal intended function in
 
support of the diesel engine driven fire pump, the day tank, tubing and
 
flexible connections, as well as the drain line and valve for the day tank, 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), as listed 
 
in LRA Table 2.3.3-13 and shown (highlighted in green) on LRA drawing
 
LR-M-122 Sheet 1.
 
LR-M-122 Sheet 2 As stated in LRA Section 2.1.1.2.2, no components in the TB either
 
perform a safety function or would pr event a safety-related function from occurring. With few exceptions, there are no fire suppression systems or
 
components in the TB that are credited with protection of safety-related or
 
safe shutdown equipment.
 
LRA Section 2.1.1.3.1 discusses scoping of the fire protection system to
 
achieve and maintain safe shutdown; that is features required for fire
 
protection of safety-related equipment and any system function that were
 
included in, or provide necessary support for, one or more of the three (3)
 
safe shutdown paths credited for compliance with Appendix R. SSCs that
 
perform an intended function for fire protection are included in the scope
 
of license renewal. These include certain hose stations (1/2HR-101 and
 
1/2HR-156) and sprinkler systems (e.g., DS-0 15, PA-091, PA-092, and
 
PA-1/26 1), which are shown as being located in the TB on LRA drawing
 
LR-M-122 Sheet 2, and are credited with protection of control structure
 
and transformer yard components. Section 3.7.3.5 and 3.7.3.2 of the
 
Technical Requirements Manual (TRM) identify the fire hose stations and
 
the spray and sprinkler systems, respectively, that are credited for safety-
 
related and safe-shutdown protection.
 
Except for the header piping and components and those suppression
 
systems and components discussed above, the remaining suppression
 
systems and components in the TB are not credited for safety-related or
 
safe-shutdown fire protection. Therefore, except as indicated above and 2-71 on LRA Drawing LR-M-122 Sheet 2, the fire suppression systems and components located in the TB are not in license renewal scope and are
 
not subject to an AMR.
 
LR-M-122 Sheet 3 As described above in response to the question on LR-M-122, Sheet 2, the suppression systems and components that are credited for
 
safety-related and safe-shutdown protection are in the scope of license
 
renewal. This includes fire hydrant FH-104, which is credited with
 
protection of diesel generator building components, and suppression
 
station DS-014, which is credited for protection of a transformer adjacent
 
to the Circ. Water Pumphouse. Except as noted, neither the Turbine
 
Building, Circ. Water Pumphouse nor River Intake Structure facilities
 
contain safety-related equipment or equipment relied upon by the safe
 
shutdown analysis. The applicant stated that, therefore, except as noted
 
above, the fire suppression systems and components in these structures
 
do not satisfy the requirements of 10 CFR 54.4, are not in license renewal
 
scope and are not subject to an AMR.
 
LR-M-122 Sheet 4 While it is briefly mentioned in NUREG-0776 Section 9.5.1.3, the
 
generator purge portion of the carbon dioxide system is not credited with
 
safety-related or safe-shutdown protection. As such, there are two pipe
 
sections in the lower, left hand comer of drawing LR-M-122, Sheet 4, that
 
are not in the scope of license renewal. The "fill line" and the "equalizing
 
line" for generator purge are isolated from the CO 2 storage tank by normally closed valves and do not have a license renewal function. The
 
applicant stated that, therefore, neither portion of the piping and
 
associated components is in license renewal scope (i.e., is not highlighted in green).
 
Valves PSV02269, PSV02270, PSV02271 and the piping between those
 
valves and valve 022978 have conservatively been highlighted green as
 
in-scope and subject to an AMR. The piping is carbon steel and the
 
valves are bronze. In addition the piping from valve 022979 through
 
0CB650 is in-scope and subject to an AMR, but was inadvertently not
 
highlighted. Both portions of pipe have been highlighted green on the
 
revised boundary drawing in the attachment to this letter. No changes to
 
the LRA are required as the material/environment combinations of this
 
additional highlighting are already covered in Table 3.3.2-13.
 
In evaluating the applicant's response to RAI 2.3.3.13-2, the staff found it was incomplete and
 
that review of LRA Section 2.3.3.13 could not be completed. The applicant explained in its
 
response that the fire protection SSCs in question are not credited for safety-related and
 
safe-shutdown. Exclusion of fire protection SSCs on the basis that its intended function is not
 
required for the protection of safe-shutdown equipment or safety-related equipment is not
 
acceptable, whether that SSC is required for compliance with 10 CFR 50.48 (i.e., required to meet Appendix A to BTP APSCB 9.5-1). Therefore, the staff concludes that these components
 
should be included within the scope of license renewal and subject to an AMR. The staff held a
 
telephone conference with the applicant on October 3, 2007, to discuss information necessary 2-72 to resolve the staff's concern described in RAI 2.3.3.13-2.
 
The staff explained that the scope of fire protection SSCs discussed above were excluded on
 
the basis that they were not "protecting" safety-related or safe-shutdown equipment, even
 
though they were accepted for compliance with the provisions of Appendix A to BTP APSCB
 
9.5-1. Furthermore, the scoping requirements of 10 CFR 54.4 states that SSCs are included
 
in-scope, which demonstrate compliance with 10 CFR 50.48. Therefore, if the SSCs were
 
installed in compliance with 10 CFR 50.48, then they should be included within the scope of
 
license renewal. 
 
The staff finds that the applicant's analysis of fire protection regulation does not completely
 
capture the fire protection SSCs required for compliance with 10 CFR 50.48. The scope of
 
SSCs required for compliance with 10 CFR 50.48 and GDC 3 goes beyond preserving the
 
ability to maintain safe-shutdown in the event of a fire. GDC 3 states in part, that "fire detection
 
and fighting systems of appropriate capacity and capability shall be provided and designed to
 
minimize the adverse effects of fires on st ructures, systems, and components important to safety." Furthermore, the general requirements provided in GDC 3 to "minimize the adverse effects of fires on SSCs important to safety" are stated to provide a general level of protection
 
which is afforded to all systems, not only where required to prevent a loss of safe-shutdown
 
capability. 10 CFR 50.48(a) states that "each operating nuclear power plant must have a fire
 
protection plan that satisfies Criterion 3 of Appendix A of this part." The term "important to
 
safety" encompasses a broader scope of equipm ent beyond safety-related and safe-shutdown.
Though there is a focus on the protection of safety-related equipment or safe-shutdown
 
equipment, this does not imply that there is an exclusion of any equipment which protects
 
nonsafety related equipment. For example, in accordance with 10 CFR 50.48, some portions of
 
suppression systems may be required in plant areas where a fire could result in the release of
 
radioactive materials to the environment, even if no safety-related or safe-shutdown equipment is located in that particular fire area. 
 
In its response, dated October 24, 2007, the applicant stated, in part, that in LRA boundary
 
drawing LR-M-122, Sheet 1, "The Diesel Oil Day Tank (0T508) vent line and the fill
 
cap-assembly line, piping, fittings, and drains have no license renewal function, are not in
 
license renewal scope and are not subject to AMR." Further, the applicant stated that the LRA
 
boundary drawings LR-M-122, Sheet 2 and LR-M-122, Sheet 3 (Turbine Building, Circ. Water
 
Pumphouse, and River Intake Structure fire suppression systems and components) in question
 
were for loss prevention and insurance purposes. Turbine Building fire suppression systems do
 
not protect safety-related equipment, nor are addressed in PPL's response to BTP APSCB 9.5-
 
1, Revision 0, Appendix A, and are not credited in the 10 CFR Part 50, Appendix R safe-
 
shutdown analysis.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.13-2 acceptable
 
because the applicant has adequately explained that the fire suppression systems and
 
components in question are not credited for 10 CFR 50.48 and GDC 3. The staff confirms that
 
these fire water suppression systems are for property protection and for loss prevention. The staff determines that the applicant correctly excluded the fire suppression systems and
 
components in question on the basis that they are not required for compliance with
 
10 CFR 50.48. The staff notes the applicant's interpretation of these components as active (short-lived components), which necessarily will re sult in more vigorous oversight of the condition and performance of the components. The applicant concurs. Further, the staff notes
 
that the applicant has considered certain fire protection systems and components as only 2-73 required to protect nonsafety-related equipment and; thus, satisfies requirements of the plant insurance carrier. The staff concludes that these fire protection systems and components were
 
correctly excluded from the scope of license renewal and from being subject to an AMR.
Therefore, the staff's concerns described in RAI 2.3.3.13-2 are resolved.
 
In RAI 2.3.3.13-3, dated June 22, 2007, the staff stated that SER Section 9.5.1.2 (NUREG-0776, dated April 1981), listed sprinkler and standpipe systems provided in the plant
 
areas for fire suppression activities. These systems were installed in the following areas:
* Reactor Core Isolation Cooling Pump Room
* High Pressure Coolant Injection Pump Room
* Heating, Ventilation, and Air-Conditioning Filter Rooms
* Railroad Airlock
* Control Building Auxiliary Rooms
* Condenser Area
* Reactor Feed Pump Turbine
* Turbine Central Area
* Turbine Condenser Gallery
* Turbine Hydro Control Power Room
* North Railroad Bay
* Turbine Condenser Mezzanine
* Diesel Engine Fire Pump Room
* Lower Cable Spreading Room (CSR)
* Upper CSR
* RFP Turbine Room
* Diesel Generator Building
* Charcoal Filters
* Standby Gas Treatment Filters
* Emergency Outside Air Filters
* Centrifuge & Conditioner
* Turbine Pump Area
* Turbine Hydro Seal Oil Unit
* Turbine Lube Oil Area
* Turbine Motor Generator Area
* Turbine Filter Room
* Turbine Moisture Separation Area
* Radwaste Tank Vent Filter Room
* Radwaste Auxiliary Rooms
* Radwaste Controlled Zone Shop
 
The staff requested that the applicant verify whether the sprinkler and standpipe systems
 
installed in the above areas of the plant are within the scope of license renewal, in accordance
 
with 10 CFR 54.4(a) and subject to an AMR, in accordance with 10 CFR 54.21(a)(1) and; if
 
excluded, provide justification.
 
In its response to RAI 2.3.3.13-3, dated July 24, 2007, the applicant stated:
 
The fire sprinkler and standpipe systems installed in the locations noted
 
by this RAI are listed in two groups below. The first group includes those
 
systems which are in the scope of license renewal and subject to an 2-74 AMR. The second group includes those systems that are not within the scope of license renewal and are not subject to an AMR, for which
 
justification is provided.
The sprinkler and standpipe systems for the following areas are in the
 
license renewal scope, and are subject to an AMR. The fire protection
 
components associated with these systems are addressed in the LRA in
 
Sections 2.3.3.13, 3.3.2.1.13, Tables 2.3.3-13 and 3.3.2-13. In addition, the table below lists the boundary drawing, with coordinates, on which the
 
related sprinkler and/or standpipe is shown as in-scope (highlighted in
 
green).
Location LRA Drawing (Coordinates) Reactor Core Isolation Cooling Pump Room    LR-M-122, Sheet 3 (B4, B5) High Pressure Coolant Injection Pump Room LR-M-122, Sheet 3 (C4, B5) Heating, Ventilation, and Air-Conditioning Filter
 
Rooms LR-M-122, Sheets 3 (A4, B4, A5, B5) Railroad Airlock LR-M-122, Sheet 3 (D5) Control Building Auxiliary Rooms LR-M-122, Sheet 2 (F4, F5) Lower Cable Spreading Room (CSR) LR-M-122, Sheet 2 (F3, F5) Upper CSR LR-M-122, Sheet 2 (F3, F6) Diesel Generator Building LR-M-122, Sheet 3 (C8, D8, E7) Charcoal Filters LR-M-122, Sheet 3 (A4, B4, A5, B5) Standby Gas Treatment Filters LR-M-122, Sheet 2 (G6), LR-VC-175, Sheet 3 Emergency Outside Air Filters LR-M-122, Sheet 2 (G6), LR-VC-178, Sheet 1  The sprinkler and standpipe systems for the following areas are not in the
 
license renewal scope and are not subject to an AMR. Except for the
 
diesel engine fire pump room, these sprinkler and standpipe systems are
 
located in the TB and the radwaste building. Consistent with the
 
guidelines of Appendix A to BTP APSCB 9.5-1, the diesel engine driven
 
and motor driven fire pumps are located in rooms separated by a three
 
hour fire wall. In particular, the diesel engine driven fire pump is located in
 
a room enclosed by three hour fire rated walls, doors, and duct
 
penetrations; whereas the motor driven fire pump is located in the main
 
pump room with the service water pumps and circulating water pumps.
2-75 This area (fire area A-l) has a low combustible loading. The sprinkler and standpipe systems in following areas do not protect safety-related
 
equipment and are not credited in the Appendix R safe shutdown
 
analysis:
* Condenser Area
* Reactor Feed Pump Turbine
* Turbine Central Area
* Turbine Condenser Gallery
* Turbine Hydro Control Power Room
* North Railroad Bay
* Turbine Condenser Mezzanine
* Diesel Engine Fire Pump Room
* PFP Turbine Room*
* Centrifuge & Conditioner
* Turbine Pump Area
* Turbine Hydro Seal Oil Unit
* Turbine Lube Oil Area
* Turbine Motor Generator Area
* Turbine Filter Room
* Turbine Moisture Separation Area
* Radwaste Tank Vent Filter Room
* Radwaste Auxiliary Rooms
* Radwaste Controlled Zone Shop Evaluated as the "Reactor Feed Pump (RFP) Turbine Room"
 
In evaluating the applicant's response to RAI 2.3.3.13-3, the staff found that it was incomplete
 
and that review of LRA Section 2.3.3.13 could not be completed. The staff notes the applicant's
 
explanation that the sprinkler and standpipe systems in the areas listed above do not support
 
SSES post-fire safe-shutdown requirements. The staff finds the applicant's explanation contrary
 
to the April 1981 SSES fire protection SER, as the CLB. The staff held a telephone conference
 
with the applicant on October 3, 2007, to discuss information necessary to resolve the staff's
 
concern described in RAI 2.3.3.13-3. During the teleconference, the staff noted that the
 
applicant had committed to satisfy BTP APCSB 9.5-1, Appendix A, Regulatory Position A.4, "Fire Suppression Systems," by providing certain equipment for the fire protection program that is also considered "important to safety."
 
The staff found that the applicant's analysis of fire protection regulations does not completely
 
capture the fire protection SSCs required for compliance with 10 CFR 50.48. The scope of
 
SSCs required for compliance to 10 CFR 50.48 and GDC 3 goes beyond preserving the ability
 
to maintain safe-shutdown in the event of a fire. GDC 3 states in part, that "fire detection and
 
fighting systems of appropriate capacity and capability shall be provided and designed to
 
minimize the adverse effects of fires on st ructures, systems, and components important to safety." Furthermore, the general requirements provided in GDC 3 to "minimize the adverse effects of fires on SSCs important to safety" are stated to provide a general level of protection
 
which is afforded to all systems, not only where required to prevent a loss of safe-shutdown
 
capability." 10 CFR 50.48(a) states that "each operating nuclear power plant must have a fire
 
protection plan that satisfies Criterion 3 of Appendix A of this part."
 
The term "important to safety" encompasses a broader scope of equipment than safety-related 2-76 and safe-shutdown equipment. Though there is a focus on the protection of safety-related equipment or safe-shutdown equipment, this does not imply that there is an exclusion of any equipment which protects nonsafety-related equi pment. For example, in accordance with 10 CFR 50.48, some portions of suppression systems may be required in plant areas where a
 
fire could result in the release of radioactive materials to the environment, even if no
 
safety-related or safe-shutdown equipment is located in that particular fire area. 
 
In its response dated October 24, 2007, the applicant stated that as identified in RAI 2.3.3.13-3, sprinkler and standpipe systems in the Condenser Area, Turbine Central Area, Turbine
 
Condenser Gallery, Turbine Hydro Control Power Room, North Railroad Bay, Turbine
 
Condenser Mezzanine, Diesel Engine Fire Pump Room, Turbine Pump Area, Turbine Filter
 
Room, Turbine Moisture Separation Area, Radw aste Tank Vent Filter Room, Radwaste Auxiliary Rooms, and Radwaste Controlled Zone Shop are not within the scope of license renewal. The applicant verified that these systems are used for property protection. The
 
applicant further stated that these sprinkler and standpipe systems do not protect safety-related
 
equipment, are not addressed in PPL's response to Appendix A to BTP APSCB 9.5-1, nor are
 
they credited in the 10 CFR Part 50, Appendix R safe-shutdown analysis.
 
In addition, the applicant stated that after further review, the sprinkler and standpipe systems for
 
the Turbine Building areas, Reactor Feed Pump Turbine (RFP Lube Oil Reservoir), PFP Turbine
 
Room (RFP Turbine Room), Centrifuge & C onditioner (Lube Oil Conditioner Room), Turbine Hydro Seal Oil Unit (Hydrogen Seal Oil Unit), Turbine Lube oil Area (Turbine Lube oil
 
Reservoir), and Turbine Motor Generator Area (Turbine generator bearings) are included in the
 
Fire Protection Review Report for SSES. They also are included in the response to Appendix A
 
to BTP APSCB 9.5-1, because they protect areas containing combustible liquid.
 
The staff confirmed that the applicant has provided revised boundary drawings LF-M-122-2, -11,
-12, -13 and -14.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.13-3 acceptable
 
because the applicant has explained that the sprinkler and standpipe systems listed below are
 
not required for compliance with fire protection regulations. The staff determines that the
 
following fire water suppression systems are fo r property protection and for loss prevention:
* Condenser Area
* Turbine Central Area
* Turbine Condenser Gallery
* Turbine Hydro Control Power Room
* North Railroad Bay
* Turbine Condenser Mezzanine
* Diesel Engine Fire Pump Room
* Turbine Pump Area
* Turbine Filter Room
* Turbine Moisture Separation Area
* Radwaste Tank Vent Filter Room
* Radwaste Auxiliary Rooms
* Radwaste Controlled Zone Shop 
 
The staff concludes that sprinkler and standpipe systems are correctly excluded from the scope of license renewal and from being subject to an AMR. In addition, the staff finds that the 2-77 applicant has committed to include the following sprinkler and standpipe systems within the scope for the license renewal and subject to an AMR:
* Turbine Building areas
* Reactor Feed Pump Turbine (RFP Lube Oil Reservoir)
* PFP Turbine Room (RFP Turbine Room)
* Centrifuge & Conditioner (Lube Oil Conditioner Room)
* Turbine Hydro Seal Oil Unit (Hydrogen Seal Oil Unit)
* Turbine Lube oil Area (Turbine Lube oil Reservoir)
* Turbine Motor Generator Area (Turbine generator bearings)
 
The staff is adequately assured that the above sprinkler and standpipe systems for fire
 
suppression will be appropriately considered during aging management activities. Therefore, the staff's concern described is RAI 2.3.3.13-3 is resolved. 
 
In RAI 2.3.3.13-4, dated June 22, 2007, the staff stated that SER Section 9.5.1.3 (NUREG-0776, dated April 1981), describes the low-pressure carbon dioxide (CO
: 2) fire extinguishing systems for electrical equipment rooms, generator purging, concealed floor and ceiling spaces. This SER section also discusses self-contained Halon 1301 fire extinguishing
 
systems for power generation complex modules. The staff noted that the total flooding CO 2 fire extinguishing systems for electrical equipment rooms, generator purging, concealed floor and ceiling spaces and self-contained Halon 1301 fire extinguishing systems for power generation
 
complex modules do not appear in LRA Section 2.3.3.13 as being in the scope of the license
 
renewal and subject to an AMR. 
 
The staff requested that the applicant verify whether the CO 2 fire extinguishing systems for electrical equipment rooms, generator purging, concealed floor and ceiling spaces and Halon
 
1301 fire extinguishing systems for power generation complex modules are within the scope of
 
license renewal, in accordance with 10 CFR 54.4(a) and subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1) and; if excluded, provide justification.
 
In its response to RAI 2.3.3.13-4, dated July 24, 2007, the applicant stated:
 
The CO 2 and Halon fire extinguishing systems 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). "Spray nozzles, CO 2 and Halon" and "Tank, low pressure CO 2 storage tank (0T102)" are explicitly listed in LRA Table 2.3.3-13 and are subject to an AMR. These suppression
 
systems also include piping, tubing, valve bodies, and bolting, which are
 
also listed in LRA Table 2.3.3-13 as subject to an AMR.
 
As shown on LRA drawing LR-M-122, Sheet 4, "Fire Protection Carbon
 
Dioxide Systems," normally closed va lves isolate the generator purging portion of the CO 2 extinguishing system from the storage tank. The storage tank, attached piping, and isolation valves are within the scope of
 
license renewal and subject to an AMR, as described above. The
 
remainder of the generator purging portion of the CO 2 fire extinguishing system is not in the scope of license renewal. The CO 2 fire extinguishing systems for safety-related and safe-shutdown system protection include those in the electrical equipment rooms and floor and ceiling spaces 2-78 (concealed) of the control room. In addition, Power Generation Control Complex (PGCC) modules are provided with self-contained Halon 1301
 
fire extinguishing systems as described in Section 4.9 of the FPRR, Revision 15, and in Section 9.5.1.3 of NUREG-0776, dated April 1981.
 
These systems are self-contained in the individual modules and, as such, are not shown on an LRA drawing.
 
In evaluating the applicant's response, the staff found that it was incomplete and that review of
 
LRA Section 2.3.3.13 could not be completed. The staff noted the applicant's explanation that
 
the CO 2 and Halon 1301 fire extinguishing systems are within the scope of license renewal, in accordance with 10 CFR 54.4(a) and subject to an AMR, pursuant to 10 CFR 54.21(a)(1). The
 
staff also noted that a part of the generator purging portion of the CO 2 extinguishing system is not within the scope of license renewal. The staff further noted that the Power Generation
 
Control Complex (PGCC) modules are provided with self-contained Halon 1301 fire
 
extinguishing systems.
 
The applicant indicated in its response to RAI 2.3.3.14-4 that the CO 2 and Halon fire extinguishing system in question is within the scope of license renewal, but a portion of the CO 2 system was not highlighted on LRA boundary drawing LR-M-122, Sheet 4. This resulted in the
 
staff holding a telephone conference with the applicant on October 3, 2007, to discuss
 
information necessary to resolve its concern described in RAI 2.3.3.13-4. During the
 
teleconference, the staff asked the applicant to explain why a portion of the CO 2 system was not highlighted on LRA boundary drawing LR-M-122, Sheet 4. Further, the staff requested that the
 
applicant verify whether the PGCC modules self-contained Halon 1301 fire extinguishing
 
systems are within the scope of license renewal, in accordance with 10 CFR 54.4(a) and
 
subject to an AMR, in accordance with 10 CFR 54.21(a)(1). 
 
The applicant clarified that a portion of the CO 2 system for the generator purging system is not within the scope of license renewal, because a malfunction of that portion of the system will not
 
prevent the CO 2 fire extinguishing system from accomplishing its 10 CFR Part 50, Appendix R function. The staff determines that the portion of the CO 2 system in question could not affect the actuation of the CO 2 system, and was correctly excluded fr om the scope of license renewal and is not subject to an AMR. The staff also determines that the applicant has considered the PGCC
 
self-contained Halon 1301 units as active components and; therefore, excluded them from the
 
scope of license renewal and subject to an AMR. Therefore, the staff's concern described in
 
RAI 2.3.3.13-4 is resolved.
 
In RAI 2.3.3.13-5, dated June 22, 2007, the staff noted that the LRA Table 2.3.3-13 excludes
 
several types of fire protection components that appear in the April 1981 SER (NUREG-0776)
 
for SSES, and/or the applicant's Fire Protection Review Report. These components are listed
 
below:
* Hose stations
* Spray nozzles (water, CO2/Halon 1301)
* Dikes for oil spill confinement
* Floor drains and curbs for fire-fighting water
* Filter housing
* Strainer housing 2-79
* Heater housing
* Chamber housing
* Actuator housing
* Pipe supports
* Halon storage bottles
* Water storage tanks
* Buried outside diesel fuel storage tanks
* Heat exchanger (bonnet)
* Turbocharger
* Lubricating oil collecting system components (reactor coolant pump)
* Engine intake and exhaust silencers/muffler (diesel driven fire pump)
* Manual smoke removal systems and their associated components (control structure including CSRs)
The staff requested that the applicant verify whether the components listed above should be included in LRA Table 2.3.3.13 and: if excluded, provide justification.
 
In its response to RAI 2.3.3.13-5, dated July 24, 2007, the applicant stated in part:
 
Fire protection system components that provide safety-related and safe-
 
shutdown system protection (i.e., that are required for compliance with 10 CFR 50.48) are in the scope of license renewal and subject to an
 
AMR unless justification is provided otherwise.
 
With certain exceptions, the components listed above do not need to be
 
included in LRA Table 2.3.3-13 in that they are already included in the
 
table (as clarified below), included in a separate LRA table excluded from
 
the scope of license renewal or not subject to an AMR. Each type of
 
component listed above is addressed in the following table. The
 
corresponding LRA location is identified for components subject to an
 
AMR and justification is provided, as applicable.
 
The applicant provided a table as part of its response that identified:
-certain components of the Fire Protection System were incorrectly
 
omitted from Section 2.3.3.13 and subsequent portions of the LRA. These
 
components are attached to and support the function of the diesel engine
 
driven fire pump (0P511), shown on LRA drawing LR-M-122, Sheet 1. For
 
the most part, these supporting components are not shown on the
 
boundary drawing. An evaluation was performed to determine the extent
 
of this condition-
 
Based on this evaluation, the applicant identified additional components as
 
being subject to an AMR. In addition, the applicant amended the applicable
 
boundary drawings and the LRA to include the applicable components.
2-80  In evaluating the applicant's response to RAI 2.3.3.13-5, the staff found that it was incomplete
 
and review of LRA Section 2.3.3.13 could not be completed.
The staff noted that although the applicant states that it considered some components to be included in other line items, the
 
descriptions of the line items in the LRA do not specifically list all the components. Further, the
 
applicant has committed to interpret some components (e.g., hose stations, curbs for fire fighting water, and pipe supports), as included in "Bulk Commodity" in LRA Table 2.4-10. 
 
The applicant included the following items within the scope of license renewal and subject to an
 
AMR, because of their intended functions as part of the pressure boundary:
* filter bodies
* heater housing
* muffler
* heat exchanger (oil cooler) shell and end cover
* heat exchanger (oil cooler) tubes
* pump casing (diesel fuel oil)
* pump casing (diesel lubricating oil)
* pump casing (diesel cooling water)
* tank (oil pan)
* turbocharger casing
 
The applicant explained that only components with an intended function other than "pressure
 
boundary" are listed separately from the line item. Because the applicant has committed to
 
interpret these components as included in the line item and the intended function is as a
 
pressure boundary only, the staff is adequately assured that these components will be
 
appropriately considered during plant aging management activities. 
 
The staff found that the actuator housing and turbocharger were not included in the line item
 
descriptions in the LRA. The staff confirms the applicant's interpretation of these components as
 
active, which necessarily will result in more vigorous oversight of the condition and performance
 
of the components. However, the staff disagreed with the applicant that the spray nozzles for
 
fire hoses are considered to be integral to the fire hose, and the applicant's evaluation that fire
 
hose nozzles are not subject to an AMR. The staff determines that the fire hose nozzle function
 
is not pressure tested like hoses and; therefore, should be considered as a passive component
 
and subject to an AMR, in accordance with 10 CFR 54.21(a)(1). The staff noted that LRA
 
Table 2.3.3-13 identified nozzles as within the scope of license renewal and subject to an AMR.
 
Based on its review, the staff is adequately assured that the applicant will appropriately consider
 
fire hose nozzles during plant aging management activities. 
 
2-81 The applicant stated that the auxiliary boilers for SSES are electric and do not have fuel oil tanks and; therefore, do not require dikes. The staff believes that the turbine lube oil reservoir
 
room, hydraulic control power room, and lube oil centrifuge and conditioner room may contain
 
dikes for oil spill confinement and requested that the applicant verify whether the dikes for oil
 
spill confinement are above areas that are in-scope, in accordance with 10 CFR 54.4(a) and
 
subject to an AMR, pursuant to 10 CFR 54.21(a)(1).
 
During the conference call on October 3, 2007 and by letter dated October 24, 2007, the
 
applicant stated that the LRA does not distinguish dikes for oil spill containment from flood
 
curbs. Flood curbs are within the scope of license renewal and subject to an AMR, addressed
 
as a bulk commodity, and listed in LRA Table 2.4-10.
 
Based on its review, the staff finds the applicant's response acceptable. The applicant stated
 
that LRA does not distinguish dikes for oil spill containment from flood curbs. Flood curbs are
 
within the scope of license renewal and subject to an AMR and included as a bulk commodity in
 
LRA Section 2.4.10, Table 2.4-10. Because the applicant has committed to interpret dikes for oil
 
spill containment as included in the "flood curbs" line item, with the intended function only being
 
that of pressure boundary, the staff is adequately assured the dikes for oil spill containment will
 
be appropriately considered during plant aging management activities. 
 
The applicant stated that the Halon cylinders are stamped DOT and are considered
 
consumables that are replaced periodically and; therefore, not subject to an AMR. The staff
 
disagreed with the applicant interpretation of consumables and noted that SRP-LR, Table 2.1-5, listed tanks as passive components. The staff believes that Halon tanks are part of the Halon
 
fire extinguishment system and; therefore, s hould be within the scope of license renewal, in accordance with 10 CFR 54.4(a) and subject to an AMR, pursuant to 10 CFR 54.21(a)(1). 
 
During the conference call on October 3, 2007 and by letter dated October 24, 2007, the
 
applicant stated that the SSES Halon cylinders are relatively small spheres, approximately
 
12 inches in diameter. The technical requirements manual TRS 3.7.3.4.1 for Units 1 and 2, directs the applicant to perform periodic weight and pressure verifications of Halon cylinders.
 
These inspections are implemented under plant procedures 9SM-113-014, SM-113-015, SM-213-014, and SM-213-015 and include inspection of the Halon cylinders for any sign of
 
damage and deterioration. These inspection activities collectively fall under the category of
 
condition monitoring and determine whether the Halon cylinders are at the end of their qualified
 
lives. The staff determined that SRP-LR, Table 2.1-3, page 2.1-15 under "consumable," item
 
"(d)," allows for the exclusion of these components from and AMR, due to required condition
 
monitoring activities. 
 
Although in other license renewal reviews, components similar to the Halon cylinders are
 
considered to be passive and, therefore, included in the scope of license renewal and subject to
 
an AMR, the staff confirms the applicant's interpretation of this component as active. On a
 
plant-specific basis, the applicant has excluded Halon cylinders from an AMR, pursuant to
 
10 CFR 54.21(a)(1)(ii). The staff also confirms that the applicant has routinely monitored Halon
 
cylinders based on performance or condition crit eria specified in Technical Requirements Manual (TRS) 3.7.3.4.1 of the TRM, thus, ensuring that the cylinders maintain their intended
 
function. 
 
Because the applicant has interpreted the Halon cylinders as part of an active component (condition monitoring to determine whether the Halon cylinders are at the end of their qualified 2-82 lives) the staff concludes that the component was correctly excluded from the scope of license renewal and is not subject to an AMR.
 
Further, the staff requested that the applicant verify whether following line items listed in the
 
above table are in-scope, in accordance with 10 CFR 54.4(a) and subject to an AMR, in
 
accordance with 10 CFR 54.21(a)(1):
* Filter housing
* Strainer housing
* Actuator housing
 
During the conference call on October 3, 2007 and by letter dated October 24, 2007, the
 
applicant stated that filter and actuator housings are within the scope of license renewal, in
 
accordance with 10 CFR 54.4(a) and subject to an AMR pursuant to 10 CFR 54.21(a)(1). The
 
filter and actuator housings are listed in LRA Table 2.3.3-13. The strainer has dual intended
 
functions; namely, the strainer housing performs the pressure boundary function and the
 
strainer internals provide the filtration function. 
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.13-5 acceptable
 
because the applicant has adequately explained its interpretation of the component
 
characterization. The staff confirms the applicant's interpretation of this component as active, which necessarily will result in more vigorous oversight of the condition and performance of the
 
component. The staff is adequately assured that these components will be appropriately
 
considered as within the scope of license renewal and subject to an AMR. Therefore, the staff's
 
concerns described in RAI 2.3.3.13-5 are resolved.
 
In RAI 2.3.3.13-6, dated June 22, 2007, the staff noted that in LRA Section 2.3.3.13, the
 
applicant discussed 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 as passive and long-lived components. Both trash racks and traveling screens are located in a fresh or raw water and/
or air environment and are typically constructed of carbon steel. Carbon steel located in a fresh or raw water environment or water and/or air
 
environment is subject to loss of material, pitti ng, crevice formation, microbiologically influenced corrosion, and fouling. The staff requested that the applicant explain the apparent exclusion of
 
the trash racks and traveling screens 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).
 
In its response to RAI 2.3.3.13-6, dated July 24, 2007, the applicant stated:
 
As described in LRA Section 2.3.3.13, System Description, Water
 
Supplies, the primary source of fire protection water is the Clarified Water
 
Storage Tank, addressed in LRA Section 2.3.3.21, and the second and
 
third sources are the basins of hyperbolic natural draft cooling towers for
 
Units 1 and 2, addressed in LRA Section 2.3.3.6. Accordingly, the fire
 
pumps at SSES are horizontal, centrifugal type pumps as described in
 
FPRR Section 4.1, rather than vertical wet pit pumps, and do not take 2-83 suction from an open bay. Since the pumps do not take suction from a natural source or bay, trash racks and traveling screens are neither
 
required nor installed at SSES.
 
Boundary drawings LR-M-115, Sheet 1 and LR-M-2115, Sheet 1, which
 
are identified in LRA Section 2.3.3.6, show the outlet screens for the
 
cooling tower basin in the scope of license renewal (highlighted green).
 
As described in LRA Section 2.4.9.6, LRA Table 2.4-9, and LRA
 
Table 3.5.2-9, the Cooling Tower Basin Outlet Screens are in license
 
renewal scope and are subject to an AMR as structural commodities.
 
They are constructed of stainless steel and are fixed screens.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.3-6 acceptable
 
because the applicant adequately described that the intended function supporting the fire pump
 
suction supply is accomplished from the water storage tank and basins of the hyperbolic natural
 
draft cooling towers for Units 1 and 2. The fire pumps at SSES do not take suction from a
 
natural source or bay, therefore, trash racks and traveling screens are not required. In addition, the staff confirms that the applicant has placed cooling tower basin outlet screens within the
 
scope of license renewal and subject to an AMR, as structural commodities. Therefore, the
 
staff's concern described in RAI 2.3.3.13-6 is resolved.
 
2.3.3.13.3 Conclusion
 
The staff reviewed the LRA, UFSAR, LRA boundary drawings (original and revised), and
 
RAI responses 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. On the basis of its review, the staff concludes
 
the applicant has appropriately identified the fire protection system and components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately
 
identified the fire protection mechanical components subject an AMR, in accordance with the
 
requirements of 10 CFR 54.21(a)(1) and; therefore, is acceptable.
 
2.3.3.14  Fuel Pool Cooling and Cleanup System and Fuel Pools and Auxiliaries 2.3.3.14.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.14 describes the fuel pool cooling and cleanup system (FPCCS) system and fuel pools and auxiliaries that cool the fuel storage pool water by transferring decay heat of the
 
irradiated fuel through heat exchangers to the SWS. The FPCCS and fuel pools and auxiliaries
 
contain safety-related components relied upon to remain functional during and following DBEs.
 
The failure of nonsafety-related SSCs in the SSCs in the FPCCS and fuel pools and auxiliaries
 
could prevent satisfactory performance of a safety-related function. LRA Table 2.3.3-14
 
identifies FPCCS and fuel pools and auxiliaries component types within the scope of license
 
renewal and subject to an AMR.
2.3.3.14.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.14, UFSAR Sections 9.1.3 and 9.1.2, and the licensing
 
renewal boundary drawings using the evaluation methodology described in SER Section 2.3
 
and the guidance in SRP-LR Section 2.3. The staff's review of LRA Section 2.3.3.14 identified 2-84 areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. In addition to RAIs 2.3.3.14-1, 2.3.3.14-2, and 2.3.3.14-11
 
related to boundary drawing continuation errors described in LRA Section 2.3.3, the applicant
 
responded to the staff's RAIs as discussed below.
In RAI 2.3.3.14-3, dated August 27, 2007, the staff noted that boundary drawing LR-M-154-1, locations C3, C6, and C9, show the boundary (pursuant to 10 CFR 54.4(a)(2)) at the top of the
 
fuel pool filter demineralizers. Though not within the scope of license renewal, two-inch vent
 
pipes are shown exiting the top of the filter demineralizers and going to the vent header
 
two-inch HBD-87 piping, which also is not within scope of licensing renewal. Boundary drawing
 
LR-M-154-1, location A1, shows a continuati on from the out-of-scope vent header two-inch HBD-87 piping to boundary drawing LR-M-166-2, location A2, where the two-inch HBD-87
 
piping is shown within the scope of license renewal. The staff requested that the applicant
 
explain why the two-inch vent piping and two-inch HBD-87 vent header piping are not within the
 
scope of license renewal.
 
In its response to RAI 2.3.3.14-3, dated October 18, 2007, the applicant stated in part:
 
License renewal Note E on drawing LR-M-166-2 states that component
 
vents routed to a tank are considered to potentially contain liquid and are
 
included in the evaluation boundaries. 
 
The vent piping from the fuel pool filter demineralizers on drawing
 
LR-M-154-1 up to the vent header and continuing onto drawing
 
LR-M-166-2 at location A2 and to the connection to the fuel pool
 
backwash receiving tank is within the scope of license renewal per the
 
criteria of 10 CFR 54.4(a)(2). The drawings were revised to highlight the
 
piping [as 10 CFR 54.4(a)(2)].
 
Because the components being added are addressed under the "piping and piping components"
 
line item in LRA Table 2.3.3-14, the applicant stated that no changes are required to this table.
 
The applicant further stated that the LRA:
 
-was amended to address the materials for the components added to
 
the scope of license renewal per this response. The internal environment
 
for the carbon and stainless steel vent piping is evaluated as a ventilation
 
environment. In addition it was noted that there is carbon steel piping
 
subject to the treated water environment. Evaluation of that piping was
 
also added to LRA Table 3.3.2-14.
 
2-85 The staff confirms that the applicant has submitted revised boundary drawings LR-M-154-1 and LR-M-166-2, and has revised LRA Table 3.3.2-14.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-3 acceptable
 
because the applicant has clarified that the piping in question is within the scope of license
 
renewal and has made appropriate revisions to boundary drawings LR-M-154-1 and
 
LR-M-166-2 and LRA Table 3.3.2-14. Therefore, the staff's concern described in RAI 2.3.3.14-3
 
is resolved.
 
In RAI 2.3.3.14-4, dated August 27, 2007, the staff noted that boundary drawing LR-M-153-2, location F4, shows the continuation of one-inch HBD piping to boundary drawing LR-M-161-1, location E1, which is within the scope of license renewal, pursuant to 10 CFR 54.4(a)(2).
 
Boundary drawing LR-M-153-2 did not provide the complete pipe identification number. Review
 
of the continuation boundary drawing LR-M-161-1, location E1, did not show the one-inch HBD
 
piping specifically identified or show the continuation of the in-scope piping from boundary
 
drawing LR-M-153-2. The staff requested that the applicant provide additional information to
 
include the complete one-inch HBD pipe identification number on boundary drawings
 
LR-M-153-2 and LR-M-161-1 and explain why the continuation of the in-scope boundary from
 
boundary drawing LR-M-153-2 is not shown as within the scope of license renewal on boundary
 
drawing LR-M-161-1.
 
In its response, dated October 18, 2007, the applicant stated:
 
The continuation of the one-inch HBD drain line from the refueling
 
bellows area of the primary containment on drawing LR-M-153-2 is
 
included in the listing of sources draining to the drywell equipment drain
 
tank on drawing LR-M-161-1, location E1. The line from LR-M-153-2, location F4, is addressed by the listing "Bellows Drain (M-153)." 
 
The subject 1-inch drain line on LR-M-153-2 that continues to
 
LR-M-161-1 should not be highlighted as within the scope of license
 
renewal for 10 CFR 54.4(a)(2) because it is located inside containment
 
where the equipment is designed to get wet. Drawing LR-M-153-2 was
 
revised to reflect this change.
The staff confirms that the applicant has submitted revised boundary drawing LR-M-153-2. 
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-4 acceptable
 
because the applicant has clarified that the piping in question on boundary drawing
 
LR-M-1-153-2 is not within the scope of license renewal and has made appropriate revisions to
 
boundary drawing LR-M-153-2. Therefore, the staff's concern described in RAI 2.3.3.14-4 is
 
resolved.
 
In RAI 2.3.3.14-5, dated August 27, 2007, the staff noted that boundary drawings LR-M-153-2, location F5, shows the continuation of two-inch HBD-1052 piping to boundary drawing
 
LR-M-161-1, location E1, which is within the scope of license renewal, pursuant to
 
10 CFR 54.4(a)(2). Review of the continuation boundary drawing LR-M-161-1, location E1, did
 
not show the two-inch HBD-1052 piping specifically identified or show the continuation of the
 
in-scope piping from boundary drawing LR-M-153-2. The staff requested that the applicant
 
provide additional information that indicates where the two-inch HBD-1052 pipe continuation is 2-86 located on boundary drawing LR-M-161-1 and explain why the continuation of the in-scope boundary from boundary drawing LR-M-153-2 is not shown as within the scope of license
 
renewal on boundary drawing LR-M-161-1.
 
In its response to RAI 2.3.3.14-5, dated October 18, 2007, the applicant stated:
 
The continuation of the 2" HBD-1052 drain line from the refueling
 
bellows area of the primary containment on drawing LR-M-153-2 is
 
included in the listing of sources draining to the drywell equipment drain
 
tank on drawing LR-M-161-1 at location E1. The line from LR-M-153-2
 
at location F5 is addressed by the listing "Bellows Drain (M-153)".
 
The subject two-inch drain line on LR-M-153-2 that continues to
 
LR-M-161-1 should not be highlighted as within the scope of license
 
renewal for 10 CFR 54.4(a)(2) because it is located inside containment
 
where the equipment is designed to get wet.
 
The staff confirms that the applicant has submitted revised boundary drawing LR-M-153-2.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-5 acceptable
 
because the applicant has clarified that the piping in question on boundary drawing
 
LR-M-1-153-2 is not within the scope of license renewal and has made appropriate revisions to
 
boundary drawing LR-M-153-2. Therefore, the staff's concern described in RAI 2.3.3.14-5 is
 
resolved.
In RAI 2.3.3.14-6, dated August 27, 2007, the staff noted that boundary drawing LR-M-2153-2, location F4, shows the continuation of one-inch HBD piping to boundary drawing LR-M-2161-1, location F1, which is within the scope of license renewal, pursuant to 10 CFR 54.4(a)(2). The
 
LR-M-2153-2 boundary drawing did not provide the complete pipe identification number. Review
 
of the continuation boundary drawing LR-M-2161-1, location F1, did not show the one-inch HBD
 
piping specifically identified or show the continuation of the in-scope piping from boundary
 
drawing LR-M-2153-2. The staff requested that the applicant provide additional information that
 
includes the complete one-inch HBD pipe identification number on boundary drawings
 
LR-M-2153-2 and LR-M-2161 and explain why the continuation of the in-scope boundary from
 
boundary drawing LR-M-2153-2 is not shown as within the scope of license renewal on
 
boundary drawing LR-M-2161.
 
In its response to RAI 2.3.3.14-6, dated October 18, 2007, the applicant stated in part:
 
The continuation of the one-inch HBD drain line from the refueling
 
bellows area of the primary containment on drawing LR-M-2153-2 is
 
included in the listing of sources draining to the drywell equipment drain
 
tank on drawing LR-M-2161-1, location F1. The line from LR-M-2153-2 at
 
location F4 is addressed by the listing "Bellows Leakage Drain (M-2153)."
 
The subject one-inch drain line on LR-M-2153-2 that continues to
 
LR-M-2161-1 should not be highlighted as within the scope of license
 
renewal for 10 CFR 54.4(a)(2) because it is located inside containment
 
where the equipment is designed to get wet. Refer to LRA
 
Section 2.1.1.2.2 and the enclosed response to RAI 2.3.3.23-3 for an 2-87 explanation.
 
The staff confirms that the applicant has submitted revised boundary drawing LR-M-2153-2.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-6 acceptable
 
because the applicant has clarified that the piping in question on boundary drawing
 
LR-M-1-2153-2 is not within the scope of license renewal and has made appropriate revisions to
 
boundary drawing LR-M-2153-2. Therefore, the staff's concern described in RAI 2.3.3.14-6 is
 
resolved.
 
In RAI 2.3.3.14-7, dated August 27, 2007, the staff noted that boundary drawing
 
LR-M-2153-2, location F5, shows the continuation of two-inch HBD-2052 piping to boundary
 
drawing LR-M-2161-1, location F1, which is within the scope of license renewal, pursuant to
 
10 CFR 54.4(a)(2). Review of the continuation boundary drawing LR-M-2161-1, location F1, did not show the two-inch HBD-2052 piping specifically identified or show the continuation of
 
the in-scope piping from boundary drawing LR-M-2153-2. The staff requested that the
 
applicant provide additional information that indicates where the two-inch HBD-2052 piping
 
continuation is located on boundary drawing LR-M-2161-1 and explain why the continuation of
 
the in-scope boundary from boundary drawing LR-M-2153-2 is not shown as within the scope
 
of license renewal on boundary drawing LR-M-2161-1.
 
In its response to RAI 2.3.3.14-7, dated October 18, 2007, the applicant stated in part:
 
The continuation of the 2 inch HBD-2052 drain line from the refueling
 
bellows area of the primary containment on drawing LR-M-2153-2 is
 
included in the listing of sources draining to the drywell equipment drain
 
tank on drawing LR-M-2161-1 at location F1. The line from LR-M-2153-2
 
at location F5 is addressed by the listing "Bellows Leakage Drain (M-2153)".
The subject 2 inch drain line on LR-M-2153-2 that continues to LR-M-2161-1 should not be highlighted [as 10 CFR 54(a)2)]. This drain
 
line is located inside primary containment where the equipment is
 
designed to get wet. Refer to LRA Section 2.1.1.2.2 and the enclosed
 
response to RAI 2.3.3.23-3 for an explanation.
 
The staff confirms that the applicant has submitted revised boundary drawing LR-M-2153-2.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-7 acceptable
 
because the applicant has clarified that the piping in question on boundary drawing
 
LR-M-1-2153-2 is not within the scope of license renewal and has made appropriate revisions to
 
boundary drawing LR-M-2153-2. Therefore, the staff's concern described in RAI 2.3.3.14-7 is
 
resolved.
 
In RAI 2.3.3.14-8, dated August 27, 2007, the staff noted that boundary drawing LR-M-153-2
 
shows six weirs with screens at locations D1, D2, D3, D5, and D6 at the ends of four-inch
 
HCD-143 piping; diffusers at locations E2 and E6 at the ends of six-inch HCD-158 piping, and
 
location E9 at the end of six-inch HCD-3023 piping; and a grate at location F9 at the start of
 
six-inch HCD-3024 piping that are within the scope of license renewal, pursuant to
 
10 CFR 54.4(a)(2). Boundary drawing LR-M-2153-2 shows six weirs with screens at locations 2-88 D1, D2, D3, D5, and D6 at the ends of four-inch HCD-243 piping; diffusers at locations E2 and E6 at the ends of six-inch HCD-258 piping; and grates at location E3 at the start of three-inch
 
HBC-220 piping that are within the scope of license renewal, pursuant to 10 CFR 54.4(a)(2).
 
None of these component types are listed in LRA Table 2.3.3-14 for components subject to an
 
AMR. The staff requested that the applicant explain why these component types are not
 
included in LRA Table 2.3.3-14.
 
In its response to RAI 2.3.3.14-8, dated October 18, 2007, the applicant stated in part:
 
The weirs (with screens) and diffusers on drawing LR-M-153-2 all perform
 
a structural integrity function. As such, they are evaluated as component
 
type "piping and piping components", which is included with a structural
 
integrity function in LRA Table 2.3.3-14. The grate at location F9 is
 
embedded in the floor of the shipping cask storage pit does not have the
 
potential for affecting safety-related components through spatial
 
interaction and therefore does not meet the criteria of 10 CFR 54.4(a)(2).
 
Drawing LR-M-153-2 has been revised to indicate that the grate at
 
location F9 is not within the scope of license renewal.
 
The weirs (with screens) and diffusers on drawing LR-M-2153-2 all
 
perform a structural integrity function. As such, they are evaluated as
 
component type "piping and piping components", which is included with a
 
structural integrity function in LRA Table 2.3.3-14.
 
The piping within the primary containment, including the grates at location
 
E3, was removed from the scope of license renewal on drawing
 
LR-M-2153-2. Refer to LRA Section 2.1.1.2.2 and the enclosed response
 
to RAI 2.3.3.23-3 for the explanation.
 
The staff confirms that the applicant has submitted revised boundary drawing LR-M-153-2.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-8 acceptable
 
because the applicant has explained that the components in question are included as a
 
component type within "piping and piping components" in LRA Table 2.3.3-14 and that boundary
 
drawing LR-M-153-2 was revised because the grate at location F9 is not in-scope. Therefore, the staff's concern described in RAI 2.3.3.14-8 is resolved.
 
In RAI 2.3.3.14-9, dated August 27, 2007, the staff noted that boundary drawing LR-M-153-2 shows grates at locations E1, E3, E5, E6, E7, E8, E9, and F9, with only the F9 grate at the start
 
of 6" HCD-3024 piping shown within the scope of licensing renewal. Boundary drawing
 
LR-M-2153-2 shows grates at locations E1, E3, E5, E6, E7, and E8, with only two of the E3
 
grates at the start of three-inch HBC-120 piping shown within the scope of license renewal. All
 
of the grates are shown located at the entrance to the drain piping within the scope of license
 
renewal, pursuant to 10 CFR 54.4(a)(2). The staff requested that the applicant explain why
 
some grates are within the scope of license renewal and some are not, when they all flow into
 
piping that is within the scope of licensing renewal.
In its response to RAI 2.3.3.14-9, dated October 18, 2007, the applicant stated in part:
 
2-89 Based on the response to RAI 2.3.3.14-8, drawing LR-M-153-2 has been revised to indicate the grate at location F9 at the start of six-inch
 
HCD-3024 piping as not within the scope of license renewal. This change
 
was based on the grate being embedded in the floor of the shipping cask
 
storage pit; therefore, not having the potential for affecting safety-related
 
components through spatial interaction and not meeting the criteria of
 
10 CFR 54.4(a)(2).
 
The piping within the primary containment, including the grates at location
 
E3, was removed from the scope of license renewal on drawing
 
LR-M-2153-2. Refer to LRA Section 2.1.1.2.2 and the enclosed response
 
to RAI 2.3.3.23-3 for the explanation. Note that revised boundary drawing
 
LR-M-2153-2 was prepared in response to RAI 2.3.3.14-11.
 
All of the grates are embedded in concrete and therefore do not have the
 
potential for affecting safety-related components through spatial
 
interaction. Therefore, the grates do not meet the criteria of
 
10 CFR 54.4(a)(2) and are not within the scope of license renewal.
 
The staff confirms that the applicant has submitted revised boundary drawing LR-M-2153-2.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-9 acceptable
 
because the applicant has explained that all the grate components in question are not within the
 
scope of license renewal, since they are embedded in concrete and that boundary drawing
 
LR-M-2153-2 was revised to indicate that none of the grates are within the scope of license
 
renewal. Therefore, the staff's concern described in RAI 2.3.3.14-9 is resolved.
 
In RAI 2.3.3.14-10, dated August 27, 2007, the staff noted that boundary drawing LR-M-153-2, location E3, shows two grates, which are identified as not within the scope of license renewal, that drain into three-inch HBC-120 piping that is within the scope of license renewal, pursuant to
 
10 CFR 54.4(a)(2). Boundary drawing LR-M-2153-2, also at location E3, shows essentially the
 
same two grates, which are identified as within the scope of licensing renewal, that drain into
 
three-inch HBC-220 piping within the scope of licensing renewal, pursuant to 10 CFR 54.4(a)(2)
 
and also draining to the liquid radwaste system. The staff requested that the applicant explain
 
why there is a difference of grate scope classification between Unit 1 and Unit 2, when the
 
grates essentially have the same location, piping size, function, and destination.
 
In its response to RAI 2.3.3.14-10, dated October 18, 2007, the applicant stated in part:
The piping within the primary containment, including the grates at location
 
E3 on drawing LR-M-2153-2, was removed from the scope of license
 
renewal. This change to drawing LR-M-2153-2 was identified as
 
Revision 1. The basis for the removal of the piping within primary
 
containment on drawings LR-M-153-2 and LR-M-2153-2 from the scope of license renewal was that safety-related components inside
 
containment are designed for a harsh environment, including spray, and
 
are not plausible targets for spatial interaction. The subject components
 
are not connected to safety-related piping. Refer to LRA Section 2.1.1.2.2
 
and the enclosed response to RAI 2.3.3.23-3 for the explanation.
 
2-90 The staff confirms that the applicant has submitted revised boundary drawings LR-M-153-2 and LR-M-2153-2.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-10 acceptable
 
because the applicant has explained that all piping and grate components in question were
 
removed from the scope of license renewal, and that boundary drawings LR-M-2153-1 and
 
LR-M-2153-2 were appropriately revised. Therefore, the staff's concern described in
 
RAI 2.3.3.14-10 is resolved.
In RAI 2.3.3.14-12, dated August 27, 2007, the staff noted that boundary drawing LR-M-2153-1, location F6, shows orifice FE 25234 highlighted in green, indicating that it is within the scope of
 
license renewal, pursuant to 10 CFR 54.4(a)(1). Boundary drawing LR-M-153-1, location F6, orifice FE 15324 is highlighted in pink, indicating that it is within the scope of license renewal, pursuant to 10 CFR 54.4(a)(2). The staff requested that the applicant explain why different
 
scoping criterion was used for the Unit 1 versus Unit 2 orifices.
 
In its response to RAI 2.3.3.14-12, dated October 18, 2007, the applicant stated in part that:
 
Orifice FE 15324, like FE 25324, is a Q-Class component (i.e., safety-related)
 
and therefore meets the scoping criteria of 10 CFR 54.4(a)(1). The highlighting
 
error on LR-M-153-1 was revised to include orifice FE15324 as within the scope
 
of license renewal for criteria 10 CFR 54.4(a)(1).
 
The staff confirms that the applicant has submitted revised boundary drawing LR-M-153-1.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-12 acceptable
 
because the applicant has clarified that the orifices in question are both within the scope of
 
license renewal, pursuant to 10 CFR 54.4(a)(1) and has revised boundary drawing LR-M-153-1.
 
Therefore, the staff's concern described in RAI 2.3.3.14-12 is resolved.
 
In RAI 2.3.3.14-13, dated August 27, 2007, the staff noted that boundary drawings LR-M-153-1, location C6 and boundary drawing LR-M-2153, location C3, show 10-inch HBC-114/214 within
 
the scope of license renewal, pursuant to 10 CFR 54.4(a)(2), as nonsafety-related for spatial
 
interaction. The piping numbering system of boundary drawing LR-M-100 indicates that these piping components are American Society of Mechanical Engineers (ASME) Boiler and Pressure
 
Vessel Code, Section III, Class 3. ASME Code, Section III, Class 3 components typically are safety-related and fall within the scope of license renewal, pursuant to 10 CFR 54.4(a)(1). The
 
staff also noted other similar occurrences on these boundary drawings. The staff requested that
 
the applicant explain why portions of ASME Code, Section III, Class 3 components on boundary
 
drawings LR-M-153/2153-1 are not safety-related and why they are not within the scope of
 
license renewal, pursuant to 10 CFR 54.4(a)(1).
 
In its response to RAI 2.3.3.14-13, dated October 18, 2007, the applicant stated:
The FSAR Table 3.2-1 under the Fuel Pool Cooling and Cleanup System, shows that the principal construction code for the piping downstream of valve 1(2)53001 (10" HBC-114/214) is ASME Section III, Class 3. The same table shows that this piping is not within the scope of 10 CFR 50, Appendix B. Hence, the pipe is ASME III, Class 3, but is not safety-related. Reference LR-M-100-2 at E3, PPL's drawing convention is 2-91 to "cross-hatch" pipelines that are safety-related. The lack of "cross-hatching" indicates that HBC-114/214, as well as other similar instances of ASME Section III pipes, are not safety-related.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-13 acceptable because the applicant has verified that UFSAR Table 3.2-1 shows that this piping is not within
 
the scope of 10 CFR Part 50, Appendix B and is not safety-related. Therefore, the staff's
 
concern described in RAI 2.3.3.14-13 is resolved.
 
2.3.3.14.3  Conclusion The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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. On the basis of its review, the staff concludes the applicant has
 
appropriately identified the fuel pool cooling and cleanup system and fuel pools and auxiliaries mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a),
and that the applicant has adequately identified the FPCCS and fuel pools and auxiliaries
 
mechanical components subject to an AMR, in accordance with the requirements of
 
10 CFR 54.21(a)(1) and; therefore, is acceptable.
2.3.3.15  Neutron Monitoring System 2.3.3.15.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.15 describes the neutron monitoring system (NMS). The NMS contains
 
safety-related components relied upon to remain functional during and following DBEs. In
 
addition, the NMS performs functions that support ATWS and EQ. LRA Table 2.3.3-15 identifies
 
NMS component types within the scope of license renewal and subject to an AMR.
 
2.3.3.15.2  Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the NMS mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system
 
components subject to an aging management review in accordance with the requirements
 
stated in 10 CFR 54.21(a)(1).
2.3.3.16  Nitrogen and Hydrogen System 
 
2.3.3.16.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.16 describes the nitrogen and hydrogen system, which provides gaseous nitrogen for containment makeup and hydrogen for cooling the main generator during normal
 
plant operation. The failure of nonsafety-related SSCs in the nitrogen and hydrogen system
 
potentially could prevent the satisfactory acco mplishment of a safety-related function. Although connected to safety-related components for makeup and purge of the nitrogen in containment, no nitrogen and hydrogen system mechanical components are subject to an AMR. 
 
2-92 2.3.3.16.2  Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the nitrogen and hydrogen system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately
 
identified the system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.17  Primary Containment Atmosphere Circulation System 2.3.3.17.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.17 describes the primary containment atmosphere circulation system. The
 
primary containment atmosphere circulation sy stem contains safety-related components relied upon to remain functional during and following DBEs. In addition, the primary containment
 
atmosphere circulation system performs functions that support EQ. LRA Table 2.3.3-16
 
identifies primary containment atmosphere circul ation system component types within the scope of license renewal and subject to an AMR.
 
2.3.3.17.2  Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the primary containment atmosphere circulation system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the
 
applicant has adequately identified the system components subject to an aging management
 
review in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.18  Process and Area Radiation Monitoring System 2.3.3.18.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.18 describes the process and area radiation monitoring system, which
 
monitors releases of radioactive material in the plant gaseous and liquid process and effluent
 
streams to detect, alarm, indicate, and generate appropriate automatic actions to control
 
releases exceeding predetermined limits. The pr ocess and area radiation monitoring system contains safety-related components relied upon to remain functional during and following DBEs.
 
The failure of nonsafety-related SSCs in the process and area radiation monitoring system potentially could prevent the satisfactory acco mplishment of a safety-related function. In addition, the process and area radiation monitori ng system performs functions that support EQ.
LRA Table 2.3.3-17 identifies process and area r adiation monitoring system component types within the scope of license renewal and subject to an AMR. 
 
2.3.3.18.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.18, UFSAR Sections 7.6 and 11.5, and the license
 
renewal boundary drawings using the methodology described in SER Section 2.3 and the
 
guidance in SRP-LR Section 2.3. The staff's review identified an area in which additional
 
information was necessary to complete the review of the applicant's scoping and screening 2-93 results. The applicant responded to the staff's RAIs as discussed below. 
 
In a phone call with the applicant on November 19, 2008, the staff requested clarification of
 
information contained in the license renewal boundary drawings. LRA Section 2.3.3.18 lists the
 
license renewal boundary drawings that depict components of the process and area radiation
 
monitoring system (RMS). During its review of drawing LR-M-178, Sheet 1, the staff was unable to discern the components that were part of the process and area RMS. The applicant was able
 
to identify components AN07801 and FE07801, in this drawing, as the parts of the process and
 
area RMS and in-scope for their pressure boundary function, only. 
 
In RAI 2.3.3.18-1, dated December 3, 2008, the staff noted that the process and area RMS was
 
composed of a number of subsystems identif ied in the UFSAR for SSES. These subsystems include both safety-related and nonsafety-related sy stems. The LRA did not specifically address the scoping and screening results for each of the subsystems listed in the UFSAR. The staff
 
requested that the applicant clarify the scoping and screening of each subsystem and provide
 
drawing locations for subsystem components, if applicable.
 
In its response to RAI 2.3.3.18-1, dated December 12, 2008, the applicant stated that the
 
following subsystems were within the scope of license renewal:
* Standby Gas Treatment Vent Duct Exhaust RMS
* Standby Gas Treatment Vent Stack Exhaust Monitor and Sample RMS
* Refueling Floor Wall Duct Exhaust RMS
* Refueling Floor High Exhaust Duct RMS
* Railroad Access Exhaust Duct RMS
* Outside Air Intake Duct (Influent) RMS
* Service Water Discharge/Supplemental Decay Heat Removal RMS
* Main Steamline RMS
* RHR Service Water RMS
* Reactor Building Closed Cooling Water RMS
* Primary Containment Atmospheric Monitoring
* Primary Containment RMS (High Range)
 
The staff confirms that the applicant's response also provided the screening results for the
 
in-scope components of each of these systems. 
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.18-1 acceptable
 
because the applicant has clarified with sufficient detail, its scoping and screening review of the
 
subsystems that make up the process and area RMS. Therefore, the staff's concern described
 
in RAI 2.3.3.18-1 is resolved. 
 
2.3.3.18.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI response, and boundary 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. On the basis of its review, the staff concludes the applicant has
 
appropriately identified the process and area RMS components within scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the process and
 
area RMS components subject to an AMR review, in accordance with the requirements of 2-94 10 CFR 54.21(a)(1) and; therefore, is acceptable.
2.3.3.19  Radwaste Liquid System 2.3.3.19.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.19 describes the radwaste liquid system, which collects, processes, stores, and monitors, for reuse and disposal, the radioactive liquid wastes generated by plant
 
operation. The radwaste liquid system contains safety-related components relied upon to
 
remain functional during and following DBEs. The failure of nonsafety-related SSCs in the
 
radwaste liquid system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the radwaste liquid system performs functions that support EQ.
 
LRA Table 2.3.3-18 identifies radwaste liquid system component types within the scope of license renewal and subject to an AMR. 
 
2.3.3.19.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.19, UFSAR Section 11.2, and the licensing renewal
 
boundary drawings using the evaluation methodology described in SER Section 2.3 and the
 
guidance in SRP-LR Section 2.3. The staff's review identified areas in which additional
 
information was necessary to complete the review of the applicant's scoping and screening
 
results. The applicant responded to the staff's RAIs as discussed below.
 
In RAI 2.3.3.19-1, dated August 27, 2007, the staff noted that boundary drawings LR-M-161-2
 
and LR-M-2161-2, locations C1 to E1, provide a list of items (components, drains, vents, etc.)
that are contained in a non-boundary continuation box that interfaces directly with two four-inch XBD pipelines within the scope of license renewal. The list does not show details about the
 
boundary drawing, sheet, and location numbers for the listed items in order to review and
 
evaluate the license renewal scope boundaries. The staff requested that the applicant identify
 
these license renewal boundaries.
 
In its response to RAI 2.3.3.19-1, dated October 18, 2007, the applicant stated:
 
The boxes on LR-M-161-2 and LR-M-2161-2 do not represent specific
 
components and are not highlighted. The boxes represent that numerous
 
drain lines from the listed systems and drawings are coming together into
 
the lines continued from the box. Most of the piping making up the drain
 
lines coming into the "box" is embedded in the building's floor and wall
 
concrete. As the concrete forms a tight seal around the embedded drain
 
line, spatial interaction is not reasonable for embedded piping. Therefore, the embedded portions of the drain lines coming into the box are not
 
subject to AMR. The portions of these drain lines not embedded in
 
concrete are within the scope of license renewal, are subject to AMR and
 
are included in LRA Section 2.3.3.19 and Table 2.3.3.18, as "Piping and
 
Piping Components" with the intended function of "Structural Integrity."
 
The piping from the box is addre ssed on LR-M-161-2 and LR-M-2161-2, the liquid radwaste drawings.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.19-1 acceptable
 
because the applicant has adequately explained how the boxes on boundary drawings 2-95 LR-M-161-2 and LR-M-2161-2 do not represent components and why they are not in-scope.
The applicant further clarified that portions of pipelines are in concrete to prevent spatial
 
interaction and; therefore, are not subject to an AMR, while those pipe sections not embedded
 
in concrete are subject to AMR and are included in LRA Section 2.3.3.19 and Table 2.3.3.18.
 
Therefore, the staff's concern described in RAI 2.3.3.19-1 is resolved.
 
In RAI 2.3.3.19-2, dated August 27, 2007, the staff noted that boundary drawings LR-M-161-1
 
and LR-M-2161-1, locations E5 and F5, and boundar y drawings LR-M-161-2 and LR-M-2161-2, locations A4, B4, C4, D4, E4, E5, E3, F3, G3, and H3, show drum traps (e.g., P-25-6, P-29-6, etc.) within the scope of license renewal. However, the drum trap is not included in LRA
 
Table 2.3.3-19 as a component subject to an AMR. The staff requested that the applicant
 
explain why the drum traps are not included in LRA Table 2.3.3-19.
 
In its response to RAI 2.3.3.19-2, dated October 18, 2007, the applicant stated:
 
As stated in LRA Section 2.1.2.1.3, screening of mechanical components
 
for nonsafety affecting safety (NSAS) considerations was performed on a
 
commodity group basis. The commodity group of "piping and piping
 
components" includes all in-line piping components except for major
 
equipment such as tanks and heat exchangers.
The components identified on the Radwaste Liquid System drawings as
 
drum traps are evaluated as the component type of "cleanout" and are
 
included in the Table 2.3.3-19 line item "Piping and piping components -
 
cleanouts and pump casings (1/2P225A/B)".
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.19-2 acceptable
 
because the applicant has verified that PPL evaluates drum traps as a line item in the
 
commodity group of "piping and piping components - cleanouts and pump casings" that is
 
included in LRA Table 2.3.3-19. Therefore, the staff's concern described in RAI 2.3.3.19-2 is
 
resolved.
 
In RAI 2.3.3.19-3, dated August 27, 2007, the staff noted that boundary drawings LR-M-161-1
 
and LR-M-2161-1, location H8 show a cooling coil in the RB sump that is connected to two-inch
 
JBD-139 and two-inch JBD-140 piping that is shown within the scope of license renewal.
 
However, the cooling coil is not included within the scope of license renewal. The staff
 
requested that the applicant explain why the cooling coil is not within the scope of license
 
renewal.
In its response to RAI 2.3.3.19-3, dated October 18, 2007, the applicant stated:
 
The cooling coil does not perform a safety-related function; therefore, is
 
not in-scope for criterion 10 CFR 54.4(a)(1). The cooling coil is
 
completely enclosed within the reactor building sump and, therefore, can
 
not have any spatial interaction with safety-related equipment and the
 
sump itself does not perform a safety-related function. Thereby the
 
cooling coil is not in-scope for criterion 10 CFR 54.4(a)(2). The coil does
 
not support any of the regulated event functions and, therefore, the
 
cooling coil is not in-scope for criterion 10 CFR 54.4(a)(3).
2-96  Based on its review, the staff finds the applicant's response to RAI 2.3.3.19-3 acceptable
 
because the applicant has verified that the cooling coil is not within the scope of license renewal
 
for license renewal because: (a) it does not perform a safety-related function, (b) it cannot have 
 
any spatial interaction with safety-related equipment, and (c) the coil does not support any of
 
the regulated event functions. Therefore, the staff's concern described in RAI 2.3.3.19-3 is
 
resolved.
 
In RAI 2.3.3.19-4, dated August 27, 2007, the staff noted that boundary drawing LR-M-2161-2, location B1, shows a continuation from demineralized water distribution on boundary drawing
 
LR-M-118-2, location C2. The staff was unable to find boundary drawing LR-M-118-2 in the
 
LRA-provided boundary drawing package. The only boundary drawing found from
 
demineralized water distribution was LR-M-118-3, which included the correct continuation from
 
location C2 to boundary drawing LR-M-2161-2, location B1. The staff requested that the
 
applicant clarify that boundary drawing LR-M-118-3, rather than boundary drawing LR-M-118-2, was the correct continuation boundary drawing to boundary drawing LR-M-2161-2 at location
 
B1.
 
In its response to RAI 2.3.3.19-4, dated October 18, 2007, the applicant stated that the
 
continuation from boundary drawing LR-M-2161-2, at location B1 should be to boundary
 
drawing LR-M-118-3 at location C2.
 
The staff confirms that the applicant has corrected and submitted revised boundary drawing
 
LR-M-2161-2.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.19-4 acceptable
 
because the applicant has revised the continuation arrow on boundary drawing LR-M-2161-2 to
 
refer to the correct boundary drawing LR-M-118-3, location C2. Therefore, the staff's concern
 
described in RAI 2.3.3.19-4 is resolved.
 
In RAI 2.3.3.19-5, dated August 27, 2007, the staff noted that boundary drawings LR-M-161-1
 
and -2161-1, locations B3 and G3, show nonsafety-related to safety-related piping components at penetrations X72A and X72B. LRA Section 2.1.1.2.2, "Spatial Failures of Nonsafety-Related
 
SSCs," page 2.1-8 states in part: "With respect to nonsafety-related piping that is directly
 
connected to safety-related piping, the seismic Category I design requirements are extended to
 
the first seismic restraint beyond the defined boundaries." The staff requested that the applicant
 
provide additional information showing the location of the seismic restraint for the
 
nonsafety-related three-inch HBD-157/257 connected to the safety-related three-inch
 
HBB-119/219 piping, which is within the license renewal boundary. 
 
In its response to RAI 2.3.3.19-5, dated October 18, 2007, the applicant stated:
 
PPL's response to RAI 2.1-3, part b, (Reference 3), identified
 
nonsafety-related (NSR) piping and components, inside primary
 
containment and connected to safety-related (SR) piping and
 
components, that are required to remain intact to ensure the structural
 
integrity of the attached SR piping and components. The 3" HBD-155/255 line connected to SR containment penetration X-72B and the 3" HBD-157/257 line connected to penetration X-72A are not highlighted. The
 
penetrations themselves serve as anchor points, and the HBD lines 2-97 inside the drywell are not within the boundaries of the seismic analyses that contain the containment boundary valves.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.19-5 acceptable
 
because the applicant has verified that containment penetrations serve as anchor points and
 
the HBD lines inside the drywell are not within the boundaries of the seismic analyses.
 
Therefore, the staff's concern described in RAI 2.3.3.19-5 is resolved.
 
2.3.3.19.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and boundary drawings (originals and
 
revised) 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. On the basis of its review, the staff concludes the applicant has appropriately identified the radwaste liquid system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has
 
adequately identified the radwaste liquid system mechanical components subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1), and; therefore, is acceptable.
2.3.3.20  Radwaste Solids Handling System 2.3.3.20.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.20 describes the radwaste solids handling system, which controls, collects, handles, processes, packages, and temporarily stores prior to offsite shipping, the wet waste
 
sludge generated by the liquid waste management system, the reactor water cleanup system, fuel pool cleanup system, the condensate cleanup sy stem, and the condensate filtration system.
The failure of nonsafety-related SSCs in the r adwaste solids handling system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-19
 
identifies radwaste solids handling system com ponent types within the scope of license renewal and subject to an AMR. 
 
2.3.3.20.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the radwaste solids hand ling system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately
 
identified the system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.21  Raw Water Treatment System 2.3.3.21.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.21 describes the raw water treatment system, which includes a clarified
 
water storage tank that is the primary source of water for the fire protection system. The raw
 
water treatment system performs functions t hat support fire protection. LRA Table 2.3.3-20 identifies raw water treatment system component types within the scope of license renewal and subject to an AMR.
2-98  2.3.3.21.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the raw water treatment system mechanical components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately
 
identified the system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.22  Reactor Building Chilled Water System 2.3.3.22.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.22 describes the RB chilled water system, which supplies chilled water
 
during normal plant operation to coolers in various areas of the reactor building (including the
 
Unit 1 and Unit 2 emergency switchgear and load center rooms) and drywell and to the reactor
 
recirculation pump motor coolers. The RB chilled water system contains safety-related
 
components relied upon to remain functional during and following DBEs. The failure of
 
nonsafety-related SSCs in the RB chilled water syst em potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the RB chilled water system performs functions that support EQ. LRA Table 2.3.3-21 identifies RB chilled water system component
 
types within the scope of license renewal and subject to an AMR. 
 
2.3.3.22.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.22, UFSAR Section 9.2.12.3, and the licensing renewal
 
boundary drawings using the evaluation methodology described in SER Section 2.3 and the
 
guidance in SRP-LR Section 2.3. The staff's review identified an area in which additional
 
information was necessary to complete the review of the applicant's scoping and screening
 
results. The applicant responded to the staff's RAI as discussed below.
 
In RAI 2.3.3.22-1, dated August 27, 2007, the staff noted boundary drawings LR-M-187-2 and
 
LR-M-2187-2 show several one-inch lines and associated isolation valves as not within the
 
scope of license renewal. These lines are directly connected to the RB chilled water system
 
lines that are within the scope of license renewal. The staff requested that the applicant explain
 
why the sections of pipe and components are not within the scope of license renewal.
 
In its response to RAI 2.3.3.22-1, dated October 18, 2007, the applicant stated:
 
2-99 PPL's response to RAI 2.1-3, (Reference 3), identified nonsafety-related (NSR) piping and components, inside primary containment and
 
connected to safety-related (SR) piping and components, that are
 
required to remain intact to ensure the structural integrity of the attached
 
SR piping and components. The identified nonsafety-related piping and
 
components are in-scope for license renewal based on the criteria of
 
10 CFR 54.4(a)(2). The scoping determination for the nonsafety-related
 
piping and components is based upon review of the governing piping
 
design analyses. The in-scope portion of the nonsafety-related piping
 
extends from the nonsafety-related -to-safety-related interface to the
 
analytical boundaries of the piping analysis which contains the SR piping
 
and components. 
 
As part of the response to RAI 2.1-3, boundary drawings LR-M-187-2, Revision 1 and LR-M-2187-2, Revision 1 were included to show the
 
revised evaluation boundaries. The piping and valves that are highlighted
 
in pink (magenta) and identified with a reference to LR NOTE D are in-
 
scope for the 10 CFR 54.4(a)(2) function discussed above. 
 
The nonsafety-related piping and valves identified by this RAI are not
 
included in the piping analyses which include the SR valves
 
HV18792B2/HV28792B2, HV18792B1/HV28792B1, HV18782A2/HV28782A2, HV18782A1/HV28782A1, HV18792A2/HV28792A2, HV18792A1/HV28792A1, HV18782B2/HV28782B2, HV18782B1/HV28782B1. The piping and
 
valves are not included in the analyses because they are small diameter
 
branch lines extending from large diameter headers. In the governing
 
piping analyses, small diameter branch lines, such as vents and drains, may be decoupled from the analysis of the headers. This is an
 
acceptable piping design practice that is employed when it is determined
 
that the small diameter branch lines do not significantly affect the loads
 
and stresses on a large diameter header. Therefore, in all cases, the
 
applicable piping analyses, which are part of the current design basis, support the conclusion that the nonsafety-related piping and valves
 
identified by this RAI are not required to remain intact to ensure the
 
structural integrity of the safety-related valves. 
 
As discussed in LRA Section 2.1.1.2.2, and further discussed in the
 
response to RAI 2.3.3.23-3, nonsafety-related piping inside containment
 
is not required to satisfy the 10 CFR 54.4(a)(2) criteria for spatial
 
considerations since the SR equipment inside containment is designed
 
for all potential spatial interactions. Therefore, the nonsafety-related
 
piping and valves identified by this RAI are not in-scope for any criteria of
 
10 CFR 54.4(a)(2).
The staff confirms that the applicant has submitted revised boundary drawings
 
LR-M-187-2 and LR-M-2187-2. 
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.22-1 acceptable
 
because the applicant has clarified that the nonsafety-related piping sections inside containment 2-100 and in question are not within the scope of license renewal because they are outside the analytical boundaries of the piping analysis, and that the safety-related equipment inside
 
containment is designed for all potential spatial interactions. Therefore, the staff's concern
 
described in RAI 2.3.3.22-1 is resolved.
 
2.3.3.22.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI response, and boundary drawings (original and
 
revised) 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. On the basis of its review, the staff concludes the
 
applicant has appropriately identified the RB chilled water system mechanical components
 
within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has
 
adequately identified the RB chilled water system mechanical components subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1) and; therefore, is acceptable.
 
2.3.3.23  Reactor Building Closed Cooling Water System  2.3.3.23.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.23 describes the reactor building closed-cooling water (RBCCW) system, which provides cooling water in the reactor and radwaste buildings to nonsafety-related
 
equipment that could carry radioactive fluids or that requires a clean water supply to minimize
 
long-term corrosion. The RBCCW system cont ains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the
 
RBCCW system potentially could prevent the sati sfactory accomplishment of a safety-related function. In addition, the RBCCW system performs functions that support EQ. LRA
 
Table 2.3.3-22 identifies RBCCW system component types within the scope of license renewal and subject to an AMR. 
 
2.3.3.23.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.23, UFSAR Section 9.2.2, and the licensing renewal
 
boundary drawings using the evaluation methodology described in SER Section 2.3 and the
 
guidance in SRP-LR Section 2.3. The staff's review identified areas in which additional
 
information was necessary to complete the review of the applicant's scoping and screening
 
results. The applicant responded to the staff's RAIs as discussed below.
 
In RAI 2.3.3.23-1, dated August 27, 2007, the staff noted boundary drawings LR-M-113-1 and
 
LR-M-2113-1, locations A&B2, A&B3, and A&B4, show RBCCW supply and return to pump seal
 
heat exchangers within the scope of license renewal; however, the RBCCW supply and return
 
piping to the motor bearing coils are not shown within the scope of license renewal. The staff
 
requested that the applicant explain why the piping upstream and/or downstream, including
 
valves 113012, 213012, 113009, 213009, 113017, and 113020, is not within the scope of
 
license renewal. Additionally, the applicant was asked to explain why the sensing lines and root
 
valves connected to the piping bounded by these isolation valves are not within the scope of
 
license renewal. 
 
In its response to RAI 2.3.3.23-1, dated October 18, 2007, the applicant stated in part:
 
2-101 PPL's response to RAI 2.1-3, part b, sent to the NRC via PLA-6177 dated April 17, 2007, identified nonsafety-related (NSR) piping and
 
components, inside primary containment and connected to safety-related (SR) piping and components, that are required to remain intact to ensure
 
the structural integrity of the attached SR piping and components. The
 
identified nonsafety-related piping and components are in-scope for
 
license renewal based on the criteria of 10 CFR 54.4(a)(2). The scoping
 
determination for the nonsafety-related piping and components is based
 
upon review of the governing piping design analyses. The in-scope
 
portion of the nonsafety-related piping extends from the nonsafety-related
-to-safety-related interface to the analytical boundaries of the piping
 
analysis which contains the safety-related piping and components.
As part of the response to RAI 2.1-3, boundary drawings LR-M-113-1, Revision 1 and LR-M-2113-1, Revision 1 were included to show the
 
revised evaluation boundaries. The piping and valves that are highlighted
 
in pink (magenta) and identified with a reference to "SEE LR NOTE C"
 
are in-scope for the 10 CFR 54.4(a)(2) function discussed above. 
 
The nonsafety-related piping and valves identified by this RAI are not
 
included in the piping analyses which include the safety-related valves
 
HV11345, HV11346, HV21345, and HV21346. The piping and valves are
 
not included in the analyses for one of two possible reasons: 1) the piping
 
and valves are located on the unanalyzed side of a physical pipe support
 
anchor which defines the boundary of the analysis, or 2) the piping and
 
valves are part of small diameter br anch lines extending from the 3" HBD-129/229 and 3" HBD-130/230 headers. In the governing piping analyses, the small diameter branch lines, including vents and drains, may be
 
decoupled from the analysis of the headers. This is an acceptable piping
 
design practice that is employed when it is determined that the small
 
diameter branch lines do not significantly affect the loads and stresses on
 
a large diameter header. Therefore, in all cases, the applicable piping
 
analyses, which are part of the current design basis, support the
 
conclusion that the nonsafety-related piping and valves identified by this
 
RAI are not required to remain intact to ensure the structural integrity of
 
the safety-related valves HV11345, HV11346, HV21345, and HV21346.
As discussed in LRA Section 2.1.1.2.2, and further discussed in the response to RAI 2.3.3.23-3, nonsafety-related piping inside containment
 
is not required to satisfy the 10 CFR 54.4(a)(2) criteria for spatial
 
considerations since the safety-related equipment inside containment is
 
designed for all potential spatial interactions. Therefore, the nonsafety-
 
related piping and valves identified by this RAI are not in-scope for any
 
criteria of 10 CFR 54.4(a)(2). 
 
The staff confirms that the applicant has submitted revised boundary drawings LR-M-113-1 and
 
LR-M-2113-1.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.23-1 acceptable because the applicant has clarified that the nonsafety-related piping sections inside containment 2-102 and in question are not within the scope of license renewal, because they are outside the analytical boundaries of the piping analysis. Therefore, the staff's concern described in RAI 2.3.3.23-1 is resolved.
In RAI 2.3.3.23-2, dated August 27, 2007, the staff noted boundary drawing LR-M-113-1 and
 
LR-M-2113-1 show several one-inch lines and associated isolation valves not within the scope
 
of license renewal. These lines are directly connected to RBCCW main lines that are within the
 
scope of license renewal. The staff requested that the applicant explain why these listed
 
sections of pipe and components are not within the scope of license renewal.
 
In its response to RAI 2.3.3.23-2, dated October 18, 2007, the applicant stated in part:
 
The RBCCW piping discussed in this RAI is shown on boundary drawings
 
LR-M-113-1 and LR-M-2113-1. The refer ence to drawing LR-M-2143-1 in the first sentence of the RAI is considered to be a typographical error.
 
PPL's response to RAI 2.1-3, part b, sent to the NRC via PLA-6177 dated
 
April 17, 2007, identified nonsafety-related (NSR) piping and
 
components, inside primary containment and connected to safety-related (SR) piping and components, that are required to remain intact to ensure
 
the structural integrity of the attached safety-related piping and
 
components. The identified nonsafety-related piping and components are
 
in-scope for license renewal based on the criteria of 10 CFR 54.4(a)(2).
 
The scoping determination for the nonsafety-related piping and
 
components is based upon review of the governing piping design
 
analyses. The in-scope portion of the nonsafety-related piping extends
 
from the nonsafety-related -to-safety-related interface to the analytical
 
boundaries of the piping analysis which contains the safety-related piping
 
and components. 
 
As part of the response to RAI 2.1-3, boundary drawings LR-M-113-1, Revision 1 and LR-M-2113-1, Revision 1 were included to show the
 
revised evaluation boundaries. The piping and valves that are highlighted
 
in pink (magenta) and identified with a reference to "SEE LR NOTE C"
 
are in-scope for the 10 CFR 54.4(a)(2) function discussed above. 
 
The nonsafety-related piping and valves identified by this RAI are not
 
included in the piping analyses which include the safety-related valves
 
HV11345, HV11346, HV21345, and HV21346. The piping and valves are
 
not included in the analyses for one of two possible reasons: 1) the piping
 
and valves are located on the unanalyzed side of a physical pipe support
 
anchor which defines the boundary of the analysis, or 2) the piping and
 
valves are part of small diameter br anch lines extending from the 3" HBD-129/229 and 3" HBD-130/230 headers. In the governing piping analyses, the small diameter branch lines, including vents and drains, may be
 
decoupled from the analysis of the headers. This is an acceptable piping
 
design practice that is employed when it is determined that the small
 
diameter branch lines do not significantly affect the loads and stresses on
 
a large diameter header. Therefore, in all cases, the applicable piping
 
analyses, which are part of the current design basis, support the 2-103 conclusion that the nonsafety-related piping and valves identified by this RAI are not required to remain intact to ensure the structural integrity of
 
the safety-related valves HV11345, HV11346, HV21345, and HV21346. 
 
As discussed in LRA Section 2.1.1.2.2, and further discussed in the
 
response to RAI 2.3.3.23-3, nonsafety-related piping inside containment
 
is not required to satisfy the 10 CFR 54.4(a)(2) criteria for spatial
 
considerations since the safety-related equipment inside containment is
 
designed for all potential spatial interactions. Therefore, the nonsafety-
 
related piping and valves identified by this RAI are not in-scope for any
 
criteria of 10 CFR 54.4(a)(2).
The staff confirms that the applicant has submitted revised boundary drawings LR-M-113-1 and LR-M-2113-1.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.23-2 acceptable because the applicant has clarified that the nonsafety-related piping sections inside containment and in question are not within the scope of license renewal, because they are outside the analytical boundaries of the piping analysis. Therefore, the staff's concern described in RAI 2.3.3.23-2 is resolved.
In RAI 2.3.3.23-3, dated August 27, 2007, the staff noted boundary drawing LR-M-113-1, license renewal note B states, "Safety-Related components inside containment (designed for
 
harsh environment) are not plausible targets for spatial interaction." The staff requested that the
 
applicant provide additional information to support the implausibility of safety-related
 
components within containment being impacted by failure of nonsafety-related systems. 
 
In its response to RAI 2.3.3.23-3, dated October 18, 2007, the applicant stated:
 
FSAR Sections 3.6.1.1 and 3.11.1 state that essential systems and
 
equipment required to mitigate the consequences of a design-basis
 
accident, or to affect a safe shutdown of the reactor, are designed to
 
remain functional after exposure to the applicable accident environmental
 
conditions and are qualified for service in harsh environments, including
 
spray and/or steam. As such, the safety-related components in the
 
primary containment are designed to remain functional for conditions that
 
bound any potential leakage, spray, or flooding and the corresponding
 
environmental effects (e.g., elevated temperatures and pressures), and
 
are not reasonable targets for spatial interaction, upon failure of
 
nonsafety-related components in that structure. Also, based on FSAR
 
Sections 3.6.1.2 - 3.6.2, safety-related components inside containment
 
are protected from the effects of pipe whip and/or jet impingement (from a
 
high-energy line failure) by separation, barriers or pipe whip restraints.
 
The portions of high-energy piping that are inside containment are all
 
safety-related and in the scope of license renewal based on
 
10 CFR 54.4(a)(1) scoping criterion. Therefore, nonsafety-related
 
mechanical components inside the containment do not have a plausible
 
potential for failure to impair or prevent the accomplishment of a safety-
 
related SSC's intended function. 
 
2-104 As such, they do not satisfy 10 CFR 54.4(a)(2), scoping criterion and are not within the scope of license renewal.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.23-3 acceptable because the applicant has provided additional information to support the note B statement concerning the implausibility of safety-relat ed components within containment being impacted by failure of nonsafety-related systems.
Therefore, the staff's concern described in RAI 2.3.3.23-3 is resolved.
In RAI 2.3.3.23-4, dated August 27, 2007, the staff noted boundary drawing LR-M-113-1, location B2, refers to note "C" which states "Highlighted nonsafety-related piping is within
 
analytical boundaries of the seismic analyses for the attached safety-related components."
 
Given the placement of the note and the highlighting approach, it is unclear as to what specific
 
components and/or piping is addressed by note "C." The staff requested that the applicant
 
clarify which specific components and/or piping is within the analytical boundaries of the seismic
 
analyses.
 
In its response to RAI 2.3.3.23-4, dated October 18, 2007, the applicant stated:
 
As discussed in the responses to RAIs 2.3.3.23-1 and 2.3.3.23-2 above, the evaluation boundaries of the nonsafety-related piping and components inside containment are based upon the analytical boundaries of the governing piping design analyses. The in-scope portion of the nonsafety-related piping extends from the nonsafety-related -to-safety-related interface to the analytical boundaries of the piping analysis which contains the safety-related piping and components.
LR Note "C" applies to all of the pink (magenta)-highlighted piping and valves inside the primary containment that are part of the HBD-129 and HBD-130 pipelines. The highlighted piping and valves are required to remain intact to ensure the structural integrity of the attached safety-related piping and components and are, therefore, in-scope for license renewal based on the criteria of 10 CFR 54.4(a)(2).
The note to "SEE LR NOTE C" on drawings LR-M-113-1 and LR-M-2113-1 at location B2 should be closer to the 4" HBD-130 and 4" HBD-230 lines in location B1. This would then be similar to the "SEE LR NOTE C" beside the 4" HBD-129 and 4" HBD-229 lines in location B3 of the drawings.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.23-4 acceptable because the applicant has clarified which components and/or piping is within the analytical boundaries of the seismic analyses, per note C. Therefore, the staff's concern described in RAI 2.3.3.23-4 is resolved.
In RAI 2.3.3.23-5, dated August 27, 2007, the staff noted boundary drawing LR-M-143-2, locations E7 and E8 show RBCCW three-inch supply to pump seal heat exchangers upstream of a three-inch to two-inch reducer as being within the scope of license renewal. The RBCCW piping and components downstream of the reducer are not within the scope of license renewal.
The distinction is unclear between the in-scope piping upstream of the reducer and the out-of-scope piping downstream of the reducer. The staff requested that the applicant explain why the 2-105 piping downstream of the three to two-inch reducer is not within the scope of license renewal.
In its response, dated October 18, 2007, the applicant stated:
As discussed in the responses to RAIs 2.3.3.23-1 and 2.3.3.23-2 above, the evaluation boundaries of the nonsafety-related piping and components inside containment are based upon the analytical boundaries of the governing piping design analyses. The in-scope portion of the nonsafety-related piping extends from the nonsafety-related -to-safety-related interface to the analytical boundaries of the piping analysis which contains the safety-related piping and components.
The analytical boundary associated with the piping analysis that includes the safety-related containment boundary valve HV11346 ends at the 3"-
 
to-2" reducer at the end of the run of 3" HBD-129 piping on LR-M-143-2
 
at location E7. Since the piping downstream of the reducer is not part of
 
the piping analysis that includes valve HV11346, it is not required to
 
remain intact to ensure the structural integrity of the safety-related valve.
 
Therefore, it is not within the scope of license renewal based on the
 
criteria of 10 CFR 54.4(a)(2).
Based on its review, the staff finds the applicant's response to RAI 2.3.3.23-5 acceptable because the applicant has clarified that the nonsafety-related piping sections inside containment and in question are not within the scope of license renewal because they are outside the analytical boundaries of the piping analysis. Therefore, the staff's concern described in RAI 2.3.3.23-5 is resolved.
In RAI 2.3.3.23-6, dated August 27, 2007, the staff noted boundary drawing LR-M-143-2, location E8, shows RBCCW three-inch supply to pump seal heat exchangers upstream of a
 
three-inch to two-inch reducer as being within scope of license renewal. The same section of
 
piping identified in Unit 2 and shown on boundary drawing LR-M-2143-2, is identified as not
 
within the scope of license renewal. The reason for this difference in RBCCW system scope
 
between Unit 1 and Unit 2 is unclear. The staff requested that the applicant explain why
 
boundary locations for these sections of piping are defined differently between Units 1 and 2. 
 
In its response to RAI 2.3.3.23-6, dated October 18, 2007, the applicant stated
 
As discussed in the response to RAI 2.3.3.23-5 above, the evaluation boundaries of the nonsafety-related piping and components inside containment are based upon the analytical boundaries of the governing piping design analyses. The in-scope portion of the nonsafety-related piping extends from the nonsafety-related -to-safety-related interface to the analytical boundaries of the piping analysis which contains the safety-related piping and components.
The analytical boundary associated with the Unit 1 piping analysis that includes the safety-related containment boundary valve HV11346 ends at the 3"-to-2" reducer at the end of the run of 3" HBD-129 piping on LR-M-143-2 at location E7. The analytical boundary associated with the Unit 2 piping analysis that includes the safety-related containment boundary valve HV21346 ends at a point just downstream of valve
 
2-106 213008 on the 3" HBD-229 piping on LR-M-2113-1 at location B2. Thus, the pink-(magenta) highlighted boundary for the Unit 2 RBCCW line ends at valve 213008, which correctly reflects the analytical boundary as the evaluation boundary for license renewal.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.23-6 acceptable because the applicant has clarified that the nonsafety-related piping sections inside containment and in question are not within the scope of license renewal, because they are outside the analytical boundaries of the piping analysis. Therefore, the staff's concern described in RAI 2.3.3.23-6 is resolved.
In RAI 2.3.3.23-7, dated August 27, 2007, the staff noted boundary drawing LR-M-143-2, locations E7 and E8 show RBCCW supply to pump seal heat exchangers pipe section three-inch HBD-129 within the scope of license renewal. The RBCCW pump seal heat exchangers return line identified as three-inch HBD-130 is not within scope for license renewal on boundary drawing LR-M-143, but identified as within the scope of license renewal on boundary drawing LR-M-113, locations A2 and A4. It is unclear why three-inch HBD-129, on boundary drawing LR-M-143 is within scope for license renewal, whereas three-inch HBD-130 on boundary drawing LR-M-143 is not within the scope of license renewal. The staff requested that the applicant explain why the return piping from the RBCCW pump seal heat exchangers is not within the scope of license renewal.
In its response to RAI 2.3.3.23-7, dated October 18, 2007, the applicant stated:
 
As discussed in the response to RAI 2.3.3.23-5 above, the evaluation boundaries of the nonsafety-related piping and components inside containment are based upon the analytical boundaries of the governing piping design analyses. The in-scope portion of the nonsafety-related piping extends from the nonsafety-related -to-safety-related interface to the analytical boundaries of the piping analysis which contains the safety-related piping and components.
The analytical boundaries associated with the piping analysis that includes the safety-related containment boundary valve HV11345 end just upstream of FE11343A and FE11343B on the 3" HBD-130 piping on LR-M-113-1 at locations A2 and A4. The analytical boundary does not encompass any components shown on LR-M-143-2. Thus, the pink-highlighted boundary ends just upstream of the FE's on LR-M-113-1 and is not continued to any piping represented on LR-M-143-2. The highlighting provides an accurate representation of all piping and piping components that are within the boundaries of the piping analysis and, therefore, within the scope of license renewal.
Since the 3" HBD-130 piping shown on LR-M-143-2 at location E8 is beyond the analytical boundary of the piping analysis that includes valve HV11345, it is not required to remain intact to ensure the structural integrity of the safety-related valve, and, therefore, it is not within the scope of license renewal based on the criteria of 10 CFR 54.4(a)(2).
Based on its review, the staff finds the applicant's response to RAI 2.3.3.23-7 acceptable 2-107 because the applicant has clarified that the nonsafety-related piping sections inside containment and in question are not within the scope of license renewal, because they are outside the analytical boundaries of the piping analysis. Therefore, the staff's concern described in RAI 2.3.3.23-7 is resolved.
2.3.3.23.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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. On the basis of its review, the staff concludes the applicant has
 
appropriately identified the RBCCW system mechanical components within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the
 
RBCCW system mechanical components subject to an AMR, in accordance with the
 
requirements of 10 CFR 54.21(a)(1), and; therefore, is acceptable.
 
2.3.3.24  Reactor Building HVAC System 2.3.3.24.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.24 describes the reactor building (RB) HVAC system, which during normal
 
plant operation serves three ventilation zones. In addition to ventilating three separate zones
 
during normal plant operation, the RB HVAC system also serves during DBA conditions, various
 
air cooling systems. The RB HVAC system c ontains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the RB
 
HVAC system potentially could prevent the sati sfactory accomplishment of a safety-related function. In addition, the RB HVAC system performs functions that support fire protection and
 
EQ. LRA Table 2.3.3-23 identifies RB HVAC sy stem component types within the scope of license renewal and subject to an AMR.
 
2.3.3.24.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the RB HVAC system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified
 
the system components subject to an aging m anagement review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2-108 2.3.3.25  Reactor Nonnuclear Instrumentation System  2.3.3.25.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.25 describes the reactor non-nuclear instrumentation (NIS) system, which
 
consists of the instrumentation for operation of the nuclear boiler for normal power generation, shutdown and refueling operations, and transient and accident conditions. The reactor non-NIS
 
system contains safety-related components relied upon to remain functional during and
 
following DBEs. In addition, the reactor non-NIS system performs functions that support fire
 
protection, ATWS, SBO, and EQ. LRA Table 2.3.3-24 identifies reactor non-NIS system
 
component types within the scope of license renewal and subject to an AMR. 
 
2.3.3.25.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.25 and UFSAR Sections 6.2 and 7.0 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, pursuant to 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 2.3.3.25-1, dated October 24, 2007, the staff requested that the applicant provide additional information regarding boundary drawing LR-M-123-12, which depicts multiple
 
"insulated couplings or unions." The staff also asked the applicant to clarify how these
 
components are included in LRA Table 2.3.3-24 for components subject to an AMR, as a
 
pressure boundary and; if excluded, provide justification.
 
In its response to RAI 2.3.3.25-1, dated November 14, 2007, the applicant stated:
 
Boundary drawing LR-M-123-12 contains the component type "insulated
 
couplings or unions." The couplings and unions on LR-M-123-12 that are
 
within the scope of license renewal are those that contains fluids and are
 
located in the Reactor Building, therefore having the potential for spatial
 
interaction with safety-related components. These components are
 
nonsafety-related and meet the scoping criteria of 10 CFR 54.4(a)(2).
 
In accordance with PPL's scoping methodology, those components are
 
included within the evaluation boundary of the Sampling System instead
 
of the Reactor Non-nuclear Instrumentation System. As described in LRA
 
Section 2.1.2.1.3, in-line components that are in-scope for
 
10 CFR 54.4(a)(2), which would include "insulated couplings or unions,"
 
are evaluated on a commodity group basis as piping and piping
 
components. The insulated couplings and unions are included in LRA
 
Section 2.3.3.28, Sampling System, and were identified as subject to
 
aging management review in Table 2.3.3-27 under the component type
 
"Piping and Piping Components." The couplings and unions that are
 
subject to aging management review perform an intended function of 2-109 Structural Integrity.
 
No changes to the LRA or boundary drawings were required per this
 
response.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.25-1 acceptable
 
because the applicant has provided the requested clarification that these components were
 
included in LRA Section 2.3.3.28 and in Table 2.3.3-27, as components subject to an AMR.
 
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, boundary drawings, and RAI response to determine
 
whether the applicant failed to identify any SSCs within the scope of license renewal. In
 
addition, the staff's review determined whether the applicant failed to identify any components
 
subject to an AMR. On the basis of its review, the staff concludes that the applicant has
 
adequately identified the reactor non-NIS components within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and that the applicant has adequately identified the reactor
 
non-NIS components subject to an AMR in accordance with the requirements of
 
10 CFR 54.21(a)(1) and; therefore, is acceptable.
 
2.3.3.26  Reactor Water Cleanup System 2.3.3.26.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.26 describes the reactor water cleanup (RWCU) system, which continuously
 
purifies the reactor water. The RWCU system contains safety-related components relied upon to
 
remain functional during and following DBEs. The failure of nonsafety-related SSCs in the
 
RWCU system potentially could prevent the sati sfactory accomplishment of a safety-related function. In addition, the RWCU system performs functions that support fire protection, ATWS, and EQ. LRA Table 2.3.3-25 identifies RWCU system component types within the scope of
 
license renewal and subject to an AMR. 
 
2.3.3.26.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the RWCU system mechanical components within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the
 
system components subject to an aging managem ent review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.27  Residual Heat Removal Service Water System  2.3.3.27.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.27 describes the RHRSW System, which is a safety-related system that is designed to provide a reliable source of cooling water to support RHR system operation and for
 
post-accident core and containment flooding. The RHRSW system contains safety-related
 
components relied upon to remain functional during and following DBEs. The failure of 2-110 nonsafety-related SSCs in the RHRSW system pot entially could prevent the satisfactory accomplishment of a safety-related function. In addition, the RHRSW system performs functions that support fire protection, ATWS, and EQ. LRA Table 2.3.3-26 identifies RHRSW system
 
component types within the scope of license renewal and subject to an AMR.
2.3.3.27.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.27, UFSAR Section 9.2.6, and the licensing renewal
 
boundary drawings using the evaluation methodology described in SER Section 2.3 and the
 
guidance in SRP-LR Section 2.3. The staff's review identified areas in which additional
 
information was necessary to complete the review of the applicant's scoping and screening
 
results. In addition to RAIs 2.3.3.27-1 and 2.3.3.27-2 related to boundary drawing continuation
 
errors discussed in SER Section 2.3.3, the applicant responded to the staff's RAIs as discussed
 
below.
 
In RAI 2.3.3.27-3, dated August 27, 2007, the staff noted that boundary drawing LR-M-2112-1, location F7 depicts pipe sections downstream of PSV21213B and PSV21212B that are not
 
within the scope of license renewal. However, similar components downstream of PSV21213A
 
and PSV21212A are within the scope of license renewal. the staff requested that the applicant
 
explain why these nonsafety-related piping and components connected to safety-related
 
components downstream of PSV21213B and PSV21212B are not within the scope of license
 
renewal.
 
In its response to RAI 2.3.3.27-3, dated October 18, 2007, the applicant stated:
 
The pipe sections downstream of PSV21213B and PSV21212B, labeled as going to "LRW", are within the scope of license renewal based on 10 CFR 54.4(a)(2) as nonsafety-related for spatial interaction and are subject to AMR. The highlighting was inadvertently missed and these two pipe sections have been highlighted in Revision 1 to drawing LR-M-2112-1. Since this is a highlighting omission, and the materials and environments are already included in LRA Section 2.3.3.27, no LRA changes are needed.
The staff confirms that the applicant has submitted revised boundary drawing LR-M-2112-1.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.27-3 acceptable because the applicant has clarified that these pipe sections are within scope of license renewal
 
and has revised the applicable boundary drawings. Therefore, the staff's concern described in
 
RAI 2.3.3.27-3 is resolved.
 
In RAI 2.3.3.27-4, dated August 27, 2007, the staff noted that boundary drawing LR-M-112-2, Revision 1, locations D3 and D8 show RHRSW piping from three-inch JRD-31 and three-inch
 
JRD-32 to the vault sump and to valves 012040 and 012041, respectively, as not within the
 
scope of license renewal. The staff requested that the applicant explain why these sections of
 
piping are not within the scope of license renewal.
 
In its response to RAI 2.3.3.27-4, dated January 3, 2008, the applicant stated:
 
2-111 The three-inch pipe lines JRD -31 and JRD-32 have been abandoned in place. These pipe sections do not contain any fluid that could interact
 
with surrounding equipment. These three-inch lines are in-scope because
 
they are connected to and provide structural support for the connected
 
safety-related piping. The one-inch piping and the valves 012031, 013030, 012038, and 012041 that are connected to the three inch pipe
 
lines JRD-31 and JRD-32 do not provide any structural support function
 
for the three-inch JRD -31 and JRD-32 piping or the safety-related piping
 
connected to the three-inch pipe lines JRD -31 and JRD-32. Therefore, neither the one inch piping nor the associated valves are within the scope
 
of license renewal for license renewal.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.27-4 acceptable
 
because the applicant has clarified that this piping does not contain any fluid that could interact
 
with surrounding equipment and that the one-inch lines and valves off of three-inch JRD-31 and
 
three-inch JRD-32 do not provide any structural support function. Therefore, the staff's concern
 
described in RAI 2.3.3.27-4 is resolved.
 
2.3.3.27.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and boundary drawings (original and
 
revised) 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. On the basis of its review, the staff concludes the
 
applicant has appropriately identified the RHRSW system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately
 
identified the RHRSW system mechanical components subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1) and; therefore, is acceptable.
2.3.3.28  Sampling System 2.3.3.28.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.28 describes the sampling system, which monitors the operation of plant
 
equipment for information needed to make operational decisions. The failure of
 
nonsafety-related SSCs in the sampling system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-27 identifies sampling system
 
component types within the scope of license renewal and subject to an AMR.
 
2.3.3.28.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the sampling system mechanical components within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the
 
system components subject to an aging managem ent review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.29  Sanitary Drainage System 2-112 2.3.3.29.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.29 describes the sanitary drainage system (SDS), which collects liquid
 
wastes from all plumbing fixtures of the plant outside restricted access areas. The drain lines
 
were designed to accommodate fire protection system design flow when actuated. The failure of
 
nonsafety-related SSCs in the SDS potentially coul d prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-28 identifies SDS component types within the scope
 
of license renewal and subject to an AMR. 
 
2.3.3.29.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the SDS mechanical components within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and that the applicant has adequately identified the system
 
components subject to an aging management review in accordance with the requirements
 
stated in 10 CFR 54.21(a)(1).
2.3.3.30  Service Air System 2.3.3.30.1  Summary of Technical Information in the Application
 
LRA Section 2.3.3.30 describes the service air system (SAS), which provides compressed air
 
for service air outlets located throughout the plant and a backup system for instrument air. The
 
failure of nonsafety-related SSCs in the SAS potentially could prevent the satisfactory
 
accomplishment of a safety-related function. LRA Table 2.3.3-29 identifies SAS component
 
types within the scope of license renewal and subject to an AMR.
 
2.3.3.30.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the SAS mechanical components within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and that the applicant has adequately identified the system
 
components subject to an aging management review in accordance with the requirements
 
stated in 10 CFR 54.21(a)(1).
2.3.3.31  Service Water System 2.3.3.31.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.31 describes the SWS, which removes heat from heat exchangers in the
 
control structure and turbine, reactor, and radwaste buildings, and transfers it to the cooling
 
towers where it is dissipated. The failure of nonsafety-related SSCs in the SWS potentially could
 
prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.3-30
 
identifies SWS component types within the scope of license renewal and subject to an AMR. 
 
2.3.3.31.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.31, UFSAR Section 9.2.1.2, and the licensing renewal 2-113 boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff's review identified areas in which additional
 
information was necessary to complete the review of the applicant's scoping and screening
 
results. In addition to RAI 2.3.3.31-2 related to boundary drawing continuation errors discussed
 
in LRA Section 2.3.3, the applicant responded to the staff's RAIs as discussed below.
 
In RAI 2.3.3.31-1, dated August 27, 2007, the staff noted that boundary drawing LR-M-110-1, locations G2 and G3 show pipe tunnel coolers (1A, 1B, 1C, and 1D) that are not within the
 
scope of license renewal. The staff requested that the applicant explain why the pipe tunnel
 
coolers are not within the scope of license renewal. 
 
In its response to RAI 2.3.3.31-1, dated October 18, 2007, the applicant stated:
 
The pipe tunnel coolers (1A, 1B, 1C, and 1D) are within the scope of
 
license renewal under criteria 10 CFR 54.4(a)(2). The components which
 
are subject to aging management review are those that may contain a
 
liquid and have the potential for spatial interaction. Therefore, the
 
channels/heads for the unit coolers are subject to aging management
 
review. The pipe tunnel unit cooler channels/head are addressed as
 
components of the Reactor Building HVAC System and are included in
 
LRA Table 2.3.3-23 under the line item "Unit coolers, drain pans, drain
 
piping, channels/heads" with an intended function of structural integrity.
 
The staff confirms that the applicant has submitted revised boundary drawing LR-M-110-1 to
 
indicate that pipe tunnel coolers (1A, 1V, 1C, and 1D) are within the scope of license renewal.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.31-1 acceptable because the applicant has clarified that the pipe tunnel coolers are within the scope of license renewal and subject to AMR. The staff confirms that the applicant has revised the boundary drawing to reflect this change. Therefore, the staff's concern described in RAI 2.3.3.31-1 is resolved.
 
In RAI 2.3.3.31-3, dated August 27, 2007, the staff noted boundary drawing LR-M-2110-1, locations G2 and G3 show pipe tunnel coolers (2A, 2B, 2C, and 2D) that are within the scope of license renewal. LRA Table 2.3.3-30, "Service Water System Components Subject to Aging Management Review," does not list coolers as a component subject to an AMR. The staff requested that the applicant explain why these pipe tunnel coolers are not included in LRA Table 2.3.3-30.
 
In its response to RAI 2.3.3.31-3, dated October 18, 2007, the applicant stated:
Pipe Tunnel Coolers (2A, 2B, 2C, and 2D), shown on drawing LR-M-2110-1 at G2 and G3, are within the scope of license renewal and are subject to AMR. Based on PPL's scoping methodology, these cooling coils have been scoped as part of the Reactor Building HVAC Systems and are included, based on 10 CFR 54.4(a)(2), in LRA Section 2.3.3.24 and associated Table 2.3.3-23. These pipe tunnel coolers are included on LRA page 2.3-99 as part of the last line item of Table 2.3.3-23, with a component type of "Unit Coolers, drain pans, drain piping, 2-114 channels/heads" with an intended function of "Structural Integrity".
Based on its review, the staff finds the applicant's response to RAI 2.3.3.31-3 acceptable because the applicant has clarified that the pipe tunnel coolers are within the scope of license renewal and subject to AMR. Therefore, the staff's concern described in RAI 2.3.3.31-3 is resolved.
2.3.3.31.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, boundary drawings, and RAI responses 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. On the basis of its review, the staff concludes the applicant has
 
appropriately identified the SWS mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the SWS
 
mechanical components subject to an AMR, in accordance with the requirements of
 
10 CFR 54.21(a)(1) and; therefore, is acceptable.
 
2.3.3.32  Standby Liquid Control System 2.3.3.32.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.32 describes the SLC system, an independent, diverse backup to the control
 
rod drive system. The SLC system function is to inject a neutron-absorbing solution into the reactor to achieve and maintain sub-criticality if control rods cannot be inserted manually. The
 
SLC system contains safety-related components relied upon to remain functional during and
 
following DBEs. The failure of nonsafety-related SSCs in the SLC system potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the SLC
 
system performs functions that support ATWS and EQ. LRA Table 2.3.3-31 identifies SLC
 
system component types within the scope of license renewal and subject to an AMR. 
 
2.3.3.32.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.32 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. The staff's
 
review identified areas in which additional information was necessary to complete the review of
 
the applicant's scoping and screening results. The applicant responses to the staff's RAIs as
 
discussed below.
 
In RAI 2.3.3.32-1, dated October 24, 2007, the staff noted boundary drawing LR-M-148-1 shows
 
the ventilation lines from the test tanks and storage tanks as not within the scope of license
 
renewal. The staff requested that the applicant clarify whether the lines are within the scope of
 
license renewal and subject to an AMR and; if excluded, provide justification. 
 
In its response to RAI 2.3.3.32-1, dated November 14, 2007, the applicant stated:
 
The standby liquid control test tank (1/2T203) and ventilation line are
 
nonsafety-related. The test tank provides support for nonsafety-related
 
piping attached to safety-related piping and is therefore within the scope
 
of license renewal. The ventilation line for the test tank is not attached to 2-115 safety-related piping and does not contain a fluid that could cause a spatial interaction with safety-related equipment. Therefore, the test tank
 
ventilation line is not within the scope of license renewal.
 
The standby liquid control storage tank (1/2T204) is safety-related.
 
Further evaluation by the applicant has been determined that the
 
ventilation line for the storage tank should be within the scope of license
 
renewal and subject to AMR. The ventilation line is evaluated as part of
 
the storage tank pressure boundary and is therefore addressed under the
 
"Tanks, SLC storage tanks (1/2T204)" in Table 2.3.3-31. The evaluation
 
for the storage tank in Table 3.3.2-31 encompasses the vent line. No
 
changes to the LRA were required.
 
The staff confirms that the applicant has submitted revised boundary drawings LR-M-148-1 and
 
LR-M-2148-1.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.32-1 acceptable because the applicant has justified not including the test tank ventilation line within the scope of license renewal and has identified the ventilation line for the standby liquid control storage tank as within the scope of license renewal and subject to an AMR. Therefore, the staff's concern described in RAI 2.3.3.31-3 is resolved.
In RAI 2.3.3.32-2, dated October 24, 2007, that staff noted boundary drawing LR-M-148-1
 
shows what appears to be a hatch on the SLC storage tank (1T204). It was unclear to the staff
 
whether the hatch and closure mechanism were included as part of the tank. The staff
 
requested that the applicant clarify whether the tank hatches and closure mechanisms are
 
within the scope of license renewal and subject to an AMR. Also, the staff requested that the
 
applicant revise LRA Table 2.3.3-31, as necessary, to reflect its response or explain under what
 
component they were included.
 
In its response to RAI 2.3.3.32-2, dated November 14, 2007, the applicant stated:
 
The SLC storage tank hatches shown on boundary drawings LR-M-148-1
 
and LR-M-2148-1 are within the scope of license renewal. The
 
highlighting of the hatches on drawings LR-M-148-1 and LR-M-2148-1
 
was inadvertently omitted. 
 
The hatches, including the closure mechanisms, are considered to be
 
part of the pressure boundary of the storage tanks. The hatches are
 
included in the line item "Tanks, SLC storage tanks (1/2T204)" in LRA
 
Table 2.3.3-31 as subject to AMR. The closure mechanisms are included
 
in the line item "Bolting" in LRA Table 2.3.3-31 as subject to aging
 
management review. No changes to the LRA were required.
 
The staff confirms that the applicant has revised boundary drawings LR-M-148-1 and
 
LR-M-2148-1. 
 
2.3.3.32.3 Conclusion 
 
The staff reviewed the LRA, UFSAR, drawings (original and revised), and RAI responses to 2-116 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. On the basis of its review, the staff concludes the applicant has
 
appropriately identified the SLC system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the
 
SLC mechanical components subject to an AMR, in accordance with the requirements of
 
10 CFR 54.21(a)(1) and; therefore, is acceptable.
 
2.3.3.33  Turbine Building Closed Cooling Water System  2.3.3.33.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.3.33 describes the TB closed cooling water (TBCCW) system, which is a
 
closed-loop cooling system that transfers heat from miscellaneous turbine plant components to
 
the SWS through the TBCCW heat exchangers. The failure of nonsafety-related SSCs in the
 
TBCCW system potentially could prevent the sati sfactory accomplishment of a safety-related function. LRA Table 2.3.3-32 identifies TBCCW system component types within the scope of
 
license renewal and subject to an AMR. 
 
2.3.3.33.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.3.33, UFSAR Section 9.2.3, and the licensing renewal
 
boundary drawings using the evaluation methodology described in SER Section 2.3 and the
 
guidance in SRP-LR Section 2.3. The staff's review identified an area in which additional
 
information was necessary to complete the review of the applicant's scoping and screening
 
results. The applicant responded to the staff's RAI as discussed below.
 
In RAI 2.3.3.33-1 dated August 27, 2007, the staff noted that the TBCCW system was
 
determined to meet the scoping criteria pursuant to 10 CFR 54.4(a)(2) to maintain the integrity
 
of nonsafety-related piping components required to support the safety-related functional
 
boundary of the SWS. This is shown in SWS boundary drawings LR-M-109-2 and LR-M-2109-2.
 
However, boundary drawings defining the license renewal boundaries and components subject
 
to an AMR were not provided. The staff requested that the applicant provide boundary drawings
 
or documentation for the TBCCW system licensing renewal boundaries and components identified in LRA Section 2.3.3.33.
 
In its response dated October 18, 2007, the applicant stated:
 
The only components in-scope for the TBCCW system are the heat
 
exchanger shell (including channels/heads), connected piping and bolting
 
which provide a nonsafety affecting safety anchor for the Emergency
 
Service Water System. The TBCCW components within the scope of
 
license renewal (highlighted pink (magenta)) are depicted on Service
 
Water System boundary drawings LR-M-109-2 and on LR-M-2109-2
 
which best illustrates the connection to the Emergency Service Water
 
System Piping 4" HRC-114/214 and 4" HRC-134/234.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.3.33-1 acceptable
 
because the applicant has clarified that the TBCCW components within the scope of license
 
renewal are adequately identified in SWS boundary drawings. Therefore, the staff's concern 2-117 described in RAI 2.3.3.33-1 is resolved.
 
2.3.3.33.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI response, and boundary drawings (original and
 
revised) 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. On the basis of its review, the staff concludes the
 
applicant has appropriately identified the TBCCW system mechanical components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately
 
identified the TBCCW system mechanical components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1) and; therefore, is acceptable.
 
2.3.4  Steam and Power Conversion Systems LRA Section 2.3.4 identifies the steam and power conversion systems SCs subject to an AMR for license renewal. The applicant described the supporting SCs of the steam and power
 
conversion systems in the following LRA sections:
* 2.3.4.1    Auxiliary boiler system
* 2.3.4.2    Bypass steam system
* 2.3.4.3    Condensate transfer and storage system
* 2.3.4.4    Condenser and air removal system
* 2.3.4.5    Feedwater system
* 2.3.4.6    Main steam system
* 2.3.4.7    Main turbine system
* 2.3.4.8    Makeup demineralizer system
* 2.3.4.9    Makeup transfer and storage system
* 2.3.4.10  Reactor feed pump turbines system
* 2.3.4.11  Refueling water transfer and storage system 2.3.4.1  Auxiliary Boiler System 2.3.4.1.1  Summary of Technical Information in the Application
 
LRA Section 2.3.4.1 describes the auxiliary boile r (AB) system, which has two boilers that supply steam to various plant processes. The failure of nonsafety-related SSCs in the AB
 
system potentially could prevent the satisfactory accomplishment of a safety-related function.
LRA Table 2.3.4-1 identifies AB system component types within the scope of license renewal and subject to an AMR. 
 
2.3.4.1.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the AB system mechanical components within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the
 
system components subject to an aging managem ent review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2-118 2.3.4.2  Bypass Steam System 2.3.4.2.1  Summary of Technical Information in the Application
 
LRA Section 2.3.4.2 describes the bypass steam system, which bypasses MS directly to the condenser to control reactor pressure under certain normal operating conditions. The failure of
 
nonsafety-related SSCs in the bypass steam system potentially could prevent the satisfactory accomplishment of a safety-related function. LR A Table 2.3.4-2 identifies bypass steam system component types within the scope of license renewal and subject to an AMR. 
 
2.3.4.2.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the bypass steam syst em mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified
 
the system components subject to an aging m anagement review in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.4.3  Condensate Transfer and Storage System  2.3.4.3.1  Summary of Technical Information in the Application
 
LRA Section 2.3.4.3 describes the condensate transfer and storage (CTS) system, which
 
consists of an atmospheric condensate storage tank for each unit, two condensate transfer
 
pumps, a common atmospheric refueling water storage tank for both units, and two refueling
 
water pumps. The failure of nonsafety-related SSCs in the CTS system potentially could prevent the satisfactory accomplishment of a safety-re lated function. The CTS system also performs functions that support fire protection, ATWS, and SBO. LRA Table 2.3.4-3 identifies CTS
 
system component types within the scope of license renewal and subject to an AMR.
 
2.3.4.3.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.4.3, UFSAR Section 9.2.10, and the licensing renewal
 
boundary drawings using the evaluation methodology described in SER Section 2.3 and the
 
guidance in SRP-LR Section 2.3. The staff's review identified areas in which additional
 
information was necessary to complete the review of the applicant's scoping and screening
 
results. The applicant responded to the staff's RAIs as discussed below.
 
In RAIs 2.3.4.3-1 and 2.3.4.3-2, dated August 27, 2007, the staff noted instances where certain
 
piping was shown within the scope of license renewal on one boundary drawing but shown not
 
within the scope of license renewal when continued on another boundary drawing. 
 
The staff requested that the applicant explain why the sections of pipe in question are not within
 
the scope of license renewal on both boundary drawings.
 
In its response to RAIs 2.3.4.3-1 and 2.3.4.3-2, dated October 18, 2007, the applicant corrected
 
the inconsistency by clarifying what portion of the piping is within the scope of license renewal. 
 
The staff confirms that the applicant has submitted corrected boundary drawings which highlight 2-119 sections of piping that are within the scope of license renewal.
 
Based on its review, the staff finds the applicant's response to the RAIs 2.3.4.3-1 and 2.3.4.3-2
 
acceptable because the applicant has clarified that the piping in question is within the scope of
 
license renewal and subject to AMR and has revised the affected boundary drawings to identify
 
the license renewal boundaries. Therefore, the staff's concern described in RAIs 2.3.4.3-1 and
 
2.3.4.3-2 is resolved.
 
In RAI 2.3.4.3-3, dated August 27, 2007, the staff noted boundary drawing LR-M-118-3, location
 
A7, shows demineralized water piping four-inch JCD-59 as not within the scope of license
 
renewal. Its continuation on boundary drawing LR-M-108-1, location C10, is shown as within the
 
scope of license renewal. The staff requested that the applicant explain why this section of pipe
 
is not within the scope of license renewal.
In its response to RAI 2.3.4.3-3, dated October 18, 2007, the applicant stated in part:
 
The inconsistency in highlighting the portion of piping 4" JCD-59 located on LR-M-108-2 at C10 was identified during a previous drawing review and the highlighting has been corrected. The portion of 4" JCD-59 that is within the scope of license renewal and subject to AMR extends from condensate storage tank 0T522B, shown on LR-M-108-1 at B8, back to the penetration from the turbine building, shown at C9. The portion upstream of that penetration, back to the continuation arrow from "M-118-3 A7", shown at C10, is in the turbine building and therefore, as described in LRA Section 2.1.1.2.2, is not within the scope of license renewal. The portion of JCD-59 between the continuation arrow and the penetration from the turbine building should not have been highlighted. 4" JCD-59, from and including the continuation arrow on LR-M-108-1 at C10 to the penetration at C9, is no longer highlighted.
The staff confirms that the applicant has submitted revised boundary drawing LR-M-108-1.
Based on its review, the staff finds the applicant's response to RAI 2.3.4.3-3 acceptable
 
because the applicant has clarified that the piping within the TB is not within the scope of
 
license renewal and has revised boundary drawing LR-M-108-1. Therefore, the staff's concern
 
described in RAI 2.3.4.3-3 is resolved.
In RAI 2.3.4.3-4, dated August 27, 2007, the staff noted boundary drawing LR-M-108-1, location
 
B2, includes license renewal note C regarding RWST 0T501. It states, "Refueling Water
 
Storage Tank could flood the adjacent condensate storage area containing safety-related
 
instruments." The tank is shown within the scope of license renewal; however, none of the
 
piping penetrations or piping connected to the tank is within the scope of license renewal. The
 
staff requested that the applicant explain why piping penetrations and connected piping are not
 
within the scope of license renewal.
 
In its response to RAI 2.3.4.3-4, dated October 18, 2007, the applicant stated:
 
The refueling storage area and Unit 1 condensate storage area are
 
located outdoors and surrounded by walls that form a common
 
berm/retention basin. The berm/retention basin is designed to retain the
 
total volume of water contained in both the refueling water storage tank 2-120 (RWST) and the Unit 1 CST if both tanks rupture simultaneously. The basin includes a sump along the west wall, near the RWST, and the
 
safety-related SCs in the condensate storage area (i.e., level
 
instrumentation associated with HPCI/RCIC supply) are located in the
 
southeast corner, with the CST between them and the RWST and
 
associated piping. As such, spray or leakage from the RWST and
 
associated piping in the storage areas will not impair or prevent the
 
accomplishment of a safety-related function, but would drain to the sump.
 
However, rupture of the RWST would flood the retention basin to a level
 
that could, conservatively, result in spatial interaction with the
 
safety-related SCs in the condensate storage area.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.4.3-4 acceptable
 
because the applicant has clarified that a berm and/or retention basin is designed to retain the
 
total volume of water contained in both the RWST and the Unit 1 CST, if both tanks
 
simultaneously rupture. Therefore, the staff's concern described in RAI 2.3.4.3-4 is resolved.
In RAI 2.3.4.3-5, dated August 27, 2007, the staff noted boundary drawing LR-M-108-1, locations G6 and H6, shows condensate transfer pump discharge lines as being within the
 
scope of license renewal; however, the recirculation lines, two-inch HCD-13, between check
 
valves 008043 and 008053 and four-inch HCD-13 are shown as not within the scope of license
 
renewal. The staff requested that the applicant explain why these pipe sections are not within
 
the scope of license renewal.
In its response to RAI 2.33.4.3-5, dated October 18, 2007, the applicant stated:
 
The condensate transfer pumps and the associated discharge lines are
 
within the scope of license renewal because they are required to supply
 
the ECCS and RCIC keep fill system to prevent water hammer whenever
 
operation of these systems is initiated for mitigation of fire and station
 
blackout events, thus meeting the scoping criteria of 10 CFR 54.4(a)(3).
 
However, the flowpath from the condensate transfer pumps back to the
 
condensate storage tank (0T522A) is not required to support this (a)(3)
 
function. It has also been determined that failure of this flowpath will not
 
prevent the accomplishment of an (a)(1) function, as it is not connected to
 
nor located near safety-related SSCs.
Based on its review, the staff finds the applicant's response to RAI 2.3.4.3-5 acceptable
 
because the applicant has clarified that the piping in question is not required to support the fire
 
protection function for SBO events, pursuant to 10 CFR 54.4(a)(3). Therefore, the staff's
 
concern described in RAI 2.3.4.3-5 is resolved.
 
In RAI 2.3.4.3-6, dated August 27, 2007, the staff noted boundary drawing LR-M-108-1, location
 
H5, shows piping one-inch HCD-9 from six-inch HCD-9 to valve 008051 as being not within the
 
scope of license renewal. The staff requested that the applicant explain why this section of pipe
 
is not within the scope of license renewal.
 
2-121 In its response to RAI 2.3.4.3-6, dated October 18, 2007, the applicant stated the one-inch HCD piping from the six-inch HCD-9 piping line to valve 008051 is within the scope of license
 
renewal. The staff confirms that the applicant has submitted revised boundary drawing
 
LR-M-108-1 placing this piping within the scope of license renewal, in accordance with
 
10 CFR 54.4(a)(3).
 
Based on its review, the staff finds the applicant's response to RAI 2.3.4.3-6 acceptable
 
because the applicant has clarified that the subject piping is within the scope of license renewal
 
and subject to an AMR and has revised boundary drawing LR-M-108-1 to identify the revised
 
license renewal boundary. Therefore, the staff's concern described in RAI 2.3.4.3-6 is resolved.
 
2.3.4.3.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and boundary drawings (original and
 
revised) 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. On the basis of its review, the staff concludes the
 
applicant has appropriately identified the CTS system mechanical components within the scope
 
of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately
 
identified the CTS system mechanical components subject to an AMR, in accordance with the
 
requirements of 10 CFR 54.21(a)(1) and; therefore, is acceptable.
 
2.3.4.4  Condenser and Air Removal System 2.3.4.4.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.4.4 describes the condenser and air removal system. The failure of
 
nonsafety-related SSCs in the condenser and air re moval system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.4-4 identifies condenser
 
and air removal system component types within the scope of license renewal and subject to an
 
AMR.
2.3.4.4.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.4.4, UFSAR Sections 10.4.1 and 10.4.2, and the licensing
 
renewal boundary drawings using the evaluation methodology described in SER Section 2.3
 
and the guidance in SRP-LR Section 2.3. The staff's review identified an area in which
 
additional information was necessary to complete the review of the applicant's scoping and
 
screening results. The applicant responded to the staff's RAI as discussed below.
 
In RAI 2.3.4.4-1, dated August 27, 2007, the staff noted that boundary drawing LR-M-141-1
 
(2141-1), location E9 shows this line highlighted in green as it exits the steam tunnel and enters
 
the TB. However, the downstream line is not highlighted on LR-M-105-2 (2105-2), location B1, where it connects to condenser shell 1A (penetration 88). The staff requested that the applicant
 
explain why these pipe sections and components are not within scope for license renewal. 
 
In its response to RAI 2.3.4.4-1, dated October 18, 2007, the applicant stated that the piping in
 
question, four-inch EAD-114 on boundary drawing LR-M-105-2, from continuation arrow
 
M-141-1 E9 located at B1 to HP condenser shell -1A, penetration 88 is within the scope of
 
license renewal and is subject to AMR. The staff confirms that the applicant has submitted 2-122 revised boundary drawings LR-M-105-2 and LR-M-2105-2 that show this piping within the scope of license renewal, pursuant to 10 CFR 54.4(a)(1).
 
Based on its review, the staff finds the applicant's response to RAI 2.3.4.4-1 acceptable
 
because the applicant has clarified that the piping in question is within the scope of license
 
renewal and subject to AMR and has submitted two revised boundary drawings that identify the
 
license renewal boundaries. 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 boundary drawings (original and
 
revised) 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. On the basis of its review, the staff concludes the
 
applicant has appropriately identified the condenser and air removal system mechanical
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the
 
applicant has adequately identified the condenser and air removal system mechanical
 
components subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1)
 
and; therefore, is acceptable.
 
2.3.4.5  Feedwater System  2.3.4.5.1  Summary of Technical Information in the Application
 
LRA Section 2.3.4.5 describes the feedwater system (FWS), which supplies high-purity, preheated feedwater to the RV at the flow and pressure required to maintain the desired RV
 
water level throughout the entire operating range from startup to full load to shutdown. The FWS
 
contains safety-related components relied upon to remain functional during and following DBEs.
 
The failure of nonsafety-related SSCs in the FWS potentially could prevent the satisfactory
 
accomplishment of a safety-related function. In addition, the FWS performs functions that
 
support fire protection, ATWS, SBO, and EQ. LRA Table 2.3.4-5 identifies FWS component
 
types within the scope of license renewal and subject to an AMR.
 
2.3.4.5.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the FWS mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system
 
components subject to an aging management review in accordance with the requirements
 
stated in 10 CFR 54.21(a)(1). 2.3.4.6  Main Steam System  2.3.4.6.1  Summary of Technical Information in the Application 
 
LRA Section 2.3.4.6 describes the MSS, which transports high-pressure steam generated in the
 
RPV to the main turbine through four MS lines, each line with a main stop and turbine control
 
valve. The MSS contains safety-related components relied upon to remain functional during and 2-123 following DBEs. The failure of nonsafety-related SSCs in the MSS potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the MSS performs
 
functions that support fire protection, ATWS, SBO, and EQ. LRA Table 2.3.4-6 identifies MSS
 
component types within the scope of license renewal and subject to an AMR.
2.3.4.6.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.3.4.6, UFSAR Section 10.3, and the licensing renewal
 
boundary drawings using the evaluation methodology described in SER Section 2.3 and the
 
guidance in SRP-LR Section 2.3. The staff's review identified areas in which additional
 
information was necessary to complete the review of the applicant's scoping and screening
 
results. The applicant responded to the staff's RAIs as discussed below.
 
In RAI 2.3.4.6-1, dated August 27, 2007, the staff noted that the boundary drawings
 
LR-M-141-1, LR-M-101-1, LR-M-101-3 and LR-M-2141-1, LR-M-2101-1, LR-M-2101-3 show several ASME Code Section III, Class 2 lines that are identified within scope of license renewal
 
but are not shown as safety-related, in accordance with the notation legend on boundary
 
drawing LR-M-100-4, Note A2. The staff requested that the applicant clarify whether these lines
 
are within the scope of license renewal, pursuant to 10 CFR 54.4(a) (1) and; if not, provide an
 
explanation.
In its response to RAI 2.3.4.6-1, dated October 18, 2007, the applicant stated:
 
The piping noted in this RAI on license renewal drawings LR-M-141-1, LR-M-101-1, and LR-M-101-3 includes the 4 main steam lines from the outermost isolation valves to the turbine stop valves, 24" DBB-101, 102, 103 & 104, and the turbine bypass lines, 24"DBB-105 and 18" DBB-105.
License renewal boundary drawings LR-M-2141-1, LR-M-2101-1, LR-M-2101-3 include 24" DBB-201, 202, 203 & 204, and the turbine bypass lines, 24"DBB-205 and 18" DBB-205. Reference LR-M-100-2 at E3, PPL's drawing convention is to "cross-hatch" pipelines that are safety-related. Note, the lack of "cross-hatching" indicates that these lines are not safety-related.
As stated in FSAR Section 10.3.1, Design Bases, the main steam supply system has no safety-related function, but is designed to supply required steam to the turbine generator and bypass steam to the condenser.
FSAR Section 10.3.2 states the main steam piping is designed to ASME Section III Class 2. FSAR Table 3.2-1 classifies the main steam piping beyond the outermost isolation valve to the turbine stop valves as ASME Section III, Class 2, but shows that this piping is not within the scope of 10 CFR 50 Appendix B.
FSAR Section 10.4.4 likewise notes the bypass system has no safety-related function and the piping is designed in accordance with ASME Section III, Class 2.
Therefore, as indicated in the FSAR, the main steam piping, through to the main stop valves and to the bypass valve chest is designed as ASME
 
Section III, Class 2, but is not classified as safety-related.
 
2-124 Based on its review, the staff finds the applicant's response to RAI 2.3.4.6-1 acceptable because the applicant has clarified that the piping in question is nonsafety-related and within the
 
scope of license renewal, pursuant to 10 CFR 54.4(a)(2) and in agreement with UFSAR
 
Sections 10.3.1 and 10.4.4. Therefore, the staff's concern described in RAI 2.3.4.6-1 is
 
resolved.
In RAI 2.3.4.6-2, dated August 27, 2007, the staff noted that the boundary drawings
 
LR-M-141-1, and LR-M-2141-1, locations A-7 upstream of 141F029A and 241F029A show sections of ASME Code Section III, Class 3 pipe as within scope of license renewal for
 
nonsafety-related spatial effects, in accordance with 10 CFR 54.4(a)(2) and as described in
 
boundary drawing LR-M-100, note A2 on Sheet 4. Since ASME Code Class 3 components are
 
described in RG 1.26, Quality Group C as safety-related, the staff requested that the applicant
 
explain why these sections of pipe are not within the scope of license renewal, pursuant to
 
10 CFR 54.4(a)(1). 
 
In its response to RAI 2.3.4.6-2, dated October 18, 2007, the applicant stated in part:
FSAR Table 3.2-1 under the "Nuclear Boiler System" heading indicates the air supply check valves and the piping downstream of the air supply check valves is safety-related. The piping upstream of the air supply check valves is not safety-related and has no safety-related function. The short section of stainless steel piping attached to the air supply check valve allows use of an insulating flange to connect two different materials.
A portion of the non safety-related piping upstream of the check valve is in-scope as it contains an anchor that provides support for the safety-related valve and is thus within the scope of license renewal based on 10 CFR 54.4(a)(2), and subject to AMR.
The staff confirms that the applicant has submitted revised boundary drawings LR-M-141-1 and LR-M-214-1.
Based on its review, the staff finds the applicant's response to RAI 2.3.4.6-2 acceptable
 
because the applicant has clarified that the piping in question is nonsafety-related and within the
 
scope of license renewal, pursuant to 10 CFR 54.4(a)(2) and is in agreement with UFSAR
 
Table 3.2-1. Therefore, the staff's concern described in RAI 2.3.4.6-2 is resolved.
In RAI 2.3.4.6-3, dated August 27, 2007, the staff noted that the boundary drawing
 
LR-M-101-1, locations A6, C6, E6, F6, and G-2, and LR-M-2101-1, locations A6, C6, E6, F6, and G-2 show one-inch instrumentation pipes and the first normally open manual isolation
 
valve within the scope of license renewal. Boundary drawing LR-M-100, Sheet 4, note A2
 
suggests that the intended function of these pipes is pressure boundary. However, the
 
connecting downstream piping is not shown as within the scope of license renewal. Since
 
failure of the downstream pipe will have the same effect as failure of the in-scope piping, the
 
staff requested that the applicant explain why the downstream piping also is not included
 
within the scope of license renewal.
 
2-125 In its response to RAI 2.3.4.6-3, dated October 18, 2007, the applicant stated:
The main stop valves on license renewal drawings LR-M-101-1 and
 
LR-M-2101-1 form the boundary associated with providing an alternate
 
pathway for main steam isolation valve (MSIV) leakage, as described in
 
LRA Section 2.3.4.6. The MSIV Leakage Isolated Condenser Treatment
 
Method (ICTM) directs any leakage through a closed MSIV to the main
 
condenser. This is a nonsafety-related function in accordance with
 
10 CFR 54.4(a)(2).
 
The intended function is to provide a flow path rather than a pressure
 
boundary. Therefore, the ICTM boundary is established at the first
 
isolation valve associated with instrumentation for the stop valves, drip
 
legs, and sensing lines in order to depict the boundaries of the path. Flow
 
is not expected in the instrument lines and any leakage from the
 
instrument lines would be inconsequential to the overall volume available
 
for hold-up and plate-out of fission products.
Based on its review, the staff finds the applicant's response to RAI 2.3.4.6-3 acceptable because the applicant has clarified that the intended function of the piping in question is to provide a flow path rather than a pressure boundary. Therefore, the staff's concern described in RAI 2.3.4.6-3 is resolved.
In RAI 2.3.4.6-4, dated August 27, 2007, the staff noted that the boundary drawing
 
LR-M-101-1, locations B-8, D-8, E-8, and G-8, and LR-M-2101-1, locations B-8, D-8, E-8, and
 
G-8, show the 28-inch lines as nonsafety-related and are considered within the scope of
 
license renewal for spatial effects. However, no portion of the nonsafety-related lines
 
connecting the 28-inch lines to control valve MS lead drain is shown as within the scope of
 
license renewal for the same spatial effects. The staff requested that the applicant explain
 
why these lines are not included within the scope of license renewal, in accordance with the
 
requirements of 10 CFR 54.4(a)(2).
 
In its response to RAI 2.3.4.6-4, dated October 18, 2007, the applicant stated:
LRA Section 2.3.4.7, Main Turbine, states that the High Pressure (HP)
Turbine Casing and associated bolting are in-scope. The HP Turbine
 
Casing and bolting are in-scope because they provide structural support (anchor to plant structure) for Main Steam System piping extending from
 
the reactor building into the turbine building. As such, the casing of the
 
HP turbine has the potential for interaction (connected to) with
 
safety-related components and is in-scope based on 10 CFR 54.4(a)(2).
 
Because the HP Turbine Casing serves as an anchor, the Main Steam
 
System piping is brought into scope based on the seismic analysis
 
boundary extending all the way back to the containment penetration. The
 
small branch piping off the Main Steam System was not included in the
 
seismic evaluation of the Main Steam piping because this piping is non-Q
 
and by specification, Bechtel Specification M406, Piping Stress Analysis
 
for SSES, Section 5.11) it is too small to have a significant effect. Also, refer to boundary drawing LR-M-101-1, LR Note D which addresses
 
anchors for pipelines less than 2 1/2" in diameter. In addition, the Main 2-126 Steam System small branch piping is not in-scope due to spatial interaction (wetting, spray, leakage, flooding) based on SSES LRA
 
Section 2.1.1.2.2.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.4.6-4 acceptable
 
because the applicant has verified that the small branch piping off the MSS was not included in
 
the seismic evaluation of the MS piping because this piping is non-Q and was not included in
 
the piping stress analysis. Therefore, the staff's concern described in RAI 2.3.4.6-4 is resolved.
 
In RAI 2.3.4.6-5, dated August 27, 2007, the staff noted that the boundary drawing
 
LR-M-101-1, locations B-7, C-7, E-7, and F-7, and LR-M-2101-1, locations B-7, C-7, E-7, and
 
F-7, show CV-1, CV-2, CV-3, and CV-4 as nonsafety-related and within the scope of license
 
renewal, pursuant to 10 CFR 54.4(a)(2). There are several nonsafety related lines that are
 
connected to the CV-1, CV-2, CV-3, and CV-4 valve pressure boundaries; however, no
 
portion of these connecting lines are shown as within the scope of license renewal. The staff
 
requested that the applicant explain why these lines are not included within the scope of
 
license renewal, in accordance with the requirements of 10 CFR 54.4(a)(2).
 
In its response to RAI 2.3.4.6-5, dated October 18, 2007, the applicant stated:
 
LRA Section 2.3.4.7, Main Turbine, states that the High Pressure (HP)
 
Turbine Casing and associated bolting are in-scope. The HP Turbine
 
Casing and bolting are in-scope because they provide structural support (anchor to plant structure) for Main Steam System piping extending from
 
the reactor building into the turbine building. As such, the casing of the
 
HP turbine has the potential for interaction (connected to) with
 
safety-related components and is in-scope based on 10 CFR 54.4(a)(2).
 
Because the HP Turbine Casing serves as an anchor, the Main Steam
 
System piping is brought into scope based on the seismic analysis
 
boundary extending all the way back to the containment penetration. The
 
small branch piping off the Main Steam System was not included in the
 
seismic evaluation of the Main Steam piping because this piping is non-Q
 
and by specification, Bechtel Specification M406, Piping Stress Analysis
 
for SSES, Section 5.11, it is too small to have a significant effect. Also, refer to boundary drawing LR-M-101-1, LR Note "D" which addresses
 
anchors for pipelines less than 2 1/2" in diameter. In addition, the Main
 
Steam System small branch piping is not in-scope due to spatial
 
interaction (wetting, spray, leakage, flooding) based on SSES LRA
 
Section 2.1.1.2.2.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.4.6-5 acceptable
 
because the applicant has verified that the small branch piping off the MSS was not included in
 
the seismic evaluation of the MS piping because this piping is non-Q and was not included in
 
the piping stress analysis. Therefore, the staff's concern described in RAI 2.3.4.6-5 is resolved.
 
In RAI 2.3.4.6-6, dated August 27, 2007, the staff noted that the boundary drawings LR-M-141-1
 
and LR-M-2141-1, Revision 1, location C-8, show piping downstream of normally closed manual isolation valves 141010A and 241010A as ASME Code Section III, Class 2 pipe. However, this
 
piping is identified as within the scope for license renewal as a nonsafety-related pipe, pursuant
 
to 10 CFR 54.4(a)(2). The staff requested that the applicant explain why these sections of pipe 2-127 are not within the scope of license renewal, in accordance with 10 CFR 54.4(a)(1).
 
In its response to RAI 2.3.4.6-6, dated October 18, 2007, the applicant stated:
 
As stated in FSAR Section 10.3.1, Design Bases, the main steam supply system has no safety-related function, but is designed to supply required steam to the turbine generator and bypass steam to the condenser.
FSAR Section 10.3.2 states the main steam piping is designed to ASME Section III Class 2. FSAR Table 3.2-1 classifies the main steam piping beyond the outermost isolation valve to the turbine stop valves, including the piping to and the normally closed isolation valves 141010A and 241010A, as ASME Section III, Class 2, but shows that this piping is not within the scope of 10 CFR 50 Appendix B.
FSAR Section 10.4.4 likewise notes the bypass system has no safety-related function and the piping is designed in accordance with ASME Section III, Class 2.
The piping downstream of normally closed manual isolation valves
 
141010A and 241010A is ASME Section III Class 2 pipe, and has no
 
safety-related function. Therefore, this piping does not meet
 
10 CFR 54.4(a)(1) scoping criteria. This piping could contain water and is
 
therefore within the scope of license renewal based on 
 
10 CFR 54.4(a)(2), due to the potential for spatial interaction.
 
Based on its review, the staff finds the applicant's response to RAI 2.3.4.6-6 acceptable
 
because the applicant has clarified that the piping in question is nonsafety-related and within the
 
scope of license renewal, pursuant to 10 CFR 54.4(a)(2) and is in agreement with UFSAR
 
Table 3.2-1 and Section 10.4.4. Therefore, the staff's concern described in RAI 2.3.4.6-6 is
 
resolved.
In RAI 2.3.4.6-7, dated August 27, 2007, the staff noted that the boundary drawings
 
LR-M-141-1, and LR-M-2141-1, Revision 1, loca tions C-7 and F-7 show piping downstream of normally closed manual isolation valves 14138A/24138A, 14101A/24101A, and 14101B/24101B
 
that appear to be ASME Code Section III, Class 2 pipe. However, these piping components are
 
identified within the scope of license renewal as nonsafety-related, pursuant to
 
10 CFR 54.4(a)(2). The staff requested that the applicant explain why these sections of pipe are
 
not within the scope of license renewal, in accordance with 10 CFR 54.4(a)(1).
 
In its response to RAI 2.3.4.6-7, dated October 18, 2007, the applicant stated:
 
As stated in FSAR Section 10.3.1, Design Bases, the main steam supply system has no safety-related function, but is designed to supply required steam to the turbine generator and bypass steam to the condenser.
FSAR Section 10.3.2 states the main steam piping is designed to ASME Section III Class 2. FSAR Table 3.2-1 classifies the main steam piping beyond the outermost isolation valve to the turbine stop valves, including the piping to and the normally closed isolation valves 14138A/24138A, 14101A/24101A, and 14101B/24101B, as ASME Section III Class 2, but shows that this piping is not within the scope of 10 CFR 50 Appendix B.
2-128  FSAR Section 10.4.4, likewise, notes the bypass system has no safety-related function and the piping is designed in accordance with ASME Section III Class 2.
The piping downstream of normally closed manual isolation valves 14138A/24138A, 14101A/24101A, and 14101B/24101B is ASME Section III Class 2 pipe, and has no safety-related function. Therefore, this piping does not meet 10 CFR 54.4(a)(1) scoping criteria. This piping could contain water and is therefore within the scope of license renewal based on 10 CFR 54.4(a)(2), due to the potential for spatial interaction.
Based on its review, the staff finds the applicant's response to RAI 2.3.4.6-7 acceptable, because the applicant has clarified that the piping in question is nonsafety-related and within the
 
scope of license renewal, pursuant to 10 CFR 54.4(a)(2) and is in agreement with UFSAR
 
Table 3.2-1 and Section 10.4.4. Therefore, the staff's concern described in RAI 2.3.4.6-7 is
 
resolved.
 
In RAI 2.3.4.6-8, dated August 27, 2007, the staff noted that boundary drawings LR-M-141-1
 
and LR-M-2141-1, locations A-7 show the nonsafety-related (line class JDD) ANSI B31.1 piping
 
connected to safety-related (line class HCC) ASME Code Section III, Class 3 piping not within
 
the scope of license renewal. In LRA Section 2.1.1.2.2, "Spatial Failures of Nonsafety-Related
 
SSCs," page 2.1-8 the applicant states in part: "With respect to nonsafety-related piping that is
 
directly connected to safety-related piping, the seismic Category I design requirements are
 
extended to the first seismic restraint beyond the defined boundaries." The staff requested that
 
the applicant provide the location of the license renewal boundary (seismic restraint) for the
 
nonsafety-related piping connected to the safety-related piping. 
 
In its response to RAI 2.3.4.6-8, dated October 18, 2007, the applicant verified that the seismic
 
anchor is located between the check valve and insulating flange.
Based on its review, the staff finds the applicant's response to RAI 2.3.4.6-8 acceptable
 
because the applicant has verified the location of the seismic anchor. Therefore, the staff's
 
concern described in RAI 2.3.4.6-8 is resolved.
 
2.3.4.6.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and boundary drawings (original and
 
revised) 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. On the basis of its review, the staff concludes the
 
applicant has appropriately identified the MSS mechanical components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified
 
the MSS mechanical components subject to an AMR, in accordance with the requirements of
 
10 CFR 54.21(a)(1) and; therefore, is acceptable.
2.3.4.7  Main Turbine System 2.3.4.7.1  Summary of Technical Information in the Application 2-129  LRA Section 2.3.4.7 describes the main turbine system (MTS), which consists of one double-
 
flow, high-pressure turbine and three double-exhaust flow, low-pressure turbines. The failure of
 
nonsafety-related SSCs in the MTS potentially coul d prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.4-7 identifies MTS component types within the scope of
 
license renewal and subject to an AMR. 
 
2.3.4.7.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the MTS mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system
 
components subject to an aging management review in accordance with the requirements
 
stated in 10 CFR 54.21(a)(1). 2.3.4.8  Makeup Demineralizer System 2.3.4.8.1  Summary of Technical Information in the Application
 
LRA Section 2.3.4.8 describes the makeup demineralizer system, which provides an adequate
 
supply of demineralized water for the plant operating requirements. The failure of nonsafety-
 
related SSCs in the makeup demineralizer system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.4-8 identifies makeup demineralizer
 
system component types within the scope of license renewal and subject to an AMR.
2.3.4.8.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the makeup demineraliz er system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately
 
identified the system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.4.9  Makeup Transfer and Storage System 2.3.4.9.1  Summary of Technical Information in the Application
 
LRA Section 2.3.4.9 describes the makeup transfer and storage system, which provides
 
demineralized water makeup to various plant serv ices from the makeup demineralizer system.
The failure of nonsafety-related SSCs in the makeup transfer and storage system potentially
 
could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.4-9
 
identifies makeup transfer and storage system component types within the scope of license
 
renewal and subject to an AMR.
 
2.3.4.9.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has 2-130 appropriately identified the makeup transfer and storage system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has
 
adequately identified the system components subject to an aging management review in
 
accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.4.10  Reactor Feed Pump Turbines System 2.3.4.10.1  Summary of Technical Information in the Application
 
LRA Section 2.3.4.10 describes the reactor f eed pump turbines system, which is driven by variable-speed, multistage turbines that receive steam from either the MS cross-connection
 
header or the crossover piping downstream of the moisture separators. The reactor feed pump
 
turbines system performs functions that support fire protection. The only components of the
 
reactor feed pump turbines system within the scope of license renewal are the reactor feed
 
pump turbine low-pressure and high-pressure stop valves. The valve bodies and their internal
 
pilot valves and oil piping/tubing perform no passive intended function. Therefore, there are no
 
reactor feed pump turbines system components subject to an AMR.
 
2.3.4.10.2 Conclusion
 
Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the
 
LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the reactor feed pump tu rbines system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has
 
adequately identified the system components subject to an aging management review in
 
accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.4.11  Refueling Water Transfer and Storage System 2.3.4.11.1  Summary of Technical Information in the Application
 
LRA Section 2.3.4.11 describes the refueling water transfer and storage system, which stores
 
the water that fills the reactor wells and dryer-separator pools of either Unit 1 or 2. During
 
refueling operations, water inventory is transferred from the storage tank to the reactor wells
 
and dryer-separator pools. The failure of nonsafety-related SSCs in the refueling water transfer
 
and storage system potentially could prevent the satisfactory accomplishment of a safety-related function. LRA Table 2.3.4-10 identifies refueling water transfer and storage system
 
component types within the scope of license renewal and subject to an AMR. 
 
2.3.4.11.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that applicant has
 
appropriately identified the SDS mechanical components within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and that the applicant has adequately identified the system
 
components subject to an aging management review in accordance with the requirements
 
stated in 10 CFR 54.21(a)(1).
2-131 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:
* Primary containment
* Reactor building
* ES SW pumphouse and spray pond
* CWPH and water treatment building
* Control structure
* DG A, B, C, and D building
* DG E building
* Turbine building
* Yard structures
* Bulk commodities In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the
 
applicant properly implemented its methodology, the staff's review focused on the
 
implementation results. This focus 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 the same for all structures. The
 
objective was to determine whether the applicant has identified, in accordance with
 
10 CFR 54.4, components and supporting structures for structures that appear to meet the
 
license renewal scoping criteria. Similarly, the staff evaluated the 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).
 
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 structure to
 
determine whether the applicant has omitted from the scope of license renewal components
 
with intended functions pursuant to 10 CFR 54.4(a). The staff also reviewed the licensing basis
 
documents to determine whether the LRA specified all intended functions in accordance with
 
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 (a) the functions are
 
performed with moving parts or a change in configuration or properties or (b) 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.
 
The staff's review of the introductory scoping portion of LRA Section 2.4 identified areas in
 
which additional information was necessary to complete the review of the applicant's scoping
 
and screening results and determine whether the applicant properly applied the scoping criteria
 
of 10 CFR 54.4(a). The applicant responded to the staff's RAIs as discussed below.
2-132  In RAI 2.4-1, dated August 3, 2007, the staff noted that LRA Section 2.4, fourth paragraph, first
 
sentence, stated that the major structures included within the scope of license renewal were as
 
listed therein. Pursuant to 10 CFR 54.4, all structures (including major structures) that perform
 
an intended function stated in 10 CFR 54.4(a) are required to be included within the scope of
 
license renewal. The staff requested that the applicant to: (a) confirm that the in-scope
 
structures and structure categories listed in LRA Section 2.4 are all inclusive; (b) clarify the
 
language used in that section of the LRA, "The major structures in the scope..."; and (c) include
 
any remaining structures that may be within the scope of license renewal and provide
 
corresponding scoping, screening and AMR results.
In its response to RAI 2.4-1, dated August 28, 2007, the applicant stated:
The in-scope structures and structure categories listed in Section 2.4 are all inclusive of
 
the in-scope License Renewal structures required by 10CFR54.4 for SSES. The term
 
"major" was used to categorize the structures to be addressed in different sections of the
 
SSES LRA. All in-scope structures for SSES are listed in the LRA with the Yard
 
Structures category encompassing all the miscellaneous in-scope Yard Structures
 
identified in Section 2.4.9. The in-scope Yard Structures are:
* Clarified Water Storage Tank Foundation
* Condensate Storage Tank Foundation and Retention Basin (Units 1 and
: 2)
* Diesel Generator Fuel Oil Storage Tanks 'A, B, C, D & E' Foundations and Vaults
* Refueling Water Storage Tank Foundation (Unit 1)
* Station Blackout component foundations and structures (Startup Transformers 
 
T-10 and T-20 and associated disconnect switches, Engineered
 
Safeguards Systems (ESS) Transformers)
* Cooling Tower Basins (Units 1 and 2)
* Duct banks, manholes, valve vaults, instrument pits, piping trenches The first sentence in the fourth paragraph of the license renewal application (LRA)
 
Section 2.4 "Scoping and Screening Results: Structures" is revised in bold italics as shown in Attachment 1 of the applicant's letter dated August 28, 2007, to read as
 
follows:  "The structures in the scope of license renewal are the:"
 
Based on its review, the staff finds the applicant's response to RAI 2.4-1 acceptable because
 
that applicant has clarified that the structures listed as within the scope of license renewal are
 
all inclusive and has accordingly revised the language in LRA Section 2.4, fourth paragraph, first sentence. Therefore, the staff's concern described in RAI 2.4-1 is resolved.
In RAI 2.4-2, dated August 3, 2007, the staff noted that UFSAR Section 3.8.4 describes the radwaste building as a safety-related non-seismic Category 1 structure. UFSAR Page 3.8-45
 
states that the reinforced concrete walls and floor and the concrete block masonry walls meet
 
structural as well as radiation shielding requirements. LRA Sections 2.3.3.19 and 2.3.3.20
 
include the radwaste liquid system and the radwas te solids handling system within the scope of 2-133 license renewal and subject to an AMR. LRA Section 2.3.3.20, first paragraph states that all radwaste solids handling system equipment serves both reactor units and is located in the radwaste building. However, LRA Table 2.2-3 excludes the radwaste building from the scope of
 
license renewal. Since the above mentioned in-sc ope systems are located inside the radwaste building, the staff requested that the applicant confirm whether this would bring the radwaste
 
building within the scope of license renewal and subject to an AMR and; if so, include the
 
radwaste building in the LRA and describe its scoping, screening and AMR results. If the
 
radwaste building is excluded, provide the technical basis for the exclusion.
 
In its response to RAI 2.4-2, dated August 28, 2007, the applicant stated:
The FSAR Section 3.8.4, title heading is a hold-over from earlier versions
 
of the FSAR, listing of the Radwaste Building as a Safety-Related
 
structure is inconsistent with the reduced quality group classification
 
described in FSAR Table 3.2-1. A Condition Report (CR 893711) has
 
been issued to rectify the FSAR text.
 
The Radwaste Building is not in the scope of License Renewal at SSES, or subject to aging management review, since it does not contain in-
 
scope components and does not perform an intended function. As shown
 
in FSAR Table 3.2-1, the Radwaste Building and associated components
 
have a Safety Class of "Other," the definition of which is shown in FSAR
 
Section 3.2.3.4. As described in Notes 22 and 31 of FSAR Table 3.2-1, a
 
lower quality group classification, associated construction codes and
 
seismic category were determined to be appropriate for Radwaste
 
Treatment systems (and building) as a result of analysis per Regulatory
 
Guides 1.26 and 1.29, which demonstrated that the site boundary dose
 
would not exceed .5 Rem due to a loss of effluent from system
 
components. This quality group classification conforms to Quality Group
 
D (Augmented) as defined in NRC Branch Technical Position ETSB 11-1.
 
Table 2.3.3-18 of the LRA identifies the piping, valves, and piping
 
components (e.g., cleanouts and pump casings) of the Radwaste Liquid
 
System that are in the scope of License Renewal and subject to aging
 
management review. These components prov ide containment isolation or are nonsafety-related components that are required to maintain integrity
 
to prevent spatial interaction with, or support for attached, safety-related
 
components. These components are located in the Reactor Building or
 
Control Structure, as shown on the LR drawings listed in LRA
 
Section 2.3.3.19 (e.g. LR-M-161 Sheet 2), and not in the Radwaste
 
Building. With respect to the Radwaste Solids Handling System, the
 
system description in LRA Section 2.3.3.20 identifies that only the system
 
tanks and associated piping and piping components in the Reactor
 
Building, as shown on drawings LR-M-154, Sheet 1 and LR-M-166, Sheets 1 and 2 are in-scope and subject to aging management review as
 
identified in LRA Table 2.3.3-19. 
 
Based on its review, the staff finds the applicant's response to RAI 2.4-2 acceptable because
 
that applicant has verified that the safety-related description of the radwaste building in UFSAR
 
Section 3.8.4 was in error and has appropriately revised the FSAR text. The staff confirms that 2-134 the applicant has also verified that its analysis of the radwaste treatment systems (and building), pursuant to RGs 1.26 and 1.29, demonstrated that the site boundary dose would not exceed
 
0.5 rem due to a loss of effluent from system components. The applicant clarified that the
 
components of the radwaste liquid system and the radwaste solids handling system, described in LRA Sections 2.3.3.19 and 2.3.3.20, that are included within the scope of license renewal and
 
subject to an AMR, are located in the RB or control structure and not in the radwaste building.
 
Since the radwaste Building does not serve an intended function pursuant to 10 CFR 54.4(a),
the staff agrees with the applicant's conclusion that the radwaste building is not within the scope
 
of license renewal. Therefore, the staff's concerns described in RAI 2.4-2 are resolved.
 
Based on the applicant's response to RAIs 2.4-1 and 2.4-2, the staff finds that the applicant's
 
list of structures within the scope of license renewal, in the introductory part of LRA Section 2.4, is all inclusive. 
 
2.4.1  Primary Containment 2.4.1.1  Summary of Technical Information in the Application 
 
In LRA Section 2.4.1, the applicant describes the primary containments, which are GE BWR, Mark II (over/under) type seismic Category I structures. The primary containment is an
 
enclosure for the RV, the reactor coolant recirculation loops, and branch connections of the
 
RCS. Essential elements of the primary containm ent are the drywell, the suppression chamber that stores a large volume of water, the drywell floor separating the drywell and the suppression
 
chamber, the connecting vent pipe system bet ween the drywell and the suppression chamber, isolation valves, the vacuum relief system, the containment cooling systems, and other service equipment. Primary containment takes the form of a truncated cone over a cylinder, with the drywell in the upper conical section and the suppression chamber in the lower cylindrical
 
section. These two sections comprise a structurally-integrated, reinforced concrete pressure
 
vessel, lined with welded steel plate and with a steel domed head for closure at the top of the
 
drywell. The drywell floor is a reinforced concrete slab, structurally connected to the
 
containment wall.
 
The primary containment contains safety-related components relied upon to remain functional
 
during and following DBEs. In addition, the primary containment performs functions that support
 
SBO.
 
LRA Table 2.4.1-1 identifies primary containment component types within the scope of license
 
renewal and subject to an AMR:
* containment liner
* containment wall
* control rod drive removal hatch
* drywell floor
* drywell floor liner
* drywell head
* drywell sumps
* foundation
* penetrations
* permanent drywell shielding
* personnel airlock and equipment hatches 2-135
* reactor pedestal
* reactor pedestal liner
* reactor shield doors
* reactor shield wall
* reactor shield wall inner and outer plates
* reactor vessel thermal insulation
* refueling bellows
* refueling seal plate
* refueling seal lead shield plates
* seismic truss and seismic stabilizer
* structural steel: beams, columns, plates, and trusses
* suppression chamber
* suppression chamber access hatches
* suppression chamber columns
* suppression chamber liner The intended functions of the primary containment component types within the scope of license
 
renewal include:
* spray shield or curb to direct flow
* thermal expansion, seismic separation, or both
* flood protection barrier
* SBO or DBA heat sink
* missile barrier
* safety-related equipment shelter or protection
* shielding against radiation
* pressure boundary or essentially leak-tight barrier in postulated design-basis events to protect public health and safety
* structural or functional support to safety-related components
* structural support to nonsafety-related components whose failure could prevent
* satisfactory accomplishment of required safety functions
* structural or functional support required for any of the 10 CFR 54.4(a)(3) regulated events  2.4.1.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.4.1 and UFSAR Sections 3.8.1 through 3.8.3, 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, pursuant to 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).
2-136  The staff's review of LRA Section 2.4.1 identified areas in which additional information was
 
necessary to complete the review of the applicant's scoping and screening results, and
 
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 applicant responded to the staff's RAIs as
 
discussed below.
 
In RAI 2.4.1-1, dated August 3, 2007, the staff noted LRA Table 2.4-1 lists the drywell head (the
 
term "Drywell Head Assembly" used in the UFSAR is more appropriate) as a primary
 
containment component type subject to an AMR.
The staff was not clear from Tables 2.4-1 and 2.4-10 whether: (a) the mating flange bolts that secure the head to the lower flange; (b) the
 
manhole bolts; and (c) the double rubber gaskets that help prevent loss of joint leak-tightness at
 
the head-to-lower flange connection and at the manhole, are included within the scope of
 
license renewal and subject to an AMR. The staff requested that the applicant confirm whether
 
these components are within the scope of license renewal and if they were not included as a
 
result of an oversight, provide a description of their scoping, screening and an AMR. If these
 
components are excluded from the scope of license r enewal, provide the technical basis for the exclusion.
In its response to RAI 2.4.1-1, dated August 28, 2007, the applicant stated:
The mating flange bolts that secure the Drywell Head to the lower flange;
 
the manhole bolts that secure the Manhole to the Drywell Head; and the
 
gaskets that help prevent loss of joint leak-tightness at the Drywell Head
 
to lower flange connection and at the manhole to Drywell Head are
 
included in the scope of License Renewal for SSES and subject to aging
 
management review. The manhole and gaskets are considered as part of
 
the host component "Drywell head" and are included under Component
 
Type "Drywell head" in Table 2.4-1. The mating flange bolts and the
 
manhole bolts are included under Component Type "Anchor bolts (ASME
 
Class 1, 2, 3 and MC supports bolting)" in Table 2.4-10. 
 
Table 2.4-1 specific component type and Table 3.5.2-1 specific
 
component/commodity are revised as shown in bold italics in Attachment 2 (of the applicant's response letter dated August 28, 2007) to describe
 
the component type as: Drywell head (drywell head assembly includes manhole and double gaskets)
Based on its review, the staff finds the applicant's response to RAI 2.4.1-1 acceptable because
 
the applicant has clarified that the mating flange bolts, the manhole bolts and the gaskets of the
 
drywell head assembly are included in the scope of license renewal and subject to an AMR. The
 
applicant verified that the manhole and gaskets are considered as part of the host component
 
"Drywell head" and are included under component ty pe "Drywell head" in LRA Table 2.4-1. The applicant revised the drywell head component type description in LRA Tables 2.4-1 and 3.5.2-1
 
to read: Drywell head (drywell head assembly includes manhole and double gaskets). The staff confirms that the mating flange bolts and the manhole bolts are included under component type
 
"Anchor bolts (ASME Code Class 1, 2, 3 and MC supports bolting)" in LRA Table 2.4-10.
 
Table 2.4-10 of the LRA has an abbreviation, among others, of "SSR" in the intended function
 
column against the component type "Anchor bolts (ASME Code Class 1, 2, 3 and MC supports
 
bolting)" which is intended to include components that provide structural or functional support to 2-137 safety-related equipment (see LRA Table 2.0-1 for definition of intended function abbreviated as "SSR") and, therefore, include the mating flange bolts and the manhole bolts of the drywell head
 
assembly. Therefore, the staff's concern described in RAI 4.2.1-1 is resolved.
 
In RAI 2.4.1-2, the staff noted LRA Table 2.4-1 lists penetrations (mechanical and electrical, primary containment boundary), as components subject to an AMR. This does not seem to
 
include the penetrations through the reactor shield wall with hinged doors or removable plugs
 
that facilitate piping (i.e., feedwater, reactor recirculation, recirculation inlet, etc.) connections to the RV which provide access for in-service inspection (see UFSAR Section 3.8.3.1.3 and
 
drawings C-1932 Sheets 3 & 5). The staff requested that the applicant confirm whether these
 
penetrations and their doors and/or plugs are within the scope of license renewal and subject to
 
an AMR and if they were not included as a result of an oversight, provide a description of their
 
scoping, screening and AMR. If they are excluded from the scope of license renewal, provide the technical basis for the exclusion.
 
In its response to RAI 2.4.1-2, dated August 28, 2007, the applicant stated:
The penetrations through the Reactor Shield Wall with hinged doors or
 
removable plugs are in the scope of License Renewal for SSES and
 
subject to aging management review. These penetrations are included
 
under Component Type "Penetrations (Mechanical and Electrical, non
 
Primary Containment boundary)" in Table 2.4-10. The Reactor Shield
 
Wall hinged doors/removable plugs are in the scope of License Renewal
 
for SSES and subject to aging management review. These doors/plugs
 
are included under Component Type "Reactor shield doors" in Table 2.4-
: 1.
 
Table 2.4-1 specific component type and Table 3.5.2-1 specific
 
component/commodity are revised as shown in bold italics in Attachment 3 (of the applicant's response letter dated August 28, 2007) to describe
 
the component type as: Reactor shield doors (includes hinged doors and removable plugs)
Based on its review, the staff finds the applicant's response to RAI 2.4.1-2 acceptable because
 
the applicant has confirmed that the penetrations through the reactor shield wall are included
 
within the scope of license renewal and subject to an AMR, and are included under the
 
component type "Penetrations (Mechanical and El ectrical, non Primary Containment boundary)"
in LRA Table 2.4-10. The staff confirms that these penetrations are part of the non-primary
 
containment boundary and appropriately belong in LRA Table 2.4-10. The applicant also verified
 
that the reactor shield wall hinged doors and removable plugs also are within the scope of
 
license renewal and subject to an AMR, and are included under the component type "Reactor
 
shield doors" in LRA Table 2.4-1. The applicant revised the corresponding component type
 
description in LRA Tables 2.4-1 and 3.5.2-1 to read: Reactor shield doors (includes hinged doors and removable plugs). Therefore, the staff's concern described in RAI 2.4.1-2 resolved. 
 
In RAI 2.4.1-3, the staff noted LRA Section 2.4.1 and Table 2.4-1 list access hatches (equipment hatch, personnel airlock, suppression chamber access hatches, and the control rod
 
drive removal hatch) as primary containment components subject to an AMR. The staff is
 
unclear form LRA Tables 2.4-1 and 2.4-10 whether the flange double-gaskets, hatch locks, hinges and closure mechanisms that help prevent loss of sealing and/or leak-tightness for these 2-138 listed hatches are included within the scope of license renewal and subject to an AMR. The staff requested that the applicant confirm whether these components are within the scope of license
 
renewal, and if they were not included as a result of an oversight, please provide a description
 
of their scoping, screening and AMR. If they ar e excluded from the scope of license renewal, provide the technical basis for the exclusion.
 
In its response to RAI 2.4.1-3, dated August 28, 2007, the applicant stated:
The Component Types "Control rod drive (CRD) removal hatch,"
 
"Personnel airlock and equipment hatches" and "Suppression chamber
 
access hatches" in Table 2.4-1 include the flange gaskets, hatch locks, hinges and closure mechanisms. These subcomponents (flange gaskets, hatch locks, hinges and closure mechanisms) are considered as part of
 
the host component and are in the scope of License Renewal for SSES
 
and subject to aging management review. Under the Discussion column
 
for LRA Table Items 3.5.1-16 and 3.5.1-17 these subcomponents are
 
listed as part of the host component. 
 
Based on its review, the staff finds the applicant's response to RAI 2.4.1-3 acceptable because
 
the applicant has clarified that the flange gaskets, hatch locks, hinges and closure mechanisms
 
are included as subcomponents considered as part of the corresponding host components (the
 
access hatches) and are within the scope of license renewal and subject to an AMR. The
 
applicant also clarified that in the discussion column for LRA Table 3.5.1-16 and 3.5.1-17, these
 
subcomponents are listed as part of the host component. The staff determines that these
 
subcomponents can be considered as part of the host components within the scope of license
 
renewal and subject to an AMR. Therefore, the staff's concern described in RAI 2.4.1-3 is
 
resolved. 
 
In RAI 2.4.1-4, the staff noted, based on information in LRA Section 2.4.1 and Tables 2.4-1 and
 
2.4-10, it is not clear whether all drywell pipe restraints and/or whip restraints are within the
 
scope of license renewal. The staff requested that the applicant confirm whether these
 
components are within the scope of license renewal, and if they were not included as a result of
 
an oversight, please provide a description of their scoping, screening and AMR. If they are
 
covered somewhere else in the LRA, please indicate the location, and if they are excluded from
 
the scope of license renewal, provide the technical basis for the exclusion.
 
In its response to RAI 2.4.1-4, dated August 28, 2007, the applicant stated:
The drywell pipe restraints/whip restraints are in the scope of License
 
Renewal for SSES and subject to aging management review. These pipe
 
restraints/whip restraints are included under Component Type "HELB
 
barriers" in Table 2.4-10. HELB barriers provide jet impingement
 
protection to various in-scope components. HELB barriers include pipe
 
whip restraints, jet impingement shields or plate barriers, and crushable
 
energy absorbers.
 
Table 2.4-10 specific component type and Table 3.5.2-10 specific
 
component/commodity are revised as shown in bold italics in Attachment 4 (of the applicant's response letter dated August 28, 2007) to describe
 
the component type as: HELB barriers (includes pipe restraints, whip 2-139 restraints, jet impingement shields/plate barriers, and crushable energy absorbers).
Based on its review, the staff finds the applicant's response to RAI 2.4.1-4 acceptable because
 
the applicant has clarified that the drywell pipe restraints and/or whip restraints are within the
 
scope of license renewal and subject to an AMR. The drywell pipe restraints and/or whip
 
restraints and are included under component type "HELB barriers" in LRA Table 2.4-10, since
 
HELB barriers provide jet impingement protection to various in-scope components. The
 
applicant further clarified that HELB barriers include pipe whip restraints, jet impingement
 
shields or plate barriers, and crushable energy absorbers. The staff confirms that the applicant
 
has appropriately revised the component type description in LRA Tables 2.4-10 and 3.5.2-10.
 
Therefore, the staff's concern described in RAI 2.4.1-3 is resolved.
 
In RAI 2.4.1-5, the staff noted LRA Section 2.4.1, page 2.4-5 states that the suppression
 
chamber vent pipe system is evaluated as a mechanical component in LRA Section 2.3.2.5.
LRA Table 2.3.2-5 includes downcomers and piping and piping components as component
 
types subject to an AMR. It is not clear whether the vent pipe support assemblies and
 
downcomer (vent) pipe bracing system (see drawing C-1932 Sheet 4 and UFSAR Figure 6.2-
: 56) are included within the scope of license renewal and subject to an AMR. The staff requested
 
that the applicant whether these components are within the scope of license renewal and
 
subject to an AMR, and if they were not included as a result of an oversight, provide a
 
description of their scoping, screening, and AMR. If these components are excluded from the
 
scope of license renewal, provide the technical basis for the exclusion.
 
In its response to RAI 2.4.1-5, dated August 28, 2007, the applicant stated:
The suppression chamber vent pipe system supports are in the scope of
 
License Renewal for SSES and subject to aging management review.
 
These supports are included under Component Type "Component and
 
piping supports (Class 1, 2, 3 and MC)" in Table 2.4-10.
 
Based on its review, the staff finds the applicant's response to RAI 2.4.1-5 acceptable because
 
the applicant has verified that the vent pipe system supports are within the scope of license
 
renewal and subject to an AMR, and are included under the component type "Component and piping supports (Class 1, 2, 3 and MC)" in LRA Table 2.4-10. The staff determines that the vent
 
system supports are appropriately classified and described in the LRA Table 2.4-10. Therefore, the staff's concern described in RAI 2.4.1-5 is resolved.
2.4.1.3 Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and related structural components to
 
determine whether the applicant failed to identify any SSCs within the scope of license renewal.
 
The staff found a certain lack of clarity, but no gross 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 there is reasonable
 
assurance that the applicant has adequately identified the primary containment 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) and; therefore, is acceptable.
2-140  2.4.2  Reactor Building 2.4.2.1  Summary of Technical Information in the Application 
 
In LRA Section 2.4.2, the applicant described the RB, a seismic Category I structure that
 
encloses the primary containment, and provi des secondary containment when the primary containment is in service during power operation and also serves as containment during reactor refueling and maintenance operations when the primary containment is open. It houses the
 
auxiliary systems of the nuclear steam supply sy stem, new fuel storage vaults, the refueling facility, and equipment essential to the safe reactor shutdown. The RB consists of the following
 
major structural components: (a) foundation mat, (b) walls, (c) floors, (d) superstructure, and (e)
 
refueling floor.
 
The RB contains safety-related components relied upon to remain functional during and
 
following DBEs. In addition, the RB performs functions that support fire protection, ATWS, and
 
SBO.
 
LRA Table 2.4.2-1 identifies RB component types within the scope of license renewal and
 
subject to an AMR:
* blowout panels
* cranes, including bridge and trolley, rails, and girders
* exterior precast concrete panels (above grade)
* exterior walls (above grade)
* exterior walls (below grade)
* floor decking
* foundations
* fuel shipping cask storage pool gates
* fuel shipping cask storage pool liner
* masonry block walls
* metal siding
* new fuel racks
* new fuel storage vault
* new fuel storage vault watertight covers
* reactor well and steam dryer and separator storage pool gates
* reactor well and steam dryer and separator storage pool liners
* reactor well shield plugs
* reinforced concrete: walls, floors, and ceilings
* roof decking
* spent fuel pool gates
* spent fuel pool liners
* spent fuel pool racks
* spent fuel rack neutron absorbers
* structural steel: beams, columns, plates, and trusses
* sump liners
* sumps The intended functions of the RB component types within the scope of license renewal include:
 
2-141
* thermal expansion, seismic separation, or both
* rated fire barrier to confine or retard fire spread in adjacent plant areas
* flood protection barrier
* shielding against high-energy line breaks
* missile barrier
* pipe whip restraint
* safety-related equipment shelter or protection
* shielding against radiation
* pressure boundary or essentially leak-tight barrier in postulated design-basis events to protect public health and safety
* structural or functional support to safety-related components
* structural support to nonsafety-related components whose failure could prevent satisfactory accomplishment of required safety functions
* structural or functional support required for any of the 10 CFR 54.4(a)(3) regulated events 2.4.2.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.4.2 and UFSAR Section 3.8.4 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, pursuant to 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).
 
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 structures. Therefore, the staff issued RAIs concerning the specific issues, to
 
determine whether the applicant properly applied the scoping criteria pursuant to
 
10 CFR 54.4(a) and the screening criteria in accordance with 10 CFR 54.21(a)(1). The following
 
discussion describes the staff's RAIs related to LRA Section 2.4.2 and the corresponding
 
applicant responses.
 
In RAI 2.4.2-1, dated August 3, 2007, the staff noted LRA Table 2.4-2 lists "Reinforced
 
concrete: walls, floors, and ceilings," within the RB, as a component type subject to an AMR.
 
The staff requested that the applicant confirm whether the two reinforced concrete girders (see
 
last paragraph of UFSAR page 3.8-41) supporting the refueling facility within the Reactor
 
Building are within the scope of license renewal and subject to an AMR and; if so, revise the
 
LRA table, accordingly. If they are not within the scope of license renewal, provide the technical
 
basis for the exclusion. 
 
2-142 In its response to RAI 2.4.2-1, dated August 28, 2007, the applicant stated:
The two reinforced concrete girders that support the refueling facility
 
within the Reactor Building are in the scope of License Renewal for SSES
 
and subject to aging management review. They are considered floor
 
beams/walls for the refueling pools and are integral to the Reactor
 
Building concrete structure. The reinforced concrete girders are included
 
under Component Type "Reinforced concrete: walls, floors, and ceilings"
 
in Table 2.4-2.
 
Table 2.4-2 specific component type and Table 3.5.2-2 specific
 
component/commodity are revised as shown in bold italics in Attachment 5 (of the applicant's response letter dated August 28, 2007) to describe
 
the component type as: 
 
Reinforced concrete:
girders , walls, floors, and ceilings
 
Based on its review, the staff finds the applicant's response to RAI 2.4.2-1 acceptable because
 
the applicant has verified that the two reinforced concrete girders supporting the refueling floor
 
girders facility within the RB are within the scope of license renewal and subject to an AMR. The
 
applicant further verified that these components are integral to the RB concrete structure and
 
are included under component type "Reinforced concrete: walls, floors, and ceilings" in the LRA
 
Table 2.4-2. The staff confirms that the applicant has revised the component type description in
 
LRA Tables 2.4-2 and 3.5.2-2 to read as: "Reinforced concrete:
girders, walls, floors, and ceilings." Therefore, the staff's concern described in RAI 2.4.2-1 is resolved.
 
In RAI 2.4.2-2, dated August 3, 2008, the staff noted LRA Table 2.4-2 lists "Reactor well shield
 
plugs," within the RB, as a component type subject to an AMR. It was not clear to the staff
 
whether the spent fuel pool plugs and dryer/separator pool plugs (see drawing C-1932 Sheet 5)
 
are included within the scope of license renewal. The staff requested that the applicant confirm
 
that these components are within the scope of license renewal and subject to an AMR and; if
 
so, revise the LTA table, accordingly. If they are not within the scope of license renewal, provide
 
the technical basis for the exclusion.
 
In its response to RAI 2.4.2-2, dated August 28, 2007, the applicant stated:
The plugs that separate the Reactor Well and the Spent Fuel Storage
 
Pool and the plugs that separate the Reactor Well and the Steam Dryer
 
and Separator Storage Pool are in the scope of License Renewal for
 
SSES and subject to aging management review. These plugs are
 
included under Component Types "Spent fuel pool gates" and "Reactor
 
well and steam dryer and separator storage pool gates" in Table 2.4-2.
 
These slot plugs are concrete enclosed in welded stainless steel.
 
Table 2.4-2 specific component type and Table 3.5.2-2 specific
 
component/commodity are revised as shown in bold italics in Attachment 6 (of the applicant's response letter dated August 28, 2007) to describe
 
the component types as:
 
Reactor well and steam dryer and separator storage pool gates (includes 2-143 steam dryer / separator pool plugs
" and "Spent fuel pool gates (includes spent fuel pool plugs)
Based on its review, the staff finds applicant's response to RAI 2.4.2-2 acceptable because the
 
applicant has verified that the plugs that separate the reactor well and the spent fuel storage
 
pool and the plugs that separate the reactor well and the steam dryer and separator storage
 
pool are within the scope of license renewal and subject to an AMR. The applicant further
 
verified that these plugs are included under component types "Spent fuel pool gates" and
 
"Reactor well and steam dryer and separator storage pool gates" in the LRA Table 2.4-2. The
 
staff confirms that the applicant has appropriately revised the component type descriptions in
 
LRA Table 2.4-2 to include these plugs. Therefore, the staff's concern described in RAI 2.4.2-2
 
is resolved.
 
In RAI 2.4.2-3, dated August 3, 2008, the staff noted LRA Tables 2.4-2, 2.4-4, 2.4-6, 2.4-7, and
 
2.4-8, list "Cranes, including bridge and trolley, rails, and girders," within the respective
 
structures, as a component type subject to an AMR. It is not clear to the staff which cranes have
 
been included within the scope of license renewal and whether all relevant subcomponents
 
("...including bridge and trolley, rails, and girders") have been screened as items subject to an
 
AMR. The staff requested that the applicant (a) identify the specific cranes in each of these
 
structures that are included within the above component type as within the scope of license
 
renewal and subject to an AMR and those that are excluded and; if excluded, provide the
 
technical basis for the exclusion; (b) confirm whether fasteners and rail hardware associated
 
with this component type are within the scope of license renewal and subject to an AMR and; if
 
not, provide the technical basis for the exclusi on and; (c) verify whether there are any other hoists and lifting devices (e.g. reactor coolant pump lifting slings, lifting rigs, etc.) that should be included within the scope of license renewal and subject to an AMR and; if so, include these
 
components in the LRA tables and provide the associated scoping, screening and an AMR
 
results. 
 
In its response to RAI 2.4.2-3, dated August 28, 2007, the applicant stated:
For SSES all material handling equipment specified in the response to
 
NUREG-0612, Control of Heavy Loads, is in the scope of License
 
Renewal for SSES and subject to an AMR. (Refer to SSES Unit 1 Control
 
of Heavy Loads - Phase 1 - Safety Evaluation Report from NRC to PPL (August 2, 1983) and SSES Unit 2 Control of Heavy Loads - Phase 1 -
 
Safety Evaluation Report from NRC to PPL (November 22, 1983). In
 
addition, other monorails, hoists and miscellaneous cranes within License
 
Renewal in-scope structures are also in the scope of License Renewal for
 
SSES and subject to an AMR. Relevant subcomponents ("...including
 
bridge and trolley, rails, and girders") are in the scope of License
 
Renewal for SSES and subject to an AMR. These subcomponents are
 
included under Component Type "Cranes, including bridge and trolley, rails, and girders" in Tables 2.4-2, 2.4-4, 2.4-6, 2.4-7, and 2.4-8. 
 
Fasteners and rail hardware associated are in the scope of License
 
Renewal for SSES and subject to an AMR. These fasteners and rail
 
hardware included under Component Type "Anchorage / Embedments
 
and Anchor Bolts" in Table 2.4-10.
 
2-144 Lifting devices (e.g. lifting slings, lifting rigs, etc.) are tools/rigging that are not within License Renewal scope at SSES.
 
All the cranes, monorails, hoists and miscellaneous cranes within the in-
 
scope License Renewal SSES structures are in the scope of License
 
Renewal for SSES and subject to an AMR.
 
The following is a list of License Renewal in-scope Cranes, Monorails, Hoists and Miscellaneous Cranes for SSES.
SSES Cranes and Monorails, Hoists (NUREG-0612)
Building Description Reactor Reactor Building Crane Reactor Refueling Platform Diesel GeneratorA to E Diesel Generator Bridge Cranes Monorails, Hoists and Miscellaneous Cranes Reactor Recirculation Pump Hoist Reactor RHR Heat Exchanger Hoists Reactor HPCI Hoist Reactor Core Spray Pump & Cooling Water Heat Exchanger HoistsReactor Equipment Shaft Crane Reactor Reactor Building Concrete Shielding Block Hoists Reactor Drywell Equipment Hatch Hoist Primary Containment Drywell Main Steam Relief Valve Hoist Primary Containment Main Steam Isolation Valve Hoist SSES Monorails, Hoists and Miscellaneous Cranes (Not within NUREG-0612)
Building Description Circulating Water Pumphouse Circulating Water Pump Bridge Crane Turbine 220 Ton Overhead Cranes Various in-scope structuresMiscellaneous monorails/hoists within in-scope structures
 
Based on its review, the staff finds the applicant's response to RAI 2.4.2-3 acceptable because
 
the applicant has verified that all material handling equipment specified in the response to
 
NUREG-0612, "Control of Heavy Loads," is within the scope of license renewal and subject to
 
an AMR. In addition, other monorails, hoists and miscellaneous cranes within in-scope
 
structures are also within the scope of license renewal and subject to an AMR. The applicant
 
also verified that:
* Relevant subcomponents ("...including bridge and trolley, rails, and girders") are within the scope of license renewal and subject to an AMR, and are included under component 2-145 type "Cranes, including bridge and trolley, rails, and girders" in LRA Tables 2.4-2, 2.4-4, 2.4-6, 2.4-7, and 2.4-8.
* All the cranes, monorails, hoists and miscellaneous cranes within the in-scope structures are within the scope of license renewal and subject to an AMR and are tabulated in a
 
comprehensive list of in-scope cranes, monorails, hoists and miscellaneous cranes for
 
SSES.
* Fasteners and rail hardware associated are within the scope of license renewal and subject to an AMR, and are included under component type "Anchorage / Embedments and Anchor Bolts" in LRA Table 2.4-10.
* Lifting devices (e.g. lifting slings, lifting rigs, etc.) are tools/rigging and not within the scope of license renewal.
The staff confirms that lifting devices such as slings and rigs are not within the scope of license renewal, since they are tools/rigging and do not serve an intended function pursuant to
 
10 CFR 54.4(a), are not passive nor long-lived, and are routinely inspected and replaced as
 
needed. The staff finds that the applicant has appropriately applied the scoping criteria pursuant
 
to 10 CFR 54.4(a) and screening criteria in accordance with 10 CFR 54.21(a)(1) and has
 
identified all the cranes and associated subcomponents that are within the scope of license
 
renewal and subject to an AMR. Therefore, the staffs concerns described in RAI 2.4.2-3 are
 
resolved. 
 
2.4.2.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and related structural components to
 
determine whether the applicant failed to identify any SSCs within the scope of license renewal.
 
The staff found a certain lack of clarity, but no gross 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 there is reasonable
 
assurance that the applicant has adequately identified the RB 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) and; therefore, is acceptable. The staff notes that RAI 2.4.2-3, the
 
applicant's response, and the staff's evaluation of the response also apply to the staff's
 
evaluation of LRA sections 2.4.2, 2.4.4, 2.4.6, 2.4.7, and 2.4.8.
 
2.4.3  Engineered Safeguards Service Water Pumphouse and Spray Pond 2.4.3.1  Summary of Technical Information in the Application 
 
In LRA Section 2.4.3, the applicant described the ES SW pumphouse and spray pond, both
 
seismic Category I structures. The ES SW pumphouse contains the ESW and RHRSW pumps
 
and the weir and discharge conduit for the spray pond. It is a two-story reinforced concrete
 
structure on a mat foundation. The first level of the structure is below grade with the following
 
major compartments: (a) pump intake chamber s, (b) overflow weir, and (c) discharge header compartments. Pumps, valving, and electrical switchgear are in the second level of the structure
 
at grade. HVAC equipment is located on a steel-framed mezzanine level. A mezzanine floor
 
supports the heating and ventilating equipment. The ES SW pumphouse consists of the
 
following major structural components: (a) foundation mat, (b) floors, (c) roof, (d) walls, and (e)
 
chambers.
 
2-146 The spray pond (ultimate heat sink) provides cooling water to support operation of the ESW and RHRSW systems during system testing, nor mal shutdown, and accident conditions. The ultimate heat sink can provide sufficient cooling water without makeup to the spray pond for at
 
least 30 days, to permit simultaneous safe-shutdown and cool-down of both reactor units and
 
can maintain them in a safe-shutdown condition. The spray pond can provide enough cooling
 
water without makeup for a design-basis LOCA in one unit with the simultaneous shutdown of
 
the other for 30 days, assuming a concurrent safe-shutdown earthquake, single failure, and loss
 
of offsite power. The spray pond consists of the following major structural components: (a) spray
 
pond liner, (b) spillway, (c) spray system, and (d) earthen embankment. The ES SW
 
pumphouse and spray pond contain safety-related components relied upon to remain functional
 
during and following DBEs. In addition, the ES SW pumphouse and spray pond perform
 
functions that support fire protection, ATWS, and SBO.
 
LRA Table 2.4.3-1 identifies ES SW pumphouse and spray pond component types within the
 
scope of license renewal and subject to an AMR:
* bulkhead closure plates
* bulkhead fixed screens
* bulkhead screen guides
* earthen embankment
* exterior walls (above grade)
* exterior walls (below grade)
* foundations
* overflow weir and chamber
* pump intake chambers
* reinforced concrete: walls, floors, and ceilings
* roof and floor decking
* roof slabs
* spray pond emergency spillway
* spray pond liner
* spray pond riser concrete encasements
* structural steel: beams, columns, plates, and trusses
* trash racks
* sumps The intended functions of the ES SW pumphouse and spray pond component types within the
 
scope of license renewal include:
* rated fire barrier to confine or retard fire spread in adjacent plant areas
* flood protection barrier
* SBO or DBA heat sink
* missile barrier
* safety-related equipment shelter or protection
* plant shutdown cooling water source
* structural or functional support to safety-related components
 
2-147
* structural support to nonsafety-related components whose failure could prevent satisfactory accomplishment of required safety functions
* structural or functional support required for any of the 10 CFR 54.4(a)(3) regulated events  2.4.3.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.4.3 and UFSAR Sections 3.8.4 and 9.2.7 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, pursuant to 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, UFSAR, and related structural components to determine whether
 
the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no
 
such omissions. In addition, the 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 there is reasonable assurance that the applicant has adequately identified
 
the ES SW pumphouse and spray pond 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) and;
 
therefore, is acceptable.
 
2.4.4  Circulating Water Pumphouse and Water Treatment Building 2.4.4.1  Summary of Technical Information in the Application 
 
In LRA Section 2.4.4, the applicant described the CWPH and water treatment building, which is
 
not a seismic Category I structure. The water treatment building is attached to the CWPH, which
 
contains electric and diesel-driven fire-water pumps separated by a structural fire barrier. The
 
water treatment building contains no equipment within the scope of license renewal but shares
 
with the CWPH a common wall, foundation, and roof, the structural components of which are
 
within the scope of license renewal, but not the remainder of the water treatment building. The
 
CWPH and water treatment building consist of the following major structural components: (a)
 
foundation mat, (b) floors, (c) walls, and (d) roof. 
 
The CWPH and water treatment building perform functions that support fire protection.
 
LRA Table 2.4.4-1 identifies CWPH and water treatment building component types within the
 
scope of license renewal and subject to an AMR:
* battery racks
* cranes, including bridge and trolley, rails, and girders
* exterior precast concrete panels (above grade)
* exterior walls (above grade) 2-148
* exterior walls (below grade)
* floor decking
* foundations
* masonry block walls
* metal siding
* reinforced concrete: walls, floors, and ceilings
* roof decking
* structural steel: beams, columns, plates, and trusses
* sumps The intended functions of the CWPH and water treatment building component types within the
 
scope of license renewal include:
* rated fire barrier to confine or retard fire spread in adjacent plant areas
* flood protection barrier
* safety-related equipment shelter or protection
* structural or functional support required for any of the 10 CFR 54.4(a)(3) regulated events 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, 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, pursuant to 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).
 
The staff notes that RAI 2.4.2-3, the applicant's response and staff evaluation in LRA
 
Section 2.4.2 (regarding the "cranes" component type) also applies to this LRA Section 2.4.4.
 
2.4.4.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and related structural components to
 
determine whether the applicant failed to identify any SSCs within the scope of license renewal.
 
The staff found a certain lack of clarity but no gross 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 there is reasonable
 
assurance that the applicant has adequately identified the CWPH and water treatment 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) and; therefore, is acceptable.
2-149  2.4.5  Control Structure 2.4.5.1  Summary of Technical Information in the Application 
 
In LRA Section 2.4.5, described the control structure, a seismic Category I structure that houses
 
the control room, the cable spreading rooms, computer and relay room, the battery room, heating and ventilation equipment room, off-gas treat ment room, and the control room visitors' gallery. The control structure consists of the following major structural components: (a)
 
foundation mat, (b) walls, (c) floors and roof, and (d) power generation control complex.
 
The control structure contains safety-related components relied upon to remain functional
 
during and following DBEs. In addition, the control structure performs functions that support fire
 
protection, ATWS, and SBO.
 
LRA Table 2.4.5-1 identifies control structure component types within the scope of license
 
renewal and subject to an AMR:
* battery racks
* control room ceiling
* exterior walls (above grade)
* exterior walls (below grade)
* floor decking
* foundations
* masonry block walls
* power generation control complex flooring
* reinforced concrete: walls, floors, and ceilings
* roof slabs
* structural steel: beams, columns, plates, and trusses The intended functions of the control structure component types within the scope of license
 
renewal include:
* thermal expansion, seismic separation, or both
* rated fire barrier to confine or retard fire spread in adjacent plant areas
* flood protection barrier
* filtered and unfiltered gaseous discharge release path
* missile barrier
* safety-related equipment shelter or protection
* shielding against radiation
* pressure boundary or essentially leak-tight barrier in postulated design-basis events to protect public health and safety
* structural or functional support to safety-related components
* structural support to nonsafety-related components whose failure could prevent satisfactory accomplishment of required safety functions
 
2-150
* structural or functional support required for any of the 10 CFR 54.4(a)(3) regulated events  2.4.5.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.4.5 and UFSAR Section 3.8.4 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, pursuant to 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, UFSAR, and related structural components to determine whether
 
the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no
 
such omissions. In addition, the 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 there is reasonable assurance that the applicant has adequately identified
 
the control structure 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) and; therefore, is acceptable.
 
2.4.6  Diesel Generator A, B, C, and D Building 2.4.6.1  Summary of Technical Information in the Application 
 
In LRA Section 2.4.6, the applicant described the DG A, B, C, and D building, a seismic
 
Category I structure housing DGs A, B, C, and D, which are essential for safe shutdown of the
 
plant. The DGs are separated from each other by concrete walls. A concrete overhang on the
 
east side of the building serves as an air intake plenum. A concrete plenum for diesel exhaust is
 
on the roof. The DG A, B, C and D building consists of the following major structural
 
components: (a) foundation mat, (b) walls, and (c) floors and roof. 
 
The DG A, B, C, and D building contains safety-related components relied upon to remain
 
functional during and following DBEs. In addition, the building performs functions that support
 
fire protection and SBO.
 
LRA Table 2.4.6-1 identifies DG A, B, C, and D building component types within the scope of
 
license renewal and subject to an AMR:
* cranes, including bridge and trolley, rails, and girders
* diesel generator exhaust plenums
* diesel generator intake plenums
* exterior precast concrete panels (above grade)
* exterior walls (above grade)
* exterior walls (below grade)
* floor decking 2-151
* foundations
* masonry block walls
* metal siding
* reinforced concrete: walls, floors, and ceilings
* roof slabs
* structural steel: beams, columns, plates, and trusses
* sumps The intended functions of the DG A, B, C, and D building component types within the scope of
 
license renewal include:
* thermal expansion, seismic separation, or both
* rated fire barrier to confine or retard fire spread in adjacent plant areas
* flood protection barrier
* missile barrier
* safety-related equipment shelter or protection
* structural or functional support to safety-related components
* structural support to nonsafety-related components whose failure could prevent satisfactory accomplishment of required safety functions
* structural or functional support required for any of the 10 CFR 54.4(a)(3) regulated events  2.4.6.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.4.6 and UFSAR Section 3.8.4 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, pursuant to 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).
 
During its review of the LRA Sections 2.4.6 and 2.4.7, the staff identified areas in which
 
additional information was necessary to complete the evaluation of the applicant's scoping and
 
screening results for structures. Therefore, the staff issued concerning the specific issues, to
 
determine whether the applicant properly applied the scoping criteria pursuant to
 
10 CFR 54.4(a) and the screening criteria in accordance with 10 CFR 54.21(a)(1). The following
 
discussion describes the staff's RAIs related to the LRA Sections 2.4.6 and 2.4.7 and the
 
corresponding applicant responses.
 
The staff notes that RAI 2.4.2-3, the applicant's response and staff evaluation in LRA
 
Section 2.4.2 (regarding the "cranes" component type) also applies to this LRA Section 2.4.6.
 
In RAI 2.4.6-1, dated August 3, 2007, the staff noted LRA Tables 2.4-6 and 2.4-7 list the
 
components of the DG A, B, C, D, and E buildings that are subject to an AMR. The staff 2-152 requested that the applicant confirm that the DG pedestals are components requiring an AMR and are included in the referenced LRA tables and; if not, provide the technical basis for the
 
exclusion.
 
In its response to RAI 2.4.6-1, dated August 28, 2007, the applicant stated:
Diesel Generator Pedestals are an integral part of the Diesel Generator
 
building concrete structure and are in the scope of License Renewal for
 
SSES and subject to aging management review. The Diesel Generator
 
Pedestals are included under Component Type "Reinforced concrete:
 
walls, floors, and ceilings" in Table 2.4-6 and Table 2.4-7.
 
Based on its review, the staff finds the applicant's response to RAI 2.4.6-1 acceptable because
 
the applicant has verified that the DG pedestals are an integral part of the DG building concrete
 
structure, within the scope of license renewal, subject to an AMR, and included under
 
component type "Reinforced concrete: walls, floors, and ceilings" in LRA Tables 2.4-6 and 2.4-
: 7. Since the pedestals are an integral part of the DG building concrete floor, staff finds that the
 
applicant has appropriately included the DG pedes tals under the component type "Reinforced concrete: walls, floors, and ceilings." Therefore, the staff's concern described in RAI 2.4.6-1 is
 
resolved. The staff notes that RAI 2.4.6-1, the applicant's response, and the above staff
 
evaluation also applies to the LRA Section 2.4.7.
2.4.6.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and related structural components to
 
determine whether the applicant failed to identify any SSCs within the scope of license renewal.
 
The staff found a certain lack of clarity but no gross 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 there is reasonable
 
assurance that the applicant has adequately identified the DG A, B, C, and D 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) and; therefore, is acceptable.
 
2.4.7  Diesel Generator E Building 2.4.7.1  Summary of Technical Information in the Application 
 
In LRA Section 2.4.7, the applicant described the DG E building, a seismic Category I structure
 
that houses DG E, which replaces one of the A, B, C, and D DGs. Openings for air intake and
 
diesel exhaust are flush with the north and south exterior walls, respectively. Interior plenums
 
are for missile protection. The DG E building consists of the following major structural
 
components: (a) foundation mat, (b) walls, and (c) floors and roof.
 
The DG E building contains safety-related components relied upon to remain functional during
 
and following DBEs. In addition, the DG E building performs functions that support fire
 
protection and SBO.
 
LRA Table 2.4.7-1 identifies DG E building component types within the scope of license renewal
 
and subject to an AMR: 
 
2-153
* battery racks
* cranes, including bridge and trolley, rails, and girders
* diesel generator exhaust plenums
* diesel generator intake plenums
* exterior walls (above grade)
* exterior walls (below grade)
* foundations
* metal siding
* reinforced concrete: walls, floors, and ceilings
* roof slabs
* sumps
 
The intended functions of the DG E building component types within the scope of license renewal include:
* rated fire barrier to confine or retard fire spread in adjacent plant areas
* flood protection barrier
* missile barrier
* safety-related equipment shelter or protection
* structural or functional support to safety-related components
* structural support to nonsafety-related components whose failure could prevent satisfactory accomplishment of required safety functions
* structural or functional support required for any of the 10 CFR 54.4(a)(3) regulated events  2.4.7.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.4.7 and UFSAR Section 3.8.4 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, pursuant to 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).
 
The staff notes that RAI 2.4.2-3, applicant's response, and the staff evaluation in LRA
 
Section 2.4.2 (regarding the "cranes" component type) also applies to LRA Section 2.4.7.
 
The staff also notes that RAI 2.4.6-1 (regarding DG pedestals), the applicant's response, and
 
the staff evaluation of the same in LRA Section 2.4.6 applies to LRA Section 2.4.7. 
 
2.4.7.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and related structural components to
 
determine whether the applicant failed to identify any SSCs within the scope of license renewal.
2-154 The staff found a certain lack of clarity but no gross 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 there is reasonable
 
assurance that the applicant has adequately identified the DG E 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) and; therefore, is acceptable.
 
2.4.8  Turbine Building 2.4.8.1  Summary of Technical Information in the Application 
 
In LRA Section 2.4.8, the applicant described the TB, not a seismic Category I structure, which
 
is divided into two units with an expansion joint separating them. It houses two in-line turbine
 
generator units and the following auxiliary equipment: condensers, condensate pumps, moisture
 
separators, air ejectors, feedwater heaters, reactor feed pumps, motor generator sets for reactor
 
recirculation pumps, recombiners, interconnecting piping and valves, and switchgears. (Note:
 
The basement elevation (656 feet) of the TB is an area accessed through the TB; with walls, floor, and foundation belonging to the control structure, but not part of the control structure
 
pressurization envelope.) The TB consists of the following major structural components: (a)
 
foundation mat, (b) walls, (c) floors and roof, (d) MS tunnel, and (e) turbine generator pedestals 
 
The failure of nonsafety-related SSCs in the TB potentially could prevent the satisfactory
 
accomplishment of a safety-related function. The TB also performs functions that support fire
 
protection and SBO.
 
LRA Table 2.4.8-1 identifies TB component types within the scope of license renewal and
 
subject to an AMR:
* blowout panels
* cranes, including bridge and trolley, rails, and girders
* exterior precast concrete panels (above grade)
* exterior walls (above grade)
* exterior walls (below grade)
* floor decking
* foundations
* main steam tunnels
* masonry block walls
* metal siding
* reinforced concrete: walls, floors, and ceilings
* roof decking
* shield plugs
* structural steel: beams, columns, plates, and trusses
* sump liners
* sumps
* turbine generator pedestals
* turbine generator pedestal structural bearing pads The intended functions of the TB component types within the scope of license renewal include:
* thermal expansion, seismic separation, or both 2-155
* rated fire barrier to confine or retard fire spread in adjacent plant areas
* flood protection barrier
* missile barrier
* safety-related equipment shelter or protection
* shielding against radiation
* pressure boundary or essentially leak-tight barrier in postulated design-basis events to protect public health and safety
* structural or functional support to safety-related components
* structural support to nonsafety-related components whose failure could prevent satisfactory accomplishment of required safety functions
* structural or functional support required for any of the 10 CFR 54.4(a)(3) regulated events  2.4.8.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.4.8 and UFSAR Section 3.8.4 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, pursuant to 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).
 
During its review of the LRA Sections 2.4.8, the staff identified areas in which additional
 
information was necessary to complete the evaluation of the applicant's scoping and screening
 
results for structures. Therefore, the staff issued RAIs concerning the specific issues, to
 
determine whether the applicant properly applied the scoping criteria pursuant to
 
10 CFR 54.4(a) and the screening criteria in accordance with 10 CFR 54.21(a)(1). The following
 
discussion describes the staff's RAIs related to the LRA Section 2.4.8 and the corresponding
 
applicant responses.
 
The staff notes that RAI 2.4.2-3, applicant response, and the staff evaluation in LRA
 
Section 2.4.2 (regarding the "cranes" component type) also applies to LRA Section 2.4.6.
In RAI 2.4.8-1, dated August 3, 2007, the staff noted LRA Table 2.4-8 lists the components of the TB that are subject to an AMR. the staff requested that the applicant confirm whether the
 
pipe tunnels at the foundation level for the off-gas piping (see third paragraph under the title
 
"Turbine Building" on page 3.8-44 of the UFSAR and drawing A-11 Sheet 1) are within the
 
scope of license renewal, subject to an AMR, and included in the referenced LRA table, and; if
 
not, provide the technical basis for the exclusion.
 
In its response to RAI 2.4.8-1, dated August 28, 2007, the applicant stated:
The pipe tunnels at the foundation level for the off-gas piping are an
 
integral part of the Turbine building concrete structure and in the scope of 2-156 License Renewal for SSES and subject to aging management review.
The pipe tunnels are included under Component Type "Reinforced
 
concrete: walls, floors, and ceilings" in Table 2.4-8.
 
Based on its review, the staff finds the applicant's response to RAI 2.4.8-1 acceptable because
 
the applicant has verified that the pipe tunnels at the foundation level for the off-gas piping are
 
an integral part of the TB concrete structure, within the scope of license renewal, and subject to
 
an AMR. The staff confirms that the applicant has included these pipe tunnels under component
 
type "Reinforced concrete: walls, floors, and ceilings" in LRA Table 2.4-8. Therefore, the staff's
 
concern described in RAI 2.4.8-1 is resolved.
2.4.8.3  Conclusion 
 
The staff reviewed the LRA, UFSAR, RAI responses, and related structural components to
 
determine whether the applicant failed to identify any SSCs within the scope of license renewal.
 
The staff found a certain lack of clarity but no gross 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 there is reasonable
 
assurance that the applicant has adequately identified the TB 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) and; therefore, is acceptable.
 
2.4.9  Yard Structures 2.4.9.1  Summary of Technical Information in the Application LRA Section 2.4.9.1 describes the yard structures, which include:
* clarified water storage tank foundation
* condensate storage tank foundation and retention basin
* DG fuel oil storage tank A, B, C, D, and E foundations and vaults
* refueling water storage tank foundation
* SBO component foundations and structures in the yard (startup transformers T-10 and T-20 and associated disconnect switches, engi neered safeguards systems transformers, and transmission towers)
* cooling tower basins
* duct banks, manholes, valve vaults, instrument pits, and piping trenches in the yard The clarified water storage tank foundation is not a seismic Category I structure. The
 
500,000-gallon clarified water storage tank in the yard is the primary water source for fire
 
protection with a standpipe in the tank which reserves 300,000 gallons of the stored water for
 
fire protection. The tank is also a source of domestic water to the plant site. The clarified water
 
storage tank foundation is a reinforced concrete slab that supports the tank bottom resting on
 
an oiled sand pad.
 
The condensate storage tank foundation and retention basin are not seismic Category I
 
structures. The condensate storage tanks are the preferred water sources for the HPCI and 2-157 RCIC pumps for both operating and testing and they supply water to the core spray pumps for testing. Each condensate storage tank maintains a minimum storage of 135,000 gallons to
 
serve HPCI and RCIC pumps during plant operation by standpipes and locked closed valves on
 
all other lines. The condensate storage tank foundation supporting the tank is a reinforced
 
concrete slab approximately 3 feet thick. Waterstops are in construction joints abutting the
 
retention basin slab. The condensate storage tank bottom rests on an oiled sand pad.
 
The DG fuel oil storage tank A, B, C, D, and E foundations and vaults are seismic Category I
 
structures. There are four 50,000-gallon nominal capacity fuel oil storage tanks for DGs A, B, C
 
and D and one 80,000-gallon nominal capacity fuel oil storage tank for DG E. The DG A, B, C, and D tanks are underground adjacent to the DG building. The DG E tank is underground
 
adjacent to the DG E building. Diesel generator fuel oil storage tanks A, B, C and D share a
 
common reinforced concrete slab foundation. Diesel generator fuel oil storage tank E has its
 
own reinforced concrete slab foundation. The concrete tank foundation slab for DG fuel oil
 
storage tanks A, B, C and D is approximately 2 feet 6 inches thick. The concrete tank
 
foundation slab for DG fuel oil storage tank E is approximately 5 feet thick. Each tank has a
 
concrete vault from grade to tank connection for access, maintenance, inspection, repair, and
 
missile protection of the connection. The vault cover at grade level is steel plate.
 
The refueling water storage tank foundation is a not a seismic Category I structure. One
 
680,000-gallon refueling water storage tank common to both units stores the water that fills the
 
reactor well and dryer separator pool of either Unit 1 or 2. The refueling water storage tank
 
foundation supporting the tank is a reinforced concrete slab approximately 3 feet thick.
 
Waterstops are in construction joints abutting the retention basin slab. The refueling water
 
storage tank bottom rests on an oiled sand pad.
 
The SBO component foundations and structures in the yard (startup transformers T-10 and
 
T-20, disconnect switches, engineered safeguards systems transformers, and transmission towers) are not seismic Category I structures. Startup transformers T-10 and T-20, associated
 
disconnect switches (motor-operated Air Break Switches 1R105 and 2R105) and transmission
 
towers provide an offsite alternating current s ource for recovery from an SBO regulated event.
The startup transformers and disconnect switches, as well as the engineered safeguards
 
systems transformers, are supported by reinfo rced concrete pads. The disconnect switches are supported by steel frame structures and the transmission conductors are supported by tapered
 
steel transmission towers and related foundations.
 
The cooling tower basins are not seismic Category I structures. The basins are designed to be
 
completely watertight with a capacity of six million gallons of water. Secondary sources of water
 
for the plant's two main automatic fire pumps, the two cooling tower basins have a minimum
 
depth of 7 feet 6 inches and the top of each is approximately 2 feet above the finished grade.
 
The cooling tower basins are constructed of reinforced concrete. Their foundations are situated
 
on bedrock.
 
Duct banks, manholes, valve vaults (including t he spray pond valve vault), instrument pits, and piping trenches are routed in the yard for physical support and shelter for in-scope mechanical
 
components (e.g., piping and valves) and in-scope electrical components (e.g., electric cables and conduits). The duct banks, manholes, valve vaults, instrument pits, and piping trenches are
 
seismic Category I when they support or contain safety-related equipment, but not equipment
 
required for regulated events.
 
2-158 The T-10 230kV switchyard and the SSES 230kV switchyard SBO component foundations and structures are located outside the security fence. The dead end structure and breakers (2S and
 
2T) support supplying power from the T-10 230kV switchyard to the 13.8kV bus 10 providing
 
offsite AC sources for recovery from an SBO. The dead end structure and breakers (2T and
 
2W) support supplying power from the 230kV switchyard to the 13.8kV bus 20 providing offsite
 
AC sources for recovery from an SBO. The dead end structures and breakers (2S & 2T and 2T
 
& 2 W) are supported by reinforced concrete foundations. The control cubicles support/protect
 
the circuitry and controls.
 
The 500kV switchyard SBO component foundations and structures are located outside the
 
security fence.
The 230kV dead end structure, the 230kV capacitive-coupled voltage transformer and line trap, the 230kV switch, the 230kV current transformer, and the 230kV
 
breaker and control cubicle support supplying power from the 500kV switchyard to the 13.8kV
 
bus 20 providing offsite AC sources for recovery from an SBO. The 230kV dead end structure, 230kV capacitive-coupled voltage transformer and line trap, 230kV switch, 230kV current
 
transformer, and 230kV breaker are supported by reinforced concrete foundations and/or steel
 
piles.
The yard structures contain safety-related components relied upon to remain functional during
 
and following DBEs. The failure of nonsafety-related SSCs in the SSCs in the yard structure
 
potentially could prevent the satisfactory acco mplishment of a safety-related function. In addition, the yard structures perform functions that support fire protection, ATWS, and SBO.
 
The yard structures also include structural components located outside the security fence that
 
are associated with SBO offsite power recovery pursuant to the guidance in the SRP-LR.
 
LRA Table 2.4.9 identifies yard structures component types within the scope of license renewal
 
and subject to an AMR:
* Battery racks (SBO)
* condensate storage tank retention basins
* cooling tower basic outlet screen guides
* cooling tower basin outlet screens
* cooling tower basin outlet structures
* cooling tower basins
* diesel generator fuel oil tank foundations
* diesel generator fuel oil tank vaults
* disconnect switch/capacitive-coupled voltage transformer and line trap/switch/current transformer/breaker support structures (SBO)
* duct banks
* manhole covers
* manholes
* masonry block walls (SBO)
* metal siding (SBO) 2-159
* outdoor tank foundations: condensate storage tank, clarified water storage tank, refueling water storage tank
* piles (500 kV switchyard) (SBO)
* piping trenches
* raised flooring (includes support system (SBO)
* roof decking
* reinforced concrete (floors) (SBO)
* structural steel: beams, columns, plates, and trusses (includes welds and bolt connections) (SBO)
* transformer/disconnect switch/capacitive-coupled voltage transformer and line trap/switch/current transformer/breaker/control cubicle foundations (SBO)
* transmission towers and dead end structures (SBO)
* trenches (SBO cables)
* valve vault and instrument pit hatches
* valve vaults and instrument pits The intended functions of the yard structures component types within the scope of license
 
renewal include:
* flood protection barrier
* missile barrier
* safety-related equipment shelter or protection
* structural or functional support to safety-related components
* structural support to nonsafety-related components whose failure could prevent satisfactory accomplishment of required safety functions
* structural or functional support required for any of the 10 CFR 54.4(a)(3) regulated events  2.4.9.2  Staff Evaluation 
 
The staff reviewed LRA Section 2.4.9, revised LRA Section 2.4.9 from SBO Scope Addition
 
PLA-6362 dated May 7, 2008, revised LRA Section 2.4.9 from SBO Scope Addition PLA-6413
 
dated August 29, 2008, and UFSAR Sections 9.2.8.2, 9.2.10, and 9.5.4, 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, pursuant to 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).
 
2-160 2.4.9.3  Conclusion 
 
The staff reviewed the LRA, LRA SBO Scope Addition PLA-6362, LRA SBO Scope Addition
 
PLA-6413, UFSAR, and related structural components to determine whether the applicant failed
 
to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In
 
addition, the 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
 
there is reasonable assurance that the applicant has adequately identified the yard 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) and; therefore, is acceptable.
 
2.4.10  Bulk Commodities 2.4.10.1  Summary of Technical Information in the Application In LRA Section 2.4.10, the applicant described the bulk commodities, structural component
 
groups that support in-scope structures and mechanical/electrical systems (e.g., anchorages, embedments, instrument panels, racks, cable trays, conduits, fire seals, fire doors, hatches, monorails, equipment and component supports) for multiple SSCs, and share material and
 
environment properties which allow a common program or inspection to manage their aging effects.
 
The bulk commodities contain safety-related components relied upon to remain functional
 
during and following DBEs. The failure of nonsafety-related SSCs in the SSCs in the bulk
 
commodities potentially could prevent the sati sfactory accomplishment of a safety-related function. In addition, bulk commodities perform functions that support fire protection, ATWS, and SBO.
 
LRA Table 2.4.10-1 identifies bulk commodities component types within the scope of license
 
renewal and subject to an AMR:
* concrete components
* elastomeric components
* fire barrier commodities
* insulating materials
* steel and other metals
* threaded fasteners The intended functions of the bulk commodities component types within the scope of license
 
renewal include:
* thermal expansion, seismic separation, or both
* rated fire barrier to confine or retard fire spread in adjacent plant are flood protection barrier
* shielding against high-energy line breaks
* heat transfer reduction
* moisture absorption prevention and thermal insulation physical support
 
2-161
* missile barrier
* safety-related equipment shelter or protection
* shielding against radiation
* pressure boundary or essentially leak-tight barrier in postulated design-basis events to protect public health and safety
* structural or functional support to safety-related components
* structural support to nonsafety-related components whose failure could prevent satisfactory accomplishment of required safety functions
* structural or functional support required for any of the 10 CFR 54.4(a)(3) regulated events  2.4.10.2  Staff Evaluation The staff reviewed LRA Section 2.4.10 and the UFSAR 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, pursuant to 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).
 
During its review of LRA Sections 2.4.10, the staff identified areas in which additional
 
information was necessary to complete the evaluation of the applicant's scoping and screening
 
results for structures. Therefore, the staff issued RAIs concerning the specific issues, to
 
determine whether the applicant properly applied the scoping criteria, pursuant to
 
10 CFR 54.4(a) and the screening, in accordance with 10 CFR 54.21(a)(1). The following
 
discussion describes the staff's RAIs related to LRA Section 2.4.10 and the corresponding
 
applicant responses.
 
In RAI 2.4.10-1, dated August 3, 2007, the staff noted Sections 2.4.1 thru 2.4.9 state that the structural commodities for these respective structures are addressed in the bulk commodities
 
evaluation in LRA Section 2.4.10. LRA Table 2.4-10 lists the bulk commodities components
 
subject to an AMR in categories based on the material of the component type. This LRA table
 
does not identify the specific structures addressed in LRA Sections 2.4.1 thru 2.4.9 in which
 
these individual component types are located. The staff requested that the applicant add a
 
column to LRA Table 2.4-10 listing the structure(s) in which each bulk commodity component
 
type is located, and clearly state whether the intent of the LRA table is identify every occurrence (all inclusive) for which these component types, in each of the applicable structures, are within
 
the scope of license renewal and subject to an AMR. In addition, the staff requested that the
 
applicant specifically identify those component types which are within the scope of license
 
renewal and subject to an AMR and those that are not and; if excluded, provide technical
 
justification for the exclusion. Also, the staff requested that the applicant confirm and address
 
whether or not there are any Lubrite sliding support bearings and/or surfaces within the scope of
 
license renewal and subject to an AMR, and whether these components will be included in LRA 2-162 Table 2.4-10.
 
In its response to RAI 2.4.10-1, dated August 28, 2007, the applicant stated:
As stated in Section 2.4.10, the Bulk Commodities common to SSES in-
 
scope License Renewal structures are listed in Table 2.4-10. They are
 
common to multiple SSCs and share material and environment properties
 
which allow a common program or inspection to manage their aging
 
effects. Commodities unique to a specific structure are included in the
 
review of that structure (Sections 2.4.1 through 2.4.9). All commodities
 
within the SSES in-scope License renewal structures are in-scope and
 
are subject to aging management review and are listed in Table 2.4-10.
 
Commodities classified as Bulk Commodities typically have no unique
 
component identification number. Therefore, a comprehensive listing of
 
components and location is not feasible. LRA Table 3.5.2-10 describes
 
and indicates Aging Management Programs for the components listed in
 
Section 2.4.10. 
 
There are no in-scope License Renewal Lubrite sliding support
 
bearings/surfaces at SSES.
 
Based on its review, the staff finds the applicant's response to RAI 2.4.10-1 acceptable because
 
the applicant has verified that the bulk commodities common to in-scope license renewal
 
structures are listed in LRA Table 2.4-10, are common to multiple SSCs, and share material and
 
environment properties which allow a common program or inspection to manage their aging effects. The applicant also verified that commodities unique to a specific structure are included
 
in the review of that structure (LRA Sections 2.4.1 through 2.4.9); and that all commodities not
 
unique to a specific structure are within the scope of license renewal, subject to an AMR, and
 
listed in LRA Table 2.4-10. The applicant stated that a comprehensive listing of components
 
and location is not feasible, since these commodities have no unique component identification
 
number. Since the applicant basically stated that the commodities listed in LRA Table 2.4-10
 
include "all" bulk commodities in the in-scope structures that are not uniquely identified in LRA
 
Sections 2.4.1 through 2.4.9, the staff finds that the applicant's list of common bulk commodities
 
in LRA Table 2.4-10 is all-inclusive of those in the in-scope structures described in LRA
 
Sections 2.4.1 through 2.4.9. The staff confirms that the applicant also has verified that there
 
are no Lubrite sliding support bearings and/or surfaces at SSES within the scope of license
 
renewal. Therefore, the staff's concerns described in RAI 2.4.10-1 are resolved.
In RAI 2.4.10-2, dated August 3, 2007, the staff noted based on information provided in LRA
 
Table 2.4-10, that it could not specifically identify the insulation and insulation jacketing included
 
within the scope of license renewal nor the specific subsets of insulation and insulation jacketing
 
included in LRA Table 2.4-10. It was also unclear to the staff whether insulation and jacketing
 
on the RV, RCS, MS system, and FWS have been included. In order to help complete its
 
screening review for insulation and insulation jacketing, the staff requested that the applicant
 
provide the following information:
 
(a) Identify the structures and structural components designated within the scope of license renewal that have insulation and/or insulation jacketing, and identify their location in the
 
plant. Identify locations of the thermal insulation that serves an intended function in
 
accordance with 10 CFR 54.4(a)(2) and describe the scoping and screening results of 2-163 thermal insulation and provide technical basis for its exclusion from the scope of license renewal.
(b) For insulation and insulation jacketing materials associated with item (a) above that do not require aging management, submit the technical basis for this conclusion, including
 
plant-specific operating experience.
(c) For insulation and insulation jacketing materials associated with item (a) above that require aging management, indicate the applicable LRA sections that identify the AMPs
 
credited to managing aging.
 
In its response to RAI 2.4.10-2, dated August 28, 2007, the applicant stated:
The component type "Reactor vessel thermal insulation" is in the scope of License
 
Renewal for SSES and subject to aging management review as listed in LRA
 
Table 2.4-1. Insulation for Reactor Coolant, Main Steam, and Feedwater System
 
components in the scope of License Renewal is also in-scope at SSES and subject to
 
aging management review as listed in LRA Table 2.4-10 under Component Types
 
"Insulation" and "Insulation jacketing."
(a) LRA Section 2.1.2.6 describes the treatment of insulation, including the identification of the various materials, indication of scope, and evaluation of degradation potential.
 
Thermal insulation provides nonsafety-related insulating characteristics and personnel
 
protection for both safety-related and nonsafety-related mechanical components that
 
contain fluid (liquid or steam).
Piping and equipment insulation is not classified as safety-related and has the intended function to maintain its structural integrity for nonsafety affecting safety (NSAS)
 
considerations, in accordance with 10 CFR 54.4(a)(2), if located in a structure that
 
contains safety-related equipment and components. Insulating materials (insulation and
 
insulation jacketing) that function to limit heat transfer or are required to maintain their
 
structural integrity are in the scope of License Renewal at SSES and subject to aging
 
management review. 
 
Similar to numerous structural components that are not uniquely identified, for which a comprehensive listing of components and location is not feasible, the various in-scope
 
insulation and insulation jacketing materials are addressed as bulk commodities.
(b) Aging management reviews have determined that no aging management is required for insulation and insulation jacketing materials associated with item (a).
As described in LRA Section 2.1.2.6, only stainless steel reflective metal or stainless
 
steel jacketed insulation is used inside containment. In other structures, aluminum or
 
aluminum jacketing is also used. Both stainless steel and aluminum insulating materials
 
are listed in LRA Table 3.5.2-10. These metallic insulating materials are exposed to
 
uncontrolled indoor air and no aging management is required consistent with
 
NUREG-1801 items VII.J-15 and V.F-2, as addressed in LRA items 3.2.1-50 and
 
3.3.1-94. Furthermore, while aluminum exposed to uncontrolled indoor air is not listed in
 
NUREG-1801 Volume II, Chapters IV or VII, stainless steel and steel exposed to
 
uncontrolled indoor air requires no aging management as listed in item NUREG-1801 2-164 items IV.E-2, VIII.I-10 and VIII.I-13. Similarly, in-scope metallic insulation materials for the Reactor Coolant, Main Steam and Feedwater systems do not require aging
 
management. This was not reflected in LRA items 3.1.1-85 or 3.4.1-41. 
 
With respect to other evaluated insulating materials, such as calcium silicate, fiberglass, Flexible "Min-K" (ceramic), woven glass fiber, and ceramic fiber listed in LRA
 
Table 3.5.2-10, aging management is also not required. Operating experience has not
 
identified any age-related degradation of insulation and typical insulation problems are
 
event driven (e.g., mechanical damage), and not considered for license renewal. 
 
The potential for degradation of insulation is described in LRA Section 2.1.2.6. The only
 
plausible aging effects that could result in degradation and failure, affecting the intended
 
function or creating a potential for spatial interaction are those which may cause reaction
 
or corrosion of barriers and coverings or that could impact the insulating materials
 
themselves. The relevant conditions do not ex ist in the indoor air environment of the subject NSAS component group for the following aging effect(s) to occur:
* Loss of Material due to Corrosion - The SSES site is a location that is rural rather than industrial or coastal and the air is not salt-laden nor does it contain
 
sufficient contaminants (e.g., sulfur) to concentrate and attack the insulation
 
barriers/coverings.
* Loss of Material, Cracking, and/or Change in Material Properties due to Ultra-Violet (UV) Radiation and/or Oxidation - Ultra-violet radiation and the oxidizing
 
effects of the air may also cause deterioration of insulation barriers and
 
coverings. However, the only insulation at SSES that is not either encapsulated
 
in aluminum or stainless steel jacketing, or is reflective metal (stainless steel or
 
aluminum), are for the diesel engine exhaust lines, where "Fibrefrax" cloth
 
blanket is an acceptable alternate jacketing material, and locations that have
 
"Temp-mat" (fiberglass blanket) or "Min-K" (ceramic fiber) insulation. Stainless
 
steel and aluminum jacket materials are resistant to the oxidizing effect of the air, due to the passive layer and are considered impervious to ultraviolet radiation (e.g., plant lighting).
With respect to "Temp-mat," "Min-K," and Fibrefrax (cloth coated alternative) insulation, the limited uses of these insulation types (e.g., diesel exhaust lines, pipe whip restraints, etc.) are not expected to experience sufficient UV radiation (plant lighting) exposure or ambient air oxidation to result in degradation.
* Loss of Material due to Wear - Wear (abrasion) is an applicable aging mechanism for insulation whenever there is relative movement between a
 
surface and an insulation barrier or cover that is in contact. However, wear
 
occurs during the performance of active functions; as a result of improper design, application, or operation; or to a very small degree with insignificant
 
consequences.
* Degradation of Insulating Materials - The insulating materials are fabricated of calcium silicate, glass fiber, or ceramic fiber. As described in LRA Item 3.3.1-93, and others, no aging management is required for glass exposed to uncontrolled
 
indoor air. The thermal resistance (insulating) characteristics of mass insulation
 
systems are not expected to naturally degr ade over the course of their service life as proper selection, design and installation for the specific service and
 
condition is assumed. Unless protective coverings of mass insulation systems 2-165 are damaged, loss/degradation of insulating material is not a concern. Mass insulation systems used in nuclear plant applications typically are sealed and
 
include a combination of insulating material and a weather barrier, vapor barrier, condensate barrier, or covering for the specific service. This outer covering (or
 
barrier) protects mass insulation from the weather, solar/UV radiation, or
 
atmospheric contaminants, and mechanical damage, but permits the evaporation
 
of any moisture vapor. Furthermore, SSES operating experience supports a lack
 
of degradation in insulating characteristics over the service life of insulation, except as the result of event-driven mechanical damage of coatings/barriers.
Details of the operating experience review and aging management review of non-metallic insulating materials are contained in auditable format and available
 
for onsite review.
(c) There are no aging effects requiring management for any subject insulating material component group that is exposed to indoor air, in order to preclude spatial interaction
 
with safety-related SCs, or for an intended (insulation) function credited in heating
 
analyses.
Based on its review, the staff finds the applicant's response to RAI 2.4.10-2 acceptable because the applicant has verified that the RV insulation is within the scope of license renewal, subject to
 
an AMR, and included under component type "Reactor vessel thermal insulation" in LRA
 
Table 2.4-1. The applicant also verified that insulation for RCS, Main Steam system, and
 
feedwater system components within the scope of license renewal is also within the scope of
 
license renewal, subject to an AMR, and listed under component types "Insulation" and
 
"Insulation jacketing," in LRA Table 2.4-10. The staff confirms that the applicant has provided a
 
detailed review of the various insulating materials in use, the potential for degradation effects, and operating experience. The staff also confirms the applicant's conclusion that, consistent
 
with the GALL Report, Volume II, none of the insulating material used in SSES requires any
 
management for aging affects, because of the applicant's favorable operating experience and
 
because these materials are exposed to an indoor air environment, only. Therefore, the staff's
 
concerns described in RAI 2.4.10-2 are resolved.
 
In RAI 2.4.10-3, dated August 3, 2007, the staff noted LRA Table 2.4-10 lists "Monorails, hoists
 
and miscellaneous cranes" as a bulk commodity component type subject to an AMR. It is not
 
clear to the staff which specific monorails, hoists and miscellaneous cranes have been identified
 
as within the scope of license renewal, and whether all relevant subcomponents (including
 
bridge and trolley, rails, girders, etc.) of these in-scope items have been screened in as items
 
requiring an AMR. The staff requested that the applicant identify the specific monorails, hoists, and cranes included within the above component type as in-scope and subject to an AMR and
 
those that are excluded, and provide the technical basis the decision. In addition, the staff
 
requested that the applicant confirm whether there are any bridge and trolley, rails, and girders
 
associated with these miscellaneous cranes and whether they are included within the scope of
 
license renewal and subject to an AMR. The staff also requested that the applicant confirm
 
whether fasteners and rail hardware associated with this component type are within the scope
 
of license renewal and subject to an AMR and; if not, provide the technical basis for the
 
exclusion.
 
In its response to RAI 2.4.10-3, dated August 28, 2007, the applicant stated:
 
2-166 Monorails, hoists and miscellaneous cranes within License Renewal in-scope structures are also in the scope of License Renewal for SSES and
 
subject to an aging management review. (Refer to response to RAI 2.4.2-
 
3 above)
 
Relevant subcomponents (including bridge and trolley, rails, and girders)
 
are in the scope of License Renewal for SSES and subject to aging
 
management review. These subcomponents are included under
 
Component Type "Monorails, hoists and miscellaneous cranes" in
 
Table 2.4-10.
 
Fasteners and rail hardware associated are in the scope of License
 
Renewal for SSES and subject to aging management review. These
 
fasteners and rail hardware included under Component Type "Anchorage
 
/ Embedments and Anchor Bolts" in Table 2.4-10.
 
Based on its review and the applicant's response to and staff evaluation of RAI 2.4.2-3 in
 
SER Section 2.4.2, the staff finds the applicant's response to RAI 2.4.10-3 acceptable because
 
the applicant has verified that all monorails, hoists and miscellaneous cranes and the relevant
 
subcomponents are in-scope structures within the scope of license and subject to an AMR.
 
Therefore, the staff's concern described n RAI 2.4.10-3 is resolved.
2.4.10.3  Conclusion The staff reviewed the LRA, UFSAR, RAI responses, and related structural components to determine whether the applicant failed to identify any SSCs within the scope of license renewal.
 
The staff found a certain lack of clarity but no gross 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 there is reasonable
 
assurance that the applicant has adequately identified the 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) and; therefore, is acceptable.
 
2.5  Scoping and Screening Results: Elect rical and Instrumentation and Controls This section documents the staff's review of the applicant's scoping and screening results for
 
electrical and I&C systems. Specifically, this section discusses electrical and I&C component commodity groups
 
In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, long-lived 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 renewal scoping criteria. Similarly, the staff evaluated the applicant's
 
screening results to verify that all passive, long-lived components were subject to an AMR in 2-167 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 pursuant to 10 CFR 54.4(a). The staff also reviewed the
 
licensing basis documents to determine whether the LRA specified all intended functions in
 
accordance with 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 (a) the functions are
 
performed with moving parts or a change in configuration or properties or (b) the SCs are
 
subject to replacement after a qualified life or specified time period, pursuant to
 
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  Electrical and Instrumentation and Controls Component Commodity Groups
 
2.5.1.1  Summary of Technical Information in the Application In LRA Section 2.5, the applicant described the electrical and I&C component commodity
 
groups, which include the following:
* Non-EQ Insulated Cables and Connections
* Non-Segregated Metal-Enclosed (Phase) Bus
* High-Voltage Insulators
* Transmission Conductors and Connections The non-EQ insulated cables and connections commodity group includes all in-scope electric
 
power cables, control cables, and instrumentation cables and in-scope connections not
 
addressed by the EQ program. An insulated cable is an assembly consisting of a conductor (aluminum or copper) with an insulated covering, fillers, and a jacket to cover the entire
 
assembly; however, the insulation is the only portion subject to evaluation. Cable connectors
 
connect the cable conductors with other cables or with motors, instruments, and a variety of electrical devices. Insulated cables and connecti ons connect specified portions of electrical circuits to deliver voltage, current, or signals.
 
The nonsegregated metal-enclosed bus under review for license renewal is within its own
 
passive enclosure and not part of any switchgear, a load center, motor control center, or other
 
active component. According to Institute of Electrical and Electronic Engineers 100-1984, "The
 
IEEE Standard Dictionary of Electrical and Electronics Terms," a nonsegregated phase bus is
 
constructed with all phase conductors in a common metal enclosure without barriers (i.e., with only air space) between the phases. Nonsegregated metal-enclosed buses connect two or more
 
elements of electric power circuits like swit chgear, transformers, switches, and other active electrical components. The license renewal review of nonsegregated metal-enclosed buses
 
includes only the bus sections between the active electrical components. The distribution bus
 
and the connections inside the enclosures of the active components are inspected and 2-168 maintained as parts of active components and therefore excluded from any AMR.
Nonsegregated metal-enclosed buses provide electr ical connections to specified portions of electrical circuits to deliver voltage and current.
 
A high-voltage insulator is a component uniquely designed to support a high-voltage conductor
 
physically and to separate the conductor electrically from another conductor or object. The
 
applicant's high-voltage insulators evaluated for license renewal include those supporting and
 
insulating high-voltage electrical components (i.e., transmission conductors and connections, particularly those for offsite power supplies). There are two basic types of insulators: (1) station
 
post and (2) strain (or suspension) insulators. Station post insulators are large and rigid. They
 
support stationary equipment (e.g., short lengths of transmission conductors and disconnect switches). Strain insulators are for applications where movement of the supported conductor is
 
expected and allowed, for example, to maintain tensional support of transmission conductors
 
between towers or other supporting structures. The high-voltage insulators within the scope of
 
license renewal are the station post insulators and strain insulators associated with the offsite
 
power supplies.
 
Transmission conductors are in the category of aluminum conductor steel-reinforced, aluminum-
 
strand conductors wrapped around a steel core. They are uninsulated, high-voltage conductors
 
that carry loads in plant switchyards and in distribution applications. Transmission conductor
 
connections are cast aluminum. The sections of transmission-type conductors at SSES within
 
the scope of license renewal are conductors associated with the offsite power supplies. The
 
transmission conductor sections are included to follow the guidance of Revision 1 of the
 
SRP-LR for offsite power restoration after an SBO. 
 
The electrical and I&C component commodity groups perform functions that support SBO.
 
LRA Table 2.5.2-1 identifies electrical and I&C component commodity group component types within the scope of license renewal and subject to an AMR:
* cable connections (metallic parts)
* fuse holders (insulation, metallic clamp)
* medium-voltage power cables
* metal-enclosed bus, non-segregated (bus and connections)
* metal-enclosed bus, non-segregated (enclosure assemblies)
* metal-enclosed bus, non-segregated (insulation and insulators)
* non-EQ insulated cables and connections
* non-EQ low-current instrument cables and connections
* high-voltage insulators
* transmission conductors and connections The intended functions of the electrical and I&C component commodity group component types within the scope of license renewal include:
* electrical connection to specified electric al circuit portions for voltage, current, or signal delivery
* electrical conductor insulation and support
 
2-169 2.5.1.2  Staff Evaluation The staff reviewed LRA Section 2.5 and UFSAR Sections 8.1, 8.2, and 8.3, using the evaluation
 
methodology described in SER Section 2.5 and the guidance in SRP-LR Section 2.5.
 
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, pursuant to 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 2.5-1 dated July 30, 2007, the staff noted that according to LRA Section 2.5, the high-
 
voltage switchyard circuit breakers that connect to the offsite sources, the circuits connecting
 
the startup transformers to the switchyard, and the associated components and structures are
 
not presently included within the scope of license renewal. GDC 17 requires that electric power
 
from the transmission network to the onsite elec tric distribution system be supplied by two physically independent circuits to minimize the likelihood of their simultaneous failure. In
 
addition, the staff noted that the guidance provided by letter 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 break ers that connect to the offsite system power transformers (startup transformer s), the transformers themselves, the intervening overhead or underground circuits between circuit breaker and
 
transformer and transformer and onsite electrical system, and the associated
 
control circuits and structures. Ensuring that the appropriate offsite power system
 
long-lived passive SCs 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.
 
Moreover, the proposed interim staff guidance (ISG) states that each path should include the
 
following:
 
The switchyard circuit breakers at transmission system voltage (69 kV and higher) that connect to the offsite system power trans formers, the transformers themselves, the  intervening overhead or underground circuits between circuit breaker and transformer and transformer and onsite electrical distribution system, and the associated control circuits and structures.
 
The staff determined that the offsite power recovery path, from two independent sources from
 
the switchyard to the plant Class 1E safety buses, includes:
* switchyard circuit breakers that connect to the offsite power system (i.e., grid)
* offsite system power transformers 2-170
* the intervening overhead or underground circuits (i.e., cables, buses and connections, transmission conductors and connections, insulators, disconnect switches, and
 
associated components)
* circuits between the circuit breakers and power transformers
* circuits between the power transformers and onsite electrical distribution system
* the associated control circuits and structures
 
The staff believes that the switchyard is part of the plant system and that the SBO recovery
 
paths, up to the switchyard circuit breakers that connect to the offsite system power
 
transformers, should be within the scope of license renewal, in accordance with staff guidance
 
in SRP-LR Section 2.5.2.1.1. The SSCs within the scope of license renewal should include a
 
circuit breaker at transmission voltage, to ensure adequate protection of the safety bus and
 
ensure recovery of offsite sources. The staff believes that the circuit breaker should be within
 
the scope of license renewal because its intended function is to maintain electrical continuity.
 
The circuit breaker maintains independence of offsite power sources, affords selective
 
protection to minimize the probability of loss of offsite power, and reduces transients from
 
affecting the onsite distribution system. For these reasons, a circuit breaker remains as the
 
scoping boundary. Using a disconnect switch or other component downstream of the breaker is
 
not consistent with the staff position for compliance with the SBO rule and is not acceptable for
 
meeting the SBO scoping requirements for license renewal. Therefore, the staff concludes that
 
the SBO recovery path that should be included in the scope of license renewal is circuits up to
 
and including the switchyard circuit breakers, at transmission voltage. Furthermore, the
 
associated control circuits and structures for the circuit breakers also should be included within
 
the scope of license renewal. 
 
The staff clarified that both paths used to control the offsite circuits to the plant should be within
 
the scope of license renewal. The staff requested that the applicant justify why these
 
components are not within the scope of license renewal and explain, in detail, which high-
 
voltage breakers and other components in the switchyard will be connected from the startup
 
transformers T10 and T20 up to the offsite power system for the purpose of SBO recovery.
 
In its response to RAI 2.5-1, dated August 23, 2007, the applicant stated that the 230 kV
 
equipment on the transmission system side of the motor-operated disconnects is not within the
 
scope of license renewal because they are part of the transmission system grid and not part of
 
the plant system. During a telephone conference, dated October 3, 2007, the staff informed the
 
applicant that its response to RAI 2.5-1 was not acceptable because is not consistent with staff
 
guidance. The staff determined that the switchyard is part of the plant system and that the SBO
 
recovery paths should be within the scope of license renewal, in accordance with the ISG. 
 
In letter dated May 7, 2008, the applicant modified the SBO recovery path for SSES, as shown
 
in LRA Figure 2.5-1, "Graphical Representation of the SSES SBO License Renewal Boundary."
 
The SSES SBO recovery path includes the transmission conductors from startup transformers
 
T10 and T20 to circuit breakers in the switchyard as well as the circuit breakers themselves.
 
The scoping boundary is at the transmission system side of the circuit breakers. From startup
 
transformer T10, the scoping boundary is 230 kV circuit breakers 2T and 2S. For the SBO
 
recovery path with startup transformer T20, the boundary is 230kV circuit breakers 2T and 2W
 
and also, a 230kV circuit breaker on the 230kV-500kV tie line, as shown in LRA Figure 2.5-1. 
 
2-171 Based on its review, the staff finds the applicant's response to RAI 2.5-1 acceptable because the applicant has verified that both SBO recovery paths are within the scope of license renewal.
 
The staff finds the applicant's response acceptable since the licensee has included switchyard
 
circuit breakers that connect to the offsite syst em power transformers (startup transformers), the transformers themselves, the intervening ov erhead or underground circuits between circuit breaker and transformer and transformer and ons ite electrical system, and the associated control circuits and structures in the scope of license renewal, in accordance with SRP-LR
 
Section 2.5.2.1.1. The staff confirms the applicant's change from motor-operated disconnects to
 
circuit breakers at transmission system voltage in the SBO recovery path, is consistent with the
 
proposed ISG (2008-01). Therefore, the staff's concern described in RAI 2.5-1 is resolved. 
 
In RAI 2.5-2 dated July 30, 2008, the staff requested confirmation that the control circuits and
 
structures associated with the 230 kV circuit breakers are within the scope of license renewal, consistent with the requirements of 10 CFR 54.4(a)(3) and the guidance found in SRP-LR
 
Sections 2.1.3.1.3 and 2.5.2.1.1.
 
In its response to RAI 2.5-2, dated August 29, 2008, the applicant revised the LRA to include
 
the control circuits within the scope of license renewal.
 
Based on its review, the staff finds the applicant's response to RAI 2.5-2 acceptable because
 
the applicant has revised the LRA to include the control circuits within the scope of license
 
renewal, consistent with staff guidance. Therefore, the staff's concern described in RAI 2.5-2 is
 
resolved. 
 
2.5.1.3  Conclusion The staff reviewed the LRA, USAR, and RAI responses to determine whether the applicant
 
failed to identify any SSCs within the scope of license renewal. The staff finds no such
 
omissions. In addition, the 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 electrical and I&C
 
component commodity groups 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) and;
 
therefore is acceptable.
 
2.6  Conclusion for Scoping and Screening The staff reviewed the information in LRA Section 2, "Scoping and Screening Methodology for
 
Identifying Structures and Components Subject to Aging Management Review and
 
Implementation Results" and determines that the applicant's scoping and screening
 
methodology was consistent with 10 CFR 54.21(a)(1) and the staff's positions on the treatment
 
of safety-related and nonsafety-related SSCs within the scope of license renewal and on SCs
 
subject to an AMR is consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1).
 
On the basis of its review, the staff concludes , that the applicant has adequately identified those systems and components within the scope of 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).
 
The staff concludes that there is reasonable assurance that the applicant will continue to
 
conduct the activities authorized by the renewed license in accordance with the CLB and any 2-172 changes to the CLB in order to comply with 10 CFR 54.21(a)(1), in accordance with the Atomic Energy Act of 1954, as amended, and NRC regulations
 
3-1    SECTION 3 AGING MANAGEMENT REVIEW RESULTS
 
This section of the safety evaluation r eport (SER) evaluates aging management programs (AMPs) and aging management reviews (AMRs) for Susquehanna Steam Electric Station (SSES Units 1 and 2, by the staff of the United States (US) Nuclear Regulatory Commission (NRC) (the staff). In Appendix B of its license renewal application (LRA), Pennsylvania Power &
 
Light (PPL) Susquehanna, LLC (PPL or the applicant) described the 50 AMPs that it relies on to
 
manage or monitor the aging of passive, long-lived structures and components (SCs).
 
In LRA Section 3, the applicant provided the results of the AMRs for those SCs identified in LRA
 
Section 2 as within the scope of license renewal and subject to an AMR.
 
3.0  Applicant's Use of the Generic Aging Lessons Learned Report In preparing its LRA, the applicant credited NUREG-1801, Revision 1, "Generic Aging Lessons
 
Learned (GALL) Report," dated September 2005. The GALL Report contains the staff's generic
 
evaluation of the existing plant programs and documents the technical basis for determining
 
where existing programs are adequate without modification, and where existing programs should be augmented for the period of extended operation. The evaluation results documented
 
in the GALL Report indicate that many of the existing programs are adequate to manage the aging effects for particular license renewal SCs. The GALL Report also contains
 
recommendations on specific areas for which existing programs should be augmented for
 
license renewal. An applicant may reference the GALL Report in its LRA to demonstrate that its
 
programs correspond to those reviewed and approved in the report.
 
The purpose of the GALL Report is to provide a summary of staff-approved AMPs to manage or monitor the aging of SCs subject to an AMR. If an applicant commits to implementing these
 
staff-approved AMPs, the time, effort, and resources for LRA review will be greatly reduced, improving the efficiency and effectiveness of the license renewal review process. The GALL
 
Report also serves as a quick reference for applicants and staff reviewers to AMPs and
 
activities that the staff has determined will adequately manage or monitor aging during the
 
period of extended operation.
 
The GALL Report identifies: (1) structures, systems, 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.
 
The staff 's 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.
3-2  In addition to its review of the LRA, the staff conducted an onsite audit of selected AMRs and
 
associated AMPs, during the week of May 5th. The onsite audits and reviews are designed tor
 
maximumize 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. The results of this audit were documented in the report of January 16, 2009. 
 
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 (ML030990052). This
 
revised LRA format incorporates lessons learned from the staff's reviews of the previous five
 
LRAs, which used a format developed from info rmation 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 SSES application is essentially the same. The
 
intent of the revised format of the LRA was to modify the tables in LRA Section 3 to provide
 
additional information that would assist in the 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 clarif ying information. The following are examples of information that might be contained within this column:
* further evaluation recommended - information or reference to where that information is located
* The name of a plant-specific program
* exceptions to GALL Report assumptions
* discussion of how the line is consistent with the corresponding line item in the GALL Report when the consistency may not be obvious 3-3
* 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 ex ample, the engineered safety features group has tables specific to the core spray system, HPCI system, and RHR 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, including abbreviations, where applicable, for the listed component types.
 
Definitions and abbreviations of intended functions are in LRA Table 2.0-1.
* 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 env ironments are indicated with a list of these environments in LRA Tables 3.0-1 and 3.0-2.
* 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.
* NUREG-1801 Volume 2 Item - The seventh column lists the GALL Report item(s) identified in the LRA as similar to the AMR results. The applicant 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.
3-4  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 had 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 had 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.
 
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 which the applicant claimed consist ency 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 acti ons 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 3-5 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.    (10) Operating Experience - Operating ex perience 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 program element (7) "corrective actions," (8)"confirmation process," and
 
(9)"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 numbers in column seven of the LRA, "NUREG-1801 Volume 2 Item," correlates to an AMR combination as identified in the GALL Report. The staff also
 
conducted onsite audits to verify these correlations. A blank in column seven indicates that the
 
applicant was unable to identify an appropriate correlation in the GALL Report. The staff also
 
conducted a technical review of combinations not consistent with the GALL Report. The next
 
column, "Table 1 Item," refers to a number indicating the correlating row in Table 1.
 
3.0.2.3  UFSAR Supplement Consistent with the SRP-LR for the AMRs and AMPs that it reviewed, the staff also reviewed
 
the updated final safety analysis report (UFSAR) supplement, which summarizes the applicant's
 
programs and activities for managing aging effects for the period of extended operation, as
 
required by 10 CFR 54.21(d).
3-6  3.0.2.4  Documentation and Documents Reviewed In its review, the staff used the LRA, LRA supplements, the SRP-LR, and the GALL Report.
 
During the onsite audit, the staff also examined the 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
 
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  SSES Aging Management Programs SSES 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 Inservice Inspection (ISI) Program (B.2.1) Existing Consistent with exception XI.M1  reactor vessel, reactor vessel internals, and reactor coolant system  3.0.3.2.1 BWR Water Chemistry Program (B.2.2) Existing Consistent XI.M2 reactor vessel, reactor vessel internals, and reactor coolant system / engineered safety features / auxiliary systems /
steam and power conversion systems / containments, structures, and component
 
supports 3.0.3.1.1 Reactor Head Closure Studs
 
Program (B.2.3) Existing Consistent XI.M3 reactor vessel, reactor vessel internals, and reactor coolant system  3.0.3.1.2 BWR Vessel ID Attachment Welds
 
Program (B.2.4) Existing Consistent XI.M4 reactor vessel, reactor vessel internals, and reactor coolant system  3.0.3.1.3 BWR Feedwater Nozzle Program (B.2.5) Existing Consistent XI.M5 reactor vessel, reactor vessel internals, and reactor coolant system  3.0.3.1.4 BWR CRD Return Line Nozzle Program (B.2.6) Existing Consistent with exception XI.M6  reactor vessel, reactor vessel internals, and reactor coolant system  3.0.3.2.2 BWR Stress Corrosion Cracking (SCC) Program (B.2.7) Existing Consistent XI.M7 reactor vessel, reactor vessel internals, and reactor coolant system  3.0.3.1.5 3-7 SSES 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 BWR Penetrations Program (B.2.8) Existing Consistent with exception XI.M8  reactor vessel, reactor vessel internals, and reactor coolant system  3.0.3.2.3 BWR Vessel Internals Program (B.2.9) Existing Consistent with enhancement XI.M9  reactor vessel, reactor vessel internals, and reactor coolant system  3.0.3.2.4 Thermal Aging and Neutron Embrittlement of
 
Cast Austenitic
 
Stainless Steel (CASS) Program (B.2.10) New Consistent XI.M13 reactor vessel, reactor vessel internals, and reactor coolant system  3.0.3.1.6 Flow-Accelerated Corrosion (FAC)
 
Program (B.2.11) Existing Consistent XI.M17 reactor vessel, reactor vessel internals, and reactor coolant system / engineered safety features / auxiliary systems /
steam and power conversion systems  3.0.3.1.7 Bolting Integrity Program (B.2.12) Existing Consistent with exceptions and
 
enhancement XI.M18  reactor vessel, reactor vessel internals, and reactor coolant system / engineered safety features / auxiliary systems /
steam and power conversion systems  3.0.3.2.5 Piping Corrosion Program (B.2.13) Existing Consistent with exceptions XI.M20  engineered safety features / auxiliary systems 3.0.3.2.6 Closed Cooling Water Chemistry
 
Program (B.2.14) Existing Consistent with exceptions XI.M21  auxiliary systems  3.0.3.2.7 Crane Inspection Program (B.2.15) Existing Consistent XI.M23 containments, structures, and component supports 3.0.3.1.8 Fire Protection Program (B.2.16) Existing Consistent with exceptions XI.M26  containments, structures, and component supports 3.0.3.2.8 Fire Water System Program (B.2.17) Existing Consistent with enhancements XI.M27  engineered safety features / auxiliary systems 3.0.3.2.9 Buried Piping Surveillance
 
Program (B.2.18) New Consistent with exception XI.M28  auxiliary systems  3.0.3.2.10 3-8 SSES 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 Condensate and Refueling Water Storage Tanks
 
Inspection (B.2.19) New Consistent XI.M29 steam and power conversion systems  3.0.3.1.9 Fuel Oil Chemistry Program (B.2.20) Existing Consistent with exceptions XI.M30  auxiliary systems  3.0.3.2.11 Reactor Vessel Surveillance
 
Program (B.2.21) Existing Consistent with exception XI.M31  reactor vessel, reactor vessel internals, and reactor coolant system  3.0.3.2.12 Chemistry Program Effectiveness
 
Inspection (B.2.22) New Consistent XI.M32 engineered safety features / auxiliary systems / steam and power conversion systems 3.0.3.1.10 Cooling Units Inspection (B.2.23) New Consistent XI.M32 auxiliary systems  3.0.3.1.11 Heat Exchanger Inspection (B.2.24) New Consistent XI.M32 engineered safety features / auxiliary systems 3.0.3.1.12 Lubricating Oil Inspection (B.2.25) New Consistent XI.M32 engineered safety features / auxiliary systems 3.0.3.1.13 Main Steam Flow Restrictor Inspection (B.2.26) New Consistent XI.M32 reactor vessel, reactor vessel internals, and reactor coolant system  3.0.3.1.14 Monitoring and Collection System
 
Inspection (B.2.27) New Consistent XI.M32 auxiliary systems  3.0.3.1.15 Supplemental Piping/Tank
 
Inspection (B.2.28) New Consistent XI.M32 engineered safety features / auxiliary systems / steam and power conversion systems 3.0.3.1.16 Selective Leaching Inspection (B.2.29) New Consistent XI.M33 engineered safety features / auxiliary systems / steam and power conversion systems 3.0.3.1.17 Buried Piping and Tanks Inspection
 
Program (B.2.30) New Consistent with exceptions XI.M34  auxiliary systems / steam and power conversion systems 3.0.3.2.13 Small Bore Class 1 Piping Inspection (B.2.31) New Consistent XI.M35 reactor vessel, reactor vessel internals, and reactor coolant system  3.0.3.1.18 3-9 SSES 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 System Walkdown Program (B.2.32) Existing Consistent with enhancements XI.M36  reactor vessel, reactor vessel internals, and reactor coolant system / engineered safety features / auxiliary systems /
steam and power conversion systems  3.0.3.2.14 Lubricating Oil Analysis Program (B.2.33) Existing Consistent with exception and
 
enhancement XI.M39  engineered safety features / auxiliary systems 3.0.3.2.15 Inservice Inspection (ISI) Program - IWE (B.2.34) Existing Consistent XI.S1 containments, structures, and component supports 3.0.3.1.19 Inservice Inspection (ISI) Program - IWL (B.2.35) Existing Consistent XI.S2 containments, structures, and component supports 3.0.3.1.20 Inservice Inspection (ISI) Program - IWF (B.2.36) Existing Consistent XI.S3 containments, structures, and component supports 3.0.3.1.21 Containment Leakage Rate Test
 
Program (B.2.37) Existing Consistent XI.S4 containments, structures, and component supports 3.0.3.1.22 Masonry Wall Program (B.2.38) Existing Consistent with enhancement XI.S5  containments, structures, and component supports 3.0.3.2.16 Structures Monitoring Program (B.2.39) Existing Consistent with enhancements XI.S6  containments, structures, and component supports /
 
electrical and instrumentation
 
and controls 3.0.3.2.17 RG 1.127 Water-Control Structures
 
Inspection (B.2.40) Existing Consistent with enhancements XI.S7  containments, structures, and component supports 3.0.3.2.18 Non-EQ Electrical Cables and
 
Connections Visual
 
Inspection Program (B.2.41) New Consistent XI.E1 electrical and instrumentation and controls 3.0.3.1.23 Non-EQ Cables and Connections Used in Low-Current
 
Instrumentation
 
Circuits Program (B.2.42) New Consistent XI.E2 electrical and instrumentation and controls 3.0.3.1.24 Non-EQ Inaccessible Medium-Voltage
 
Cables Program (B.2.43) New Consistent XI.E3 electrical and instrumentation and controls 3.0.3.1.25 3-10 SSES 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 Metal-Enclosed Bus Inspection Program (B.2.44) New Consistent XI.E4 electrical and instrumentation and controls 3.0.3.1.26 Non-EQ Electrical Cable Connections
 
Program (B.2.45) New Consistent XI.E6 electrical and instrumentation and controls 3.0.3.1.27 Area-Based NSAS Inspection (B.2.46) New Plant-specific N/A auxiliary systems  3.0.3.3.1 Leak Chase Channel Monitoring Activities (B.2.47) Existing Plant-specific N/A c ontainments, structures, and component supports 3.0.3.3.2 Preventive Maintenance
 
Activities -
RCIC/HPCI Turbine
 
Casings (B.2.48) Existing Plant-specific N/A engineered safety features  3.0.3.3.3 Preventive Maintenance
 
Activities - Main Turbine (B2.49) Existing Plant-Specific N/A engineered safety features 3.0.3.3.4 Fuse Holders Program (B.2.50) New Consistent with exceptions Xl.E5 electrical and instrumentation and controls 3.0.3.2.20 Fatigue Monitoring Program (B.3.1) Existing Consistent with enhancements X.M1  reactor vessel, reactor vessel internals, and reactor coolant system / engineered safety features / auxiliary systems /
steam and power conversion systems / containments, structures, and component
 
supports 3.0.3.2.19 EQ Program (B.3.2) Existing Consistent X.E1 electrical and instrumentation and controls 3.0.3.1.28 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:
* Boiling Water Reactor (BWR) Water Chemistry Program
* Reactor Head Closure Studs Program
* BWR Vessel Inside Diameter (ID) Attachment Welds Program
* BWR Feedwater Nozzle Program
* BWR Stress Corrosion Cracking (SCC) Program 3-11
* Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS)
Program
* Flow-Accelerated Corrosion (FAC) Program
* Crane Inspection Program
* Condensate and Refueling Water Storage Tanks Inspection
* Chemistry Program Effectiveness Inspection
* Cooling Units Inspection
* Heat Exchanger Inspection
* Lubricating Oil Inspection
* Main Steam Flow Restrictor Inspection
* Monitoring and Collection System Inspection
* Supplemental Piping/Tank Inspection
* Selective Leaching Inspection
* Small Bore Class 1 Piping Inspection
* Inservice Inspection Program (ISI) Program - IWE
* ISI Program - IWL
* ISI Program - IWF
* Containment Leakage Rate Test Program
* Non-EQ Electrical Cables and Connections Visual Inspection Program
* Non-EQ Cables and Connections Used in Low-C urrent Instrumentation Circuits Program
* Non-EQ Inaccessible Medium-Voltage Cables Program
* Metal-Enclosed Bus Inspection Program
* Non-EQ Electrical Cable Connections Program
* Environmental Qualification (EQ) Program 3.0.3.1.1  BWR Water Chemistry Program 
 
Summary of Technical Information in the Application. In LRA Section B.2.2, the applicant described the existing BWR Water Chemistry Program as consistent with GALL AMP XI.M2, "Water Chemistry." The applicant stated that the BWR Water Chemistry Program is a mitigation
 
program that manages potential aging effects for plant components in a treated water
 
environment. The applicant also stated that the program manages loss of material and cracking
 
through monitoring and control of relevant water chemistry parameters, such as sulfates, halogens, dissolved oxygen, and conductivity, cons istent with applicable Electric Power Research Institute (EPRI) water chemistry guidelines.
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the applicant's AMP evaluation report for the BWR Water
 
Chemistry Program, together with implem enting procedures and supporting documentation related to the program. The staff noted that the program elements in the AMP that the applicant
 
claimed as consistent with the GALL Report are consistent with the corresponding program 3-12 element criteria recommended in GALL AMP XI.M2, with the exception of two program element aspects which the staff determined a need for additional clarification and for which a request for
 
additional information (RAI) was issued. The staff evaluates these aspects of the AMP in the
 
following discussion.
 
In RAI B.2.2-1, item 1, dated June 23, 2008, the staff noted the following on program elements that the applicant claimed to be consistent with GALL AMP XI.M2:
 
Item 1 (on "parameters monitored/inspected") - In the GALL Report, this program
 
element refers to BWRVIP-29 (EPRI TR-103515), "BWR Water Chemistry
 
Guidelines - 1996 Revision," or later revisions, which recommends continuous
 
monitoring of local electrochemical corrosion potential. However, in lieu of direct
 
electrochemical corrosion potential monitoring, the applicant currently relies on
 
monitoring of dissolved oxygen for indication of relevant conditions for corrosion.
 
The staff requested that the applicant provide a technical justification as to why this
 
deviation from the EPRI guidelines is acceptable and explain why this is not
 
considered to be an exception to the GALL Report.
 
In its response to RAI B.2.2-1, item 1, dated July 17, 2008, the applicant provided the following
 
discussion:
 
EPRI TR-103515 recommends continuous monitoring of local electrochemical
 
corrosion potential (ECP) during reactor power operation (greater than 10
 
percent rated power) as a method to demonstrate the effectiveness of hydrogen
 
water chemistry (HWC). EPRI TR-103515 also describes alternative techniques
 
using predictive models to verify the effectiveness of HWC. In such instances, TR-103515 recommends models be benchm arked against ECP measurements in radiolytically identical and operationally similar applications and a correlation
 
be developed between protective chemistry conditions, e.g., ECP, and other
 
plant (secondary) parameters that respond to hydrogen injection and are
 
normally continuously monitored. As described in TR-103515, secondary plant
 
parameters such as feedwater hydrogen flow rate or concentration, normalized
 
main steam line radiation or main steam line oxygen concentration, and reactor
 
coolant oxygen or hydrogen concentration can be directly related to primary
 
parameters such as ECP. The correlation between ECP and secondary
 
parameters, such as dissolved oxygen, is essential since the useful life for the
 
ECP probes can be less than a fuel cycle.
 
The BWR Water Chemistry program continuously monitors reactor water for
 
dissolved oxygen concentration and uses hydrogen injection to reduce dissolved
 
oxygen to protective levels (equivalent to ECP of less than -230 mV SHE
 
[standard hydrogen electrode]). ECP measurements were taken during initial
 
implementation of HWC and correlated with secondary parameters, including
 
dissolved oxygen. When dissolved oxygen is not available, other secondary
 
parameter correlations may be used to determine that protection is being
 
achieved. Therefore, since the use of dissolved oxygen in lieu of continuous
 
monitoring of ECP is consistent with the EPRI TR-103515 guidelines, no
 
exception to GALL is required.
 
In evaluating the applicant's response, the staff reviewed EPRI TR-103515-R2, Section 2.10.3, 3-13 "Secondary Monitoring Parameters," and Section 5.4, "Alternate ECP Estimation Techniques."
The staff confirms that the EPRI guidelines include provisions for using secondary plant
 
parameters, such as dissolved oxygen, in lieu of continuous electrochemical corrosion potential
 
monitoring. The EPRI guidelines state that plant-specific correlations should be developed to
 
relate secondary parameter values to electrochemical corrosion potential measurements and
 
can be used when direct electrochemical corrosion potential monitoring is not available.
 
Based on its review, the staff finds the applicant's response to RAI B.2.2-1, item 1 acceptable
 
because the applicant has developed plant-specific correlations relating continuously monitored
 
parameters to measured electrochemical corrosion potential values, which are consistent with
 
the EPRI TR-103515 that is endorsed by the GALL Report, and the applicant uses those
 
monitored parameters to control electrochemical corrosion potential at recommended protective
 
levels. The staff determines that the applicant's response is acceptable and that this aspect of
 
the applicant's program is consistent with the recommendations in the GALL Report. Therefore, the staff's concern described in RAI B.2.2-1, item 1 is resolved.
 
In RAI B.2.2-1, item 2, dated June 23, 2008, the staff noted the following on program elements that the applicant claimed to be consistent with GALL AMP XI.M2:
 
Item 2 (on "monitoring and trending") - In the GALL Report, this program element
 
refers to the EPRI water chemistry guidelines, TR-103515, or later revisions, which
 
recommends weekly monitoring of conductivity, chlorides, and sulfate in the
 
condensate storage tank (CST); however, the applicant currently measures
 
conductivity, chlorides, and sulfate in the CST on a monthly basis. The staff
 
requested that the applicant provide a technical justification as to why this deviation
 
from the EPRI guidelines is acceptable and explain why this is not considered to be
 
an exception to the GALL Report.
 
In its response to RAI B.2.2-1, item 2, dated July 17, 2008, the applicant provided the following
 
discussion:
 
EPRI TR-103515 recommends weekly monitoring of conductivity, chlorides, and sulfates in the condensate storage tank but allows for reduced monitoring if the sources of water are monitored. During normal power operation, all source water to the condensate storage tanks is routinely monitored for conductivity, chlorides, and sulfates. Therefore, the BWR Water Chemistry Program is consistent with the EPRI guidance and the monitoring frequency is not considered to be an
 
exception to GALL.
 
In evaluating the applicant's response, the staff reviewed EPRI TR-103515-R2, Table B-1, "Diagnostic Parameters for Demineralized Water Storage Tank (DWST) and Condensate
 
Storage Tank (CST)." The staff confirms that a note associated with this table states that the
 
frequency of CST analyses may be reduced or eliminated if all source water is routinely
 
monitored for conductivity, chlorides, and sulfates parameters. The staff noted that the
 
applicant's response states that during normal power operation all source water to the CST is
 
routinely monitored. The staff also noted that EPRI TR-103515-R2 states that each plant
 
should use the guidelines to develop site-specific procedures identifying parameters to be monitored, along with recommended frequencies and limits. Because the applicant provides routine monitoring for all source water to the CST during normal power operation and the EPRI guidelines describe the monitoring frequencies as recommendations, rather than requirements, 3-14 the staff finds the reduction in CST monitoring frequency from weekly to monthly to be acceptable and to be consistent with the recommendations in EPRI TR-103515, which is
 
endorsed by the GALL Report. On this basis, the staff finds the applicant's response to
 
RAI B.2.2-1, item 2 to be acceptable and this aspect of the applicant's program to be consistent
 
with the recommendations in the GALL Report.
 
Based on its review, and resolution of the related RAI as described above, the staff finds the
 
applicant's BWR Water Chemistry Program consistent with the program elements of GALL AMP XI.M2 and; therefore, is acceptable.
 
Operating Experience
. The staff reviewed the applicant's operating experience (OE) described in LRA Section B.2.2. The applicant stated that the BWR Water Chemistry Program
 
incorporates EPRI and Institute of Nuclear Power Operations (INPO) guideline documents as
 
well as lessons learned from site and other utility OE. The applicant stated that the program has
 
been and continues to be subject to internal and external assessments of the performance to
 
identify strengths and potential adverse trends. The applicant further stated that plant-specific
 
OE did not reveal a loss of component intended function for components exposed to reactor
 
coolant, feedwater (FW), condensate, control rod drive (CRD) hydraulic water, or accident
 
mitigation water (i.e., suppression pool water) that could be attributed to an inadequacy of the
 
BWR Water Chemistry Program.
 
During the onsite audit, the staff reviewed the applicant's OE reports for the BWR Water
 
Chemistry Program. The staff reviewed selected corrective action condition reports (CRs)
 
related to the BWR Water Chemistry Program and interviewed the applicant's technical staff to
 
confirm that the plant-specific OE did not reveal any degradation not bounded by industry
 
experience.
 
The staff noted that the applicant has a history of CRs related to high sulfate levels in reactor
 
water for a period of several days following refueling outages (RFOs), and that the applicant has
 
undertaken root cause evaluations and programmatic changes to reduce and control the high
 
sulfate levels. The applicant stated that there have been no component failures attributed to the
 
transient elevation of sulfate in the reactor following refueling.
 
In RAI B.2.2-2, dated June 23, 2008, the staff requested that the applicant explain its activities
 
related to understanding and mitigating this chemistry program issue, addressing the cause of
 
the problem, corrective actions and comparisons with other BWRs having similar condensate demineralizers.
 
In its response to RAI B.2.2-2, dated July 17, 2008, the applicant provided the following
 
discussion:
 
The elevated sulfate levels following refueling outages were determined to be the
 
result of operational actions, such as removing a condensate pump from service, which disturbed or upset the condensate demineralizer resin bed and allowed the
 
cation resin, which releases sulfate and organic sulfonates, to migrate to near the
 
outlet (bottom) of the resin bed. When the condensate demineralizers were
 
restarted after an outage, the sulfates and sulfonates that had concentrated in
 
the bed during the outage washed out of the cation resin at the bottom of the
 
demineralizer bed and caused the elevated sulfate levels. The elevated sulfate
 
levels continued for a week or two, until the excess was rinsed off the beds or
 
new anion resin heels were added to the vessels.
3-15  PPL undertook two corrective actions to mitigate the elevated sulfate level issue.
 
One included a change in operation of the condensate demineralizers and/or
 
condensate pumps as they are taken out of service. The procedures were
 
changed to bypass the condensate demineralizer so as to not upset the beds
 
during initial startup or final shutdown of the condensate pumps. Another
 
corrective action rinses the resin bed with demineralized water before starting the
 
condensate demineralizer. The out of service condensate demineralizer resin
 
bed is covered with demineralized water which is flushed to radwaste, taking any
 
excess sulfates with it, thus mitigating the elevated sulfate level. The condensate
 
demineralizer is placed in service after the rinse is completed.
 
In addition, PPL installed a condensate filtration system in the late 1990s. Since
 
then, PPL has experienced a continually improving trend in sulfate levels, including the elevated sulfate levels following each outage. PPL maintains sulfate
 
data as a monthly average, as reported to INPO. The data shows that monthly
 
average sulfate levels following outages have not exceeded 5 ppb since
 
completion of the Unit 2 outage in 2003.
 
These actions have resulted in monthly aver age sulfate levels that are typically below 2 ppb and often below 1 ppb. Comparison of SSES with other BWRs
 
having similar filters and condensate demineralizers, based on October 2007
 
data, places both SSES units above the median value, but below the EPRI
 
recommended goal of 2 ppb.
 
Based on the review, that staff finds the applicant's response to RAI B.2.2-2 acceptable
 
because the applicant has verified that its OE is within the envelope of industry experience and
 
the applicant's BWR Water Chemistry Program has demonstrated its ability to detect and
 
correct operational problems. Therefore, the staff's concern described in RAI B.2.2-2 is
 
resolved.
 
Based on this review, the staff finds that the OE for this AMP demonstrates that the applicant's
 
BWR Water Chemistry Program is achieving its objective of mitigating loss of material due to
 
general, crevice and pitting corrosion and cracking caused by SSC in steel and/or stainless
 
steel exposed to treated water; and that the applicant is taking appropriate corrective actions
 
through implementation of this program.
 
The staff confirms that the "operating experience" program element satisfies the criterion
 
defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10. Therefore, the staff finds this program element acceptable.
 
UFSAR Supplement. The applicant provided the UFSAR supplement for the BWR Water Chemistry Program in LRA Section A.1.2.11. The staff notes that the UFSAR supplement's
 
description for the BWR Water Chemistry Program conforms to the recommended UFSAR
 
supplement for this type of program as described in the SRP-LR. The staff also notes that in
 
LRA Table A-1, Commitment No. 2, the applicant committed to ongoing implementation of the
 
BWR Water Chemistry Program for aging management of applicable components, during the
 
period of extended operation. 
 
Based on the review, the staff finds that the UFSAR supplement summary in LRA
 
Section A.1.2.11 provides an acceptable description of the applicant's BWR Water Chemistry 3-16 Program because it is consistent with the UFSAR supplement summary description in the SRP-LR for the Water Chemistry Program. The staff also finds that the information in the
 
UFSAR supplement is an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
 
Conclusion. On the basis of the review of the applicant's BWR Water Chemistry Program and the applicant's responses and resolutions of the related RAIs, the staff finds all program
 
elements consistent with the GALL Report. The staff concludes that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB for the period of extended operation, as
 
required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this
 
AMP and concludes that it provides an adequate summary description of the program, as
 
required by 10 CFR 54.21(d) and; therefore, is acceptable.
 
3.0.3.1.2  Reactor Head Closure Studs Program 
 
Summary of Technical Information in the Application. In LRA Section B.2.3, the applicant described the existing Reactor Head Closure Studs AMP as consistent with the GALL AMP XI.M3, "Reactor Head Closure Studs." The R eactor Head Closure Studs Program provides for condition monitoring and preventive actions to manage stud cracking. The program is implemented through plant procedures based on the inspection requirements specified in the American Society of Mechanical Engineers (ASME) Code, Section XI, Subsection IWB, Table IWB 2500-1, and the preventive measures described in Regulatory Guide (RG) 1.65. 
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the applicant's onsite documentation supporting the
 
applicant's conclusion that the program elements are consistent with the elements in GALL AMP XI.M3. 
 
The staff compared the elements in the applicant
's program with the GALL Report program elements. The staff confirmed that the maximum reported ultimate tensile strength for the
 
reactor head closure studs and nuts is 163.5 ksi, which is less than the 170 ksi specification
 
cited in the GALL Report "scope of program" program element. 
 
The staff noted that the applicant had indicated that the current scope of the program applies to the ASME Code Section XI, 1998 Edition, inclusive of the 2000 Addenda. The program description in the GALL AMP XI.M3 states that the GALL Report applies to inspection, repair, and replacement activities for ASME Code components covered in ASME Code Section XI, the
 
2001 Edition, inclusive of the 2003 Addenda. The staff noted that the applicant had clarified that the use of ASME Code Section XI, the 1998 Edition, inclusive of the 2000 Addenda, is consistent with the program description statement in the GALL AMP XI.M3 because the
 
Statements of Consideration (SOC) on 10 CFR Part 54 clarifies that acceptable editions of the ASME Code Section XI are those up through the most recently endorsed edition of the Code
 
mentioned in 10 CFR 50.55a. The staff verified that the SOC on 10 CFR Part 54 does include this clarification, and on that basis, the applicant's use of ASME Code Section XI, 1998 Edition, inclusive of the 2000 Addenda, is consistent with the Code edition mentioned in the program description of GALL AMP XI.M3. Based on this review, the staff finds the applicant's crediting of the ASME Code Section XI, 1998 edition, inclusive of the 2000 Addenda (for aging management) is consistent with the criteria in GALL AMP XI.M3. 
 
The staff confirmed that, in LRA Commitment No. 3, the applicant has committed to the ongoing 3-17 implementation of the Reactor Head Closure Stud Program for aging management of those in-scope components that the AMP is credited. The staff also confirmed that the applicant has
 
placed this commitment in LRA A.1.2.40 for the Reactor Head Closure Stud Program. 
 
In comparing the seven program elements in the applicant's program to those in  GALL AMP XI.M3, the staff noted that the program elements for which the applicant claimed
 
consistency with the GALL Report were consistent with the corresponding program element criteria recommended in GALL AMP XI.M3. The "
operating experience" program element is discussed separately below.
 
Operating Experience. The staff reviewed the applicant's OE described in the LRA Section B.2.3. The applicant stated that plant-specific OE did not reveal any degradation. The
 
staff reviewed the OE reports provided in the LRA and in the plant basis documents, the staff
 
confirmed that the plant-specific OE reviewed did not reveal any reactor head closure stud
 
cracking or loss of material, or any other age related degradation with the RPV head studs, nuts, or washers.
 
The staff confirms that the "operating experience" program element satisfies the criterion
 
defined in the GALL Report and the guidance found in SRP-LR A.1.2.3.10. Therefore, the staff
 
finds this program element acceptable.
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary for the Reactor Head Closure Studs Program in LRA section A.1.2.40. The staff reviewed this section and finds
 
it acceptable because it is consistent with the corresponding program description in SRP-LR
 
Table 3.1-2. The staff determines that the information in the UFSAR supplement is an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
 
The staff confirms that, in LRA Commitment No. 3, the applicant has committed to the ongoing
 
implementation of the Reactor Head Closure Stud Program for aging management of those in-scope components for which the AMP is credited. The staff also confirms that the applicant has
 
placed this commitment for the Reactor Head Closure Stud Program in LRA Section A.1.2.40. 
 
Conclusion. On the basis of the review of the applicant's Reactor Head Closure Stud Aging Management 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 functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed
 
the UFSAR supplement for this AMP and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d) and; therefore, is acceptable.
 
3.0.3.1.3  BWR Vessel Inside Diameter Attachment Welds Program 
 
Summary of Technical Information in the Application. In LRA Section B.2.4, the applicant described the BWR Vessel ID Attachment Weld s Program as an existing program that is consistent with GALL Report AMP XI.M4, "BWR Vessel ID Attachment Welds." The applicant
 
stated that the program includes inspection and flaw evaluation, pursuant to the guidelines of
 
the staff-approved Boiling Water Reactor Vessel and Internals Project (BWRVIP) report
 
BWRVIP-48; and monitoring and control of reactor coolant water chemistry, pursuant to the
 
guidelines of BWRVIP-29. The program helps to ensure the long-term integrity and safe
 
operation of the vessel ID attachment welds.
3-18  Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also confirmed that the plant program contains all of the elements of the
 
referenced GALL Report. The staff also conducted onsite interviews with the applicant to
 
confirm these results.
 
The staff noted that the applicant's BWR Vessel ID Attachment Welds Program is based on the
 
augmented inspection and flaw evaluation guideline criteria in Boiling Water Reactor Vessel and
 
Internals Project (BWRVIP) Proprietary Topical Report No. TR-108724, "BWR Vessel and
 
Internals Project, Vessel [Inner Diameter] ID Attachment Weld Inspection and Flaw Evaluation
 
Guidelines (BWRVIP-48)." The staff approved the topical report to be credited for license
 
renewal in a safety evaluation (SE) dated January 17, 2001. The approved version of the topical
 
report is Topical Report BWRVIP-48-A.
 
In the SE on Topical Report BWRVIP-48-A, the staff issued three renewal applicant action items
 
for BWR applicants crediting BWRVIP-48-A for aging management of reactor vessel (RV) ID
 
attachment welds. The applicant provided the staff's renewal applicant action item descriptions
 
and its responses to these actions items in LRA Appendix C, Table BWRVIP-48-A. The three
 
action items follow:
 
(1) The staff's first renewal applicant action item required that applicants identify those guideline criteria aspects in BWRVIP-48-A that they might deviate from. The staff noted
 
that the applicant would not deviate from the recommended inspection and flaw
 
evaluation criteria provided in BWRVIP-48-A and; thus, determined that the applicant
 
adequately addressed the staff's action item. Based on this review, the staff concludes
 
that the applicant has adequately addressed the staff's first renewal applicant action
 
item on BWRVIP-48-A. Therefore, this renewal applicant action item is resolved.
(2) The staff's second renewal applicant action item required that BWR applicants provide a UFSAR supplement summary description of the AMP based on the BWRVIP-48-A
 
recommended criteria. The applicant stated that LRA Appendix A includes the UFSAR
 
supplement for the BWR Vessel ID Attachment Welds Program. The staff confirms that
 
the applicant has provided its UFSAR supplement summary description for the BWR
 
Vessel ID Attachment Welds Program in LRA Section A.1.2.9. The staff's evaluation of
 
the applicant's UFSAR supplement for this program follows later in this evaluation.
 
Based on this review, the staff concludes that the applicant has adequately addressed
 
the staff's second renewal applicant action item on BWRVIP-48-A. Therefore, this
 
renewal applicant action item is resolved.
(3) The staff's third renewal applicant action item required that BWR applicants ensure that the inspection criteria in BWRVIP-48-A will not conflict with or result in changes to the
 
plant's Technical Specifications (TSs). The applicant stated that its implementation of
 
the inspection strategy in BWRVIP-48-A will not result in the need for any changes to the
 
TS for either Unit 1 or Unit 2. The staff reviewed the TSs for Units 1 and 2 and confirms
 
that, while the methods in BWRVIP-48-A may constitute alternative staff-approved
 
inspection guidelines for the ASME Code Class 1 RV ID attachment welds, the TSs for Units 1 and 2 do not include any requirements to implement the ASME Code Section XI, Inservice Inspection (ISI) Programs requirements for the facility. The staff also confirms
 
that the applicant's TSs center on operational-based, surveillance-based, and
 
administrative control-based TS requi rements and that the ISI Program and requirements are implemented through the applicant's ASME Code Section XI, ISI 3-19 Program, pursuant to 10 CFR 50.55a. Thus, based on this review, the staff concludes that the applicant has provided an adequate basis for concluding that its implementation
 
of the guidelines in BWRVIP-48-A will not conflict with or result in any necessary
 
changes in the TSs. Based on this review, the staff concludes that the applicant has
 
adequately addressed the staff's third renewal applicant action item on BWRVIP-48-A.
 
Therefore, this renewal applicant action item is resolved.
 
Based on its review, the staff finds the applicant's BWR Vessel Inside Diameter Attachment
 
Welds Program consistent with the program elements of GALL AMP XI.M4 and; therefore, is acceptable.
 
Operating Experience. The staff reviewed the applicant's OE basis document for safety significant OE relevant to the aging management of BWR Vessel ID attachment weld
 
components. The staff noted that the applicant only provided an overall OE summary statement
 
in the "operating experience" program element for BWR Vessel ID Attachment Weld Program and did not provide any examples of SSES-spec ific or generic OE demonstrating that the AMP accomplishes its intended objective. However, the staff noted that the license renewal
 
program basis document for the BWR Vessel ID Attachment Welds Program did include the ISI outage summary reports for the Units 1 and 2 refueling and inspection outages (1RIO13 and
 
2RIO11, respectively). The staff confirmed that, in these outage summaries, the applicant did
 
not identify any recordable flaw indications resulting from its augmented inspections of the RV
 
ID attachment welds. 
 
Based on this review, the staff confirms that the applicant has been implementing the
 
inspections of its RV ID attachment welds in accordance with the ISI requirements of the ASME Code Section XI, as modified by the recommended augmented inspection criteria in Topical
 
Report No. BWRVIP-48-A and approved in the staff's SE on BWRVIP-48-A, dated
 
January 17, 2001. The staff finds that the applicant's refueling outages (RFOs) and inspection
 
reports (IRs) provide acceptable confirmation that currently there is no plant-specific OE for the
 
RV ID attachment welds inspected during outages 1RIO13 and 2RIO12.
 
The staff confirms that the OE program element satisfies the criterion defined in the GALL
 
Report and the guidance found in SRP LR Section A.1.2.3.10. Therefore, the staff finds this
 
program element acceptable.
 
UFSAR Supplement. The applicant provided an UFSAR supplement for its BWR Vessel ID Attachment Welds Program in LRA Section A.1.2.9, Commitment No. 4. The staff confirms that
 
the UFSAR supplement summary description for the BWR Vessel ID Attachment Welds
 
Program conforms to the staff's recommended UFSAR supplement for these type of programs as described in SRP-LR Table 3.1-2. The staff also confirms that in UFSAR Supplement
 
Table A-1, the applicant committed (Commitment No. 4) to ongoing implementation of its BWR
 
Vessel ID Attachment Welds Program for agi ng management of those Units 1 and 2 in-scope components that the AMP is credited for. Further, the staff confirms that the applicant has linked
 
this commitment to UFSAR Supplement A.1.2.9 for the BWR Vessel ID Attachment Welds
 
Program. Based on this review, the staff finds that UFSAR Supplement A.1.2.9, when coupled
 
to LRA Commitment No. 4, provides an acceptable UFSAR supplement summary description of
 
the applicant's BWR Vessel ID Attachment Welds Program. The staff determines that the
 
information in the UFSAR supplement is an adequate summary description of the program, as
 
required by 10 CFR 54.21(d).
 
Conclusion. On the basis of the audit and review of the applicant's BWR Vessel ID Attachment 3-20 Welds Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that effects of aging will be adequately managed
 
so that the intended function(s) will be maintained consistent with the CLB for the period of
 
extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR
 
supplement for this AMP and concludes that it provides an adequate summary description of the
 
program, as required by 10 CFR 54.21(d) and; therefore, is acceptable.
 
3.0.3.1.4  BWR Feedwater Nozzle Program 
 
Summary of Technical Information in the Application. In LRA Section B.2.5, the applicant described the BWR Feedwater Nozzle Program as an existing program that is consistent with GALL Report AMP XI.M5, "BWR Feedwater Nozzle." The applicant stated that this program includes enhanced ISI pursuant to ASME Code Section XI, Subsection IWB, Table IWB 2500-1
 
and the recommendations of report GE-NE-523-A71-0594; and system modifications to mitigate cracking.
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also confirmed that the plant program contains all of the elements of the
 
referenced GALL Report. The staff conducted onsite interviews with the applicant to confirm
 
these results.
 
In the "acceptance criteria" program element of the program basis document, the applicant stated that it may use acceptance criteria in staff-approved BWRVIP guideline documents as an alternative to the acceptance criteria for the FW nozzles required by the ASME Code Section XI, Subsection IWB. This is a similar statement to the one provided by the applicant in LRA B.2.1, "Inservice Inspection Program." 
 
In RAI B.2.1-2, dated June 12, 2008, the staff requested that the applicant clarify whether proposals to use alternative BWRVIP guideline criteria in lieu of ASME Code Section XI
 
requirements would be submitted for relief. 
 
In its response to RAI B.2.1-2, dated July 14, 2008, the applicant stated that all proposals to use staff-approved BWRVIP guideline criteria in lieu of applicable ASME Code Section XI
 
requirements will be submitted for staff approval as part of each 10-year ISI plan, pursuant to 10 CFR 50.55a. The staff noted that the applicant clarified that the use of the ASME Code Section XI, 1998 Edition, inclusive of the 2000 Addenda, is consistent with the program description statement in GALL AMP XI.M1 because the SOC on 10 CFR Part 54 clarifies that acceptable editions of the ASME Code Section XI are those acceptable endorsed editions of the ASME Code Section XI up through the most recently endorsed edition of the Code mentioned in
 
10 CFR 50.55a. The staff verified that the SOC on 10 CFR Part 54 does include this clarification, and that based on this clarification, use of the ASME Code Section XI, 1998
 
Edition, inclusive of the 2000 Addenda, is consistent with the Code edition mentioned in the program description of GALL AMP XI.M1. Based on this review, the staff finds the applicant's crediting of the ASME Code Section XI, 1998 Edition, inclusive of the 2000 Addenda (for aging management) is consistent with the criteria in GALL AMP XI.M1. The staff evaluated the
 
applicant's response to this RAI in SER Section 3.0.3.2.1. 
 
Based on the review, the staff finds the applicant's BWR Feedwater Nozzle Program consistent with the program elements of GALL AMP XI.M5 and; therefore, is acceptable.
 
Operating Experience. The staff reviewed the applicant's OE basis document for safety 3-21 significant OE relevant to the aging management of FW nozzles. The staff noted that the applicant had conducted pre-service examinations of the six Unit 1 FW nozzles and inner radii
 
were conducted and found no indications of cracking. Subsequent inspections of the Units 1
 
and 2 FW nozzles resulted in no recordable indications of cracking. The staff noted that the
 
program basis document provided OE events resu lting from augmented examinations that were performed on the FW nozzles during the last refueling and inspection outage for Unit 1.
 
Specifically, the staff noted that the applicant's augmented ultrasonic testing (UT) examinations of Unit 1 FW nozzle N4A indicated the presence of eight recordable flaw indications that were dispositioned as acceptable for further service, pursuant to ASME Code Section XI, IWB-3000.
 
However, the applicant did not cite these flaw indications as relevant OE for this AMP.
 
In RAI B.2.5-1, dated June 12, 2008, the staff requested that the applicant amend the "operating
 
experience" program element for LRA Section B.2.5 to identify cracking of the Unit 1 N4A FW
 
nozzle as relevant OE for the AMP and to explain in detail which augmented UT reinspection
 
frequency the applicant will use in the future for the Unit 1 FW nozzle N4A.
In its response to RAI B.2.5-1, dated July 14, 2008, the applicant amended the "operating
 
experience" program element to state that subsequent inspections of the Units 1 and 2 FW
 
nozzles have resulted only in one recordable indication, and consistent with industry OE and
 
corresponding staff-approved recommendations, the inspection frequency for the FW nozzles is
 
once per 10-year interval. The applicant also provided the following OE:
 
During the fourteenth Unit 1 refueling outage in March 2006, all critical regions of the  six Unit 1 feedwater nozzles were ultrasonically (UT) inspected as part of the ISI Program. No recordable indications were detected in five of the six nozzles. The UT
 
results for Nozzle N4A indicated one recordable flaw and seven other indications that
 
were too small to characterize as flaws. The one recordable flaw was evaluated against the criteria in ASME Section XI Table IWB 3510-1. It was determined to be acceptable
 
for continued service, since the flaw size was less than half of that allowed by IWB-3510.
 
This flaw indication did not represent a noticeable change from the previous inspection
 
results. Since the flaw indication is within the acceptance criterion established in ASME Section XI, no change in the inspection frequency for the N4A or any other feedwater nozzle at SSES is required by the ISI Program or ASME Section XI.
During the thirteenth Unit 2 refueling outage in March 2007, all critical regions of the six
 
Unit 2 feedwater nozzles were ultrasonically (UT) inspected as part of the ISI Program.
 
No recordable indications were detected in any of the six nozzles.
 
Based on its review, the staff finds the applicant's response to RAI B.2.5-1 acceptable because
 
the applicant has identified the flaw indications on the FW nozzle as part of its OE input, provided the inspection frequency, and provided the results of further inspections of the Unit 1
 
and 2 FW nozzles, which showed no recordable indications of cracking. Therefore, the staff's
 
concern described in RAI B.2.5-1 is resolved. 
 
The staff confirms that the OE program element satisfies the criterion defined in the GALL
 
Report and the guidance found in SRP LR Section A.1.2.3.10. Therefore, the staff finds this
 
program element acceptable.
 
UFSAR Supplement. The applicant provided the UFSAR supplement for its BWR Feedwater Nozzle Program in LRA Section A.1.2.6, Commitment No. 5. The staff reviewed this section and
 
finds it acceptable because it is consistent with the corresponding program description in 3-22 SRP-LR Table 3.1-2. The staff also confirms that the applicant has committed to ongoing implementation of its BWR Feedwater Nozzle Pr ogram for aging management of those in-scope components for which the AMP is credited. Further, the staff confirms that the applicant has
 
linked this commitment to UFSAR Supplement Section A.1.2.6 for the BWR Feedwater Nozzle
 
Program.
 
The staff notes that the description for the applicant's BWR Feedwater Nozzle Program states
 
that the UT methodology for the augmented inspections of the FW nozzles will be implemented
 
in accordance with the recommendations of BWR Owners Group Topical Report No. GENE-
 
523-71-0594. In contrast, the UFSAR supplement summary description for this AMP indicates
 
that the augmented UT inspections of the nozzles will be implemented in accordance with the
 
recommendations in applicable BWRVIP guidelines.
 
In RAI B.2.5-2, dated June 12, 2008, the staff requested that the applicant clarify which UT
 
methodology would be used in the BWR Feedwater Nozzle Program.
 
In its response to RAI B.2.5-2, dated July 14, 2008, the applicant stated that the BWR
 
Feedwater Nozzle Program is a part of the ISI Program. The applicant further stated that the ISI requirements for the FW nozzles comply with ASME Code Section XI, Subsection IWB, Table 2500-1, and staff-approved BWR Owners Group Topical Report, GENE-523-A71-0594, Revision 1, which provides guidance for inspecting the FW nozzle bore region using UT methodologies. The applicant also stated that this is consistent with GALL AMP XI.M5 and that
 
its BWR Feedwater Nozzle Program is committed to following the GENE-523-A71-0594, Revision 1 guidelines, during the period of extended operation. The applicant amended the LRA
 
to delete the references to BWRVIP guidelines from the LRA Section B.2.5 program description
 
and from LRA Section A.1.2.6.
 
Based on its review, the staff finds the applicant's response to RAI B.2.5-2 acceptable because
 
the applicant has sufficiently clarified that its ISI Program includes the BWR FW nozzles, and
 
the applicant has committed to following the staff-approved GENE-523-A71-0594, Rev. 1
 
guidelines during the period of extended operation, which makes the program consistent with GALL AMP XI.M5. Therefore, the staff's concern described in RAI B.2.5-2 is resolved.
 
Based on this review, the staff finds that UFSAR Supplement Section A.1.2.6, as amended, and
 
coupled to LRA Commitment No. 5, provides an acceptable UFSAR supplement summary
 
description of the applicant's BWR Feedwater Nozzle Program because it is consistent with the
 
UFSAR supplement summary guidance for BWR Feedwater Nozzle Programs in the SRP-LR. 
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of the review of the applicant's BWR Feedwater Nozzle Program and the applicant's response to the staff's RAIs, the staff finds all program elements consistent with
 
the GALL Report. The staff concludes that the applicant has demonstrated that effects of aging
 
will be adequately managed so that the intended function(s) will be maintained consistent with
 
the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concludes that, as amended, it provides an
 
adequate summary description of the program, as required by 10 CFR 54.21(d) and; therefore, is acceptable.
 
3-23 3.0.3.1.5  BWR Stress Corrosion Cracking Program 
 
Summary of Technical Information in the Application. In LRA Section B.2.7, the applicant described the BWR Stress Corrosion Cracking (SCC) Program as an existing program that is consistent with GALL AMP XI.M7, "BWR Stress Corrosion Cracking." The applicant stated that
 
the program includes preventive measures to mitigate intergranular stress corrosion cracking (IGSCC) and inspection and flaw evaluation to monitor IGSCC and its effects. The applicant
 
also stated that the staff-approved Boiling Water Reactor Vessel and Internals Project (BWRVIP) report BWRVIP-75 allows for modifications of inspection scope in the Generic Letter (GL) 88-01 program.
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also confirmed that the plant program contains all of the elements of the
 
referenced GALL Report. The staff conducted onsite interviews with the applicant to confirm
 
these results.
 
In comparing the elements in the applicant's program to those in GALL AMP XI.M7, the staff noted that the program elements in the applicant's AMP claim of consistency with the GALL
 
Report were consistent with the corresponding program element criteria recommended in GALL AMP XI.M7, with the exception of two program element aspects identified below that the staff determined required additional clarification. 
 
The staff noted in the program basis document t hat applicant's "preventive actions" program element for the BWR Stress Corrosion Cracking Program indicated that two welds scheduled for
 
stress relief had not received a post-weld heat treatment consistent with GL 88-01 and
 
NUREG-0313 recommendations and were unacceptable for stress relief credit by the staff. The
 
staff also noted that the applicant identified that the plant had initiated HWC control as a basis
 
for reducing the electro-chemical potentials of the Class 1 stainless steel welds below the
 
potential associated with the onset of SCC. 
 
In RAI B.2.7-1, dated June 12, 2008, the staff requested that the applicant discuss whether
 
there is any established link between the findings identified in the staff's SE on the applicant's
 
response to GL 88-01 and the circumferential SCC induced flaw indications detected in the
 
Unit 1 N2J recirculation outlet nozzle safe-end weld and in the Unit 1 NIB recirculation inlet
 
nozzle safe end weld. Specifically, the staff requested that the applicant identify whether these
 
safe-end nozzle welds were among the Class 1 stainless steel piping welds scheduled for
 
induction heat stress relief treatments and whether the N2J and NIB nozzle safe-end welds
 
were the same welds that had not received the recommended post-weld heat treatments as part
 
of this stress relief process. The staff further requested that the applicant identify the dates for
 
initiation of HWC at Units 1 and 2.
 
In its response to RAI B.2.7-1, dated July 14, 2008, the applicant stated:
 
The discussion in the license renewal basis document for the "preventive actions" program element for the BWR Stress Corrosion Cracking Program incorrectly stated that
 
there are "two SI-treated welds that were not given post-weld heat treatment." The
 
correct statement is that there are "two SI-treated welds that were not completely
 
ultrasonically examined post-SI."
 
The two welds in question are identified in the PPL letter to the NRC, PLA-3263, dated
 
October 2, 1989, as DCA1081-FW-5 and DCA1102-FW-6. These welds are piping welds 3-24 on the Unit 1 Residual Heat Removal System, not the SSES Unit 1 NIB and N2J recirculation nozzle-safe end welds. And, these piping welds did, in fact, have the
 
Induction Heating Stress Improvement Proce ss (IHSI) performed within two years of commercial operation, consistent with the NRC Generic Letter (GL) 88-01/NUREG-0313
 
recommendations. However, the post-IHSI ultrasonic examination (UT) of the welds
 
could not be performed, as required by NUREG-0313, due to the weld configuration. In
 
PLA-3263, PPL classified these two welds as IGSCC Category G and committed to
 
inspect the welds during the next refueling outage. In the NRC's SE on the SSES
 
response to GL 88-01, it was the classification of these two welds as IGSCC Category G
 
that the NRC found to be unacceptable. Subsequently, PPL inspected these welds
 
during the Unit 1 [fifth] refueling outage in 1990, and the welds are now classified as
 
IGSCC Category B. The Unit 1 N1B and N2J nozzle-safe end welds did not have IHSI
 
within two years of commercial operation. As these are dissimilar metal welds, IHSI is
 
not an appropriate stress improvement method. Instead, these welds had the
 
Mechanical Stress Improvement Process (MSI P) applied after approximately ten years of commercial operation. There is no link between the findings identified in the NRC's SE
 
on the PPL response to GL 88-01 and the flaw indications detected in the Unit 1 NIB and
 
N2J recirculation nozzle safe-end welds.
 
The staff reviewed the applicant's response and determines that the two welds in question were
 
on the residual heat removal (RHR) system and that those welds did receive the post-weld heat
 
treatment. The staff further determines that the applicant's recirculation nozzle safe-end welds
 
also received the post-weld heat treatment.
 
Based on its review, the staff finds the applicant's response to RAI B.2.7-1 acceptable because
 
the applicant has adequately clarified that the welds in question have been post-weld heat
 
treated, consistent with the GL 88-01 and NUREG-0313 recommendations, and have been
 
appropriately classified and inspected. Therefore, the staff's concerns described in RAI B.2.7-1
 
are resolved.
 
The staff noted that staff-approved guidelines in BWRVIP Topical Report BWRVIP-75A provide
 
the latest recommendations for augmented SCC ISIs. However, the staff noted that the
 
applicant had only credited the BWRVIP-75A criteria for expansion of the sample size upon
 
detection of a relevant SCC-induced flaw indication and that the applicant continued to use the
 
recommended augmented ISI criteria in GL 88-01 and NUREG-0313 to perform the augmented
 
ISI examinations (i.e., augmented UT examinations) of these stainless steel Class 1 pipe welds. 
 
In RAI B.2.7-2, dated June 12, 2008, the staff requested that the applicant clarify whether the
 
updated staff-approved guidelines in Topical Report BWRVIP-75A would be used as an option
 
for performing other aspects of the augmented ISI Program for these ASME Code Class 1
 
stainless steel pipe welds; and whether the flaw acceptance criteria in staff-approved Topical
 
Report BWRVIP-75A or Topical Report BWRVIP-14 will be used for the acceptance criteria of
 
any crack indications that might be detected in these ASME Code Class I stainless steel pipe
 
welds.
 
In its response to RAI B.2.7-2, dated July 14, 2008, the applicant stated that it does not use
 
BWRVIP-75-A for flaw acceptance criteria, since the report contains no flaw acceptance criteria
 
guidance. The applicant further stated that:
 
-flaw evaluation and acceptance criteria are in accordance with the ASME Code, Section XI, IWB-3640, as specified in NUREG-0313, Revision 2. PPL is committed to 3-25 follow all requirements of NUREG-0313, Revision 2, except for the inspection criteria and schedule. The NRC-approved BWRVIP-14 addresses crack growth evaluation of
 
flawed BWR shroud welds and other stainless steel internals. As part of the ASME Code
 
flaw evaluation, a crack growth analysis is required. While PPL may use certain data and
 
evaluation methods from BWRVIP-14 in a crack growth analysis, the evaluation and acceptance criteria will be in accordance with the ASME Code, Section XI, IWB-3640.
 
The staff reviewed BWRVIP-75-A, which provides the criteria and inspection schedule for
 
different categories of welds. Because BWRVIP-75-A does not contain flaw acceptance criteria, the staff finds it acceptable to use ASME Code, Section XI, IWB-3640 for flaw evaluation and
 
acceptance criteria, which includes the requirement of crack growth analysis because the
 
components within the scope of this AMP are ASME Code Class 1 components. The ASME Code Section XI provides the necessary informat ion to perform the crack growth analysis, which could be further supplemented by certain data and evaluation methods from BWRVIP-14.
 
Based on its review, the staff finds the applicant's response to RAI B.2.7-2 acceptable because
 
the applicant has adequately explained why its does not use the BWRVIP-75-A as a basis for flaw acceptance, but, rather, ASME Code, Section XI, IWB-3640. Therefore, the staff's concern
 
described in RAI B.2.7-2 is resolved.
 
Based on its review, the staff finds the applicant's BWR Stress Corrosion Cracking Program consistent with the program elements of GALL AMP XI.M7 and; therefore, is acceptable.
 
Operating Experience. The staff reviewed the applicant's OE described in the license renewal basis document for the BWR Stress Corrosion Cracking. The staff confirmed that the applicant
 
appropriately identified the circumferential crack indications in the Unit 1 N2J recirculation
 
nozzle outlet safe-end weld and the Unit 1 N1B recirculation inlet nozzle safe-end weld as
 
relevant OE for this AMP. The staff also confirmed that the applicant implemented the
 
inspections of these stainless steel welds through an augmentation of its ISI Program and that
 
the applicant provided the condition reports (CRs) on these events in the license renewal basis
 
binder for the AMP. 
 
The staff noted that the applicant also listed a CR on flaw indications in 12 small-bore Class 1
 
piping components as relevant OE for this AMP. The staff reviewed these CRs as part of its
 
onsite review of the AMP. The staff determined that the CRs demonstrated that the detection of
 
these flaw indications were the result of the non-destructive test examinations implemented
 
through an augmentation of the applicant's ISI Program, and that the CRs indicated that the
 
applicant had performed appropriate Code repairs of the flaw indications in the small bore
 
nozzle welds. Based on this review, the staff found that the applicant had taken appropriate
 
actions to address these small bore Class 1 pipe flaw indications.
 
Based on this review, the staff finds that: (1) the listing of relevant OE for this
 
AMP demonstrates that the applicant's BWR Stress Corrosion Cracking Program, as
 
implemented through an augmentation of the applicant's ISI  Program, achieves its objective of detecting relevant flaw indications (cracks) that may be induced by SCC, and (2) the applicant is
 
taking appropriate corrective actions for recordable flaw indications detected through
 
implementation of this program.
 
The staff confirms that the OE program element satisfies the criterion defined in the GALL
 
Report and the guidance found in SRP LR Section A.1.2.3.10. Therefore, the staff finds this
 
program element acceptable.
3-26  UFSAR Supplement. The applicant provided the UFSAR supplement for the BWR Stress Corrosion Cracking Program in LRA Section A.1.2.8, Commitment No. 7. The staff reviewed this
 
section and finds it acceptable because it is consistent with the corresponding program
 
description in SRP-LR Table 3.1-2. The staff also confirms that the applicant has committed (Commitment No. 7) in UFSAR Supplement Table A-1, to ongoing implementation of its BWR
 
Stress Corrosion Cracking Program for aging management of those in-scope components for
 
which the AMP is credited. 
 
Based on this review, the staff finds that the UFSAR supplement summary description, when
 
coupled with Commitment No. 7, provides an acceptable description of the applicant's BWR
 
Stress Corrosion Cracking Program because it is consistent with UFSAR supplement summary
 
description for Stress Corrosion Cracking Programs found in the SRP-LR.
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of its review of the applicant's BWR Stress Corrosion Cracking Program and its responses to the staff's RAIs, the staff finds all program elements consistent
 
with the GALL Report. The staff concludes that the applicant has demonstrated that effects of
 
aging will be adequately managed so that the intended function(s) will be maintained consistent
 
with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff
 
also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d) and; therefore, is
 
acceptable.
 
3.0.3.1.6  Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS)
 
Program 
 
Summary of Technical Information in the Application. In LRA Section B.2.10, the applicant described the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless
 
Steel (CASS) Program as a new program that w ill be consistent with the program elements in GALL AMP XI.M13, "Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic
 
Stainless Steel." The applicant stated that the program is credited to manage loss of fracture
 
toughness in RV internal components that are fabricated from CASS.
 
Staff Evaluation. During the audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also confirmed that the plant program contains all of the elements of
 
the referenced GALL Report. The staff conducted onsite interviews with the applicant to confirm
 
these results.
 
In comparing the elements in the applicant's program to those in GALL AMP XI.M13, the staff noted that the program elements in the applicant's AMP claim of consistency with the GALL
 
Report were consistent with the corresponding program element criteria recommended in GALL AMP XI.M13, with the exception of five program elements aspects identified below that the staff
 
determined required additional clarification. 
 
The "scope of program" program element for the Thermal Aging and Neutron Irradiation
 
Embrittlement of Cast Austenitic Stainless Steel Program, states that the CASS RV internal
 
components will be screened for their susceptibility to loss of fracture toughness by thermal
 
aging embrittlement and neutron irradiation embri ttlement. However, the program element does 3-27 not establish which staff-approved guideline(s) or basis document(s) will be used to screen the CASS RV internal components for susceptibility to these aging phenomena. Furthermore, the
 
staff noted an inconsistency between the applicant's "scope of program" and the "parameters
 
monitored/inspected" program element descripti ons in the license renewal basis document for the AMP. The staff noted that the applicant did not identify and distinguish between the specific
 
parameter criteria used to screen the CASS RV internal components for reduction of fracture
 
toughness by thermal aging embrittlement and by neutron irradiation embrittlement. 
 
In RAI B.2.10-1, dated June 12, 2008, 2008, the staff requested (part A) that the applicant
 
clarify which staff-approved guidance or basis document it will use for susceptibility screening
 
for loss of fracture toughness by thermal aging embrittlement and neutron irradiation
 
embrittlement. The staff also requested (part B) that the applicant explain the discrepancy
 
between the "scope of program" and the "paramet ers monitored/inspected" program elements for specific parameters used for susceptibility screening.
 
In its response to RAI B.2.10-1, part A, dated July 14, 2008, the applicant amended the LRA
 
and revised the "scope of program" element to delete the specific parameters identified and
 
instead added the staff-approved guideline that will be used for screening. The following
 
statement was added to LRA Section B.2.10:
 
Screening for thermal aging will be based on casting method, molybdenum content, and
 
ferrite content, in accordance with the criteria found in the May 19, 2000, letter from
 
Christopher Grimes (NRC) to D. J. Walters (NEI), "Thermal Aging Embrittlement of Cast
 
Austenitic Steel Components," and in EPRI Technical Report 100976, "Evaluation of
 
Thermal Aging Embrittlement for Cast Austenitic Steel Components," January 2001.
 
Screening for neutron embrittlement will use the fluence threshold of lE+17 n/cm² (E>1Mev).
 
Similarly, in response to RAI B.2.10-1 part B, the applicant deleted the specific parameters from
 
the "parameters monitored/inspected" element and instead added the following statement to
 
LRA Section B.2.10:
 
Those components screened as susceptible to Reduction of Fracture Toughness (either
 
due to thermal aging or neutron embrittlement) will require inspection unless it is
 
determined by component-specific evaluations that inspection is not required. The
 
component specific evaluation will include a mechanical loading assessment to
 
determine the maximum tensile loading on the component. If the loading is low enough
 
to preclude fracture, then supplemental inspection of the component is not required. 
 
Based on its review, the staff finds the applicant's response to RAI B.2.10-1 acceptable
 
because the applicant has correctly identified the staff-approved document it will use for
 
susceptibility screening, and has amended the "par ameters monitored/inspected" program element in the LRA that identifies how susceptible components will be inspected. The staff
 
determines that this action provides assurance that the applicant's program is consistent with GALL AMP XI.M13. Therefore, the staff's concern described in RAI B.2.10-1 is resolved. 
 
The staff noted in the program basis document that the "detection of aging effects" program
 
element indicates that the applicant may use UT as one of the inspection techniques to detect
 
cracking in these CASS components. However, the current state-of-the-art UT inspection
 
methods have not yet been qualified as being capable of detecting cracks in CASS materials. 
 
3-28 In RAI B.2.10-2, dated June 12, 2008, the staff requested (part A) that the applicant clarify whether the state-of-the-art UT techniques are capable of detecting cracks in CASS materials, and; if not, verify the alternate inspection technique or method that will be implemented to
 
monitor for cracking, if condition monitoring was chosen as the process for aging management
 
of fracture toughness. The staff also requested (part B) that the applicant justify the basis for the
 
"detection of aging effects" or "monitoring or trending" program elements for the AMP not
 
crediting a supplemental flaw tolerance analysis as an alternative for managing reduction of
 
fracture toughness in these CASS RV internal components. 
 
In its response to RAI B.2.10-2, part A, dated July 14, 2008, the applicant acknowledged that it
 
was not aware of any staff-approved UT techniques for detecting cracking in CASS
 
components. The applicant stated that the statements made in the LRA were intended to
 
preserve the option to include new examination techniques, such as UT, only if they are
 
developed and approved in the future. The applicant further stated that at present, the
 
enhanced visual examination (EVT-1) is the only staff-approved inspection technique, as recommended by GALL AMP XI.M13. The staff confirms that the applicant has revised the
 
"detection of aging effects" program element to delete the phrase "including visual, ultrasonic, and surface techniques," and replaced it with "enhanced visual."
 
In response to part B, the applicant stated that it did not credit a supplemental flaw tolerance
 
evaluation because the CASS RV internals covered by this program are not reactor coolant
 
pressure boundary (RCPB) components; consequently, a classic critical flaw size analysis is not
 
directly applicable. Once the susceptible components are identified, the applicant may perform
 
a component-specific evaluation as discussed in the "detection of aging effects" program element in GALL AMP XI.M13. The staff confirms that the applicant has amended the LRA to
 
include a statement in the "detection of aging effects" program element that for those
 
components screened as susceptible to reduction of fracture toughness that a component-
 
specific evaluation may be performed to determine whether supplemental inspection of the
 
component is required, as discussed under the "
parameters monitored or inspected" program element. 
 
Based on its review, the staff finds the applicant's response to RAI B.2.10-2 acceptable
 
because the applicant has adequately justified an alternate basis for managing the aging effects
 
by performing component-specific evaluati on supplemental evaluation when required.
Additionally, the staff finds the applicant's response acceptable because the applicant has
 
confirmed that it will perform enhanced visual technique examinations, by qualified personnel, consistent with the recommendations provided in the GALL Report, following procedures pursuant to ASME Code Section XI and 10 CFR Part 50, Appendix B. The staff determines that
 
the applicant will employ these alternate methods, if, based on screening, the material is
 
deemed susceptible and the aging effect is managed by inspection of the component.
 
Therefore, the staff's concerns described in RAI B.2.10-2 are resolved.
 
The staff noted that the BWRVIP in the "scope of program" program element states (in part) that
 
the program is credited for limited management of loss of material and reduction of fracture
 
toughness in the RV internal components at SSES.
 
In RAI B.2.10-3, dated June 12, 2008, the staff requested that the applicant clarify whether it is
 
crediting the BWRVIP as a option for managing reduction of fracture toughness in CASS RV
 
internal components and; if so, identify the BWRVIP as an exception to the CASS Program, identify the staff-approved BWRVIP-based guideline reports that will be credited and used, and
 
revise the UFSAR supplement, accordingly.
3-29  In its response to RAI B.2.10-3, dated July 14, 2008, the applicant clarified that as shown in
 
LRA Table 3.1.2-2, the BWRVIP is credited for managing reduction of fracture toughness for
 
components made of either stainless steel (non-cast) or nickel-based alloy. The applicant also
 
stated that the BWRVIP is not credited for managing reduction of fracture toughness for any
 
CASS RV internal components. The applicant further stated that as shown in LRA Table 3.1.2-
 
2, the Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS)
 
Program is credited for managing reduction of fracture toughness for all CASS RV internals and; therefore, there is no exception to GALL AMP XI.M13.
 
The staff reviewed LRA Table 3.1.2-2 for CASS components and noted that applicant has
 
credited the Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS) Program to manage the aging effect of reduction of fracture toughness for all CASS RV
 
internal components. The staff also confirmed that the non-CASS internal components are
 
managed by the BWRVIP.
 
Based on its review, the staff finds the applicant's response to RAI B.2.10-3 acceptable
 
because the applicant has adequately clarified that the BWRVIP is credited for managing
 
reduction of fracture toughness for components made of either stainless steel (non-cast) or
 
nickel-based alloy, only. Therefore, the staff's concern described in RAI B.2.10-3 is resolved.
 
Based on its review, the staff finds the applicant's Thermal Aging and Neutron Irradiation
 
Embrittlement of Cast Austenitic Stainless Steel Program consistent with the program elements of GALL AMP XI.M13 and; therefore, is acceptable.
 
Operating Experience. The staff reviewed the applicant's OE described in the license renewal basis document for the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic
 
Stainless Steel Program. The applicant has identified the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS) Program as a new program for Units 1 and 2, and did not report any OE events on reduction of fracture toughness in CASS RV internal
 
components as being relevant to the "operating experience" program element for the AMP.
However, for this program, and for other new AMPs where the applicant provided no current
 
plant-specific OE, the staff issued a generic RAI.
 
In RAI B.2-1, dated June 10, 2008, the staff requested that the applicant commit to provide
 
documentation of plant-specific OE for staff review after the program has been implemented, but, prior to entering the period of extended operation.
 
In its response to RAI B.2.1, dated July 8, 2008, the applicant stated that OE will be gained for
 
new AMPs described in LRA Appendix B as thes e programs are implemented during the period of extended operation. The applicant stated that results of tests, inspections, and other aging
 
management activities conducted in accordance with these programs will be subject to
 
confirmation and corrective action elements of the Susquehanna 10 CFR Part 50, Appendix B, Quality Assurance Program. Results will be subject to staff review during regional inspections, under existing staff inspection modules. Test and inspection results that do not meet
 
acceptance criteria will be evaluated under the Units 1 and 2 Corrective Action Program, which
 
includes requirements to identify appropriate corrective actions and verify the effectiveness of
 
those actions. Items entered into the SSES Corrective Action Program are available for review
 
by the NRC Resident Inspector.
 
The staff noted the applicant's statement that inspection methods will be consistent with 3-30 industry practices and are consistent with the "operating experience" program element for GALL AMP XI.M13. The staff also noted that regional staff site-inspections provide an opportunity for
 
staff review and assessment of the effectiveness of the applicant's Thermal Aging and Neutron
 
Irradiation Embrittlement of Cast Austenitic Stainless Steel Program, after the applicant has
 
developed OE with that program. The staff concludes that the corrective action program, based
 
on internal and external plant OE, will capture OE to support the conclusion that the effects of
 
aging are adequately managed. On this basis, the staff finds this program element acceptable
 
and concludes that a separate commitment is not necessary. 
 
The staff confirms that the OE program element satisfies the criterion defined in the GALL
 
Report and the guidance found in SRP LR Section A.1.2.3.10. Therefore, the staff finds this
 
program element acceptable.
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary for the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program in LRA
 
Section A.1.2.48, Commitment No. 10. The staff reviewed this section and finds it acceptable
 
because it is consistent with the corresponding program description in SRP-LR Table 3.1-2. The
 
staff also confirms that the applicant has committed to implement the new Thermal Aging and
 
Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program prior to entering
 
the period of extended operation. 
 
Based on this review, the staff finds that UFSAR Supplement Section A.1.2.48, when coupled
 
with Commitment No. 10, provides an acceptable UFSAR supplement summary description of
 
the applicant's Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless
 
Steel Program because it is consistent with the guidance in the SRP-LR for Thermal Aging and
 
Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Programs. 
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of its review of the applicant's Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program and the applicant's response to the
 
staff's RAIs, the staff finds all program elements consistent with the GALL Report. The staff
 
concludes that the applicant has demonstrated that effects of aging will be adequately managed
 
so that the intended function(s) will be maintained consistent with the CLB for the period of
 
extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR
 
supplement for this AMP and concludes that it provides an adequate summary description of the
 
program, as required by 10 CFR 54.21(d) and, therefore, is acceptable.
 
3.0.3.1.7  Flow-Accelerated Corrosion (FAC) Program 
 
Summary of Technical Information in the Application. In LRA Section B.2.11, the applicant described the Flow-Accelerated Corrosion Program as an existing program that is consistent with the GALL Report AMP XI.M17, "Flow-Accelerated Corrosion." The applicant stated that this
 
program follows the guidance and recommendations of EPRI Nuclear Safety Analysis Center (NSAC)-202L and combines the elements of predictive analysis, inspections (to baseline and
 
monitor wall thinning), industry experience, station information gathering and communication, and engineering judgment to monitor and predict FAC wear rates.
 
Staff Evaluation. During its audit the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also confirmed that the plant program contains all of the elements of the 3-31 referenced GALL Report. The staff conducted onsite interviews with the applicant to confirm these results.
 
The staff reviewed the applicant's license renewal basis document and confirmed that the
 
program scope includes the systems and component s that could be affected by FAC. In comparing the elements in the applicant's program to those in GALL AMP XI.M17, the staff noted that the program elements in the applicant's AMP claiming consistency with the GALL
 
Report were consistent with the corresponding program element criteria recommended in GALL AMP XI.M17, with the exception of two program element aspects identified below that the staff determined required additional clarification. 
 
In the "scope of program" program elemen t, the applicant identified the systems and components within the scope of this program. However, the staff noted that the carbon steel
 
condensers (shell) from LRA Table 3.4.2-4, the condenser and air removal system; the carbon
 
steel turbine casings from LRA Table 3.4.2-7, and the main turbine system were not included in
 
the program element, "scope of the program." The staff further noted that the FAC Program is
 
credited to manage the aging effect for both of these components in LRA Table 3.4.2-4 and
 
3.4.2-7.
 
In RAI B.2.11-1, dated May 30, 2008, the staff requested that the applicant confirm that these
 
components are included in the scope of the existing FAC Program and; if not, justify why LRA
 
Section B.2.11 is not enhanced to include these components.
 
In its response to RAI B.2.11-1, dated June 30, 2008, the applicant stated that the condenser
 
and air removal system and the main turbine system are included in the scope of license
 
renewal because they are non-related safety systems impacting safety-related systems. The condenser shell was credited as the anchor for the safety-related piping and provided a
 
structural integrity function. However, the applicant stated that another anchor has been
 
identified for this pipe line before it reaches the condenser. The staff determined that with the
 
elimination of the structural integrity function, there are no aging effects that require
 
management for the condenser shell, and the  FAC Program need not be credited. Therefore, the applicant revised LRA Tables 2.3.4-4, 3.4.1, and 3.4.2-4 to remove the condenser shell from
 
the scope of license renewal.
 
The applicant stated the main turbine continues to be credited for structural integrity. However, since the main turbine is not within the scope of the current FAC Program, the applicant
 
proposes to use a plant-specific program to manage loss of material due to FAC for the HP
 
turbine. The "Preventive Maintenance Activities - Main Turbine Casing Program" is an existing
 
plant-specific program proposed by the applicant.
The staff's evaluation of this program is documented in SER Section 3.0.3.3.4.
 
The staff reviewed the applicant's response and concludes that because the applicant proposes
 
a plant-specific program to manage the aging effect of loss of material due to FAC, the staff
 
finds it acceptable that the applicant does not include the main turbine casing in the scope of
 
the Flow-Accelerated Corrosion Program.
 
Based on its review, the staff finds the applicant's response to RAI B.2.11-1 acceptable
 
because the applicant has verified and the staff confirms that the condenser shell is no longer
 
used for structural integrity to support a safety-related system and as a result, need not be
 
within the scope of license renewal. The staff also confirms that the applicant has revised the
 
appropriate LRA tables to remove the condenser shell from the scope of license renewal.
3-32 Therefore, the staff's concern described in RAI B.2.11-1 is resolved.
 
In the "monitoring and trending" program element, it was not clear to the staff what criterion the applicant used to increase sample size. GALL AMP XI.M17 states that inspection results are
 
evaluated to determine whether additional inspections are needed to assure that the extent of
 
wall thinning is adequately determined.
 
In RAI B.2.11-2, dated May 30, 2008, the staff requested that the applicant explain how it
 
expands sample size and what acceptance criterion is used for sample expansion.
 
In its response to RAI B.2.11-2, dated June 30, 2008, the applicant stated that the FAC Program
 
procedure requires an inspection sample expansion "if the remaining life of an inspected
 
component cannot be calculated to be at least one operating cycle." The applicant further stated
 
that the remaining life calculation is based on the measured component wall thickness and the
 
calculated wear rate. The applicant also stated that this procedure provides additional guidance
 
when the remaining life is adequate for another operating cycle, but inspection results are other
 
than what was expected. The applicant indicated that expanded sample inspections are
 
specified to capture locations with the highest probability of significant wear. The applicant
 
noted that this guidance is consistent with EPRI NSAC-202L, and requires an updated FAC
 
analysis and additional inspections, as appropriate, if inspection results are unexpected and
 
inconsistent with predictions. 
 
Based on its review, the staff finds the applicant's response to RAI B.2.11-2 acceptable
 
because the applicant has adequately explained how it expands sample size and what
 
acceptance criterion is used for sample expansion. 
 
The staff concludes that because this guidance ensures that if unexpected results occur, a
 
review of the systems is performed, and samp le expansion is considered to capture the locations with the highest probability of significant wear. Therefore, the staff's concern described
 
in RAI B.2.11-2 is resolved.
 
Based on its review, the staff finds the applicant's FAC Program consistent with the program elements of GALL AMP XI.M17 and; therefore, is acceptable.
 
Operating Experience. The staff reviewed the applicant's OE described in LRA Section B2.11 and interviewed the applicant's technical personnel to confirm that the plant-specific OE did not
 
reveal any aging effects not bounded by the GALL Report. The staff also confirmed that
 
applicable aging effects and industry and plant-specific OE have been reviewed by the applicant
 
and are evaluated in the GALL Report. 
 
The staff also reviewed the applicant's "operating experience" discussion provided in the
 
applicant's license renewal basis document for the FAC Program. The staff reviewed a sample
 
of condition reports and confirmed that the applicant has identified FAC and implemented
 
appropriate corrective actions. The staff noted that in the last Unit 1 and Unit 2 outages, over
 
120 locations in each unit were inspected and eleven additional examinations in each unit were
 
performed as expanded scope. The applicant identified planned replacements and performed
 
emergent replacements. The staff reviewed the results of the outages for Units 1 and 2 and
 
confirmed that appropriate corrective actions were implemented. 
 
Furthermore, the staff confirmed that the applicant has addressed OE identified after the
 
issuance of the GALL Report. The staff finds that the applicant's FAC Program, with the 3-33 corrective actions discussed in the LRA, has been effective in identifying, monitoring, and correcting the effects of FAC and can be expected to ensure that piping wall thickness will be
 
maintained above the minimum required by design.
 
The staff confirms that the OE program element satisfies the criterion described in the GALL
 
Report and the guidance found in SRP LR Section A.1.2.3.10. Therefore, the staff finds this
 
program element acceptable.
 
UFSAR Supplement. The applicant provided the UFSAR supplement for the FAC Program in LRA Section A1.2.20, Commitment No. 11. The staff reviewed this section and finds it
 
acceptable because it is consistent with the corresponding program description in SRP-LR
 
Table 3.4-2. The staff confirms that the applicant has committed to implement the FAC Program
 
through the period of extended operation.
 
Based on this review, the staff determines that UFSAR Supplement Section A1.2.20 provides
 
an acceptable UFSAR supplement summary description of the applicant's FAC Program
 
because it is consistent with the UFSAR supplement summary description for FAC Program in
 
the SRP-LR.
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of its review of the applicant's FAC Program and the applicant's response to the staff's RAIs, the staff finds all program elements consistent with the GALL
 
Report. The staff concludes that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended function(s) will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed
 
the UFSAR supplement for this AMP and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d) and; therefore, is acceptable.
 
3.0.3.1.8  Crane Inspection Program 
 
Summary of Technical Information in the Application. In LRA Section B.2.15, the applicant described the existing Crane Inspection Program as consistent with GALL AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems."
 
The Crane Inspection Program manages the effects of general corrosion on the crane and
 
trolley structural components for those cranes that are within the scope of 10 CFR 54.4, and the
 
effects of wear on the rails in the rail syst em. The program utilizes guidance found in American National Standards Institute (ANSI) B30.2 "Overhead and Gantry Cranes (Top Running Bridge, Single or Multiple Girder, Top Running Trolley Hoist)", ANSI B30.11 "Monorails and Underhung
 
Cranes", and ANSI B30.16 "Overhead Hoists (Underhung)." 
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff confirmed that the plant program contains all of the elements of the
 
referenced GALL Report. The staff conducted onsite interviews with the applicant to confirm
 
these results.
 
In RAI B.2.15-1, dated June 30, 2008 the staff requested that the applicant explain the scope of
 
its Crane Inspection Program. In comparing the elements in the applicant's program to those in GALL AMP XI.M23, the staff found that the applicant did not explicitly identify "the effects of
 
wear on the rails in the rail system" in their basis document for the program element, "scope of 3-34 program." It was unclear to the staff whether this item should have been identified as an exception.
 
In its response to RAI B.2.15-1, dated July 28, 2008, the applicant stated that although "the
 
effects of wear on the rails in the rail system" wa s not explicitly identified in the program basis documents, it is indeed an aging effect which is managed by the Crane Inspection Program.
 
The staff confirms that the applicant has revised LRA Section B.2.15 to clarify the intent of the
 
program to specifically include wear of the crane rails.
 
Based on its review, the staff finds the applicant's response to RAI B.2.15-1 acceptable
 
because the applicant has clarified that "the effects of wear on the rails in the rail system" is an
 
aging effect which is managed by the Crane Inspection Program and has revised the LRA to
 
clarify the intent of this AMP. Therefore, the staff's concern described in RAI B.2.15-1 is
 
resolved.
 
Similarly, the staff found that the applicant did not explicitly identify "wear" in its basis document
 
for the GALL report program element, "acceptance criteria." It is unclear to the staff whether this
 
item should have been identified as an exception.
 
In RAI B.2.15-2, dated June 30, 2008, the staff requested that the applicant further explain the
 
scope its Crane Inspection Program.
 
In its response to RAI B.2.15-2, dated July 28, 2008, the applicant stated that although wear of
 
the crane rails was not explicitly identified in the GALL Report acceptance criteria program element, it is indeed an aging effect which is managed by the Crane Inspection Program. The
 
staff confirms that the applicant has also revised LRA Section B.2.15, Crane Inspection
 
Program to clarify the intent of the program to specifically include wear of the crane rails.
 
Based on its review, the staff finds the applicant's response to RAI B.2.15-2 acceptable
 
because the applicant has clarified that "wear" is an aging effect which is managed by the SSES
 
Crane Inspection Program and has revised the LRA to clarify the intent of this AMP. Therefore, the staff's concern described in RAI B.2.15-2 is resolved.
 
On the basis of its onsite review and discussions with the applicant, the staff determined that
 
the applicant's Crane Inspection Program is implemented through SSES's procedures based on
 
staff-approved guidance. Inspections to detect degradation are visual in nature, and are
 
conducted on a routine basis, which include annual inspections for the reactor building crane
 
and refueling platform, and bi-annual inspections for the diesel generator bridge cranes. In
 
addition, the staff noted, through review of station procedures, that some more infrequently used
 
cranes are inspected either every two years or prior to use.
 
In comparing the seven program elements in t he applicant's program, the staff finds that the applicant has addressed the elements in a satisfactory manner. Furthermore, the staff finds that these elements were consistent with GALL AMP XI.M23. 
 
Operating Experience. The staff also reviewed the applicant's OE described in LRA Section B.2.15. The applicant stated that "Related crane/hoist inspections have found no
 
age-related degradation problems." Through the review of OE reports, including a sample of
 
condition reports and interviews of the applicant's technical staff, the staff confirmed that the
 
plant-specific OE did not reveal any degradation not bounded by industry experience. During an
 
onsite audit review of plant-specific documentation, the staff found that in 2007, a crack was 3-35 detected in a structural load-bearing weld. This incident was not reported in the LRA OE summary. The staff determined more information was needed to assess the severity of the
 
incident.
 
In RAI B.2.15-3, dated June 30, 2008, the staff requested that the applicant provide a detailed
 
explanation on the 2007 crane incident.
 
In its response to RAI B.2.15-3, dated July 28, 2008, the applicant stated that follow up
 
corrective actions were completed in a timely manner to adequately address the issue. These
 
actions included inspection of the weld, an engineering evaluation, consultation with the crane
 
vendor's engineer, repair of the weld, load testing, and finally a re-inspection. The applicant
 
returned the crane to service after it had determined that all tests were satisfactory. The staff
 
determined that the crack in a structural load-bearing weld is OE already bounded by industry
 
experience, and was properly addressed by the applicant's aging management program.
 
Based on its review, the staff finds the applicant's response to RAI B.2.15-3 acceptable
 
because the applicant has provided a satisfactory explanation of the incident involving a crack
 
detected in a structural load-bearing weld and the corrective actions taken to address the issue.
 
Therefore, the staff's concern described in RAI B.2.15-3 is resolved. 
 
The staff confirms that the "operating experience" program element satisfies the criterion
 
defined in the GALL Report and the guidance found in SRP-LR A.1.2.3.10. Therefore, the staff
 
finds this program element acceptable.
 
UFSAR Supplement. The applicant provided the UFSAR supplement for the Crane Inspection Program in LRA section A.1.2.17, Commitment No. 14. The staff reviewed this section and finds
 
it acceptable because it is consistent with the corresponding program description in SRP-LR
 
Table 3.3-2.
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d). 
 
The staff confirmed that the applicant has committed to the ongoing implementation of the
 
Crane Inspection Program for aging management of those in-scope components for which the
 
AMP is credited. The staff also confirmed that the applicant has placed this commitment for the
 
Crane Inspection Program in UFSAR Supplement Summary Section A.1.2.17. 
 
Conclusion. On the basis of its review of the applicant's Crane Inspection Aging Management Program, as well as the applicant's RAI responses, the staff finds all program elements
 
consistent with the GALL Report. The staff concludes that the applicant has demonstrated that
 
effects of aging on crane and trolley structural components for those cranes within the scope of
 
10 CFR 54.4, and the effects of wear on the rails in the rail system will be adequately managed
 
so that the intended functions of these components will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed
 
the UFSAR supplement for this AMP and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d) and; therefore, is acceptable.
 
3.0.3.1.9  Condensate and Refueling Water Storage Tanks Inspection Program
 
Summary of Technical Information in the Application
. In LRA B2.19, the applicant described the Condensate and Refueling Water Storage Inspections Program as a new one-time inspection 3-36 that, in conjunction with the Systems Walkdown Program, will be consistent with the GALL AMP XI.M29, "Aboveground Steel Tanks."
 
The applicant stated that this program, in c onjunction with the Systems Walkdown Program, includes the inspection of the condensate storage tank (CST) and refueling water storage tank (RWST) inaccessible surfaces (i.e. tank bottoms) and accessible external surfaces.
 
Furthermore, the applicant stated that this program includes volumetric and/or visual
 
inspections that will be used to provide an indication of loss of material due to crevice, general
 
or pitting corrosion that has occurred or may likely occur.
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the applicant's AMP evaluation for the Condensate and
 
Refueling Water Storage Tanks Inspection Program, together with the applicant's program basis
 
documents. The applicant claims that the Condensate and Refueling Water Storage Tanks
 
Inspection Program, in conjunction with the Syst ems Walkdown Program, will be consistent with GALL AMP XI.M29. 
 
In comparing the seven program elements in the applicant's program to those in  GALL AMP XI.M29, the staff noted that the applicant claimed that the program elements in the
 
applicant's AMP were consistent with the GALL Report. However the staff required additional
 
information to complete its review of two program elements; "scope of program" and
 
"acceptance criteria." 
 
The staff further noted that, based on GALL AMP XI.M29, paints, coatings, sealants and
 
caulking are to be monitored for degradation. In the Condensate and Refueling Water Storage
 
Tanks Inspection Program, the applicant stated that these materials will be monitored under the
 
Systems Walkdown Program. Upon review of the Systems Walkdown Program basis documents, the staff noted that these materials were not included in the scope of program for
 
this AMP.
 
In RAI B.2.19-1, dated June 13, 2008, the staff requested that the applicant explain the basis for
 
not scoping in paints, coatings, sealants and caulking as materials that should be monitored for
 
degradation, in either the Condensate and Refueling Water Storage Tanks Inspection Program
 
or the Systems Walkdown Program. The staff al so requested that the applicant explain the method in which the applicant will visually inspect these materials under the Systems Walkdown
 
Program.
 
In its response to RAI B.2.19-1, dated July  24, 2008, the applicant stated that one exception
 
was taken which affects the "scope of program,"
"preventative actions," "parameters monitored or inspected," "detection of aging effects," and "acceptance criteria" program elements. The
 
"operating experience" program element is discussed separately below.
 
The staff noted in the applicant's response to RAI B.2.19-1, dated July  24, 2008, that the applicant has taken an exception to GALL XI.M29 for the "scope of program," "preventative actions," "parameters monitored or inspected," "detection of aging effects," and "acceptance
 
criteria" program elements. The staff evaluation of this exception follows.
 
Based on GALL AMP XI.29, the staff determined that corrective actions are initiated upon the
 
detection of any degradation of paints, coatings, sealants and caulking. However, the staff
 
noted that in the applicant's Condensate and Refueling Water Storage Tanks Inspection
 
Program and the Systems Walkdown Progr am, the corresponding program element 3-37 "acceptance criteria" states that there shall be no unacceptable loss of material.
 
In RAI B.2.19-2, dated June 13, 2008, the staff requested that the applicant explain the discrepancy between the GALL AMP XI.M29 and the applicant's Condensate and Refueling
 
Water Storage Tanks Inspection Program and the Systems Walkdown Program and; justify its
 
basis for taking actions only upon the detection of an unacceptable loss of material. Additionally, the staff requested that the applicant explain why the program element for the Condensate and
 
Refueling Water Storage Tanks Inspection Program and Systems Walkdown Program differs from GALL AMP XI.M29.
 
In its response to RAI B.2.19-2, dated July 24, 2008, the applicant stated that it has clarified and
 
amended LRA Section B.2.19 to state that any indications of loss of material detected during
 
the inspection of the tank bottoms will be reported and evaluated. The staff confirmed that the
 
applicant has amended LRA Section B.2.19 to state that the results of the volumetric test
 
performed on the tank bottom will be evaluated against the design thickness, and any indication
 
of loss of material will be reported through the corrective actions process and then evaluated
 
against the design corrosion allowance. The staff also confirmed that the applicant had
 
amended LRA Section B.2.19 to state that indications of corrosion on the accessible external
 
surface of the tanks will be reported and will require further evaluation.
 
Based on its review, the staff finds the applicant's response acceptable because the applicant
 
has amended LRA Section B.2.19 to state that any indication of degradation on the tanks
 
bottoms and corrosion on the accessible external surfaces will be reported and evaluated, consistent with recommendations in GALL AMP XI.M29. Therefore, the staff's concerns
 
described in RAI B.2.19-2 are resolved.
 
Exception 1 Based on the applicant's response to RAI B.2.19-1, the following exception was taken which affects the "scope of program," "preventative ac tions," "parameters monitored or inspected,"
"detection of aging effects," and "acceptance criteria" program elements: 
 
Coatings of the tanks surfaces are not credited for preventing corrosion. The
 
coatings do not perform an intended function for license renewal, aging
 
management is not required, and degradation is not reported.
 
Sealants at the interface between the tanks and the concrete pedestal is
 
evaluated as a structural commodity and is not within the scope of the
 
Condensate and Refueling Water Storage Tanks Inspection.
 
The staff noted in the applicant's response to RAI B.2.19-1, dated July  24, 2008, that the
 
applicant does not credit paints and coating for prevention and mitigation of corrosion on the
 
external surfaces of the CST and RWST. The staff further noted that since paints, coatings, sealants and caulking are not credited for aging management as part of license renewal, the
 
applicant is not required to manage aging effects that may affect paints, coating, sealants and
 
caulking as part of the Systems Walkdown Program. However, the applicant stated that caulking
 
and sealants will be inspected by the Structures Monitoring Program. The staff confirms that the
 
scope of the applicant's Structures Monitoring Program includes the CST and RWST and
 
inspection of the associated caulking and sealants at the foundation and support pedestals. The
 
staff notes that visual inspections of the condition of paints and coatings on the external
 
surfaces of the CST and RWST will indicate whether degradation and corrosion is occurring on 3-38 the underlying material, even though paints and coatings are not credited.
 
Based on its review, the staff finds the applicant's response to RAI B.2.19-1 acceptable
 
because: (a) the applicant has not credited paints and coatings with preventing and mitigating
 
aging of the underlying materials, and therefore does not require aging management; (b) the
 
applicant will perform periodic visual inspections of the external surfaces of the tanks to
 
determine the condition of the underlying metallic material; and (c) the staff confirmed that
 
sealants and caulking are inspected and monitored by the applicant's Structures Monitoring
 
Program. Therefore, the staff's concern described in RAI B.2.19-1 is resolved.
 
The staff finds the applicant's exception acceptable because the applicant will perform its
 
periodic visual inspections of the external surfaces of the CST and RWST for indications of
 
corrosion of the underlying material, and the staff has confirmed that the applicant will inspect
 
and monitor sealants and caulking by the Structures Monitoring Program.
 
Operating Experience. The staff reviewed the applicant's OE described in the license renewal basis document for the Condensate and Refueling Water Storage Tanks Inspection Program.
 
The applicant stated that the Condensate and Refueling Water Storage Tanks Inspection
 
Program is a new one-time inspection activity for which there is no OE and that inspection
 
methods will be consistent with accepted industry practices. For this program and for other new
 
AMPs where the applicant provided no current plant-specific OE, the staff issued a generic RAI.
 
In RAI B.2.1, dated June 10, 2008, the staff requested that the applicant commit to provide
 
documentation of plant-specific OE, for staff review, after the program has been implemented, but prior to entering the period of extended operation.
 
In its response to RAI B.2.1, dated July 8, 2008, the applicant stated that OE for new AMPs
 
described in LRA Appendix B will be gained as t hese new programs are implemented during the period of extended operation. The applicant further stated that results of tests, inspections, and
 
other aging management activities conducted in accordance with these programs will be subject
 
to confirmation and corrective action elements of the Susquehanna 10 CFR Part 50, Appendix B, Quality Assurance Program and that results will be subject to staff review during
 
regional inspections under existing staff inspection modules. The applicant also stated that it will
 
perform one-time inspections, prior to entry to the period of extended operation, to confirm the
 
effectiveness of existing AMPs, and that these programs are subject to review under NRC
 
Inspection Procedure 71003, "Post-Approval Site Inspection for License Renewal." 
 
The staff notes that the applicant's statement that inspection methods will be consistent with
 
industry practices is consistent with the "operating experience" program element for GALL AMP XI.M29. The staff also notes that post-approv al site inspections provide an opportunity for staff review and assess the effectiveness of the applicant's Condensate and Refueling Water
 
Storage Tanks Inspection Program, after the applicant has developed OE with that program.
 
The staff concludes that the corrective action program, based on industry and plant-specific OE, will capture future OE to support the conclusion that the effects of aging are adequately
 
managed. 
 
During its review, the staff noted that even though the applicant states OE does not currently
 
exist for this program, the applicant reviewed its CRs Database for indications of degradation of
 
the CSTs and RWSTs and did not find any indications. During its onsite review, the staff
 
reviewed the CRs for the Systems Walkdown Pr ogram provided in the license renewal basis documents, in order to determine whether there have been indications of degradation to the 3-39 protective coatings, sealants, caulking and tank bottoms of the CSTs and RWSTs. Based on its review, the staff did not identify any CRs related of the degradation to the protective coatings, sealants, caulking and tank bottoms of the CSTs and RWSTs.
 
On this basis, the staff confirms that the "operating experience" program element satisfies the
 
criterion defined in the GALL Report and the guidance in SRP-LR Section A.1.2.3.10. Therefore, the staff finds this program element acceptable and concludes that a separate commitment is
 
not necessary. 
 
The staff reviewed this section and finds it acceptable because it is consistent with the
 
corresponding description in SRP-LR Table 3.3-2 and because the summary description includes the bases for determining that aging effects will be managed.
 
The staff determines that the UFSAR supplement for this AMP provides 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 Condensate and Refueling Water Storage Tanks Inspection Program and the applicant's responses to the RAIs, the staff
 
finds all program elements consistent with the GALL Report. 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 its credited. 
 
The staff concludes that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended function(s) will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed
 
the UFSAR supplement for this AMP and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d), and; therefore, is acceptable.
 
3.0.3.1.10  Chemistry Program Effectiveness Inspection 
 
Summary of Technical Information in the Application. In LRA Section B.2.22, the applicant described the new Chemistry Program Effectiv eness Inspection as consistent with GALL AMP XI.M32, "One-Time Inspection." The applicant stated that the program is a one-time
 
inspection program to detect and characterize the condition of materials in representative
 
low-flow and stagnant areas of plant systems in fluenced by the BWR Water Chemistry Program, the Closed Cooling Water Chemistry Program, and the Fuel Oil Chemistry Program, all of which are mitigation programs. The applicant also stated that the inspection provides direct evidence
 
as to whether, and to what extent, a loss of material due to crevice, general, or pitting corrosion
 
and to microbiologically influenced corrosion (MIC) in fuel oil, as well as cracking due to SCC of
 
susceptible materials in susceptible locations has occurred. The applicant further stated that
 
implementation of the program (Commitment No. 19), which is scheduled to be completed
 
during the 10-year period prior to the period of extended operation, will provide confirmation of chemistry program effectiveness and assure that the integrity of susceptible components is
 
maintained consistent with the CLB during the period of extended operation.
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the applicant's AMP evaluation for the Chemistry Program Effectiveness Inspection, together with the applicant's program outline which provides specific
 
guidance for preparation of implementing procedures related to this new program. The staff
 
noted the program elements in the AMP that the applicant claimed were consistent with the GALL Report are consistent with GALL AMP XI.M32, with the exception of two program element 3-40 aspects for which the staff required additional information.
 
The staff noted that the applicant's description of the "monitoring and trending" program element
 
for the Chemistry Program Effectiveness Inspecti on refers to using engineering evaluations to determine sample size and inspection locations, but provides no details of the methodology to
 
be used.
 
In RAI B.2.22-1, dated June 23, 2008, the staff requested that the applicant describe the
 
methodology it will use to select sample sizes and sample locations for various components and
 
also explain what methodology or basis will be used for sample size expansion, if unanticipated
 
aging effects are found.
 
In its response to RAI B.2.22-1, dated July 17, 2008, the applicant stated the following:
 
The sample population will be selected such that it is representative of each
 
material and environment combination within the scope of the inspection.
 
Consideration will be given in the sample selection to the variations among the
 
treated water environments that could affect the potential for aging effects to
 
occur. Each material type exposed to fuel oil will also be included in the sample
 
population. The sample selection will focus on those locations determined to be
 
subject to low flow or stagnant conditions, as these locations are expected to be
 
the most likely to first experience the effects of degradation should it be
 
evidenced. Identification of the inspection locations will be based on engineering
 
knowledge of the system(s), supported by walkdowns of the systems as necessary, including the time in service and severity of operating condition. The
 
inspection will focus on those systems, or portions of systems, most subject to stagnant or low flow condition.
 
The results of the inspection of the sample population will be reviewed for any
 
evidence of degradation. If degradation is detected the results will be entered into
 
the SSES corrective action program. The corrective action program requires
 
evaluation of the extent of the degradation, the effect on the component intended
 
function, and the necessary corrective actions. The need to perform inspections
 
of a larger portion of the total population of components within the scope of the
 
activity will also be considered.
 
The staff confirms that the applicant has amended LRA Section B.2.22 and revised the second
 
paragraph in the discussion of "monitoring and trending" to read as follows:
 
Sample size will be determined by engineering evaluation, as described for the
 
"detection of aging effects" program element above. Unacceptable inspection
 
findings will be evaluated using the SSES corrective action process. The
 
evaluation done under the SSES corrective action program will identify
 
appropriate corrective actions including the need to perform additional
 
inspections.
 
In evaluating the applicant's response, the staff noted that the applicant provided additional
 
qualitative information with regard to the methodology it used to select sample sizes and
 
locations. The applicant also provided a link between its corrective action program and its
 
methodology and basis for sample size expansion. The staff noted that the additional
 
information provided by the applicant with regard to the "monitoring and trending" program 3-41 element is at a level of detail consistent with the description of this program element in GALL AMP XI.M32. 
 
Based on its review, the staff finds the applicant's response to RAI B.2.22-1 acceptable
 
because the applicant has provided an adequate description of its Chemistry Program
 
Effectiveness Inspection which is consistent with the program element as described in the GALL
 
Report. Therefore, the staff's concern described in RAI B.2.22-1 is resolved.
The staff noted that the applicant's description of the "acceptance criteria" program element
 
for the Chemistry Program Effectiveness Inspection states that there shall be "no
 
unacceptable loss of material, or cracking of stainless steel exposed to temperatures above
 
140ºF, that could result in a loss of component intended function during the period of
 
extended operation, as determined by engineering evaluation." However, the "acceptance
 
criteria" program element in the GALL Report states that any indication or relevant conditions of degradation detected are to be evaluated.
 
In RAI B.2.22-2, dated July 17, 2008, the staff requested that the applicant explain why the
 
acceptance criteria in the applicant's program is different from the recommendation in the
 
GALL Report and clarify what is meant by "no unacceptable loss of material or cracking," as
 
used in the acceptance criteria for the applicant's program.
 
In its response to RAI B.2.22-2, dated July 17, 2008, the applicant stated the following: 
 
Any indications or relevant conditions of degradation detected during the
 
inspections will be evaluated. Similar to the example provided in the GALL text, the inspection observations will be compared to predetermined acceptance
 
criteria. Inspection results that do not meet the acceptance criteria will be entered
 
into the corrective action program for evaluation.
 
The staff confirms that the applicant has amended LRA B.2.22 to provide consistency with the description of the "acceptance criteria" program element in GALL AMP XI.M32 and has revised
 
the text to read as follows:
 
Any indications or relevant conditions of degradation detected during the
 
inspections will be compared to pre-determined acceptance criteria. If the
 
acceptance criteria are not met, then the indications/conditions will be evaluated
 
under the SSES corrective action program to determine whether they could result
 
in a loss of component intended function during the period of extended operation.
 
In evaluating the applicant's response, the staff notes that that the applicant's revision to the
 
LRA brings its description for the "acceptance cr iteria" in the Chemical Program Effectiveness Inspection into conformance with the "acceptance criteria" program element in GALL AMP XI.M32.
 
Based on its review, the staff finds the applicant's response to RAI B.2.22-2 acceptable
 
because the applicant has adequately explained the basis for why the acceptance criteria in the
 
Chemistry Program Effectiveness Inspection di ffers from the recommendation in the GALL Report and has revised the LRA to correct the discrepancy. The staff determines that with this
 
revision, the "acceptance criteria" program element of the applicant's program is consistent with
 
the same program element in the GALL Report. Therefore, the staff concern described in
 
RAI B.2.22-2 is resolved.
3-42  In a letter dated December 11, 2008, the applicant amended the description of the Chemical
 
Program Effectiveness Inspection in LRA Section B.2.22. The applicant revised the "scope of
 
program" description to state that the Chemical Program Effectiveness Inspection includes the surfaces of nickel-alloy components, in addition to aluminum, copper alloy, carbon, and low
 
alloy steel, cast iron, and stainless steel components, which were already listed as within the
 
scope of the AMP. The applicant also made a similar revision to LRA Commitment No. 19 to
 
add surfaces of nickel-alloy components, in addition to the other previously listed materials of
 
construction.
 
The applicant stated that it had reviewed an LRA change made in response to RAI B.2.14-2, dated August 12, 2008, and identified that its earlier change with respect to components in the
 
diesel generator system was incomplete. The applicant further stated that in its earlier change, corrosion monitoring probes in the diesel jacket cooling water system would be used to monitor
 
actual corrosion rates as part of the Closed Cooling Water Chemistry Program and that the
 
Chemical Program Effectiveness Inspection would not be used to monitor corrosion in the diesel jacket cooling water system. The applicant also stated that a subsequent review determined
 
that the corrosion probes are used only to monitor corrosion of steel components, and that the
 
Chemical Program Effectiveness Inspection will be used to confirm that loss of material is not
 
occurring in other diesel jacket cooling water system components, including nickel-alloy (Monel)
 
heat exchanger tube plugs.
 
The staff reviewed the applicant's changes to the Chemical Program Effectiveness Inspection
 
"scope of program" program element and commitment as described above. The staff determines that surface examinations prov ided by the applicant's Chemical Program Effectiveness Inspection for other materials are also capable of detecting loss of material due to
 
pitting or crevice corrosion in nickel-alloy components. On the basis that the Chemistry Program
 
Effectiveness Inspection AMP includes surface examinations that can detect loss of material in
 
nickel alloy components, the staff finds the applicant's addition of nickel-alloy components to the
 
"scope of program" program element and to LRA Commitment No. 19 to be acceptable.
 
Based on its staff's review, and resolution of the related RAIs as described above, the staff finds
 
the Chemistry Program Effectiveness Inspection c onsistent with the program elements of GALL AMP XI.M32 and; therefore, is acceptable.
 
Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.22.
The applicant stated that the Chemistry Program Effectiveness Inspection is a new one-time
 
inspection activity for which there is no OE and that inspection methods will be consistent with
 
accepted industry practices. For this program and for other new AMPs where the applicant
 
provided no current plant-specific OE, the staff issued generic RAI B.2.1.
 
In RAI B.2.1, dated June 10, 2008, the staff requested that the applicant commit to provide
 
documentation of plant-specific operating for staff review, after the program has been
 
implemented, but prior to entering the period of extended operation.
 
In its response to RAI B.2.1, dated July 8, 2008, the applicant stated that OE for new AMPs
 
described in LRA Appendix B will be gained as these programs are implemented during the
 
period of extended operation. The applicant further stated that results of tests, inspections, and
 
other aging management activities, conducted in accordance with these programs, will be
 
subject to confirmation and corrective action elements of the Susquehanna 10 CFR Part 50, Appendix B, Quality Assurance Program. The results will be subject to staff review during 3-43 regional inspections under existing staff inspection modules. The applicant also stated that, to confirm the effectiveness of existing AMPs, one-ti me inspections will be performed prior to entry into the period of extended operation, and that these programs are subject to review under NRC
 
Inspection Procedure 71003, "Post-Approval Site Inspection for License Renewal."
 
The staff notes the applicant's statement that inspection methods will be consistent with industry
 
practices is consistent with the "operating experience" program element for GALL AMP XI.M32.
The staff also notes that post-approval site inspections provide an opportunity for staff review
 
and assessment of the effectiveness of the applicant's Chemistry Program Effectiveness Inspection, after the applicant has developed OE with that program. The staff concludes that the
 
corrective action program, based on internal and external plant OE, will capture OE to support
 
the conclusion that the effects of aging are adequately managed. On this basis, the staff
 
confirms that the "operating experience" program element satisfies the criterion defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10. Therefore, the staff finds
 
this program element acceptable and concludes that a separate commitment is not necessary. 
 
UFSAR Supplement. The applicant provided the UFSAR supplement for the Chemistry Program Effectiveness Inspection in LRA Section A.1.2.12, Commitment No. 19. The staff also notes that
 
the applicant has committed to implement the C hemistry Program Effectiveness Inspection for aging management of applicable components during the 10-years prior to the period of
 
extended operation.
 
Based on this review, the staff finds that the UFSAR supplement summary in LRA
 
Section A.1.2.12 provides an acceptable description of the applicant's Chemistry Program
 
Effectiveness Inspection because it is consistent with the UFSAR supplement summary
 
description for the One-Time Inspection program in the SRP-LR.
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of its review of the applicant's Chemistry Program Effectiveness Inspection and resolution of the relevant RAIs as described above, the staff finds all program
 
elements consistent with the GALL Report. The staff concludes that the applicant has
 
demonstrated that effects of aging will be adequately managed so that the intended function(s)
 
will be maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concludes that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d) and; therefore, is acceptable.
 
3.0.3.1.11  Cooling Units Inspection 
 
Summary of Technical Information in the Application. In LRA Section B.2.23, the applicant described the Cooling Units Inspection Program as a new program that will be consistent with GALL AMP XI.M32, "One-Time Inspection." The applicant stated that this program will detect
 
and characterize the condition of aluminum, carbon steel, copper alloy, and stainless steel
 
cooling unit components that are exposed to a v entilation environment or to an uncontrolled raw water environment from cooling unit drain pans, and of certain heat exchanger components exposed to treated water or ventilation environments. The applicant further stated that the
 
inspection provides direct evidence as to whether and to what extent, loss of material or
 
reduction of heat transfer has occurred, or may likely occur and result in a loss of intended
 
function.
3-44  Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. In comparing the elements in the applicant's program to those in GALL AMP XI.M32, the staff noted that the program elements in the applicant's AMP claim of
 
consistency with the GALL Report were consistent with GALL AMP XI.M32, with the exception of four program element aspects identified below that the staff determined required additional
 
clarification. The staff also confirmed that the plant program contains all of the elements of the
 
referenced GALL Report. The staff conducted onsite interviews with the applicant to confirm
 
these results.
 
In the "scope of program" program element, the applicant stated that this program detects loss of material due to crevice and pitting corrosion and selective leaching of the copper-alloy cooler
 
channel in the control structure heating, ventilation, and air conditioning (HVAC) system. GALL AMP XI.M33, "Selective Leaching of Materials," states that selective leaching generally does not
 
cause changes in dimensions and is difficult to detect. The examination techniques used by the Cooling Units Inspection Program to detect degradation are visual and/or volumetric. Neither
 
one of these techniques by itself will detect selective leaching.
 
In RAI B.2.23-1, dated June 23, 2008, the staff requested that the applicant justify how this
 
program will manage selective leaching and expl ain why these components are not included in the Selective Leaching Inspection Program.
 
In its response to RAI B.2.23-1, dated July 25, 2008, the applicant amended the LRA to credit
 
the Selective Leaching Inspection Program, in place of the Cooling Units Inspection Program, to
 
manage loss of material due to selective leaching of the copper control structure HVAC cooler
 
channels.
 
Based on its review, the staff finds the applicant's response to RAI B. 2.23-1 acceptable
 
because the applicant has amended the LRA to manage these components for loss of material
 
due to selective leaching with the Selective Leaching Inspection Program, which contains
 
appropriate techniques to manage this aging effect. Therefore, the staff's concern described in
 
RAI B.2.23-1 is resolved.
 
In the "detection of aging effects" program element, the applicant stated that a combination of
 
established volumetric or visual examination techniques will be used to identify evidence of loss of material or to confirm a lack thereof. However, GALL AMP XI.M32 recommends specific
 
inspection methods which are dependent on aging effects and mechanisms.
 
In RAI B.2.23-2, dated June 23, 2008, the staff requested that the applicant clarify the
 
inspection techniques that it will use.
 
In its response to RAI B.2.23-2, dated July 25, 2008, the applicant stated that visual inspection (VT-1 or equivalent) and/or volumetric inspection (radiographic test (RT) or UT) techniques will
 
be used to determine whether crevice or pitting corrosion is occurring; visual inspection (VT-3 or
 
equivalent) and/or volumetric inspection (RT or UT) techniques will be used to determine
 
whether galvanic or general corrosion is occurring; and visual inspection (VT-3 or equivalent)
 
techniques will be used to determine whether reduction in heat transfer is occurring. The
 
applicant also stated that the specific inspection technique will be determined prior to the inspection activities and will be consistent with the recommendations in GALL AMP XI.M32.
 
Based on its review, the staff finds the applicant's response to RAI B. 2.23-2 acceptable 3-45 because the applicant has identified specific inspection techniques it will use for detection of the aging mechanisms that are consistent with the recommendations in GALL AMP XI.M32.
 
In the "monitoring and trending" program element, the applicant stated that no actions are taken
 
as part of this program, since it is a one-time inspection activity. In the "monitoring and trending" program element, GALL AMP XI.M32 states that "unacceptable inspection findings are
 
evaluated in accordance with the site corrective action process to determine the need for
 
subsequent (including periodic) inspections-" 
 
In RAI B.2.23-3, dated June 23, 2008, the staff requested that the applicant confirm whether the
 
corrective action program will increase the sample size, in the event aging effects are detected. 
 
In its response to RAI B.2.23-3, dated July 25, 2008, the applicant responded that unacceptable
 
inspection findings will be evaluated under the SSES Corrective Action Program. The evaluation
 
performed under this program will identify appropriate corrective actions, including the need to
 
perform additional inspections.
 
Based on its review, the staff finds the applicant's response to RAI B.2.23-3 acceptable
 
because the applicant has confirmed that it will evaluate unacceptable inspection findings under
 
the SSES Corrective Action Program and take appropriate corrective action, including the need
 
to perform additional inspections. The staff further finds the response acceptable because the applicant's actions are consistent with the recommendations of the GALL AMP XI.M32
 
"monitoring and trending" program element. Therefore, the staff's concern described in
 
RAI 2.23-3 is resolved.
 
In the "acceptance criteria" program element, GALL AMP XI.M32 states that any indication or relevant conditions of degradation detected are evaluated. However, in LRA Section B.2.28, the
 
applicant stated under the acceptance criteria that: "no unacceptable loss of material (or wall
 
thinning), could result in a loss of component intended function, during the period of extended
 
operation, as determined by engineering evaluation."
 
In RAI B.2.23-4, dated June 23, 2008, the staff requested that the applicant explain why the
 
acceptance criteria for the Cooling Units Inspection Program differ from the recommendations of
 
the GALL Report and clarify what is meant by "no unacceptable loss of material (or wall
 
thinning)."
 
In its response to RAI B.2.23-4, dated July 25, 2008, the applicant amended LRA Cooling
 
Unit Inspection Program "acceptance criteria" element to state:
 
Any indications or relevant conditions of degradation detected during the inspections will
 
be compared to pre-determined acceptance criteria. If the acceptance criteria are not
 
met, then the indications/conditions will be evaluated under the SSES Corrective Action
 
Program to determine whether they could result in a loss of component intended function
 
during the period of extended operation.
 
Based on its review, the staff finds the applicant's response to RAI B.2.23-4 acceptable
 
because the applicant has adequately explained why the acceptance criteria for the Cooling
 
Units Inspection Program differ from the recommendations of the GALL Report and has
 
sufficiently clarified what is meant by "no unacceptable loss of material (or wall thinning)." The
 
staff also finds the applicant's response acceptable because the applicant has amended the
 
"acceptance criteria" program element for this AMP to be consistent with the recommendations 3-46 in GALL AMP XI.M32. Therefore, the staff's concern described in RAI B.2.23-4 is resolved.
 
Based on its review, the staff finds the applicant's Cooling Units Inspection Program consistent with the program elements of GALL AMP XI.M32 and; therefore, is acceptable.
 
Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.23 and interviewed the applicant's technical personnel to confirm that the plant-specific OE did not
 
reveal any aging effects not bounded by the GALL Report. The staff also confirmed that
 
applicable aging effects and industry and plant-specific OE have been reviewed by the applicant
 
and are evaluated in the GALL Report. 
 
The "operating experience" program element states that the Cooling Units Inspection Program is a new program and there is no plant-specific program OE indicating the need for an aging
 
management progam. However, the staff noted that the applicant has generated several CRs
 
during walkdowns, surveillance and maintenance activities on the cooling units that are included
 
in the scope of this program.
 
In RAI B.2.23-5, dated June 23, 2008, the staff requested that the applicant identify whether
 
there exists, any age related degradation documentation for these cooling units. 
 
In its response to RAI B.2.23-5, dated July 25, 2008, the applicant stated that CRs associated
 
with the cooling units within the scope of the Cooling Units Inspection Program have been
 
generated during various routine plant activities. The applicant also stated that a review of those
 
CRs did not identify any age-related degradation for the specific subcomponents addressed by
 
the Cooling Units Inspection Program.
 
Based on its review, the staff finds the applicant's response to RAI B.2.23-5 acceptable
 
because the applicant has reviewed the condition reports for OE and did not identify any
 
age-related degradation for the specific subcomponents addressed by the Cooling
 
Unit Inspection Program. Therefore, the staff's concern described in RAI B.2.23-5 is resolved.
 
Furthermore, the staff confirms that the applicant has addressed OE identified after the
 
issuance of the GALL Report. The staff finds that the applicant's Cooling Units Inspection
 
Program can be expected to ensure that the effects of aging will be adequately managed during
 
the period of extended operation.
 
The staff also confirms that the OE program element satisfies the criterion defined in the GALL
 
Report and the guidance found in SRP LR Section A.1.2.3.10. Therefore, the staff finds this
 
program element acceptable.
 
UFSAR Supplement. The applicant provided the UFSAR supplement for the Cooling Units Inspection Program in LRA Section A.1.2.16, Commitment No. 20. The staff reviewed this
 
section and finds that it is acceptable because it is consistent with the corresponding program
 
description in SRP-LR Table 3.3-2 and because the applicant has committed to implement the
 
Cooling Units Inspection Program within the 10-year period prior to the period of extended
 
operation.
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of the review of the applicant's Cooling Units Inspection Program and 3-47 the applicant's response to the staff's RAIs, 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 functions will be maintained consistent
 
with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff
 
also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d), and; therefore, is
 
acceptable.
 
3.0.3.1.12  Heat Exchanger Inspection
 
Summary of Technical Information in the Application. In LRA Section B.2.24, the applicant described the Heat Exchanger Inspection Program as a new program that will be consistent with GALL Report AMP XI.M32, "One-Time Inspection." The applicant stated that this program will
 
detect and characterize cracking due to SCC and reduction in heat transfer due to fouling of
 
heat exchanger tubes exposed to treated water. 
 
The applicant further stated that the inspection provides direct evidence as to whether, and to
 
what extent, cracking due to SCC or reduction in heat transfer due to fouling has occurred or is
 
likely to occur that may result in a loss of intended function. 
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also confirmed that the plant program contains all of the elements of the
 
referenced GALL Report and that the conditions at the plant are bounded by the conditions for
 
which the GALL Report is evaluated. The staff conducted onsite interviews with the applicant to
 
confirm these results.
 
The staff noted the applicant stated that instead of focusing on a representative sample
 
population, the Heat Exchanger Inspection Program will be applied to all heat exchangers within
 
the scope of the program. The inspection and test techniques will be as recommended by GALL AMP XI.M32 for detecting the aging effect of concern.
 
The staff reviewed the applicant's license renewal basis document and confirmed that the
 
program scope includes all the heat exchangers likely to be affected by the heat exchanger
 
inspection. In its response to RAI B.2.17-2, dated June 30, 2008, and as identified in the SER
 
section 3.0.3.2.9, the applicant stated that this program will detect and characterize reduction in
 
heat transfer due to fouling of heat exchanger tubes exposed to raw water or a lubricating oil
 
environment, which brought additional components into the scope of this program. The
 
applicant added the diesel-engine driven fire pump heat exchangers and oil coolers in the
 
program scope. The staff noted that the additional components the applicant has brought into
 
the scope of program are appropriate, and are heat exchanger components that require aging
 
management as part of this program.
 
Based on its review, the staff finds the applicant's Heat Exchanger Inspection Program consistent with the program elements of GALL AMP XI.M32 and; therefore, is acceptable.
 
Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.24 and interviewed the applicant's technical personnel to confirm that the plant-specific OE did not
 
reveal any aging effects not bounded by the GALL Report. The staff also confirmed that
 
applicable aging effects and industry and plant-specific OE have been reviewed by the applicant
 
and are evaluated in the GALL Report. 
 
3-48 The applicant stated for the "operating experience" program element that the Heat Exchanger Inspection Program is a new program and there is no plant-specific program OE. However, the
 
applicant further stated that during performance of surveillance tests or preventive maintenance, any observed degradation of tubes would have been documented.
 
In RAI B.2.24-1, dated June 23, 2008, the staff requested that the applicant identify examples of
 
issues that may have been documented to address age-related degradation of the heat
 
exchanger tubes within the scope of this program, and include them in the OE element.
 
In its response to RAI B.2.24-1, dated July 25, 2008, the applicant stated that a review of
 
documentation generated during various routine plant activities associated with the heat
 
exchangers was performed within the scope of the Heat Exchanger Inspection Program. The
 
review did not identify any age-related degradation of the heat exchanger tubes within the scope
 
of this inspection.
 
Based on its review, the staff finds the applicant's response to RAI B.2.24-1 acceptable
 
because the applicant has verified and the staff confirms that the applicant's review of plant OE
 
related to the heat exchangers within the scope of the Heat Exchanger Inspection Program did
 
not identify any age related degradation. Therefore, the staff's concern described in
 
RAI B.2.24-1 is resolved.
 
The staff finds that the applicant's Heat Exchanger Inspection Program can be expected to
 
ensure that effects of aging will be adequately managed during the period of extended
 
operation.
 
The staff confirms that the OE program element satisfies the criterion defined in the GALL
 
Report and the guidance found in SRP-LR Section A.1.2.3.10. Therefore, the staff finds this
 
program element acceptable.
 
UFSAR Supplement. The applicant provided the UFSAR supplement for the Heat Exchanger Inspection Program in LRA Section A.1.2.22, Commitment No. 21, amended by letter dated
 
June 30, 2008. The staff reviewed this section and finds it acceptable because it is consistent, with the amendment, with the corresponding program description in SRP-LR Table 3.3-2. The
 
staff confirms that the applicant has amended the UFSAR supplement to include the diesel
 
engine driven fire pump heat exchangers and oil coolers in the UFSAR supplement and had
 
committed to implement the Heat Exchanger Inspec tion Program within the 10-year period, prior to the period of extended operation.
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of its review of the applicant's Heat Exchanger Inspection Program and the applicant's response to the RAIs, 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 functions will be maintained consistent
 
with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff
 
also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d) and; therefore, is
 
acceptable.
3-49  3.0.3.1.13  Lubricating Oil Inspection
 
Summary of Technical Information in the Application. In LRA Section B.2.25, the applicant described the "Lubricating Oil Inspection Program" as a new program consistent with GALL AMP XI.M32, "One-Time Inspection Program." The app licant stated that this program will verify the effectiveness of Lubricating Oil Analysis Program by sampling systems and components exposed to lubricating oil. The program will test fo r a loss of material due to crevice, galvanic, general or pitting corrosion. In addition, this program will also test for selective leaching or
 
reduction in heat transfer due to fouling. 
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also confirmed that the plant program contains all of the elements of the
 
referenced GALL Report and that the conditions at the plant are bounded by the conditions for
 
which the GALL Report is evaluated. The staff conducted onsite interviews with the applicant to
 
confirm these results.
 
In comparing the seven program elements in the applicant's program to those in  GALL AMP XI.M32, the staff noted the program elements in the applicant's AMP claim of
 
consistency with the GALL Report were consistent with GALL AMP XI.M32, with the exception of one program element; namely, the "scope of program." The staff determined a need for
 
additional clarification which resulted in the issuance of RAIs. The "operating experience"
 
program element is discussed separately below.
 
The staff noted that the Lubricating Oil Inspection and Lubricating Oil Analysis Programs
 
manage components in the diesel generator, control structure chilled water, residual heat
 
removal (RHR), reactor core isolation cooling (RCIC), and high-pressure coolant injection (HPCI) systems. It was not clear to the staff whether there are additional systems that require management by these two AMPs because of their exposure to lubricating oil.
 
In RAI B.2.25-1, dated July 10, 2008, the staff requested that the applicant identify whether
 
there are any other systems exposed to lubricat ing oil that are within the scope of license renewal.
 
In its response to RAI B.2.25-1, dated August 12, 2008, the applicant stated that during its
 
review of LRA Section B.2.25, it had identified that the reactor building chilled water system was
 
omitted from the systems that are within the scope of the programs that manage aging for lubricating oils. The staff confirmed that the applicant amended LRA Section B.2.25 to include
 
the reactor building chilled water system within the scope of this program.
 
Based on its review, the staff finds the applicant's response to RAI B.2.25-1 acceptable
 
because the applicant has identified the reactor building chilled water system as a system
 
exposed to lubricating oil and has amended the LRA to reflect the addition of this system within
 
the scope of the Lubricating Oil Inspection Program.
 
Operating Experience. The staff reviewed the applicant's OE discussion described in the license renewal basis document for the Lubricating Oil Analysis Inspection Program. The applicant
 
stated that this AMP is a new one-time inspection activity for which there is no OE and that
 
inspection methods will be consistent with accepted industry practices. For this program and for
 
other new AMPs where the applicant provided no current plant-specific OE, the staff issued
 
generic RAI B.2.1 3-50  In RAI B.2.1, dated June 10, 2008, the staff requested that the applicant commit to provide
 
documentation of plant-specific OE for staff review, after the program has been implemented, but prior to entering the period of extended operation.
 
In its response to RAI B.2.1, dated July 8, 2008, the applicant stated that OE for new AMPs
 
described in LRA Appendix B will be gained as these new programs are implemented, during
 
the period of extended operation. The applicant further stated that results of tests, inspections, and other aging management activities conducted in accordance with these programs, will be
 
subject to confirmation and corrective action elements of the Susquehanna 10 CFR Part 50, Appendix B, Quality Assurance Program and that results will be subject to staff review during
 
regional inspections under existing staff inspection modules. The applicant also stated that
 
one-time inspections will be performed prior to entry to the period of extended operation to
 
confirm the effectiveness of existing AMPs, and t hat these programs are subject to review under NRC Inspection Procedure 71003, "Post-Approval Site Inspection for License Renewal." 
 
The staff noted the applicant's statement that inspection methods will be consistent with
 
industry practices is consistent with the "operating experience" program element for GALL AMP XI.M32. The staff also noted that post-approval site inspections provide an opportunity for staff to review and assess the effectiveness of the applicant's Lubricating Oil Inspection
 
Program, after the applicant has developed OE with that program. The staff concludes that the
 
corrective action program, based on industry and plant-specific OE, will capture OE to support
 
the conclusion that the effects of aging are adequately managed. On this basis, the staff
 
confirms that the applicant's "operating experience" program element satisfies the criterion
 
defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10. Therefore, the staff finds this program element acceptable and concludes that a separate commitment is
 
not necessary. 
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary of the Lubricating Oil Inspection Program in LRA Section A.1.2.29, Commitment No. 49. The staff
 
reviewed this section and finds it acceptable because it is consistent with the corresponding
 
program description in SRP-LR Table 3.2-1. The staff confirms that the applicant has committed
 
to implementing this program prior to the period of extended operation, and that the applicant
 
has amended the LRA to include the reactor building chilled water system within the scope of
 
the Lubricating Oil Inspection Program. The staff also confirms that the applicant has placed this
 
commitment for the Lubricating Oil Inspection Program in UFSAR Supplement Summary
 
Section A.1.2.29. 
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of the audit and review of the applicant's Lubricating Oil Inspection Program and the applicant's responses to the RAIs, the staff finds all program elements
 
consistent with the GALL Report. Also, the staff confirms that the applicant has committed (Commitment No. 49) to implement this program prior to the period of extended operation. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately
 
managed so that the intended function(s) will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the
 
UFSAR supplement for this AMP and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d) and; therefore, is acceptable.
 
3-51  3.0.3.1.14  Main Steam Flow Restrictor Inspection
 
Summary of Technical Information in the Application. In LRA Section B.2.26, the applicant described the Main Steam Flow Restrictor Ins pection Program as a new program that will be consistent with GALL AMP XI.M32, "One-Time Inspection." The applicant stated that this
 
program will detect and characterize reduction of fracture toughness of the CASS
 
subcomponents of the main steam flow restrictors. The applicant also stated that the inspection
 
will detect cracking that is symptomatic of reduction of fracture toughness. The applicant further
 
stated that reduction of fracture toughness does not cause cracking, but the reduced toughness
 
allows existing cracks to propagate at higher rates. 
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. In comparing the elements in the applicant's program to those in GALL AMP XI.M32, the staff noted the program elements in the applicant's AMP claim of consistency with the GALL Report were consistent with GALL AMP XI.M32, with the exception of the three
 
program element aspects identified below, for which the staff determined required additional
 
clarification. The staff confirmed that the applicant's plant program contains all of the elements
 
of the referenced GALL Report. Further, the staff conducted onsite interviews with the applicant
 
to confirm these results. 
 
In the "detection of aging effects" program element, the applicant stated that it will use a
 
combination of established visual examination techniques to detect reduction of fracture toughness as evidenced by cracking. However, GALL AMP XI.M32 recommends specific
 
inspection methods dependent on aging mechanisms.
 
In RAI B.2.26-1, dated June 23, 2008, the staff requested that the applicant clarify the
 
inspection techniques it will use to detect evidence of cracking.
 
In its response to RAI B.2.26-1, dated July 25, 2008, the applicant stated that pursuant to its
 
response to RAI B.2.26-2, which is provided below, the Main Steam Flow Restrictor Inspection
 
Program has been deleted.
In the "acceptance criteria" program element, GALL AMP XI.M32 states that any indication or relevant conditions of degradation detected are evaluated. In LRA Section B.2.26, the applicant
 
stated that the acceptance criterion is: "no cracking that could result in a loss of component
 
intended function(s) during the period of extended operation, as determined by engineering
 
evaluation."
 
In RAI B.2.26-2, dated June 23, 2008, the staff requested that the applicant (a) confirm whether
 
the CASS MS flow restrictors were screened for thermal aging; (b) indicate whether the CASS
 
MS flow restrictors are susceptible to thermal aging; (c) indicate whether flaw tolerance
 
evaluations will be performed, if cracking is det ected; and (d) explain what type of corrective actions and monitoring will be implemented, if cracking is detected.
 
In the response to RAI B.2.26-2, dated July 25, 2008, the applicant stated that consistent with GALL AMP XI.M12, "Thermal Embrittlement of Cast Austenitic Stainless Steel (CASS)," PPL
 
has performed a screening of the CASS portions of the main steam flow restrictors to determine
 
their susceptibility for thermal aging. The applicant determined that the CASS portions of the
 
flow restrictors are not susceptible to reduction of fracture toughness due to thermal
 
embrittlement on the following basis:
3-52  The applicant stated that the CASS portions of the flow restrictors were cast by a
 
centrifugal casting method. PPL reviewed the QA documentation packages for the flow
 
restrictors and determined that the castings were constructed from cast austenitic
 
stainless steel, in conformance with material specification SA-351 CF8. This material is a
 
low-molybdenum grade of CASS, as opposed to a high-molybdenum grade (i.e., "M" grade) of CASS material, such as SA- 351 CF8M, which requires 2-3% molybdenum
 
content. Therefore, the steam line flow restrictor castings for SSES are considered to be
 
constructed of low molybdenum (0.5% maximum) content material. In accordance with the guidance provided in the GALL Section XI.M12, the centrifugally-cast, low
 
molybdenum CASS portions of the flow restrictors are not susceptible to thermal
 
embrittlement. As such, the AMP B.2.26 "Main Steam Flow Restrictor Inspection" which was intended to manage reduction of fracture toughness due to thermal embrittlement
 
for CASS portions of the main steam flow restrictors is not an aging management
 
program required for license renewal because, as described above, the CASS portions
 
of the main steam flow restrictors are not susceptible to reduction of fracture toughness due thermal embrittlement.
 
In addition to the screening for susceptibility for thermal aging, the applicant re-evaluated the
 
other conclusions from the AMR of the main steam flow restrictors. The applicant provided the
 
following results and conclusions of the re-evaluation in its response to RAI B.2.26-2:
 
The flow restrictors in the Main Steam system are not pressure boundary components. Therefore, neither ASME Section III nor ANSI B31.1, which
 
typically require a fatigue analysis or the use of stress range reduction factors for
 
7000 cycles, are applicable. As such, fatigue cracking of the main steam flow
 
restrictors is not an applicable aging effect.
The Inservice Inspection (ISI) Program was credited to confirm the effectiveness of the BWR Water Chemistry Program to manage a loss of material for the main
 
steam flow restrictors. The basis for crediting the ISI program was that similar
 
materials and environments were inspected by ISI. However, the Chemistry
 
Program Effectiveness Inspection (CPEI) confirms the effectiveness of the BWR
 
Water Chemistry Program. While ISI results may be considered in the
 
development and implementation of the CPEI one-time inspection, the ISI
 
Program is not an aging management program fo r the main steam flow restrictors.
Stress Corrosion Cracking (SCC) is not an aging effect requiring management for the main steam flow restrictors because there is no tensile stress in the CASS
 
portions of the flow restrictors to promote SCC. Also, the flow restrictors do not have a
 
pressure boundary function that could be affected by cracking, and cracking will not
 
affect the flow restriction function of the flow restrictors. Extreme cracking that could
 
result in the loss of flow restrictor structural integrity could affect its flow restriction
 
function; however, such a failure is not plausible, given the lack of a driving mechanism
 
for crack initiation and/or crack growth.
 
The applicant revised LRA Section 3.1.2.1.3, Table 3.1.1, Table 3.1.2-3, Appendix A (Table of
 
Contents, Section A.1.2.30, and Table A-1), and Appendix B (Table of Contents, Table B-1, Table B-2, and Section B.2.26) to reflect these results that reduction in fracture toughness due
 
to thermal embrittlement is not an AERM for license renewal.
 
3-53 The staff reviewed the applicant's response and confirmed that based on the screening criteria provided in GALL AMP XI.M12, the CASS portion of the flow restrictors are not susceptible to
 
reduction of fracture toughness because all centrifugal-cast low-molybdenum steels are not
 
susceptible to this aging effect. Furthermore, based on a review of the drawings provided by the
 
applicant during the audit, the staff determined that these flow restrictors are in-line flow
 
restrictors and therefore, are not pressure boundary components. 
 
Based on its review, the staff finds the applicant's response to RAI B.26-2 acceptable because
 
the applicant has verified and the staff confirms that: (a) the CASS flow restrictors are not
 
susceptible to reduction of fracture toughness due to thermal embrittlement; (b) the flow
 
restrictors are not pressure boundary components; and (c) the BWR Water Chemistry Program
 
and ISI Program are credited for similar mate rial and environments to manage the aging effects of loss of material. The staff agrees with the deletion of the Main Steam Line Flow Restrictor
 
Inspection Program from the LRA. Therefore, the staff's concern described in RAI B.2.26-2 is
 
resolved.
 
In the "detection of aging effects" program element, the applicant stated that the Main Steam
 
Flow Restrictor Inspection Program will be applied to all eight (four per unit) main steam flow
 
restrictors.
 
In RAI B.2.26-3, the staff requested that the applicant clarify whether this means that all eight
 
flow restrictors will be inspected and; if not, please provide the sample size, and identify
 
whether the program will provide for increasing t he sample size in the event that aging effects are detected.
 
In its response to RAI B.2.26-3, dated July 25, 2008, the applicant stated that pursuant to its
 
response to RAI B.2.26-2 above, the Main Steam Flow Restrictor Inspection Program has been
 
deleted.
 
Based on its review, the staff finds the applicant's response to RAI B.2.26-3 acceptable
 
because the applicant has verified and the staff confirms that the Main Steam Flow Restrictor
 
Inspection Program has been deleted. Therefore, the staff's concern described in RAI B.2.26-3
 
is resolved.
 
UFSAR Supplement. In its letter dated July 25, 2008, the applicant deleted UFSAR Summary Section A.1.2.30, Commitment No. 22, because the Main Steam Flow Restrictor Inspection
 
Program has been deleted. The staff's evaluation of the applicant's deletion of the Main Steam
 
Flow Restrictor Inspection Program is described above.
 
Conclusion.
In the letter dated July 25, 2008, the applicant responded that pursuant to its response to RAI B.2.26-2 above, the Main Steam Flow Restrictor Inspection Program has been
 
deleted. On the basis that the CASS flow restrictors are not susceptible to reduction of fracture
 
toughness due to thermal embrittlement, the flow restrictors are not pressure boundary
 
components, and LRA Section B.2.2, BWR Water Chemistry Program and Section B.2.1, ISI
 
Program are credited for similar material and environments to manage the aging effects of loss of material, the staff finds the applicant response acceptable and agrees with the deletion of the
 
Main Steam Line Flow Restrictor Inspection Program from the LRA.
The staff concurs with the deletion and the staff's basis for agreement is described above.
 
3-54  3.0.3.1.15  Monitoring and Collection System Inspection 
 
Summary of Technical Information in the Application. In LRA Section B.2.27, the applicant described the Monitoring and Collection System In spection Program as a new program that will be consistent with GALL AMP XI.M32, "One-Time Inspection." The applicant stated that this
 
program will detect and characterize the condition of the internal surfaces of subject
 
components that are exposed to equipment and/or area drainage water and other potential
 
contaminants or fluids. The applicant further stated that the inspection provides direct evidence
 
as to whether, and to what extent, a loss of material due to crevice, general or pitting corrosion, or to MIC has occurred or is likely to occur in the liquid waste management system that may
 
result in a loss of intended function.
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. In comparing the elements in the applicant's program to those in GALL AMP XI.M32, the staff noted the program elements in the applicant's AMP claim of consistency with the GALL Report were consistent with GALL AMP XI.M32, with the exception of three
 
program element aspects identified below that the staff determined required additional
 
clarification. The staff also confirmed that the plant program contains all of the elements of the
 
referenced GALL Report. The staff conducted onsite interviews with the applicant to confirm
 
these results.
 
In the "detection of aging effects" program element, the applicant stated that a combination of
 
established volumetric or visual examination techniques will be used to identify evidence of loss of material or to confirm a lack thereof. However, GALL AMP XI.M32 recommends specific
 
inspection methods dependent on aging mechanisms.
 
In RAI B.2.27-1, dated June 23, 2008, the staff requested that the applicant clarify which
 
inspection techniques it will use.
 
In its response to RAI B.2.27-1, dated July  25, 2008, the applicant stated that visual inspection (VT-1 or equivalent) and/or Volumetric inspection (RT or UT) techniques will be used to
 
determine whether crevice or pitting corrosion is occurring; visual inspection (VT-3 or
 
equivalent) and/or Volumetric inspection (RT or UT) techniques will be used to determine
 
whether galvanic or general corrosion is occurring; and visual inspection (VT-3 or equivalent)
 
techniques will be used to determine whether reduction in heat transfer is occurring. The
 
specific inspection technique will be determined prior to inspection activities and will be consistent with the recommendations in GALL AMP XI.M32.
 
Based on its review, the staff finds the applicant's response to RAI B.2.27-1 acceptable
 
because the applicant has provided specific inspection techniques for detection of the aging effects and the mechanisms are consistent with the recommendations in GALL AMP XI.M32.
 
Therefore, the staff's concern described in RAI B.2.27-1 is resolved.
 
In the "monitoring and trending" program element, the applicant stated that no actions are taken
 
as part of this program, since it is a one-time inspection activity. In the "monitoring and trending" program element, the GALL AMP XI.M32 states that "unacceptable inspection findings are
 
evaluated in accordance with the site corrective action process to determine the need for
 
subsequent (including periodic) inspections-" 
 
In RAI B.2.27-2, dated June 23, 2008, the staff requested that the applicant confirm whether the 3-55 corrective action program will increase the sample size, in the event aging effects are detected.
 
In its response to RAI B.27-2, dated July 25, 2008, the applicant stated that unacceptable
 
inspection findings will be evaluated under the SSES Corrective Action Program, which will
 
identify appropriate corrective actions, including the need to perform additional inspections.
 
Based on its review, the staff finds the applicant's response to RAI B.2.27-2 acceptable
 
because the applicant will evaluate unacceptable inspection findings under its corrective action
 
program and take appropriate corrective action, including performance of additional inspections, which is consistent with the recommendations of the GALL AMP XI.M32 "monitoring and
 
trending" program element. Therefore, the staff's concern described in RAI B.2.27-2 is resolved.
 
In the "acceptance criteria" program element, GALL AMP XI.M32 states that any indication or relevant conditions of degradation detected are evaluated. In LRA Section B.2.27, the applicant
 
stated the following acceptance criteria: "no unacceptable loss of material (or wall thinning) that
 
could result in a loss of component intended function during the period of extended operation, as determined by engineering evaluation."
 
In RAI B.2.27-3, dated June 23, 2008, the staff requested that the applicant explain why the
 
acceptance criteria for the Monitoring and Collect ion System Inspection Program differ from the recommendations of the GALL Report, and clarify what is meant by "no unacceptable loss of
 
material (or wall thinning)."
 
In its response to RAI B.2.27-3, dated July 25, 2008, the applicant amended the Monitoring and
 
Collection System Inspection Program accept ance criteria" program element to state:
Any indications or relevant conditions of degradation detected during the inspections will
 
be compared to pre-determined acceptance criteria. If the acceptance criteria are not
 
met, then the indications/conditions will be evaluated under the SSES Corrective Action
 
Program to determine whether they could result in a loss of component intended function
 
during the period of extended operation.
 
Based on its review, the staff finds the applicant's response to RAI B.2.27-3 acceptable
 
because the applicant has appropriately am ended the Monitoring and Collection System Inspection Program "acceptance criteria" program element to be consistent with the recommendations provided in GALL AMP XI.M32. Therefore, the staff's concern described in
 
RAI B.2.27-3 is resolved.
 
Based on its review, the staff finds the Monitoring and Collection System Inspection Program consistent with the program elements of GALL AMP XI.M32 and; therefore, is acceptable.
 
Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.27 and interviewed the applicant's technical personnel to confirm that the plant-specific OE did not
 
reveal any aging effects not bounded by the GALL Report. The staff also confirmed that
 
applicable aging effects and industry and plant-specific OE have been reviewed by the applicant
 
and are evaluated in the GALL Report. 
 
The "operating experience" program element in the LRA states that the Monitoring and
 
Collection System Inspection Program is a new program and there is no plant-specific program OE. Furthermore, the staff confirmed that the applicant has addressed OE identified after the
 
issuance of the GALL Report. However, for this program and for other new AMPs where the 3-56 applicant provided no current plant-specific OE, the staff issued a generic RAI.
 
In RAI B.2-1, dated June 10, 2008, the staff requested that the applicant commit to provide
 
documentation of plant-specific OE for staff review, after the program has been implemented, but, prior to entering the period of extended operation.
 
In its response to RAI B.2.1, dated July 8, 2008, the applicant stated that OE for new AMPs
 
described in LRA Appendix B will be gained as t hese new programs are implemented during the period of extended operation. The applicant further stated that results of tests, inspections, and
 
other aging management activities conducted in accordance with these programs will be subject
 
to confirmation and corrective action elements of the Susquehanna 10 CFR Part 50, Appendix B, Quality Assurance Program and that results will be subject to staff review during
 
regional inspections under existing staff inspection modules. The applicant also stated that one-
 
time inspections will be performed prior to entry to the period of extended operation, to confirm
 
the effectiveness of existing AMPs, and that these programs are subject to review under NRC
 
Inspection Procedure 71003, "Post-Approval Site Inspection for License Renewal." 
 
The staff noted the applicant's statement that inspection methods will be consistent with
 
industry practices is consistent with the "operating experience" program element for GALL AMP XI.M32. The staff also noted that post-approval site inspections provide an opportunity for staff to review and assess the effectiveness of the applicant's Monitoring and Collection System
 
Inspection Program, after the applicant has developed OE with that program. The staff
 
concludes that the corrective action program, based on internal and external plant OE, will
 
capture OE to support the conclusion that the effects of aging are adequately managed. On this
 
basis, the staff finds this program element acceptable and concludes that a separate
 
commitment is not necessary.
 
The staff confirms that the "operating experience" program element satisfies the criterion
 
defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10. Therefore, the staff finds this program element acceptable.
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary for the Monitoring and Collection System Inspection Program in LRA Section A.1.2.33, Commitment
 
No. 23. The staff reviewed this section and finds it acceptable because it is consistent with the
 
corresponding program description in SRP-LR Table 3.3-2. The staff also finds that the
 
applicant has committed to implement the Monitoring and Collection System Inspection
 
Program within the 10-year period, prior to the period of extended operation.
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of the review of the applicant's Monitoring and Collection System Inspection Program and the applicant's response to the staff's RAIs, 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
 
functions will be maintained consistent with the CLB for the period of extended operation, as
 
required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this
 
AMP and concludes that it provides an adequate summary description of the program, as
 
required by 10 CFR 54.21(d), and; therefore, is acceptable.
3-57  3.0.3.1.16  Supplemental Piping/Tank Inspection Program
 
Summary of Technical Information in the Application. In LRA Section B.2.28, the applicant described the Supplemental Piping/Tank Inspecti on Program as a new program that will be consistent with GALL Report AMP XI.M32, "One-Time Inspection." The applicant stated that this
 
program will detect and characterize the condition of carbon and stainless steel components
 
that are exposed to moist air environments, particularly the aggressive wet and/or dry
 
environment that exists at air-water interfaces. The applicant further stated that the inspection
 
provides direct evidence as to whether and to what extent, loss of material due to crevice, galvanic, general and pitting corrosion, has occurred or is likely to occur that could result in a
 
loss of intended function.
 
Staff Evaluation. During its audit, the staff confirmed the applicant's claim of consistency with the GALL Report. In comparing the elements in the applicant's program to those in GALL AMP XI.M32, the staff noted that the program elements in the applicant's AMP claimed to be
 
consistent with GALL were consistent with the corresponding program element criteria
 
recommended in the program elements of GALL AMP XI.M32 with the exception of below identified four program element aspects that the staff determined were in need of additional
 
clarification. The staff also confirmed that the plant program contains all of the elements of the
 
referenced GALL Report program. On-site interviews were also held to confirm these results.
 
In the "scope of program" program element, t he LRA identifies systems and components within the scope of the program. In Table 3.2.2-9, diesel generator starting air system, the
 
Supplemental Piping/Tank Inspection Program is credited for managing the aging effect of loss of material for stainless steel drain trap bodies and carbon steel moisture separators. However, this system and components are not included in t he scope of this program. The staff issued RAI B.2.28-1 by letter dated June 23, 2008, to request the applicant to justify why this system is not
 
included in the program scope.
 
In its letter dated July 25, 2008, the applicant responded to RAI B.2.28-1 stating that the carbon
 
steel moisture separators and stainless steel drain trap bodies in the diesel generator starting
 
air system are within the scope of the Supplemental Piping/Tank Inspection. The applicant
 
further stated the Diesel Generators system should have been included in the listing of systems within the scope of this inspection, but was inadvertently omitted. The applicant revised the LRA
 
Section B.2.28 "scope of program" element to in clude diesel generators system in the list of systems within the scope of this program.
 
On the basis that the diesel generators system is added to the scope of the program and thus
 
accurately identifying components and systems in t he scope of this program, the staff finds the response acceptable. Therefore, the staff's concern described in RAI B.2.28-1 is resolved.
 
In the letter dated October 21, 2008, in response to the NRC regional inspection of the LRA, the
 
applicant revised the "scope of program" program elem ent to include diesel fuel oil system in the list of systems within the scope of the program. 
 
On the basis that the diesel fuel oil system is added to the scope of the program and thus
 
accurately identifying components and systems in t he scope of this program, the staff finds the revision acceptable.
 
In the letter dated September 30, 2008, in response to the NRC regional inspection of the LRA, 3-58 the applicant revised the "scope of program" program element to include aging management of loss of material due to crevice, galvanic, general, and pitting corrosion within the air space of
 
diesel generator starting air receiver tanks and E diesel compressor skid air receiver tanks. The
 
applicant also revised the "detection of aging effects" program element to include at least 2 of
 
these tanks in the sample population for inspection.
 
On the basis that the diesel generator starting air receiver tanks and E diesel compressor skid
 
air receiver tanks are included in the sample population, the staff finds the response acceptable
 
because the applicant has included these tanks in the program scope and two of these tanks
 
will be part of the sample population that will be inspected, which will provide inspection results
 
that could be evaluated and applied to the other tanks. 
 
In the "detection of aging effects" program element, the LRA states that a combination of
 
established volumetric or visual examination techniques will be used to identify evidence of loss of material or to confirm a lack thereof. However, the GALL AMP XI.M32, "One-Time
 
Inspection," recommends specific inspection methods dependent on aging effects and
 
mechanisms. The staff issued RAI B.2.28-2 by letter dated June 23, 2008, to request the
 
applicant to clarify the inspection techniques that will be used for the different aging effects and
 
mechanisms.
 
In the letter dated July 25, 2008, the applicant responded to RAI B.2.28-2 stating that visual
 
inspection (VT-1 or equivalent) and/or Volumetric inspection (RT or UT) techniques will be used
 
to determine whether crevice or pitting corrosion is occurring; visual inspection (VT-3 or
 
equivalent) and/or Volumetric inspection (RT or UT) techniques will be used to determine
 
whether galvanic or general corrosion is occurring; and visual inspection (VT-3 or equivalent)
 
techniques will be used to determine whether reduction in heat transfer is occurring. The
 
applicant stated the specific inspection technique will be determined prior to the inspection activities and will be consistent with the recommendations in GALL AMP XI.M32.
 
The staff reviewed the applicant's response and finds the specific inspection techniques
 
provided by the applicant for detection of the aging effects and mechanisms are consistent with the recommendations provided by GALL AMP XI.M32 and are acceptable. On this basis, the
 
staff finds the applicant response acceptable.
 
In the "monitoring and trending" program element, the LRA states that no actions are taken as
 
part of this program, since it is a one-time inspection activity. In the "monitoring and trending" program element, GALL AMP XI.M32 states that unacceptable inspection findings are evaluated in accordance with the site corrective action process to determine the need for subsequent (including periodic) inspections. The staff issued RAI B.2.28-3 by letter dated June 23, 2008, to
 
request the applicant to confirm if the corrective action program will increase the sample size in
 
the event aging effects are detected.
 
In the letter dated July 25, 2008, the applicant responded to RAI B.2.28-3 stating that
 
unacceptable inspection findings will be evaluated under the SSES corrective action program.
 
The evaluation done under the SSES corrective action program will identify appropriate
 
corrective actions, including the need to perform additional inspections.
 
On the basis that the applicant will evaluate unacceptable inspection findings under the SSES
 
corrective action program and take appropriate corrective action including the need to perform
 
additional inspections, the staff finds the response acceptable because the applicant is consistent with the recommendations of the GALL AMP XI.M32 "monitoring and trending" 3-59 program element. 
 
In the "acceptance criteria" program element, the GALL AMP XI.M32 states that any indication or relevant conditions of degradation detected are evaluated. The LRA Section B.2.28 identifies
 
acceptance criteria as: no unacceptable loss of material (or wall thinning) that could result in a
 
loss of component intended function during the period of extended operation, as determined by
 
engineering evaluation. The staff issued RAI B.2.28-4 by letter dated June 23, 2008, to request
 
the applicant to explain why the acceptance criteria for AMP B.2.28 differ from the
 
recommendations of the GALL Report and to clarify what "no unacceptable loss of material (or
 
wall thinning)" means.
 
In the letter dated July 25, 2008, the applicant amended LRA Section B.2.28, Supplemental
 
Piping/Tank Inspection Program "acceptance criteria" program element to state:
 
Any indications or relevant conditions of degradation detected during the inspections will
 
be compared to pre-determined acceptance criteria. If the acceptance criteria are not
 
met, then the indications/conditions will be evaluated under the SSES Corrective Action
 
Program to determine whether they could result in a loss of component intended function
 
during the period of extended operation.
 
The staff reviewed the applicant's response and finds that the amended "acceptance criteria"
 
program element is consistent with the recommendations provided in GALL AMP XI.M32, and therefore the staff finds the response acceptable.
 
In a letter dated January 12, 2009, the applicant amended the scope of the Supplemental Piping
 
and Tanks Inspection Program to include the internal steel and stainless steel emergency diesel
 
generator exhaust piping, piping component, and piping element surfaces that are exposed to
 
the diesel exhaust environment (which is identified in LRA Table 3.0-1 as a subsection of the
 
ventilation air environment). The staff noted t hat the applicant made the applicable amendment of this AMP in order to conform to the staff's recommendations in SRP-LR Section 3.3.2.2.3.3
 
and the GALL AMR VII.H2-1, for the management of stress corrosion cracking in stainless steel
 
diesel generator exhaust piping components and in SRP-LR Section 3.3.2.2.7.3 and GALL AMR
 
VII.H2-2, for the management of loss of material in steel stainless steel emergency diesel
 
generator exhaust piping components. The staff finds that the applicant amendment of the LRA
 
to include the internal surfaces of these components is acceptable because it conforms to the
 
staff's aging management recommendations in these SRP-LR and GALL AMR sections that a
 
valid AMP be credited to manage cracking and loss of material in these diesel generator
 
exhaust piping components. The staff's evaluations in SER Sections 3.3.2.2.3.3 and 3.3.2.2.7.3
 
provide additional details on why it is acceptable to credit this AMP for aging management of
 
these emergency diesel generator exhaust piping components.
 
Based on its review, the staff finds the Supplementary Piping/Tank Inspection Program
 
consistent with the program elements with the program elements of GALL AMP XI.32, and therefore acceptable.
 
Operating Experience. The staff reviewed the operating experience described in LRA Section B.2.28 and interviewed the applicant's technical personnel to confirm that the plant-specific
 
operating experience did not reveal any aging effects not bounded by the GALL Report. The staff also confirmed that applicable aging effects and industry and plant-specific operating
 
experience have been reviewed by the applicant and are evaluated in the GALL Report. 
 
3-60 The "operating experience" program element in the LRA states that the Supplementary Piping/Tank Inspection is a new program and there is no plant-specific program operating
 
experience. Furthermore, the staff confirmed that the applicant has addressed operating
 
experience identified after the issuance of the GALL Report. However, for this program and for
 
other new AMPs where the applicant provided no current plant-specific operating experience, the staff issued generic RAI B.2-1 by letter dated June 10, 2008, asking that the applicant
 
commit to provide documentation of plant-specific operating experience for staff review after the
 
program has been implemented, but prior to entering the period of extended operation.
 
In the letter dated July 8, 2008, the applicant responded to RAI B.2-1 and stated that operating
 
experience for new aging management program s described in LRA Appendix B will be gained as these new programs are implemented during the period of extended operation. The applicant stated that results of tests, inspections, and other aging management activities conducted in
 
accordance with these programs will be subject to confirmation and corrective action elements
 
of the SSES 10 CFR 50, Appendix B, quality assurance program and that results will be subject
 
to NRC review during regional inspections under existing NRC inspection modules. The
 
applicant further stated that one-time inspections will be performed prior to entry to the period of
 
extended operation to confirm the effectiv eness of existing aging management programs and that these programs are subject to review under NRC Inspection Procedure 71003, Post-
 
Approval Site Inspection for License Renewal. 
 
The staff noted that the applicant's statement that inspection methods will be consistent with
 
industry practices is consistent with the "operating experience" program element for GALL AMP XI.M32. The staff also noted that post-approval site inspections provide an opportunity for staff
 
review and assessment of the effectiveness of the applicant's Supplementary Piping/Tank
 
Inspection Program after the applicant has developed operating experience with that program.
 
The staff concludes that the corrective action program, based on internal and external plant
 
operating experience, would capture operating experience in the future to support the
 
conclusion that the effects of aging are adequately managed. On this basis, the staff finds this
 
program element acceptable and concludes that a separate commitment is not necessary.
 
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.1.2.46, Commitment No. 24, the applicant provided the UFSAR supplement for the Supplementary Piping/Tank Inspection Program. The staff verified
 
that the UFSAR supplement summary description for the Supplementary Piping/Tank Inspection
 
Program was in conformance with the staff's recommended UFSAR supplement for the One-
 
Time Inspection Program provided in Table 3.3-2 of the SRP-LR. 
 
Based on this review, the staff finds that UFSAR supplement Section A.1.2.46 provides an
 
acceptable UFSAR Supplement summary description of the applicant's Supplementary
 
Piping/Tank Inspection Program because it is c onsistent with the UFSAR supplement summary description in the SRP-LR for the One-Time Inspection Program and because the applicant has
 
included in Table A-1, Commitment No. 24 to implement the Supplementary Piping/Tank
 
Inspection Program within the 10-year period prior to the period of extended operation.
 
The staff reviewed this section and determines that the information in the UFSAR supplement
 
provides an adequate summary description of the program consistent with the SRP-LR, as
 
required by 10 CFR 54.21(d).
3-61  Conclusion
:  On the basis of its review of the applicant's Supplementary Piping/Tank Inspection Program and the applicant's response to the staff's RAIs, 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 functions will be
 
maintained consistent with the CLB for the period of extended operation, as required by 10 CFR
 
54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it
 
provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.1.17  Selective Leaching Inspection Program
 
Summary of Technical Information in the Application. In LRA Section B.2.29, the applicant described the new Selective Leaching Program as consistent with GALL AMP XI.M33, "Selective Leaching of Materials." This program co mbines the use of a visual inspection with a hardness test on the external and internal surfaces of materials susceptible to selective
 
leaching, to determine whether the aging effect of loss of material due to selective leaching has
 
occurred.
 
Staff Evaluation. During its audit, the staff confirmed the applicant's claim of consistency with the GALL Report. In comparing the elements in the applicant's program to those in GALL AMP XI.M33, the staff noted the program elements in the applicant's AMP claim of consistency with the GALL Report were consistent with GALL AMP XI.M33, with the exception of the one
 
program element aspect identified below that the staff determined required additional
 
clarification. The staff also confirmed that the plant program contains all of the elements of the
 
referenced GALL Report. The staff conducted onsite interviews with the applicant to confirm
 
these results.
 
The staff reviewed the applicant's Program Evaluation Document and confirmed that the
 
program scope includes all systems that could be susceptible to selective leaching. The staff noted that this includes copper alloys (brass and bronze), cast iron, and ductile iron exposed to
 
raw water, treated water, groundwater (buried), indoor air with condensation, outdoor air, and
 
fuel oil environments. The staff further noted that twenty-five plant systems have this combination of material and environment and include susceptible components that include
 
piping and tubing, valve bodies, pump and turbocharger casings, heat exchangers, coolers, chillers, hydrants, sprinkler heads, strainers, level gauges, orifices, and heater sheaths. The
 
staff finds the applicant's Selective Leaching Program acceptable because it conforms to the recommendations in GALL AMP XI.M33. 
 
During the review of the applicant's Cooling Unit Inspection Program (SER section 3.0.3.1.11),
the staff noted that the "scope of program" element in the LRA states that loss of material due to
 
crevice corrosion, pitting corrosion, and selective leaching of the copper-alloy cooler channel in
 
the control structure HVAC system. As stated in the GALL Report, selective leaching does not cause a noticeable change in dimensions and is difficu lt to detect using visual and/or volumetric detection techniques, which are the techniques used in the Cooling Unit Inspection Program.
 
In RAI B.2.23-1, dated June 23, 2008, the staff requested that the applicant justify the use of the
 
Cooling Unit Inspection Program to manage loss of material due to selective leaching in the
 
control structure HVAC system. The staff also requested that the applicant explain why the
 
copper-alloy cooler channel was not included within the scope of the Selective Leaching
 
Inspection Program.
 
3-62 In the response to RAI B.2.23-1, dated July 25, 2008, the applicant stated that the LRA has been amended to credit the Selective Leaching Inspection Program, in place of the Cooling
 
Unit Inspection Program, to manage loss of material due to selective leaching for the copper
 
alloy cooler channel in the control structure HVAC system. 
 
Based on the review, the staff finds the applicant's response to RAI B.2.23-1 acceptable
 
because the applicant has amended the LRA to credit the Selective Leaching Program to
 
manage loss of material due to selective leaching for the copper-alloy cooler channel in the
 
control structure HVAC system. Therefore, the staff's concern described in RAI B.2.23-1 is
 
resolved.
 
Based on the review, the staff finds the Selective Leaching Program consistent with the program elements in GALL AMP XI.M33 and; therefore, is acceptable.
 
Operating Experience. The applicant stated that the Selective Leaching Program is a new program for which there is no OE and that inspection methods will be consistent with accepted
 
industry practices. For this program and for other new AMPs where the applicant provided no
 
current plant-specific OE, the staff issued a generic RAI.
 
In RAI B.2.1, dated June 10, 2008, the staff requested that the applicant commit to provide
 
documentation of plant-specific operating for staff review, after the program has been
 
implemented, but, prior to entering the period of extended operation.
 
In the response to RAI B.2.1, dated July 8, 2008, the applicant stated that OE for new AMPs
 
described in LRA Appendix B will be gained as t hese new programs are implemented during the period of extended operation. The applicant stated that results of tests, inspections, and other
 
aging management activities conducted in accordance with these programs will be subject to
 
confirmation and corrective action elements of the Susquehanna 10 CFR Part 50, Appendix B, Quality Assurance Program. Results will be subject to staff review during regional inspections
 
under existing staff inspection modules. The applic ant stated that these new programs will be implemented prior to, and continue through, the period of extended operation and that OE will
 
be gained for these programs as they are implemented. The applicant further stated that test
 
and inspection results that do not meet acceptance criteria for these new programs will be
 
evaluated under the applicant's corrective action program, which includes requirements for
 
identification of appropriate corrective actions and verification of the effectiveness of corrective
 
actions.
 
The staff noted the applicant's statement that inspection methods will be consistent with
 
industry practices is consistent with the "operating experience" program element for GALL AMP XI.M33. The staff also noted that post-approval site inspections provide an opportunity for the staff to review and assess the effectiveness of the applicant's Selective Leaching Program, after the applicant has developed OE with that program. The staff concludes that the corrective
 
action program, based on internal and external plant OE, will capture OE to support the
 
conclusion that the effects of aging are adequately managed.
 
On this basis, the staff confirms that the "operating experience" program element satisfies the
 
criterion defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable and concludes that a separate commitment is not
 
necessary.
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary for the Selective 3-63 Leaching Program in LRA Section A.1.2.43, Commitment No. 25. The staff reviewed this section and determines that the information in the UFSAR supplement provides an adequate summary
 
description of the program consistent with the SRP-LR, as required by 10 CFR 54.21(d). The
 
staff confirms that the applicant has made a co mmitment to implement this new program, after issuance of the renewed license and prior to entering the period of extended operation. 
 
Conclusion. On the basis of the review of the applicant's Selective Leaching Program and the applicant's RAI responses, the staff finds all program elements consistent with the GALL
 
Report. The staff concludes that the applicant has demonstrated that effects of aging the will be
 
adequately managed so that the intended functions of these components will be maintained
 
consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concludes that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d) and; therefore, is acceptable.
 
3.0.3.1.18  Small Bore Class 1 Piping Inspection Program
 
Summary of Technical Information in the Application. In LRA Section B.2.31, the applicant described the new Small Bore Class 1 Piping Inspection as consistent with GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping." The applicant stated that the
 
program is a one-time inspection program to confirm the effectiveness of the BWR Water
 
Chemistry Program in mitigating loss of material and cracking for small bore Class 1 piping and
 
also to verify, by inspections for cracking, that reduction of fracture toughness due to thermal
 
embrittlement requires no additional aging m anagement for small bore Class 1 piping. The applicant also stated that the program is applicable to small bore ASME Code Class 1 piping
 
and piping components less than four inches nominal pipe size (<NPS 4), which includes pipes, fittings, and branch connections, and that the inspection provides additional assurances that
 
either aging of small bore ASME Code Class 1 piping is not occurring or that the aging is
 
insignificant. The applicant further stated that implementation of the program is scheduled to be
 
completed during the 10-year period, prior to the period of extended operation (Commitment
 
No. 27, LRA Table A-1).
 
Staff Evaluation. During the audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the applicant's AMP evaluation for the Small Bore Class 1
 
Piping Inspection Program, together with the applicant's program outline which provides specific
 
guidance for preparation of implementing procedures related to this new program. In comparing the program description and elements in the applicant's AMP to those in GALL AMP XI.M35, the
 
staff noted a number of instances where the program description and elements that the
 
applicant claimed to be consistent with the GALL Report did not appear to be consistent with
 
the corresponding program element criteria recommended in GALL AMP XI.M35. Furthermore, it appeared to the staff that for the one-time inspection of small-bore Code Class 1 piping, the applicant combined recommendations in GALL AMP XI.M35 with recommendations in GALL AMP XI.M32, "One-Time Inspection." The applicant's AMP resulting from this combination was substantially different from GALL AMP XI.M35, with which the applicant claimed consistency.
The staff identified a need for additional clarification and issued four RAIs to support the staff's
 
evaluation of the applicant's Small Bore Class 1 Piping Inspection program. The staff evaluates
 
the applicant's responses to these RAIs in the following discussions.
 
The applicant stated in the LRA that the Small Bore Class 1 Piping Inspection Program, is a new program that will be consistent with GALL AMP XI.M35. The applicant further stated that the GALL AMP XI.M35 is credited only with managing the aging effect of cracking, and 3-64 the only examination technique used is volumetric examination. However, in the LRA, both in the program description and in several agi ng management review line items, the Small Bore Class 1 Piping Inspection is credited with confirming effectiveness of the BWR Water
 
Chemistry Program in mitigating the aging effect of loss of material using "nondestructive
 
examinations (including volumetric techniques)." 
 
In RAI B.2.31-1, dated June 23, 2008, the staff requested that the applicant provide the
 
basis for categorizing the Small Bore Class 1 Piping Inspection Program as being consistent with the GALL AMP XI.M35 when the Small Bore Class 1 Piping Inspection
 
Program implies that non-volumetric examination techniques may be used as an alternate
 
basis for performing the one-time inspections of the small bore Class 1 piping components and when this AMP is credited with managing an aging effect (i.e., loss of material) that is not within the scope of the GALL AMP XI.M35. The staff also requested that the applicant
 
clarify whether the LRA will be amended to identify these aspects of the program as exceptions to GALL AMP XI.M35 and; if so, justify the basis for crediting these exceptions
 
for aging management of small bore Class 1 piping components.
 
In its response to RAI B.2.31-1, dated July 25, 2008, the applicant stated the following:
 
The SSES LRA is amended [as shown in a multi-page attachment] to
 
demonstrate that AMP B.2.31, Small Bore Class 1 Piping Inspection, is consistent with GALL AMP XI.M35 with no exceptions.
 
AMP B.2.31 is credited for managing the aging effect of cracking, as a result of
 
stress corrosion or thermal or mechanical loading, and one-time volumetric
 
examination is the acceptable method for confirming that cracking of ASME Code
 
Class 1 small-bore piping is not occurring.
 
AMP B.2.22, Chemistry Program Effectiveness Inspection, is credited with
 
verifying the effectiveness of AMP B.2.2, BWR Water Chemistry Program, to
 
mitigate loss of material.
 
The applicant provided a multi-page attachment (Attachment 3 to PLA-6391, LRA Revisions in
 
Response to RAIs B.2.31-1 and B.2.31-3) as part of the response, in which the applicant described revisions to LRA text and tables affected by its responses to RAIs B.2.31-1 and
 
B.2.31-3. 
 
The staff noted the changes affecting text related to AMP descriptions and the AMR results
 
tables as well as evaluations in the LRA.
 
The AMP related text sections in the LRA affected by the applicant's changes are as
 
follows:
Section A.1.2.44, the UFSAR supplement describing the Small Bore Class 1
 
Piping Inspection was revised to delete aging management for loss of material
 
and to state: "Small Bore Class 1 Piping Inspection is a one-time inspection to
 
detect cracking resulting from thermal and mechanical loading or intergranular
 
stress corrosion. The inspection will provide assurance that either cracking of
 
small bore Class 1 piping is not occurring or the cracking is insignificant, such
 
that an aging management program (AMP) is not warranted. The inspection will
 
also confirm the effectiveness of the BWR Water Chemistry Program in 3-65 mitigating cracking due to intergranular stress corrosion."
 
Table A-1, "SSES License Renewal Commitments," was revised to state in
 
Commitment No. 27 that the Small Bore Class 1 Piping Inspection will verify that
 
cracking is not occurring and thereby validate the effectiveness of the Chemistry
 
Program to mitigate cracking.
 
Section B.2.22, "Chemistry Program Effectiveness Inspection," was revised to
 
include reactor coolant system (RCS) pressure boundary components within the
 
scope of the program.
 
Section B.2.31, Small Bore Class 1 Piping Inspection, was revised in multiple
 
places consistent with removing management of loss of material from the scope
 
of the program and relocating it into the Chemistry Program Effectiveness
 
Inspection program. The changes clarified that the focus of the Small Bore
 
Class 1 Piping Inspection Program is to detect cracking resulting from thermal
 
and mechanical loading or intergranular stress corrosion and that the
 
non-destructive examination will use volumetric techniques, consistent with the recommendations in GALL AMP XI.M35. The applicant stated that the program
 
may also include destructive examinations.
 
LRA Appendix C, "Response to BWRVIP Applicant Action Items, Discussion of
 
BWRVIP-74-A," was revised to state that effectiveness of the BWR Water
 
Chemistry Program to mitigate cracking in the flange leak detection lines will be
 
verified by the Chemistry Program Effectiveness Inspection (rather than the
 
previously identified Small Bore Class 1 Piping Inspection Program).
 
The AMR results tables and evaluations in the LRA affected by the applicant's changes are as
 
follows:
Table 3.1.1, "Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System" Table 3.1.2-3, "Aging Management Review Resu lts - Reactor Coolant System Pressure Boundary" Section 3.1.2.2.3.1, "BWR Top Head and Top Head Nozzles, PWR Steam Generator Shell Assembly" Section 3.1.2.2.2.3, "Flanges, Nozzles, Penetrations, Pressure Housings, Safe Ends, and Vessel Shells, Heads, and Welds" Section 3.1.2.2.4.1, "BWR Top Head Enclosure Vessel Flange Leak Detection Lines"  Section 3.1.2.2.8.1, "Stainless Steel Jet Pump Sensing Lines" The staff reviewed all of the applicant's LRA changes, noting that the changes removed the activities associated with monitoring for loss of material from the scope of the Small Bore
 
Class 1 Piping Inspection Program and reassigned them to the Chemistry Program Effectiveness Inspection, consistent with the GALL AMP XI.M32. By making these changes, the 3-66 applicant fully addressed and resolved the staff's concerns with the applicant's Small Bore Class 1 Piping Inspection program, as initially described in the LRA, combined elements of the GALL AMP XI.M32 with elements of GALL AMP XI.M35. However, in its review of the
 
applicant's LRA changes, the staff noted the following three instances in which the as-revised
 
LRA did not appear to conform with the applicant's general approach of removing activities
 
associated with monitoring for loss of material from the scope of the Small Bore Class 1 Piping
 
Inspection Program and reassigning them to the Chemistry Program Effectiveness Inspection:
The change in LRA Section 3.1.2.2.4.1, "BWR Top Head Enclosure Vessel Flange Leak Detection Lines," that replaced use of the Small Bore Class 1 Piping Inspection Program
 
with the Chemistry Program Effectiveness Inspection for monitoring the aging effect of
 
cracking due to SCC in stainless steel lines exposed to treated water, did not appear to
 
be appropriate. The change in LRA Section 3.1.2.2.8.1, "Stainless Steel Jet Pump Sensing Lines," that replaced use of the Small Bore Class 1 Piping Inspection Program with the Chemistry
 
Program Effectiveness Inspection for monitoring the aging effect of cracking in the
 
stainless steel lines external to the vessel, did not appear to be appropriate. The change in LRA Appendix C, "Response to BWRVIP Applicant Action Items," which was made for consistency with the change in LRA Section 3.1.2.2.4.1, also did not
 
appear to be appropriate.
 
In RAI B.2.31-5, the staff requested that the applicant explain the basis for these changes. 
 
In addition, the staff noted that in making the changes to the LRA, the applicant introduced
 
wording that referred to "significant" and "insignificant" cracking.
 
In RAI B.2.31-6, the staff requested that the applicant clarify the meaning of "significant" and
 
"insignificant" cracking or eliminate the problematic wording.
 
In its response to RAI B.2.31-5, dated September 11, 2008, the applicant reversed the changes
 
that had been made in LRA Sections  3.1.2.2.4.1 and 3.1.2.2.8.1 and Appendix C, and restored
 
these affected parts of the LRA to the version originally submitted by the applicant.
 
Based on the review, the staff finds the applicant's response to RAI B.2.31-5 acceptable
 
because the applicant has reversed the changes to the LRA that were made in error and
 
restored the LRA text affected by these changes to the originally submitted version of these
 
LRA Sections, so that monitoring for loss of material will be performed by the Chemistry Program Effectiveness Inspection and monitoring for cracking will be performed by the Small Bore Class 1 Piping Inspection Program. Therefore, the staff's concern described in
 
RAI B.2.31-5 is resolved.
 
In the response to RAI B.2.31-6, dated September 11, 2008, the applicant revised text in LRA
 
Section A.1.2.44 to state that the Small Bore Class 1 Piping Inspection will provide assurance
 
that cracking of small bore Class 1 piping is not occurring or an evaluation of any detected crack
 
indications will be performed to justify continued operation with no further monitoring, such that
 
an AMP is not warranted. The applicant also revised the "program description" in LRA
 
Section B.2.31 to include a similar statement and also to state that should cracking be revealed
 
by a one-time inspection or previous OE, periodic inspection will be performed under a
 
plant-specific AMP, unless cracking is evaluated and determined to be acceptable for continued
 
operation during the period of extended operation, with no further monitoring. The applicant also 3-67 revised the "monitoring and trending" program element in LRA Section B.2.31 to include a similar statement.
 
Based on the review, the staff finds the applicant's response to RAI B.2.31-6 acceptable
 
because the applicant has removed problematic wording from the LRA and has provided
 
acceptable criteria for the disposition of crack indications, if found by the Small Bore Class 1
 
Piping Inspection Program. Therefore, the staff's concern described in RAI B.2.31-6 is resolved. 
 
The staff reviewed the composite of LRA changes made by the applicant in response to
 
RAI B.2.31-1, as amended by the applicant's responses to RAIs B.2.31-5 and B.2.31-6, and determines that the as-revised program description and program elements for the applicant's Small Bore Class 1 Piping Inspection Program are consistent with GALL AMP XI.M35.
 
Based on the review, the staff finds the applicant's response to RAI B.2.31-1 acceptable
 
because the applicant has appropriately revised the LRA sections and table to ensure consistency with GALL AMP XI.M35. Therefore, the staff's concerns described in RAI B.2.31-1
 
are resolved
 
The applicant stated in the LRA that the Small bore Class 1 Piping Inspection Program will be
 
used to monitor both the aging effect of cracking and the aging effect of loss of material in
 
Class 1 small bore piping. However, the environmental stressors that may lead to cracking are
 
not necessarily the same as the environmental stressors that may lead to loss of material. 
 
In RAI B.2.31-2, dated June 23, 2008, the staff requested that the applicant clarify the selection
 
processes and criteria that will be applied to ensure that the program will select and schedule
 
inspections for the most limiting small bore Class 1 piping locations for both of these aging
 
effects.
 
In the response to RAI B.2.31-2, dated July 25, 2008, the applicant stated:
 
The Small Bore Class 1 Piping Inspection, as amended in the response to
 
RAI B.2.31-1, is credited to manage only cracking. As such, in the selection of
 
the small bore Class 1 piping locations for the one-time inspection, there is no
 
need to consider environmental stressors that may lead to loss of material. 
 
The selection criteria to be applied as part of this program are provided in the
 
"Monitoring and Trending" program element discussion in LRA Section B.2.31.
 
The staff notes that the applicant's revision to the LRA eliminated management of loss of
 
material from the scope of the Small Bore Class 1 Piping Inspection Program. Because the
 
revised AMP manages only the aging effect of cracking, which is consistent with the recommendations in GALL AMP XI.M35, the potential issue addressed in RAI B.2.31-2 was
 
eliminated by the LRA amendment that resulted from RAI B.2.31-1.
 
Based on the review, the staff finds the applicant's response to RAI B.2.31-2 acceptable
 
because the applicant has revised the Small Bore Class 1 Piping Inspection Program to
 
manage only the aging effect of cracking, consistent with the recommendations in the GALL AMP XI.M35. Therefore, the staff's concern described in RAI B.2.31-2 is resolved.
 
In describing the Small Bore Class 1 Piping Inspection Program, under the program
 
element "monitoring and trending" in LRA Section B.2.31, the applicant stated that actual 3-68 inspection locations will be based on physical accessibility, exposure levels, nondestructive examination techniques, and locations identified in NRC Information Notice (IN) 97-46.
 
IN 97-46 was written relative to cracking that was detected in small bore unisolable
 
high-pressure injection piping at Oconee Unit 2, which is a pressurized water reactor (PWR).
 
In RAI B.2.31-3, dated June 23, 2008, the staff requested that the applicant justify the basis
 
for applying the Oconee Unit 2 experience as applicable OE for the Small Bore Class 1
 
Piping Inspection Program, and clarify how the information contained in IN 97-46 will be
 
applied in the selection process in order to ensure that the small bore Class 1 piping
 
locations most susceptible to cracking, as a result of thermal and mechanical loading or
 
SCC, will be selected for the one-time inspection.
 
In the response to RAI B.2.31-3, dated July  25, 2008, that applicant stated:
 
The considerations in determining the inspection for AMP B.2.31, Small Bore
 
Class 1 Piping Inspection, include operating experience and related industry
 
guidance documents. Operating experience to date includes NRC Information
 
Notice (IN) 97-46, which was issued to all holders of operating licenses or
 
construction permits for power reactors (BWRs and PWRs). IN 97-46 states that
 
a gap between a thermal sleeve and the associated safe-end allowed intermittent
 
mixing of the hot reactor coolant and the cooler makeup water flowing through
 
the pipeline, resulting in alternating heating and cooling of the weld between the
 
pipe and the safe-end. This phenomenon was a likely contributor to the fatigue
 
cracking that occurred at the weld. PPL will consider the potential for piping
 
locations to experience intermittent mixing between hot and cold flows in the
 
sample selection of inspection locations for AMP B.2.31.
 
The SSES LRA is amended to state, more generally, that operating experience
 
will be considered, without referencing a specific document such as IN-97-46.
 
In evaluating the applicant's response, the staff reviewed the changes made by the applicant in
 
the LRA description of program element "monitoring and trending" for the Small Bore Class 1
 
Piping Inspection Program. The staff notes that the applicant's changes replace the previous
 
reference to Information Notice 97-46 with a more general statement that applicable OE will be
 
included in determining the actual inspection locations.
 
Based on its review, the staff finds the applicant's response to RAI B.2.31-3 acceptable
 
because the applicant has amended the LRA to eliminate the reference to IN 97-46, but, continue to state that applicable OE will be considered. Therefore, the staff's concern described
 
in RAI B.2.31-3 is resolved.
 
In describing the Small Bore Class 1 Piping Inspection, under program element "detection
 
of aging effects" in LRA Section B.2.31, the applicant stated that it found cracking due to
 
vibrational fatigue of small bore piping and is performing augmented inspections as part of
 
the Inservice Inspection Program.
 
In RAI B.2.31-4, dated June 23, 2008, the staff requested that the applicant Identify the
 
small bore piping components that experienced the vibrational-induced cracks and the
 
augmented inspection techniques that resulted in the detection of the cracking in the piping
 
components. Additionally, the staff requested that the applicant clarify whether it has taken 3-69 appropriate corrective actions either to repair the flaw indications in the components or to replace the impacted components, and identify whether those components' locations will be
 
reinspected in the future. If these components will be reinspected in the future, identify and
 
provide technical justification for the inspection technique and frequency that will be used.
 
In the response to RAI B.2.31-4, dated July 25, 2008, the applicant stated:
 
SSES experienced nine socket weld failures (leaks) between 1992 and 2005. All
 
of the leaks were on small bore piping attached to the Unit 2 reactor recirculation system. No socket weld failures have been experienced on Unit 1. All of the
 
leaking welds were cut out and replaced, or entirely eliminated by modification of
 
the pipeline.
 
In response to the socket weld failures experienced at SSES and other plants, the SSES ISI group developed a shear wave ultrasonic (UT) inspection
 
technique to volumetrically inspect socket welds. The shear wave UT is an
 
augmented technique that has been used extensively during plant outages since
 
2000 to inspect welds that had been determined to be at-risk for vibrational
 
fatigue due to their proximity to a vibration source (e.g., a recirculation pump). 
 
Every weld with a crack-like indication was either cut-out and replaced or
 
eliminated by a piping modification. Numerous modifications were made to
 
replace socket-welded fittings with solid pipe (using pipe bends, instead of
 
fittings) and to alter the natural frequency of the piping to avoid excitation by the
 
vibration source. All new socket welds were made with the EPRI 2x1
 
configuration to improve fatigue resistance. To date, none of the 2x1 welds have
 
resulted in a leaking crack at SSES.
 
Recent inspection results have indicated a substantial reduction in the number of
 
indications. PPL is confident that vibrational fatigue on the subject piping welds
 
has been successfully addressed. As such, the necessity to continue volumetric
 
inspections under the augmented ISI program is currently being evaluated.
 
Based on its review, the staff finds the applicant's response to RAI B.2.31-4 acceptable
 
because the applicant has provided detailed summary information about its methodology for
 
and history of small bore pipe examination, and because the applicant's response supports a
 
conclusion that previous problems with vibrational fatigue on small bore piping welds have been
 
successfully addressed. Therefore, the staff's concern described in RAI B.2.31-4 is resolved.
 
The staff notes that in a letter dated September 30, 2008, the applicant revised LRA
 
Section B.2.31 by deleting the discussions related to small bore piping failures attributed to
 
vibrational (high-cycle) fatigue. The applicant made this change because the Small Bore
 
Class 1 Piping Inspection Program is credited with managing age-related cracking due to stress
 
corrosion or thermal and mechanical loading, but not with managing cracking due to high-cycle, vibrational fatigue, which is a short-term failure mechanism, not a long term aging mechanism.
 
The staff finds this LRA change acceptable because it deletes from the LRA the discussion of a
 
short-term failure mechanism that is not managed by the Small Bore Class 1 Inspection
 
Program, and because the Small Bore Class 1 Inspection Program, including all revisions to the
 
LRA, is consistent with the corresponding AMP as described in the GALL Report.
 
Based on its review, and resolution of the related RAIs as described above, the staff finds the 3-70 Small-Bore Class 1 Piping Inspection Program consistent with program elements of GALL AMP XI.M35 and; therefore, is acceptable.
 
Operating Experience. The applicant stated that the Small Bore Class 1 Piping Inspection Program is a new one-time inspection activity for which there is no OE and that inspection
 
methods will be consistent with accepted industry practices. For this program and for other new
 
AMPs where the applicant provided no current plant-specific OE, the staff issued a generic RAI.
 
In RAI B.2.1, dated June 10, 2008, the staff requested that the applicant commit to provide
 
documentation of plant-specific operating for staff review, after the program has been
 
implemented, but, prior to entering the period of extended operation.
 
In the response to RAI B.2.1, dated July 8, 2008, the applicant stated that OE for new AMPs
 
described in LRA Appendix B will be gained as t hese new programs are implemented during the period of extended operation. The applicant further stated that results of tests, inspections, and other aging management activities conducted in accordance with these programs will be subject
 
to confirmation and corrective action elements of the Susquehanna 10 CFR Part 50, Appendix B, Quality Assurance Program. Results will be subject to staff review during regional
 
inspections, under existing staff inspection modules. The applicant also stated that one-time
 
inspections will be performed prior to entry into the period of extended operation to confirm the
 
effectiveness of existing AMPs, and that these programs are subject to review under NRC
 
Inspection Procedure 71003, "Post-Approval Site Inspection for License Renewal."
 
The staff noted the applicant's statement that inspection methods will be consistent with
 
industry practices is consistent with the "operating experience" program element for GALL AMP XI.M35. The staff also noted that post-approval site inspections provide an opportunity for staff to review and assess the effectiveness of the applicant's Small Bore Class 1 Piping
 
Inspection Program, after the applicant has developed OE with that program. The staff
 
concludes that the corrective action program, based on internal and external experience, will capture OE to support the conclusion that the effects of aging are adequately managed.
 
On this basis, the staff confirms that the "operating experience" program element satisfies the
 
criterion defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10.
 
Therefore, the staff finds this program element acceptable and concludes that a separate
 
commitment is not necessary.
 
UFSAR Supplement. The applicant provides the UFSAR supplement summary for the Small Bore Class 1 Piping Inspection Program in LRA Section A.1.2.44, Commitment No. 27. The staff
 
reviewed this section, as revised in response to RAI B.2.31-1, and finds it acceptable because it
 
is consistent with the corresponding program description in SRP-LR Table 3.1-2. The staff also
 
notes that the applicant has committed to implement the Small Bore Class 1 Piping Inspection
 
Program for aging management of applicable co mponents during the 10-years prior to the period of extended operation. 
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of the review of the applicant's Small Bore Class 1 Piping Inspection Program, the staff finds that, after incorporation of all LRA and program revisions made in
 
response to the staff's RAIs, all program elements are consistent with the GALL Report. The
 
staff concludes that the applicant has demonstrated that effects of aging will be adequately 3-71 managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the
 
UFSAR supplement for this AMP and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d) and; therefore, is acceptable.
 
3.0.3.1.19  Inservice Inspection Program (ISI) Program - IWE 
 
Summary of Technical Information in the Application. In LRA Section B.2.34, the applicant described the existing Inservice Inspection (ISI) Program - IWE as consistent with GALL AMP XI.S1 "ASME Section XI, Subsection IWE." 
 
The applicant stated that the Inservice Inspection (ISI) Program - IWE is implemented through
 
plant procedures which provide for ISI of Class MC and metallic liners of Class CC components.
Section 50.55a of 10 CFR requires the use of the examination requirements in the ASME Code, Section XI, Subsection IWE, for steel liners of concrete containments and other containment components. The applicant also stated that it has implemented ASME Code Section XI, Subsection IWE, 1998 Edition with the 2000 Addenda, and will adopt new ASME Code editions
 
and addenda, consistent with the provisions of 10 CFR 50.55a, during the period of extended
 
operation.
 
Staff Evaluation. During the onsite review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff interviewed the applicant's technical staff and reviewed the applicant's ASME Code Section XI, Subsection IWE Program onsite basis documents to determine their consistency with GALL AMP XI.S1. Specifically, the staff reviewed
 
the program elements and associated onsite document s and found that they are consistent with the GALL Report. On the basis of its review, the staff concludes that the applicant's Inservice
 
Inspection (ISI) Program - IWE provides assurance that the steel containments (Class MC) and
 
steel liners for concrete containments (Class CC) will be adequately managed. 
 
Based on its review, the staff finds the applicant's Inservice Inspection (ISI) Program - IWE consistent with the program elements of GALL AMP XI.S1 and; therefore, is acceptable.
 
Operating Experience. The staff also reviewed the applicant's OE described in LRA Section B.2.34 and some of the applicant's onsite basis documents, including some samples of
 
condition reports, and interviewed the applicant's technical staff to confirm that the plant-specific
 
OE did not reveal any degradation not bounded by industry experience. In the application and
 
during the onsite review, the applicant explained that the OE of the Inservice Inspection (ISI)
 
Program - IWE activities shows no adverse trend of program performance. The staff noted that
 
previous SSES IWE inspections have identified age-related degradation including flaking, discoloration, light to heavy pitting, and corrosion. The staff also noted that underwater
 
containment suppression chambers were inspected by VT-3 certified divers. Metal loss appears
 
to have progressed slowly and localized pitting is below the threshold values. The staff further
 
noted that deficiencies were further evaluated and corrected by the applicant in accordance with
 
the Inservice Inspection (ISI) Program - IWE.
The documents reviewed by the staff provided assurance that the program is capturing degradation and correcting it in accordance with ASME Code Section XI. The applicant also established periodic IWE inspections in which all
 
accessible surfaces of the steel containments and steel liners for concrete containments are
 
visually inspected for the duration of plant operation. The staff's OE review has concluded that
 
administrative controls are effective in detecting age-related degradation and in initiating
 
corrective action. The staff did not identify any age-related related issues not bounded by the
 
industry OE.
3-72  On this basis, the staff confirms that the "operating experience" program element satisfies the
 
criterion defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10.
 
Therefore, the staff finds this program element acceptable.
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary for the Inservice Inspection (ISI) Program - IWE in LRA Section A.1.2.24, Commitment No. 29. 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 review of the applicant's Inservice Inspection (ISI) Program -
IWE, 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 functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement
 
for this AMP and concludes that it adequately describes the program, as required by
 
10 CFR 54.21(d) and; therefore, is acceptable.
 
3.0.3.1.20  Inservice Inspection (ISI) Program - IWL 
 
Summary of Technical Information in the Application. In LRA Section B.2.35, the applicant described the existing Inservice Inspection (ISI) Program - IWL as consistent with GALL AMP XI.S2, "ASME Section XI, Subsection IWL." 
 
The Inservice Inspection (ISI) Program - IWL cons ists of periodic visual inspections of the reinforced concrete containment structures for Units 1 and 2. The applicant stated in the LRA
 
that no significant aging effects have been identified for the concrete containment structures.
 
Staff Evaluation. During its review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff interviewed the applicant's technical staff and reviewed the
 
applicant's Inservice Inspection (ISI) Program - IWL onsite basis documents to determine their consistency with GALL AMP XI.S2. Specifically, the staff reviewed the program elements and
 
associated onsite documents and found that they are consistent with the GALL Report. On the
 
basis of its review, the staff concludes that the applicant's Inservice Inspection (ISI) Program -
 
IWL provides assurance that the reinforced concrete containment structures will be adequately
 
managed.
 
Based on its review, the staff finds the applicant's Inservice Inspection (ISI) Program - IWL consistent with the program elements of GALL AMP XI.S2 and; therefore, is acceptable.
 
Operating Experience. The staff also reviewed the applicant's OE described in LRA Section B.2.35 and some of the applicant's onsite basis documents, including inspection data
 
and summaries, and interviewed the applicant's technical staff to confirm that the plant-specific
 
OE did not reveal any degradation not bounded by industry experience. In the application and
 
during the onsite review, the applicant explained that the OE of the ISI Program - IWL activities
 
shows no adverse trend of program performance.
The staff noted that previous IWL inspections have identified minor exterior surface cracks on the containment surface. The staff also noted
 
that deficiencies were documented, further evaluated, and corrected, if necessary, in
 
accordance with the ISI Program - IWL. For ex ample, visual examinations in 2000 discovered surface cracking on the containment exterior. The applicant provided documentation showing the cracking to be less than the allowable values in accordance with American Concrete 3-73 Institute (ACI) 224R, Table 4.1 and acceptable pursuant to its applicable plant specification. The staff further noted that the applicant established periodic containment concrete IWL inspections
 
in which all accessible external surfaces containment buildings are visually inspected for the
 
duration of plant operation. The staff's OE review has concluded that administrative controls are
 
effective in detecting age-related degradation and initiating corrective action. The staff did not
 
identify any age-related issues not bounded by the industry OE.
 
On this basis, the staff confirms that the "operating experience" program element satisfies the
 
criterion defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10.
 
Therefore, the staff finds this program element acceptable.
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary for the Inservice Inspection (ISI) Program - IWL in LRA Section A.1.2.26, Commitment No. 31. 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 the review of the applicant's Inservice Inspection (ISI) Program -
IWL, 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 functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement
 
for this AMP and concludes that it provides an adequate summary of the program, as required
 
by 10 CFR 54.21(d) and; therefore, is acceptable.
 
3.0.3.1.21  Inservice Inspection (ISI) Program - IWF 
 
Summary of Technical Information in the Application. In LRA Section B.2.36, the applicant described the existing Inservice Inspection (ISI) Program - IWF as consistent with GALL AMP XI.S3, "ASME Section XI, Subsection IWF." 
 
The applicant stated that the Inservice Inspection (ISI) Program - IWF is implemented through
 
plant procedures, which provide for periodic visual ISI of Class 1, 2, and 3 component supports
 
for loss of mechanical function and material. Section 50.55a of 10 CFR requires the use of the
 
examination requirements pursuant to ASME Code, Section XI, Subsection IWF, for ASME Code Class 1, 2, 3, and MC piping and components and their associated supports. The applicant also stated that it has implemented ASME Code Section XI, Subsection IWF, 1998
 
Edition with the 2000 Addenda, and will adopt new ASME Code editions and addenda, consistent with the provisions of 10 CFR 50.55a, during the period of extended operation.
 
Staff Evaluation. During its onsite review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff interviewed the applicant's technical staff and reviewed the
 
applicant's Inservice Inspection (ISI) Program - IWF onsite basis documents to determine their consistency with the GALL AMP XI.S3. Specifically, the staff reviewed the program elements
 
and associated onsite documents and found that they are consistent with the GALL Report. On
 
the basis of the review, the staff concludes that the applicant's Inservice Inspection (ISI)
 
Program - IWF provides assurance that the ASME Code Class 1, 2, and 3 component supports
 
will be adequately managed. 
 
Based on its review, the staff finds the applicant's Inservice Inspection (ISI) Program - IWF consistent with the program elements of GALL AMP XI.S3 and; therefore, is acceptable.
 
3-74 Operating Experience. The staff also reviewed the applicant's OE described in the LRA Section B.2.36 and some of the applicant's onsite basis documents, including some samples of
 
condition reports (CR), and interviewed the applicant's technical staff to confirm that the plant-
 
specific OE did not reveal any degradation not bounded by industry experience. In the
 
application and during the onsite review, the applicant explained that the OE of the Inservice
 
Inspection (ISI) Program - IWF activities shows no adverse trend of program performance. The
 
staff noted in the LRA OE that previous IWF inspections have identified non aging-related
 
degradation such as bent rods on spring can supports and sway struts. Deficiencies were
 
further evaluated and corrected in accordance with the Inservice Inspection (ISI) Program -
 
IWF. During its onsite review, the staff requested that the applicant provide more information
 
about the bent spring can supports described in the OE of the LRA. The applicant provided the
 
CRs which detailed the finding and the resolution. The staff reviewed the documents which
 
provided assurance that the applicant's program captures degradation and corrects it, in accordance with ASME Code Section XI. The applicant has established periodic IWF
 
inspections in which ASME Code Class 1, 2, and 3 component supports are visually inspected
 
for the duration of plant operation. The staff's OE review concludes that the applicant's
 
administrative controls are effective in detecting age-related degradation and initiating corrective action. The staff did not identify any age-related related issues not bounded by the industry OE.
 
On this basis, the staff confirms that the "operating experience" program element satisfies the
 
criterion defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10.
 
Therefore, the staff finds this program element acceptable.
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary for the Inservice Inspection (ISI) Program - IWF in LRA Section A.1.2.25, Commitment No. 30. 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 the review of the applicant's Inservice Inspection (ISI) Program -
IWF, 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 functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement
 
for this AMP and concludes that it adequately describes the program, as required by
 
10 CFR 54.21(d) and; therefore, is acceptable.
 
3.0.3.1.22  Containment Leakage Rate Test Program 
 
Summary of Technical Information in the Application. In LRA Section B.2.37, the applicant described the existing Containment Leakage Rate Test Program as consistent with the GALL AMP XI.S4, "10 CFR Part 50, Appendix J." The applicant uses Option B, the performance-
 
based approach, to implement the requirement of containment leak rate monitoring and testing.
 
The 10 CFR Part 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 c ontainment and systems and components penetrating primary containment does not exceed the acceptance criteria limits.
 
Staff Evaluation. During its onsite review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff interviewed the applicant's technical staff and reviewed the
 
applicant's Containment Leakage Rate Test Program onsite basis documents to determine their 3-75 consistency with the GALL AMP XI.S4. Specifically, the staff reviewed the program elements and associated onsite documents and found that they are consistent with the GALL Report. On
 
the basis of the review, the staff concludes that the applicant's Containment Leakage Rate Test
 
Program provides assurance that leakage through primary containment and system and components penetrating primary containment will be adequately managed. 
 
Based on the review, the staff finds the applicant's Containment Leakage Rate Test Program consistent with the program elements of GALL AMP XI.S4 and; therefore, is acceptable.
 
Operating Experience. The staff also reviewed the applicant's OE described in LRA Section B.2.37 and some of the applicant's onsite documents, including some samples of
 
condition reports, and interviewed the applicant's technical staff to confirm that the plant-specific
 
OE did not reveal any degradation not bounded by industry experience. The staff found that the
 
most recent containment structure integrated leak rate tests were performed in April 2006 and
 
2007 for Units 1 and 2, respectively. The results were below the plant limits found in the
 
technical specifications, and demonstrate the leak tightness of the containments. 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
 
also reviewed a CR which the applicant documented corrosion discovered on an access hatch
 
during the IWE inspection. The corrosion was removed and all four door seals were replaced.
 
The staff did not identify any age-related issues not bounded by the industry OE.
 
On this basis, the staff confirms that the "operating experience" program element satisfies the
 
criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. Therefore, the staff
 
finds this program element acceptable.
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary for the Containment Leakage Rate Test Program in LRA Section A.1.2.15, Commitment No. 32. 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 the review of the applicant's Containment Leakage Rate Test 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 functions will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the
 
UFSAR supplement for this AMP and concludes that it adequately describes the program, as
 
required by 10 CFR 54.21(d) and; therefore, is acceptable.
 
3.0.3.1.23  Non-EQ Electrical Cables and Connections Visual Inspection Program 
 
Summary of Technical Information in the Application. In LRA Section B.2.41, the applicant described the Non-Environmental Qualification (EQ) Electrical Cables and Connections Visual Inspection Program as a new program that is consistent with the GALL AMP XI.E1, "Electrical
 
Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification
 
Requirements." The applicant stated that this AMP will provide reasonable assurance that the
 
applicable electrical components will perform their intended function(s) for the period of
 
extended operation. The applicant also stated that the program provides for the periodic visual
 
inspection of accessible, non-EQ electrical cables and connections, in order to determine if age-
 
related degradation is occurring, particularly in plant areas with high temperatures and/or high
 
radiation levels.
3-76  Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed and compared the "
scope of program," "preventative actions,"
"parameters monitored/detected," "detection of aging effects," "monitoring and trending,"
 
"acceptance criteria," and "operating experienc e" program elements of the AMP to the corresponding program element criteria in the GALL AMP XI.E1. 
 
The staff compared the program elements in the applicant's program to those in GALL AMP XI.E1 to verify that the program el ements in the applicant's AMP, which the LRA identified as consistent with the GALL Report, were consistent with the corresponding program element criteria recommended in the program elements of the GALL AMP XI.E1. The staff determined that additional information was required to complete its review. 
 
The GALL AMP XI.E1 considers the technical information and guidance provided in
 
NUREG/CR-5643, Institute for Electrical and Electronic Engineers (IEEE) Standard P1205, SAND 96-0344, and EPRI TR-109619. 
 
In LRA Section B.2.41, the applicant stated that this program is consistent with the GALL
 
Report; however, the applicant did not provide technical information and guidance as referenced in the GALL AMP XI.E1.
 
In RAI B.2.41-1, dated July  3, 2008, the staff requested that the applicant provide the specific
 
industry guidance or explain why the guidance was not necessary.
 
In its response to RAI B.2.41-1, dated August 05, 2008, the applicant stated that the technical documents listed in GALL AMP XI.E1 (e.g., NUREG/CR-5643, IEEE Standard P1205, SAND96-0344, and EPRI TR-109619) provide inform ation pertinent to plant environmental conditions, environmental effects (particularly wi th regard to adverse environmental conditions), evaluation of environmental conditions and effects, degradation mechanisms, and aging effects.
 
The applicant also stated that the information is relevant to the understanding of electrical cable
 
aging mechanisms and effects, and is also relevant to potential inspection methods necessary
 
to identify degradation. The applicant further stated that the technical guidance contained in
 
these staff and industry reports will be used as input to develop this AMP. 
 
Based on the review, the staff finds the applicant's response to RAI B.2.41-1 acceptable
 
because the applicant has identified the appropriate references that are consistent with those in the GALL AMP XI.E1. Therefore, the staff's concern described in RAI B.2.14-1 is resolved.
 
The GALL XI.E1 states that an adverse localized environment is a condition in a limited plant area that is significantly more severe than the specified service environment for the cable. The
 
staff reviewed the plant basis document associated with the Non-EQ Electrical Cables and
 
Connections Visual Inspection Program and noted that the applicant did not define the criteria
 
for an adverse localized environment.
 
In RAI B.2.41-2, dated July 3, 2008, the staff requested that the applicant discuss how an
 
adverse localized environment is determined based on the most limiting service environment of cables (i.e., radiation, temperature, and moisture) within the scope of the GALL AMP XI.E1. The GALL AMP XI.E1 states conductor insulation material used in electrical cables and connection
 
may degrade in adverse localized environments. The exposure of electrical cables and
 
connections to adverse localized environments caused by heat, or radiation can result in
 
reduced insulation resistance.
3-77  In the response to RAI B.2.41-2, dated August 05, 2008, the applicant stated that adverse
 
localized environments are identified by using a combination of existing information and plant walk downs. The applicant further stated that an adverse localized environment typically occurs when cables are routed in proximity to a source of heat or radiation, or are exposed to
 
significant moisture. The applicant also stated that Information sources that can be used to
 
identify potential adverse localized environments in clude, plant design information, experience and knowledge of plant personnel, radiological survey maps, and plant OE records. Plant walk
 
downs guided by the information from these sour ces, along with the use of thermography to identify heat sources, will determine the adverse localized environments. 
 
The staff found the applicant's response unacceptable because the applicant did not clearly
 
identify the threshold condition (i.e. temperature, radiation) at which the localized environment is
 
considered adverse. In a follow up conference call on October 10, 2008, the staff requested that
 
the applicant define the most limiting temperature and radiation dose values that will be used to
 
identify an adverse localized environment.
 
In a letter dated October 31, 2008, the applicant responded with a supplement to RAI B.2.41-2
 
and stated that the most restrictive 60-year servic e limiting temperature for electrical insulating materials in use at SSES is 112 o F for polyvinyl chloride. The most restrictive 60-year service limiting radiation dose for electrical insulating materials in use at SSES is 5 x 10 4 rads for fluorinated ethylene propylene. These values will be used as the thresholds for evaluation to
 
identify adverse localized environments.
 
Based on the review, the staff finds the applicant's response to RAI B.2.41-2, in addition to the
 
supplemental response acceptable because the applicant has clearly indentified the threshold
 
condition (i.e. temperature, radiation) at whic h the localized environment is considered adverse.
Therefore, the staff's concern described in RAI B.2.41-2 is resolved.
 
In addition to the requirements of 10 CFR Part 50, Appendix B, the "corrective actions" program
 
element in the electrical GALL Report AMPs recommends certain actions, such as making a
 
determination of whether the same condition or situation is applicable to other accessible or
 
inaccessible cables and connections. In the LRA, the applicant stated that the AMPs are
 
consistent with the GALL Report and referred to a corrective action element in LRA
 
Section B.1.3 that is common to all AMPs. The corrective actions described in LRA Section B.1.3 do not contain certain recommendations described in GALL AMP XI.E1.
 
In RAI Q3, dated July 3, 2008, the staff requested that the applicant explain in detail how the generic corrective actions in LRA Section B.1.3 are consistent with GALL AMP XI.E1. 
 
In the response to RAI Q3, dated August 05, 2008, the applicant stated that for the Non-EQ
 
Electrical Cables and Connections Visual Inspection Program, all unacceptable visual indications of cable and connection jacket surface anomalies will be subject to an engineering
 
evaluation. The applicant further stated that evaluation will consider the age and OE of the
 
component, as well as the severity of the anomaly and whether the anomaly has previously been correlated to degradation of the conductor insulation or connections. The applicant also
 
stated that corrective actions may include, but are not limited to, testing, shielding or otherwise
 
changing the environment, or relocation and/or replacement of the affected cable or connection.
 
When an unacceptable condition or situation is identified, the applicant stated that it determines
 
whether the same condition or situation is applicable to other cables or connections within the
 
scope of license renewal.
3-78  Based on the review, the staff finds the applicant's response to RAI Q3 acceptable because the
 
applicant has adequately explained that the corrective actions it has identified will include actions as described in GALL AMP XI.E1. Therefore, the staff concern described in RAI Q3 is
 
resolved.
 
Based on the review of the information contained in the LRA and the applicant's responses to
 
RAIs B.2.41-1, B.2.41-2 and Q3, the staff determines that the Non-EQ Electrical Cable &
 
Connections Visual Inspection Program is consistent with the program elements of GALL AMP XI.E1 and; therefore, is acceptable.
 
Operating Experience. The staff also reviewed the applicant's OE in the onsite plant basis document. The staff confirmed that the applicant has correctly identified the appropriate root
 
causes of cable aging and has taken appropriate corrective actions. 
 
However, under the "operating experience" program element in the Non-EQ Electrical Cables and Connections Visual Inspection Program, the applicant stated that the AMP is a new
 
program for which there is no SSES plant-specific OE.
 
In RAI Q1, dated July  3, 2008, the staff requested that the applicant describe plant-specific OE
 
associated with cables and connections in this AMP and explain how the new program will
 
manage the aging effects of cable and connection insulation. 
 
In the response to RAI Q1, dated August 5, 2008, the applicant included the following OE: (a)
 
during routine preventive maintenance activities in 2000, cables connected to moisture
 
separator level switches were found to be brittle and cracked due to excessive heat and the
 
damaged cables were replaced and (b) in 2002, instrumentation cables connected to a
 
thermocouple in the main steam tunnel were found to be heat damaged and brittle. The
 
damaged section of cable was replaced.
 
Based on the review, the staff finds the applicant's response to RAI Q1 acceptable because the
 
applicant has provided an adequate description of plant-specific OE associated with the cables
 
and connectors in the Non-EQ Electrical Cabl es and Connections Visual Inspection Program.
The staff determines that the OE is consistent with and bounded by those in the GALL AMP XI.E1. Therefore, the staff's concern described in RAI Q1 is resolved. 
 
On this basis, the staff determines that the "operating experience" program element satisfies the
 
criterion defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10.
 
Therefore, the staff finds this program element acceptable. 
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary for the Non-EQ Electrical Cable and Connections Visual Inspection Program in LRA Section A.1.2.35, Commitment No. 36. The staff notes that SRP-LR Table 3.6-2 identifies when an inspection will
 
be implemented and how often the inspection w ill be performed. The UFSAR supplement for the Non-EQ Electrical Cables and Connections Vis ual Inspection Program does not provide the frequency of inspection.
 
In RAI Q2, dated July 3, 2008, the staff requested that the applicant provide the frequency of
 
inspection in the UFSAR supplement. 
 
In the response to RAI Q2, dated August 05, 2008, the applicant included the inspection 3-79 frequency in the UFSAR supplement, in agreement with the Non-EQ Electrical Cables and Connections Visual Inspection Program.
 
Based on the review, the staff finds the applicant's response to RAI Q2 acceptable because the
 
applicant had revised the UFSAR supplement to include the frequency of inspection. Therefore, the staff's concern described in RAI Q2 is resolved.
 
On this basis, the staff determines that the UFSAR supplement provides an adequate summary
 
description of the applicant's Non-EQ Electrical Cable and Connections Visual Inspection, as
 
required by 10 CFR 54.21(d). The staff notes that the applicant has committed (Commitment
 
No. 36) to implement this AMP prior to the period of extended operation.
 
Conclusion. On the basis of the review of the applicant's Non-EQ Electrical Cable and Connections Visual Inspection Program and the applicant's responses to RAIs B.2.41-1, B.2.41-2, Q1, Q2, and Q3, the staff finds all program elements consistent with the GALL Report.
 
The staff concludes that the applicant has demonstrated that effects of aging will be adequately
 
managed so that the intended function(s) will be maintained consistent with the CLB for the
 
period of extended operation as required by 10 CFR 54.21(a)(3). The staff also reviewed the
 
UFSAR supplement for this AMP and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d) and; therefore, is acceptable.
 
3.0.3.1.24  Non-EQ Cables and Connections Used in Low-Current Instrumentation Circuits
 
Program 
 
Summary of Technical Information in the Application. In LRA Section B.2.42, the applicant described the Non-EQ Cables and Connections Used in Low-Current Instrumentation Circuits Program as a new program consistent with the GALL AMP XI.E2, "Electrical Cables and
 
Connections Not Subject to 10 CFR50.49 Environmental Qualification Requirements Used in
 
Instrumentation Circuits." The applicant stated that the purpose of this AMP is to manage the
 
age-related degradation associated with non-EQ, low current instrumentation cables and
 
connections within the scope of license renewal. The applicant also stated that this program
 
applies to in-scope, non-EQ electrical cables and connections used in neutron monitoring
 
circuits with sensitive, low-current signals. The sensitive nature of these circuits is such that
 
visual inspection alone may not detect degradation to the insulation resistance function of the
 
conductor insulation. 
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed and compared the "
scope of program," "preventive actions,"
"parameters monitored/detected," "detection of aging effects," "monitoring and trending,"
 
"acceptance criteria," and "operating experienc e" program elements of the AMP to the corresponding program element criteria in GALL AMP XI.E2. 
 
The staff compared the programs elements in the applicant's AMP to those in the GALL AMP XI.E2. The staff verified that the program elements, which the LRA identified as consistent
 
with the GALL Report, were consistent with the corresponding program element criteria recommended in GALL AMP XI.E2. However, the staff determined that additional information
 
was required to complete its review.
 
The GALL AMP XI.E2 considers the technical information and guidance provided in
 
NUREG/CR-5643, IEEE Standard P1205, SAND96-0344 and EPRI TR-109619. In LRA
 
Section B.2.42, the applicant stated that its program is consistent with the GALL Report, but did 3-80 not provide any information on industrial technical guidance.
 
In RAI B.2.42-1, dated July  3, 2008, the staff requested that the applicant provide specific
 
technical guidance which it will use to develop this AMP. 
 
In its response to RAI B.2.42-1, dated August 05, 2008, the applicant stated that the technical documents listed in GALL AMP XI.E2 (e.g., NUREG/CR-5643, IEEE Standard P1205, SAND 96-0344, and EPRI TR-109619) provide inform ation pertinent to plant environmental conditions, environmental effects (i.e., adverse environmental conditions), evaluation of environmental conditions and effects, degradation mechanisms, and aging effects. The
 
applicant also stated that the information is relevant to the understanding of electrical cable
 
aging mechanisms and effects, and is also relevant to potential inspection methods to identify
 
degradation. The applicant further stated that technical guidance contained in these staff and
 
industry reports will be used as input to develop this AMP.
 
Based on the review, the staff finds the applicant's response to RAI B.2.42-1 acceptable
 
because the applicant has confirmed that it will use industrial guidance to develop the AMP and that the guidance identified by the applicant is consistent with that in GALL AMP XI.E2.
 
Therefore, the staff's concern described in RAI B.2.42-1 is resolved.
 
The GALL AMP XI.E2 states that a proven cable system test for detecting deterioration of the
 
insulation system such as insulation resistance tests, time domain reflectometry tests, or other
 
testing judged to be effective in determining cable insulation condition as justified in the
 
application, should be performed. In LRA Section B.2.42, under the same element, the applicant
 
stated that the testing methodology will be specified prior to the first test.
 
In RAI B.2.42-2, dated July 3, 2008, the staff requested that the applicant provide the type of
 
tests that it will use to detect degradation of insulation in high-voltage, and in low-level signal
 
instrumentation circuits.
 
In its response to RAI B.2.42-2, dated August 05, 2008, the applicant stated that this is a new
 
program that will be implemented consistent with the GALL Report. Therefore, as recommended in the GALL Report, a proven cable system test for detecting degradation of insulation such as, insulation resistance testing, time domain reflectometry, or other suitable test, will be used. The
 
applicant further stated that the test method will be selected prior to performance of the first test
 
and will be a test type consistent with the recommendations in the GALL Report.
 
Based on its review, the staff finds the applicant's response to RAI B.2.42-2 acceptable
 
because the applicant has identified proven methods of testing that it will use and that these methods are consistent with those recommended in the GALL AMP XI.E2. Therefore, the staff's
 
concern described in RAI B.2.42-2 is resolved.
 
In addition to the requirements of 10 CFR Part 50, Appendix B, the "corrective actions" program
 
element in the electrical GALL Report AMPs recommends certain actions, such as making a
 
determination of whether the same condition or situation is applicable to other accessible or
 
inaccessible cables and connections. In the LRA, the applicant stated that its AMPs are
 
consistent with the GALL Report and referred to a corrective action element in LRA
 
Section B.1.3, common to all AMPs. The staff determined that the corrective actions described
 
in this LRA section may not contain certain recommendations described in the GALL AMP XI.E2.
 
3-81 In RAI Q3, dated July  3, 2008, the staff requested that the applicant explain in detail how the generic corrective actions in LRA Section B.1.3 are consistent with GALL AMP XI.E2. 
 
In its response to RAI Q3, dated August 05, 2008, the applicant stated for the Non-EQ Cables
 
and Connections Used in Low-Current Instrumentation Circuits Program, corrective actions
 
such as recalibration and circuit trouble-shooting are implemented when calibration or
 
surveillance results do not meet the acceptance criteria. The applicant performs an engineering
 
evaluation when the test results do not meet the acceptance criteria. The applicant also stated
 
that the evaluation will consider the significance of the test results, the operability of the
 
component, the reportability of the event, the extent of the concern, the potential root causes, the corrective actions required, and the likelihood of recurrence.
 
Based on its review, the staff finds the applicant's response to RAI Q3 acceptable because the applicant has identified corrective actions that are consistent with those in GALL AMP XI.E2.
 
Therefore, the staff's concern described in RAI Q3 is resolved.
 
Based on its review of the information contained in the LRA and the applicant's responses to
 
RAIs B.2.42-1, B.2.42-2 and Q3, the staff finds the applicant's Non-EQ Cables and Connections
 
Used in Low-Current Instrumentation Circuits Pr ogram consistent with the program elements of GALL AMP XI.E2 and; therefore, is acceptable.
 
Operating Experience. The staff reviewed CRs as part of its onsite review of the Non-EQ Cables and Connections Used in Low-Current Instrumentation Circuits Program. The staff determined
 
that the CRs demonstrate that the applicant has implemented appropriate corrective actions.
 
However, the applicant states that the Non-EQ Cables and Connections Used in Low-Current
 
Instrumentation Circuits Program is a new program for which there is no plant-specific OE.
 
In RAI Q1, dated July  3, 2008, the staff requested that the applicant describe plant-specific OE
 
associated with cables and connections in this AMP and explain how the new program will
 
manage the aging effects of cable and connection insulations used in low-current
 
instrumentation circuits. 
 
In its response to RAI Q1, dated August 05, 2008, the applicant stated that the Non-EQ Cables
 
and Connections Used in Low-Current Instrumentation Circuits Program has not been
 
implemented, but the following example of OE demons trates that the aging effect of interest in this AMP (i.e., reduction in insulation resistance), can be, and has been, successfully detected.
 
During routine plant maintenance activities in 2003, two Unit 2 local power range monitoring
 
cables were identified with lower than acceptable insulation resistance. The applicant replaced those cables. GALL AMP XI.E2 states that exposure of electrical cables to adverse localized
 
environments caused by heat, radiation, or moisture can result in reduced insulation resistance.
 
Reduced insulation resistance caused an increase in leakage currents between conductors and
 
from individual conductor to ground. A reduction in insulation resistance is a concern for circuits
 
with sensitive, high-voltage, low-level signals such as radiation monitoring and nuclear
 
instrumentation circuits, because a reduced insulation resistance may contribute to signal
 
inaccuracies.
 
Based on its review, the staff finds the applicant's response to RAI Q1 acceptable because the
 
applicant has adequately described the plant-specific OE associated with cables and
 
connections in this AMP and has sufficiently explained how the new program will manage the aging effects of cable and connection insulations used in low-current instrumentation circuits.
 
The staff determines that reduced insulation resistance is the aging effect of sensitive 3-82 instrumentation cables installed in an adverse localized environment. This aging effect is bounded by that in the GALL AMP XI.E2. Therefore, the staff's concern described in RAI Q1 is
 
resolved.
 
On the basis of its review, the staff determines that the "operating experience" program element
 
satisfies the criterion defined in the GALL Report and the guidance found in SRP-LR
 
Section A.1.2.3.10. Therefore, the staff finds this program element acceptable. 
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary description for the Non-EQ Cables and Connections Used in Low-Cu rrent Instrumentation Circuits Program in LRA Section A.1.2.34, Commitment No. 37. The staff notes that SRP-LR Table 3.6-2 identifies
 
when an inspection will be implemented and how often the inspection will be performed. The applicant's UFSAR supplement for the Non-EQ Cables and Connections Used in Low-Current
 
Instrumentation Circuits Program does not provide the frequency of inspection.
 
In RAI Q2, dated July 3, 2008, the staff requested that the applicant provide the frequency of
 
inspection in the UFSAR supplement.
 
In its response to RAI Q2, dated August 05, 2008, the applicant provided the inspection
 
frequency, as described in the Non-EQ Cables and Connections Used in Low-Current
 
Instrumentation Circuits Program, in the UFSAR supplement. The staff finds that UFSAR
 
supplement summary description in LRA Section A.1.2.34 provides an adequate summary
 
description of the applicant's Non-EQ Cables and Connections Used in Low-Current
 
Instrumentation Circuits Program, as required by 10 CFR 54.21(d). The staff confirms the
 
applicant's commitment (Commitment No. 37) to implement this AMP prior to the period of
 
extended operation.
 
Conclusion. On the basis of its technical review of the applicant's Non-EQ Cables and Connections Used in Low-Current Instrumentation Circuits Program, the staff finds all program
 
elements consistent with the GALL Report. Upon reviewing the LRA and the applicant's
 
responses to RAIs B.2.42-1 B.2.42-2, Q1, Q2, and Q3, the staff finds all program elements
 
consistent with the GALL Report. The staff concludes that the applicant has demonstrated that
 
effects of aging will be adequately managed so that the intended function(s) will be maintained
 
consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concludes that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d) and. therefore, is acceptable.
 
3.0.3.1.25  Non-EQ Inaccessible Medium-Voltage Cables Program 
 
Summary of Technical Information in the Application. In LRA Section B.2.43, the applicant described the new Non-EQ Inaccessible Medium-V oltage Cables Program as consistent with GALL AMP XI.E3, "Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 EQ
 
Requirements." The applicant also stated that this AMP will manage the aging of non-EQ
 
inaccessible medium-voltage electrical cables subject to wetting, within the scope of license
 
renewal. The applicant further stated that the program provides for the periodic testing of non-
 
EQ inaccessible medium-voltage electrical cables, in order to determine if age-related
 
degradation is occurring, and includes provisions for the inspection of associated manholes to
 
identify any collection of water.
 
Staff Evaluation. During the audit, the staff reviewed the applicant's claim of consistency with 3-83 the GALL Report. The staff reviewed and compar ed the "scope of program," "preventive actions," "parameters monitored/detected," "detection of aging effects," "monitoring and
 
trending," "acceptance criteria," and operating ex perience" program elements of the AMP to GALL AMP XI.E3. 
 
The staff compared the program elements in the applicant's program to those in the GALL AMP XI.E3 and verified that the program elements in the applicant's AMP, which the
 
applicant identified as consistent with the GALL Report, were consistent with the GALL AMP XI.E3. However, the staff determined that additional information was required to complete
 
its review.
In LRA Section B.2.43, under the "scope of program" element, the applicant stated that this program applies to six cables associated with the offsite power supply for SSES. The applicant
 
also stated that these are the only inaccessible medium-voltage cables that are within the scope
 
of license renewal and are exposed to significant moisture and significant voltage. Significant
 
voltage is defined by the GALL Report as any device or cable that is energized more that 25%
 
of the time. The staff noted that the RHR and emergency service water (ESW) pump cables
 
could be subjected to significant moisture and significant voltage.
 
In RAI B.2.43-1, dated July  3, 2008, the staff requested that the applicant explain why these
 
cables are not within the scope of the Non-EQ Inaccessible Medium-Voltage Cables Program. 
 
In the response to RAI B. 2.43-1, dated August 5, 2008, the applicant stated that the cables for
 
the RHR pump motors are not within the scope of the Non-EQ Inaccessible Medium-Voltage
 
Cables Program because they are not routed underground and are not exposed to significant
 
moisture. The cables for the RHR service water (RHRSW) and ESW pump motors are not
 
included in the scope of the Non-EQ Inaccessi ble Medium-Voltage Cables Program because they are energized less that 25% of the time. The applicant also stated that as described in the GALL AMP XI.E3, this AMP applies to inaccessibl e medium-voltage cables within the scope of license renewal that are exposed to significant moisture, simultaneously with significant voltage.
 
The GALL Report states that significant moisture is defined as periodic exposures to moisture
 
that last more than a few days, and significant voltage is defined as being subject to system
 
voltage more than 25% of the time. The applicant concluded that, because the RHR, RHRSW, and ESW pump motor cables are either not exposed to significant moisture, or to significant
 
voltage, they are excluded from the scope of t he Non-EQ Inaccessible Medium-Voltage Cables Program.
 
Based on the review, the staff finds the applicant's response to RAI B.2.43-1 acceptable
 
because the applicant has adequately explained that the RHR, RHRSW, and ESW pump motor
 
cables are either not exposed to significant moisture or to significant voltage; therefore, they are
 
not required to be within the scope of the Non-EQ Inaccessible Medium-Voltage Cables
 
Program. Therefore, the staff's concern described in RAI B.2.43-1 is resolved. 
 
The GALL AMP XI.E3 considers the technical information and guidance provided in
 
NUREG/CR-5643, IEEE Standard P1205, SAND96-0344 and EPRI TR-109619. In LRA
 
Section B.2.43, the applicant stated that the program is consistent with the GALL Report and
 
yet, it did not provide any information on industrial technical guidance.
 
In RAI B.2.43-3, dated July 3, 2008, the staff requested that the applicant provide technical
 
guidance for the Non-EQ Inaccessible Medium-Voltage Cables Program or provide a justification for why this guidance is not necessary.
3-84  In the response to RAI B.2.43-3, dated August 5, 2008, the applicant stated that the technical documents listed in GALL AMP XI.E3 (e.g., NUREG/CR-5643, IEEE Standard P1205, SAND96-0344, and EPRI TR-109619) provide inform ation pertinent to plant environmental conditions, environmental effects (i.e., adverse environmental conditions), evaluation of environmental conditions and effects, degradation mechanisms, and aging effects. The
 
applicant further stated that the information is relevant to understanding electrical cable aging
 
mechanisms and effects, and is also relevant to potential testing methods to identify
 
degradation. The technical guidance contained in these staff and industry reports will be used
 
as input to develop this AMP.
 
Based on the review, the staff finds the applicant's response to RAI B.2.43-3 acceptable because the applicant has provided the technical documents listed in the GALL AMP XI.E3 as
 
its references. Therefore, the staff's concern described in RAI B.2.43-3 is resolved. 
 
The GALL AMP XI.E3, under the "detection of aging effects" program element, states that the
 
specific type of test is to be a proven test for detecting deterioration of the insulation system due
 
to wetting (i.e., power factor, partial discharge, or polarization index), as described in EPRI
 
TR-103834-P1-2, or other testing that is state-of-the-art at the time of the test is performed. In
 
LRA Section B.2.43, under the same attribute, the applicant stated that the program will utilize a
 
proven test for detecting deterioration of the cable insulation due to wetting and energization, and will reflect the actual test methodology prior to the initial performance of the cable testing. 
 
In RAI B.2.43-4, dated July 3, 2008, the staff requested that the applicant describe the testing
 
methodology for detecting deterioration of the cable insulation under this AMP.
 
In the response to RAI B.2.43-4, dated August 5, 2008, the applicant stated that this is a new
 
program that will be implemented consistent with the GALL Report. The applicant further stated
 
that, as recommended in the GALL Report, a proven test for detecting deterioration of the
 
insulating system (i.e., such as, power factor, par tial discharge, polarization index), as described in EPRI TR103834-P1-2, or other state-of-the-art testing, will be used. The test method will be
 
selected prior to performance of the first test and will be a test-type consistent with the
 
recommendations of the GALL Report.
 
Based on its review, the staff finds the applicant's response to RAI B.2.43-4 acceptable
 
because the applicant has reasonably described the testing methodology for detecting
 
deterioration of the cable insulation under this AMP, which is consistent with those recommended in the GALL AMP XI.E3. Therefore, the staff's concern described in RAI B.2.43-4
 
is resolved.
 
In addition to the requirements of 10 CFR Part 50, Appendix B, the "corrective actions" program
 
element in the electrical GALL AMPs recommends certain actions, such as making a
 
determination of whether the same condition or situation is applicable to other accessible or
 
inaccessible cables and connections. In the LRA, the applicant stated that its AMPs are
 
consistent with the GALL Report and referred to a corrective action element in LRA
 
Section B.1.3, common to all AMPs. The staff determined that the corrective actions described
 
in LRA Section B.1.3 may not contain certain recommendations described in the GALL AMP XI.E3.
 
In RAI Q3, dated July  3, 2008, the staff requested that the applicant explain in detail how the generic corrective actions in LRA Section B.1.3 are consistent with GALL AMP XI.E3.
3-85  In its response to RAI Q3, dated August 5, 2008, the applicant stated that for the Non-EQ
 
Inaccessible Medium-Voltage Cables Program, an engineering evaluation is performed in order to ensure that the intended function of the electrical cables can be maintained consistent with
 
the CLB, when the test acceptance criteria are not met. The evaluation will consider the
 
significance of the test results, the operability of the component, the reportability of the event, the extent of the concern, the potential root causes, the corrective actions required, and the
 
likelihood of recurrence. When an unacceptable condition or situation is identified, a
 
determination will be made as to whether the same condition or situation is applicable to other
 
in-scope medium-voltage cables.
 
Based on its review, the staff finds the applicant's response to RAI Q3 acceptable because the
 
applicant has adequately explained how the corrective actions are consistent with those in GALL AMP XI.E3. Therefore, the staff's concern described in RAI Q3 is resolved.
 
Based on the review of the information contained in the LRA and the applicant's responses to
 
RAIs B.2.43-1, B.2.43-3, B.2.43-4, and Q3, the staff finds the Non-EQ Inaccessible
 
Medium-Voltage Cables Program consistent with the program elements of GALL AMP XI.E3, and; therefore, is acceptable.
 
Operating Experience. The staff reviewed the applicant's OE and noted that inaccessible medium-voltage cables in certain manholes at SSES have experienced significant moisture (i.e., cable in standing water for more than few days). In addition, during a walk down, the staff found
 
several feet of water in Manhole Numbers 2 and 16. 
 
The staff identified water in manholes as a generic, current operating plant issue in IN 2002-12, "Submerged Safety-Related Electrical Cables," dated March 21, 2002, and GL 2007-01, "Inaccessible or Underground Power Cable Failures That Disable Accident Mitigation Systems
 
Or Cause Plant Transients," dated February 7, 2007. The staff will address water in manholes, during the current period of operation, through the reactor oversight process, in accordance with
 
the requirements of 10 CFR Part 50. 
 
During its review of the LRA, the staff determined that the Non-EQ Inaccessible
 
Medium-Voltage Cable Program, if implemented as described, would ensure that the aging affects on inaccessible medium-voltage cables, due to exposure to significant moisture and
 
significant voltage, will be adequately managed during the period of extended operation, and pursuant to the guidance contained in GALL AMP XI.E3. The Non-EQ Inaccessible
 
Medium-Voltage Cable Program is a new AMP which will require the applicant to test the cables and to evaluate plant-specific OE to determine whether the inspection frequency of the
 
manholes should be increased to ensure that the cables will be maintained in a dry
 
environment, during the period of extended period of operation. 
 
In the LRA, the applicant stated that the Non-EQ Inaccessible Medium-Voltage Cable Program is a new program for which there is no plant-specific OE.
 
In RAI Q1, dated July  3, 2008, the staff requested that the applicant describe plant-specific OE
 
associated with cables and connections in this AMP and explain how the new program will
 
manage non-EQ medium voltage cables. 
 
In the response to RAI Q1, dated August 5, 2008, the applicant stated that the Non-EQ
 
Inaccessible Medium-Voltage Cable Program is license renewal AMP and has not yet been 3-86 implemented. However, the following example of OE demonstrates that the aging effects of interest in this AMP (i.e.
, degradation of the conductor insulation for medium-voltage cables exposed to significant moisture and voltage) can be, and has been, successfully detected at
 
SSES. The applicant further stated that it detected a negative trend in power factor test results
 
of 15 kV underground cables supplying power to the plant's river water intake. The test results
 
are indicative of expected aging of the cable insulation system. The applicant also stated that
 
these cables continue to be monitored under the plant corrective action program. 
 
Based on its review, the staff finds the applicant's response to RAI Q1 acceptable because the
 
applicant has adequately explained how the aging effects due to significant moisture and
 
voltage will be detected and the corrective actions it will take. The staff determines that the
 
applicant's response supports the conclusion that this AMP will provide assurance that the
 
aging effects will be managed consistent with CLB, during the period of extended operation.
 
Therefore, the staff's concern described in RAI Q1 is resolved. 
 
On this basis, the staff determines that the "operating experience" program element satisfies the
 
criterion defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10.
 
Therefore, the staff finds this program element acceptable. 
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary for the Non-EQ Inaccessible Medium-Voltage Cables Program in LRA Section A.1.2.36, Commitment No. 38. 
 
The staff notes that SRP-LR Table 3.6-2 identifies when an inspection will be implemented and
 
how often the inspection will be performed. The UFSAR supplement for the Non-EQ
 
Inaccessible Medium-Voltage Cables Program does not provide the frequency of inspection.
 
In RAI Q2, dated July 3, 2008, the staff requested that the applicant provide the frequency of
 
inspection in the UFSAR supplement. 
 
In the response to RAI Q2, dated August 5, 2008, the applicant provided the inspection
 
frequency for its UFSAR supplement.
 
Based on the review, the staff finds the applicant's response to RAI Q2 acceptable because the
 
applicant has provided the frequency of inspection in the UFSAR supplement.
 
The staff finds that UFSAR Supplement summary description in LRA Section A.1.2.36 provides
 
an adequate summary description of the applicant's Non-EQ Inaccessible Medium-Voltage
 
Cables Program, as required by 10 CFR 54.21(d). The staff notes that the applicant has
 
committed (Commitment No. 38) to implement this AMP prior to the period of extended
 
operation. 
 
Conclusion. On the basis of the review of the applicant's Non-EQ Inaccessible Medium-Voltage Cables Program and the applicant's responses to RAI B.2.43-1, B.2.43-3, B.2.43-4, Q1, Q2, and
 
Q3, the staff finds all program elements consistent with the GALL Report. The staff concludes
 
that the applicant has demonstrated that effects of aging will be adequately managed so that
 
the intended function(s) will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(d). 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) and; therefore, is acceptable.
 
3-87 3.0.3.1.26  Metal-Enclosed Bus Inspection Program 
 
Summary of Technical Information in the Application. In LRA Section B.2.44, the applicant described the new Metal-Enclosed Bus Inspection Program as consistent with the GALL AMP XI.E4, "Metal-Enclosed Bus." The applicant also stated that this AMP will provide the
 
periodic inspection of the applicable metal-enclosed bus, in order to determine whether age-
 
related degradation is occurring. The applicant further stated that the program provides for the
 
periodic inspection of the applicable metal-enclosed bus, in order to determine if age-related
 
degradation is occurring.
 
Staff Evaluation. During the audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed and compared the "scope of program," "preventative actions," "parameters monitored/detected," "detection of aging effects," "monitoring and
 
trending," "acceptance criteria," and "operating exper ience" program elements of the AMP to the corresponding program element criteria in the GALL AMP XI.E4. 
 
The staff compared the programs elements in the applicant's program to those in the GALL AMP XI.E4. The staff noted the program elements in the applicant's AMP claim of consistency with GALL were consistent with the GALL AMP XI.E4. The staff determined that
 
additional information was required to complete its review.
 
In addition to the requirements of 10 CFR Part 50, Appendix B, the "corrective actions" program element in the electrical GALL AMP XI.E4 recommends certain actions, such as making a
 
determination of whether the same condition or situation is applicable to other accessible or
 
inaccessible metal-enclosed busses. In the LRA, the applicant stated that its AMP is consistent
 
with the GALL Report and referred to a corrective action element in the LRA, Section B.1.3, common to all AMPs. The staff determined that the corrective actions described in LRA Section B.1.3 do not contain certain recommendations described in the GALL AMP XI.E4.
 
In RAI Q3, dated July 3, 2008, the staff requested that the applicant explain, in detail, how the generic corrective actions in LRA Section B.1.3 are consistent with GALL AMP XI.E4. 
 
In its response to RAI Q3, dated August 5, 2008, the applicant stated that for the new
 
Metal-Enclosed Bus Inspection Program, further investigation and evaluation are performed
 
when the acceptance criteria are not met. Corrective actions may include, but are not limited to
 
cleaning, drying, an increased inspection frequency, replacement, or repair of the affected
 
metal-enclosed bus components. If an unacceptable condition or situation is identified, the
 
applicant further stated that it determines whether the same condition or situation is applicable
 
to other metal-enclosed busses. 
 
Based on the review, the staff finds the applicant's response to RAI Q3 acceptable because the
 
applicant has adequately explained how its generic corrective actions in the new Metal-Enclosed Bus Inspection Program are consistent with the GALL AMP XI.E4. The staff
 
determines that the applicant's corrective actions are consistent with those in the GALL AMP XI.E4. Therefore, the staff's concern described in RAI Q3 is resolved.
 
Based on the review, the staff finds the Metal-Enclosed Bus Inspection Program consistent with the program elements of GALL AMP XI.E4 and; therefore, is acceptable.
 
Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.44.
The staff also reviewed industry experience relevant to this AMP and noted that industry 3-88 experience has shown that failures have occurred on metal-enclosed busses caused by cracked insulation and moisture or debris buildup internal to the metal enclosed busses.
 
Experience also has shown that bus connections in metal-enclosed busses exposed to
 
appreciable ohmic heating, during operation, may experience loosening due to repeated cycling
 
of connected loads. However, under the "operating experience" program element in the LRA, the applicant states that the Metal-Enclosed Bus Inspection Program is a new program for
 
which there is no plant-specific OE.
 
In RAI Q1, dated July 3, 2008, the staff requested that the applicant describe plant-specific OE
 
associated with cables and connections in this AMP and explain how the new program will
 
manage the aging effects of metal-enclosed buses. 
 
In the response to RAI Q1, dated August 5, 2008, the applicant stated that visual inspections
 
were performed of bus 0A206 in 2006 and 0A107 in 1996. No significant age-related
 
degradation was detected during these inspections. The applicant also stated that bus
 
enclosures were found to be clean, with no evidence of overheating of bus connections. The
 
applicant concluded that these activities demonstrate that the bus is generally accessible for
 
visual inspection and in good condition, such that if any aging effects of interest for this
 
AMP occur, they should be detected during future inspections.
 
Based on the review, the staff finds the applicant's response to RAI Q1 acceptable because the
 
applicant has adequately explained how the Metal-Enclosed Bus Inspection Program will
 
manage the aging effects of metal-enclosed buses. The staff determines that the aging effects
 
of metal-enclosed busses will be detected and this AMP will provide assurance that the aging
 
effects will be managed consistent with CLB, during the period of extended operation.
 
Therefore, the staff's concern described in RAI Q1 is resolved.
 
On this basis, the staff confirms that the "operating experience" program element satisfies the
 
criterion defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10.
 
Therefore, the staff finds this program element acceptable. 
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary for the Metal-Enclosed Bus Inspection Program in LRA Section A.1.2.32, Commitment No. 39. The
 
staff notes that SRP-LR Table 3.6-2 identif ies when an inspection will be implemented and how often the inspection will be performed. The staff determined that the UFSAR supplement for the
 
Metal-Enclosed Bus Inspection Program does not provide the frequency of inspection.
 
In RAI Q2, dated July 3, 2008, the staff requested that the applicant provide the frequency of
 
inspection in the UFSAR supplement. 
 
In the response to RAI Q2, dated August 5, 2008, the applicant provided the inspection
 
frequency for the UFSAR supplement.
 
Based on the review, the staff finds the applicant's response to RAI Q2 acceptable because the
 
applicant has provided the inspection frequency for the UFSAR supplement. Therefore, the
 
staff's concern described in RAI Q2 is resolved.
 
The staff finds that UFSAR supplement in LRA Section A.1.2.32 provides an adequate summary
 
description of the applicant's Metal-Enclosed Bus Inspection Program, as required by
 
10 CFR 54.21(d). The staff notes that the applicant has committed (Commitment No. 39) to
 
implement this AMP, prior to the period of extended operation.
3-89  Conclusion. On the basis of the review of the applicant's Metal-Enclosed Bus Inspection Program and the applicant's responses to RAIs Q1, Q2, and Q3, the staff finds all program
 
elements consistent with the GALL Report. The staff concludes that the applicant has
 
demonstrated that effects of aging will be adequately managed so that the intended function(s)
 
will be maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concludes that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d) and; therefore, is acceptable.
 
3.0.3.1.27 Non-EQ Electrical Cable Connections Program Summary of Technical Information in the Application. In LRA Section B.2.45, the applicant described the new Non-EQ Electrical Cable Connections Program as consistent with the GALL AMP XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental
 
Qualification Requirements." The applicant stated that this AMP will manage the aging effects
 
for the metallic parts of non-EQ electrical cabl e connections within the scope of license renewal.
It will address cable connections that are used to connect cable conductors to other cables or
 
electrical devices.
 
Staff Evaluation.
During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed and compared the "
scope of program," "preventative actions,"
"parameters monitored/detected," "detection of aging effects," "monitoring and trending,"
 
"acceptance criteria," and "operating experienc e" program elements of the AMP to the corresponding program element criteria in GALL AMP XI.E6. 
 
The staff compared the programs elements in the applicant's program to those in GALL AMP XI.E6. The staff noted that the program elements in the applicant's AMP claim of consistency with the GALL Report were consistent with the GALL AMP XI.E6. The staff
 
determined that additional information was required to complete its review.
 
In addition to the requirements of 10 CFR Part 50, Appendix B, the "corrective actions" program
 
element in the electrical GALL AMPs recommends certain actions, such as making a
 
determination of whether the same condition or situation is applicable to other accessible or
 
inaccessible cables and connections. In the LRA, the applicant stated that the AMPs are
 
consistent with the GALL Report and referred to a corrective action element in LRA
 
Section B.1.3, common to all AMPs. The staff determined that the corrective actions described
 
in LRA Section B.1.3 do not contain certain recommendations described in the GALL AMP XI.E6.
 
In RAI Q3, dated July  3, 2008, the staff requested that the applicant explain, in detail, how the generic corrective actions in LRA Section B.1.3 are consistent with the GALL AMP XI.E6. 
 
In the response to RAI Q3, dated August 5, 2008, the applicant stated that for the GALL AMP XI.E6, (the Non-EQ Electrical Cable Connections Program), it performs an engineering evaluation, when the test acceptance criteria are not met, to ensure that the intended functions
 
of the cable connections can be maintained, consistent with the CLB. The evaluation will
 
consider the significance of the test results, the operability of the component, the reportability of
 
the event, the extent of the concern, the potential root causes, the corrective actions required, and the likelihood of recurrence. The applicant further stated that when an unacceptable
 
condition or situation is identified, a determination is made as to whether the same condition or 3-90 situation is applicable to other in-scope cable connections that were not tested.
 
Based on its review, the staff finds the applicant's response to RAI Q3 acceptable because the
 
applicant has adequately explained how the generic corrective actions in LRA Section B.1.3 are consistent with the GALL AMP XI.E6. The staff confirms that the corrective actions identified by the applicant are consistent with those recommended in the GALL report AMP XI.E6. Therefore, the staff's concern described in RAI Q3 is resolved.
 
Based on the review, the staff finds the Non-EQ Electrical Cable Connections Program consistent with the program elements of the GALL AMP XI.E6 and; therefore, is acceptable.
 
Operating Experience.
The staff reviewed the applicant's OE described in LRA Section B.2.45.
The staff also reviewed industry guidance with relevance to this AMP. The staff noted that under
 
the OE program element in the LRA, the applicant stated that the Non-EQ Electrical Cable
 
Connections Program is a new program for which there is no plant-specific OE.
 
In RAI Q1, dated July 3, 2008, the staff requested that the applicant describe plant-specific OE
 
associated with cables and connections in this AMP and explain how the new program will
 
manage the aging effects of cable and connection insulations. 
 
In the response to RAI Q1, dated August 05, 2008, the applicant stated that this license renewal
 
AMP has not yet implemented, but, the following ar e examples of OE that demonstrate that the aging effects of interest in this AMP (i.e., loosening of cable connections), can be, and have
 
been successfully detected. The applicant further stated that during routine maintenance
 
activities in 2007, it found a cable crimp connection in a switchgear cubicle, operating at a
 
higher temperature than other connections in the same circuit. The applicant determined that
 
the temperature differential was only minor and; thus, not an operability concern. Nonetheless, the applicant replaced the cable lug. The applicant concluded that this demonstrates that a
 
loose connection can be detected via thermography, before loss of intended functions. The
 
applicant further stated that in 1997, usi ng thermography while performing preventive maintenance activities on a battery charger, it detected a hot spot on the DC output cable lugs.
 
The applicant replaced the cable lugs and returned the battery charger to service, without loss
 
of intended function.
 
Based on the review, the staff finds the applicant's response to RAI Q1 acceptable because the
 
applicant has demonstrated that the aging effects of cable connections will be detected using
 
thermography. The staff determines that this AMP will provide assurance that the aging effects will be managed consistent with the CLB. Therefore, the staff's concern described in RAI Q1 is
 
resolved. 
 
On this basis, including the applicant's response to the RAI, the staff confirms that the
 
"operating experience" program element satisf ies the criterion defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10. Therefore, the staff finds this program
 
element acceptable. 
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary for the Non-EQ Electrical Cable Connections Program in LRA Section A.1.2.37, Commitment No. 50. The staff
 
notes that SRP-LR Table 3.6-2 identifies w hen an inspection will be implemented and how often the inspection will be performed. The UFSAR supplement for the Non-EQ Electrical Cable &
 
Connections Visual Inspection Program does not provide the frequency of inspection.
 
3-91 In RAI Q2, dated July 3, 2008, the staff requested that the applicant provide the frequency of inspection in the UFSAR supplement. 
 
In the response to RAI Q2, dated August 5, 2008, the applicant provided the inspection
 
frequency for its UFSAR supplement, Commitment No. 50.
 
Based on the review, the staff finds the applicant's response to RAI Q2 acceptable because the
 
applicant has provided the frequency of inspection for the UFSAR summary. Therefore, the
 
staff's concern described in RAI Q2 is resolved.
 
The staff finds that UFSAR Supplement summary description in LRA Section A.1.2.37, provides
 
an adequate summary description of the applicant's Non-EQ Electrical Cable Connections
 
Program, as required by 10 CFR 54.21(d). The staff notes that the applicant has committed to
 
implement this AMP prior to the period of extended operation.
 
Conclusion.
On the basis of the review of the applicant's Non-EQ Electrical Cable Connections Program, the staff finds all program elements consistent with the GALL Report. The staff
 
concludes that the applicant has demonstrated that effects of aging will be adequately managed
 
so that the intended function(s) will be maintained consistent with the CLB, for the period of
 
extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR
 
supplement for this AMP and concludes that it provides an adequate summary description of the
 
program, as required by 10 CFR 54.21(d) and; therefore, is acceptable.
3.0.3.1.28  Environmental Qualification (EQ) Program 
 
Summary of Technical Information in the Application. In LRA Section B.3.2, the applicant described the existing Environmental Qualificati on (EQ) Program as consistent with the GALL AMP X.E1, "Environmental Qualification (EQ) of Electric components" The applicant stated that this EQ program manages component thermal, r adiation, and cyclic aging through the use of aging evaluation in accordance with 10 CFR 50.49(f) qualification methods. 
 
As required by 10 CFR 50.49, EQ components not qualified for the current license term are to
 
be refurbished, replaced or have their qualification extended, prior to reaching the aging limits
 
established in the evaluation.
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed and compared the "
scope of program," "preventive actions,"
"parameters monitored/detected," "detection of aging effects," "monitoring and trending,"
 
"acceptance criteria," and "operating experienc e" program elements of the AMP to the corresponding program element criteria in the GALL AMP X.E1. 
 
The staff's review of the "corrective actions,"
"administrative controls," and "confirmatory controls" program elements for the Environmental Qualification (EQ) Program was performed as part of the staff's review of the QA attributes of the AMPs and is discussed in SER
 
Section 3.0.4.
 
In comparing the programs elements in the applicant's program to those in the GALL AMP X.E1, the staff noted the program elements in the applicant's AMP claim of consistency with the GALL Report, were consistent with GALL AMP X.E1.
 
Based on the review, the staff finds the Environmental Qualification (EQ) Program consistent 3-92 with the program elements of the GALL AMP X.E1 and; therefore, is acceptable. Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.3.2.
The staff also reviewed the applicant's plant basis documents and finds that the applicant
 
discussed OE with existing program. The OE, including past corrective actions, which resulted
 
in a program's enhancement. The applicant stated in CR 191057, that while performing
 
investigation of equipment, it concluded that terminal voltages typically exceed the 120 VAC rating of solenoid-operated valves in the EQ program. The study concluded an establishment of the maximum end-device voltages for U1 Class 1E 120V panels, and on the average 10 and
 
T20 bus voltage over the last year. A review of effected Environmental Qualification
 
Assessment Report has determined that temperature rise due to self-heat, at voltages above
 
120 VAC, has not been factored into qualified life determinations. Corrective action was taken to
 
address the issue. The staff determines that this information will provide objective evidence to
 
support the conclusion that the effects of aging will be managed so that the intended functions
 
will be maintained consistent with CLB, during the period of extended operation. 
 
The staff confirms that the "operating experience" program element satisfies the criterion
 
defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10. Therefore, the staff finds this program element acceptable.
 
UFSAR Supplement The applicant provided the UFSAR supplement summary of the EQ of electrical equipment in LRA Section A.1.3.4, Commitment No. 44. The summary description is
 
not consistent with SRP-LR Table 4.4.2, as it does not contain reanalysis attributes. Reanalysis should address the attributes of analytical methods, data collection and reduction methods, underlying assumptions, acceptance criteria, corrective actions, if acceptance criteria are not
 
met, and the period of time when the reanalysis will be completed.
 
In RAI B.3.2-1, dated July 3, 2008, the staff requested that the applicant revise the UFSAR
 
supplement to include these reanalysis attributes. 
 
In the response to RAI B.3.2-1, dated August 5, 2008, the applicant added the following in LRA
 
Section A.1.3.4:
 
10 CFR 50.49 requires EQ components that are not qualified for the current license term
 
to be refurbished, replaced, or have their qualifications extended prior to reaching the
 
aging limits established in the aging evaluation. Reanalysis of aging evaluation to extend
 
the qualifications of components is performed on a routine basis as part of the EQ
 
Program. Important attributes for the reanalysis of aging evaluations include analytical
 
methods, data collection and reduction methods, underlying assumptions, acceptance
 
criteria, corrective actions (if acceptance criteria are not met), and the time remaining to
 
the end of qualified life.
 
Based on the review, the staff finds the applicant's response to RAI 3.2-1 acceptable because
 
the applicant has revised the UFSAR supplement to be consistent with SRP-LR Table 4.4.2.
 
Therefore, the staff's concern described in RAI 3.2-1 is resolved.
 
The staff finds that the UFSAR supplement summary description in LRA Section A.1.3.4, provides an adequate summary description of t he applicant's EQ Program, as required by 10 CFR 54.21(d). The staff notes that the applicant has committed (Commitment No. 44) to
 
implement this AMP prior to the period of extended operation.
 
3-93 Conclusion. On the basis of the review of the applicant's Environmental Qualification (EQ)
Program, the staff finds all program elements consistent with the GALL Report. The staff
 
concludes that the applicant has demonstrated that effects of aging will be adequately managed
 
so that the intended 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, including the applicant's response to RAI B.3.2-1, and concludes that
 
it provides an adequate summary description of the program, as required by 10 CFR 54,21(d)
 
and; therefore, is acceptable.
 
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:
* Inservice Inspection (ISI) Program
* BWR CRD Return Line Nozzle Program
* BWR Penetrations Program
* BWR Vessel Internals Program
* Bolting Integrity Program
* Piping Corrosion Program
* Closed Cooling Water Chemistry Program
* Fire Protection Program
* Fire Water System Program
* Buried Piping and Surveillance Program
* Fuel Oil Chemistry Program
* Reactor Vessel Surveillance Program
* Buried Piping and Tanks Inspection Program
* System Walkdown Program
* Lubricating Oil Analysis Program
* Masonry Wall Program
* Structures Monitoring Program
* RG 1.127 Water-Control Structures Inspection
* Fatigue Monitoring Program For AMPs that the applicant claimed are consistent with the GALL Report, with exception(s), enhancement(s), or both, 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  Inservice Inspection (ISI) Program 
 
Summary of Technical Information in the Application In LRA Section B.2.1, the applicant described the Inservice Inspection (ISI) Program as an existing program that is consistent, with an exception, to the GALL AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD." The applicant stated that the program is in accordance with the requirements of ASME Code Section XI, Division 1, Subsections IWA, IWB, IWC, IWD, IWE, IWF, IWL, 1998 Edition through the 2000 Addenda, Mandatory Appendices, Inspection Program
 
B of IWA-2432, and approved ASME Code Cases.
 
3-94  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, is adequate to manage the aging effects for which the LRA credits it.
 
The staff also confirmed that the applicant's program contains all of the elements of the GALL
 
Report. The staff conducted onsite interviews with the applicant to confirm these results. 
 
The staff noted the applicant had indicated that the current scope of the program applies to the ASME Code Section XI, 1998 Edition, inclusive of the 2000 Addenda. The program description in the GALL AMP XI.M1 states that the GALL Report applies to inspection, repair, and replacement activities for ASME Code components covered in the ASME Code Section XI, 2001
 
Edition, inclusive of the 2003 Addenda. The staff noted that the applicant clarified that the use of the ASME Code Section XI, 1998 Edition, inclusive of the 2000 Addenda, is consistent with the program description statement in GALL AMP XI.M1 because the SOC on 10 CFR Part 54 clarifies that acceptable editions of the ASME Code Section XI are those acceptable endorsed editions of the ASME Code Section XI up through the most recently endorsed edition of the
 
Code mentioned in 10 CFR 50.55a. The staff verified that the SOC on 10 CFR Part 54 does
 
include this clarification, and that based on this clarification, use of the ASME Code Section XI, 1998 Edition, inclusive of the 2000 Addenda, is consistent with the Code edition mentioned in the program description of GALL AMP XI.M1. Based on this review, the staff finds the applicant's crediting of the ASME Code Section XI, 1998 Edition, inclusive of the 2000 Addenda (for aging management) is consistent with the criteria in GALL AMP XI.M1.
 
In comparing the elements in the applicant's program to those in the GALL AMP XI.M1, the staff noted the program elements in the applicant's AMP claim of consistency with the GALL Report were consistent with the GALL AMP XI.M1 with the exception of program elements aspects
 
identified below. The staff determined that additional information was required to complete its
 
review. 
 
The staff noted that the applicant had not identified the parameters or aging effect that the
 
program manages in either the "scope of progr am," "parameters monitored/inspected," or "detection of aging effects" program elements for the AMP.
 
In RAI B.2.1-1, dated June 12, 2008, the staff requested that the applicant identify the
 
parameters or aging effects that are within the scope of and are managed by the Inservice
 
Inspection (ISI) Program. 
 
In the response to RAI B.2.1-1, dated July 14, 2008, the applicant stated that during the period
 
of extended operation, the Insevice Inspection (ISI) Program is credited to manage the following
 
aging effects/mechanisms for components within the reactor coolant system, including the RV
 
and RV internals:
 
Cracking due to stress corrosion cracking, intergranular stress corrosion cracking, and irradiation-assisted stress corrosion cracking Loss of material due to general, pitting, and crevice corrosion Loss of fracture toughness due to thermal aging embrittlement of CASS components
 
The applicant also stated that loss of fracture toughness due to thermal aging embrittlement of
 
CASS components is managed via the detection of cracking and the monitoring of crack growth.
3-95  The staff finds the applicant's response partially addressed the staff's inquiry raised in 
 
RAI B.2.1-1, because the applicant has identified the aging effects managed by the Inservice
 
Inspection (ISI) Program. However, the staff noted that, in LRA Table 3.1.2-3, the applicant
 
credits the Inservice Inspection (ISI) Program to manage loss of fracture toughness of CASS
 
recirculation pump thermal barriers. The staff also noted that the thermal barriers in the pumps (which provide a Class 1 to Class 2 interface) may not actually be accessible for inspection. The
 
staff further noted that UT volumetric techniques, to date, cannot distinguish between UT
 
signals that come from the CASS microstructures, from those that result from crack and/or flaw
 
indications in the CASS material. Given that thermal aging of CASS can lead to a lower fracture
 
toughness and cracking, the staff issued a follow-up RAI.
 
In RAI B.2.1-1R, dated October 27, 2008, the staff requested that the applicant describe the
 
aging management of the primary recirculation pump CASS thermal barrier cover, specifically
 
addressing the aging management of cracking that could occur between the pump shaft cavity
 
and the reactor building closed-cooling water (RBCCW) cooling water cavity; and identify what
 
inspection techniques will be used to perform these inspections. 
 
In the response to RAI B.2.1-1R, dated November 17, 2008, the applicant stated that the use of
 
the Inservice Inspection (ISI) Program to manage the aging effect of thermal aging
 
embrittlement is consistent with the GALL R eport item IV.C1-3, for Class 1 pump casings. The applicant further stated that PPL identified the thermal barrier as a separate component of the
 
pump, even though it is part of the pump cover. The applicant further stated that the pump cover
 
has a series of passages, created by machining and drilling, to allow cooling water, from the
 
RBCCW system, to be circulated through the portion of the casing that surrounds the pump
 
shaft, and that the portion of the pump cover that contains these passages and performs the
 
cooling function is called the thermal barrier. The applicant also stated that since the thermal
 
barrier is the same cast component as the pump cover, the Inservice Inspection (ISI) Program is
 
also credited for managing loss of fracture toughness for the RCPB of the thermal barrier, which
 
includes the portion of the pump cover between the pump shaft cavity and the cooling water
 
cavity of the RBCCW system. 
 
The staff reviewed the applicant's response and noted that AMR item IV.C-3 in the GALL Report, Volume 2 states that programs corresponding to the GALL AMP XI.M1 are acceptable
 
programs to credit for management of loss of fracture toughness in ASME Code Class 1 CASS pump casings. The staff noted that, like the pump casings, the CASS pump covers also provide
 
a portion of the RCPB portions of the pumps. The Inservice Inspection (ISI) Program finds that
 
since the thermal barrier is part of the pump cover, the use of this AMP to manage the aging
 
effects of the pump cover is an acceptable equivalency for managing the aging effect of the
 
thermal barrier, which is normally not accessible.
 
Based on the review, the staff finds the applicant's response to RAI B.2.1-1R acceptable
 
because the applicant has adequately described the aging management of the primary
 
recirculation pump CASS thermal barrier cover and has identified the inspection techniques it
 
will use to perform these inspections. On the basis that the thermal barrier is part of the
 
recirculation pump cover and that the GALL Report item IV.C-3 recommends that the Inservice Inspection (ISI) Program be credited to manage reduction of fracture toughness of CASS
 
recirculation pump casings and covers, the staff also finds the applicant's basis for crediting the
 
ISI program for aging management of reduction of fracture toughness to be acceptable for these
 
components. Therefore, the staff's concerns described in RAI B.2.1-1R are resolved.
 
3-96 The staff noted that the license renewal basis document for the Inservice Inspection (ISI)
Program indicates that the criteria, in particular staff-approved BWRVIP reports, may be used in lieu of applicable ASME Code Section XI ISI requirements for ASME Code Class 1, 2, or 3
 
components.
 
In RAI B.2.1-2, dated June 12, 2008, the staff requested that the applicant address the basis for crediting the BWRVIP report criteria in lieu of the ASME Code Section XI requirements that are
 
implemented under the Inservice Inspection (ISI) Program and for requesting clarification
 
whether or not proposals to use staff-approved BWRVIP guideline criteria in lieu of applicable ASME Code Section XI requirements will be submitted for staff approval.
 
In the response to RAI B.2.1-2, dated July 14, 2008, the applicant stated that all proposals to use staff-approved BWRVIP guideline criteria in lieu of applicable ASME Code Section XI
 
requirements will be submitted for staff approval as part of the relief request submittals for each 10-year ISI Inspection Plan, in accordance with 10 CFR 50.55a. 
 
Based on the review, the staff finds the applicant's response to RAI B.2.1-2 acceptable because
 
the applicant has confirmed that it will submit all proposals to use BWRVIP guidance criteria in lieu of ASME Code Section XI requirements for staff approval as part of 10 CFR 50.55a(a)(3)
 
relief requests for the 10-year ISI Plans. Therefore, the staff's concern described in RAI B.2.1-2
 
is resolved.
 
The staff noted that the "corrective actions" program element discussion in the basis document
 
for the Inservice Inspection (ISI) Program indicates that the corrective actions for the program
 
will be implemented through implementation of the applicant's 10 CFR Part 50, Appendix B, Quality Assurance Program.
 
In RAI B.2.1-3, dated June 12, 2008, the staff requested that the applicant clarify how
 
implementation of the SSES 10 CFR Part 50, Appendix B, Quality Assurance Program will
 
ensure that the corrective actions for ASME Code Class 1, 2, or 3 components will be implemented, in accordance with applicable corrective actions in ASME Code Section XI Article
 
IWB-3000, or its sub-articles, paragraphs, or subparagraphs; in staff-approved ASME Code
 
Cases endorsed for use in the latest staff-issued version of RG 1.147; or through the staff's
 
relief request process defined in 10 CFR 50.55a.
 
In the response to RAI B.2.1-3, dated July 14, 2008, the applicant stated that the Inservice
 
Inspection (ISI) Program and governing procedures specify compliance with ASME Code Section XI corrective actions for defects found in Class 1, 2, or 3 components and includes use
 
of the acceptance standards in the applicable sections of IWB-3000. The applicant also stated
 
that the approved 10-Year ISI plan describes the use of staff-approved ASME Code Cases endorsed for use in the latest staff-issued version of RG 1.147 and when alternative standards
 
are necessary, staff approval is obtained through the NRC Relief Request process.
 
The applicant further stated that the QA program specifies audits of the Inservice Inspection (ISI) Program every two years, following established auditing procedures, and that these audits
 
are conducted in accordance with assessment basis documents that provide guidelines specific
 
to the addressed topic. The applicant clarified that the SSES audit guideline for the Inservice
 
Inspection (ISI) Program explicitly addresses compliance with 10 CFR 50.55a and related
 
regulatory requirements and commitments.
 
The staff reviewed the response and noted that the Inservice Inspection (ISI) Program specifies 3-97 compliance with ASME Code Section XI corrective actions, including acceptance standards in the applicable sections of IWB-3000. Furthermore, the staff noted that the applicant performs
 
QA audits of its Inservice Inspection (ISI) Pr ogram every two years as required by the QA program, and verified that these QA audits are performed to ensure the corrective actions for
 
the program are implemented in accordance with the corrective actions requirements in the ASME Code Section XI, staff-approved ASME Code Cases, or in accordance with acceptable
 
alternative correction action programs requested and approved through the staff's
 
10 CFR 50.55a(a)(3) alternative ISI program process (i.e., through the staff's ISI program relief
 
request process).
 
Based on this review, the staff finds the applicant's response to RAI B.2.1-3 acceptable
 
because the applicant has implemented its QA program to ensure that the corrective actions are in compliance with either 10 CFR 50.55a and applicable ASME Code Section XI corrective
 
action requirements, staff-approved ASME Code Ca ses, or acceptable alternative correction action programs that are approved through the staff's 10 CFR 50.55a(a)(3) alternative ISI
 
program process, and because the applicant's program conforms to the recommendations in
 
the "corrective actions" program element in the GALL AMP XI.M1. Therefore, the staff's concerns described in RAI B.2.1-3 are resolved.
Exception 1
 
The applicant has taken an exception to the "detection of aging effects" program element in the GALL AMP XI.M1. In this exception, the applicant proposed to use a risk-informed ISI methodology in lieu of the ASME Code Section XI tables for determining the inspection
 
samples of particular ASME Code Class welds. 
 
The staff noted that use of risk-informed ISI methodologies and programs must be
 
requested and approved by the staff, in accordanc e with the staff's alternative program relief request provisions in 10 CFR 50.55a(a)(3). Consistent with this requirement, the staff
 
makes the following statement in Chapter 1 of the GALL Report, Revision 1, Volume 2, for
 
proposals to use alternative programs in lieu of complying with applicable ASME Code Section XI requirements:
If an applicant seeks relief from specific requirements of 10 CFR 50.55a and Section XI of the ASME Code for the period of extended operation, the applicant will
 
need to re-apply for relief through the 10 CFR 50.55a relief request process once
 
the operating license for the facility has been renewed.
 
The staff verified that the risk-informed ISI program for Units 1 and 2 was approved in a
 
staff-issued SE dated September 28, 2005. The staff also noted that the risk-informed ISI
 
program relief request was only approved for the 3 rd 10-Year ISI interval for Units 1 and 2 and that risk-informed ISI has yet to be proposed and approved for any of the 10-Year ISI intervals within the scope of the period of extended operation for Units 1 and 2. 
 
In RAI B.2.1-5, dated June 12, 2008, the staff requested that the applicant commit to request
 
relief for use of risk-informed ISI within 12 months before the start of each 10-Year ISI interval, if
 
the applicant was planning on using a risk-informed ISI methodology for the 4 th 10-Year ISI intervals or subsequent 10-Year ISI intervals for Units 1 and 2.
 
In the response to RAI B.2.1-5, dated July 14, 2008, the applicant revised the LRA to remove
 
the statement that identifies the use of risk-informed ISI as an exception to the GALL 3-98 AMP XI.M1. The applicant stated that since the use of risk-informed ISI at SSES must be approved pursuant to 10 CFR 50.55a(a)(3), it is not considered to be an exception to the GALL
 
Report.
 
Based on its review, the staff finds the applicant's response to RAI B.2.1-5 acceptable because
 
the applicant has removed the use of risk-informed ISI as an exception to the GALL Report. The
 
staff determines that the applicant need not make an LRA commitment to request relief for the
 
use of risk-informed ISI in future intervals because the applicant is already committed to seek
 
approval for the use of risk-informed ISI, in accordance with 10 CFR 50.55a(a)(3). Therefore, the staff's concern described in RAI B.2.1-5 is resolved.
 
Based on its review, the staff finds the applicant's ISI Program consistent with the program elements of the GALL AMP XI.M1 and; therefore, is acceptable.
 
Operating Experience The staff reviewed the applicant's OE basis document for safety significant OE relevant to the aging management of ASME Code Class 1, 2, and 3 components.
 
The staff noted that the applicant only provided an overall OE summary statement in the
 
"operating experience" program element for the Inservice Inspection Program and did not provide any examples of SSES specific and generic OE that would demonstrate that the AMP is accomplishing its intended objective. 
 
During the onsite review of this AMP, the staff determined the license renewal basis binder for
 
the Inservice Inspection Program included two CRs on circumferential flaw indications that were
 
recorded for the safe end welds of the Unit 1 N4J recirculation outlet nozzle and N1B
 
recirculation inlet nozzle, resulting from previous augmented UT examinations performed on these weld locations. The staff noted that the augmented inspections of these safe-end welds
 
are credited in accordance with the BWR Stress Corrosion Cracking Program, and are
 
implemented through augmented inspections per formed under the Inservice Inspection Program. The staff determined that these CRs are significant because the applicable safe-end
 
welds are ASME Code Class 1 RCPB locations, and because a complete circumferential weld
 
failure of the nozzle safe-end components could result in a loss-of-coolant accident for the
 
facility. 
 
Thus, even though the staff verified that the applicant had listed the experience as relevant OE
 
for the BWR Stress Corrosion Cracking Program and had taken appropriate corrective actions
 
of the flaw indications by performing weld overlays of the components, the staff felt that the
 
applicant should have mentioned these flaw indications as relevant OE for the Inservice
 
Inspection Program, in the same manner that the CRs were listed as relevant OE for the BWR
 
Stress Corrosion Cracking Program. The staff also noted that the applicant did not specify
 
which staff-approved weld overlay methodology was applied to the repair of the flaw indications (i.e., cracks) in the recirculation inlet and outlet nozzles.
 
In RAI B.2.1-4, part a, dated June 12, 2008, the staff requested that the applicant amend the
 
LRA to list these circumferential crack safe-end nozzle events as relevant OE for the "operating
 
experience" program element in Inservice Inspec tion (ISI) Program. In RAI B.2.1-4, part b, the staff requested that the applicant identify the particular weld overlay methodology (along with its
 
reference basis) used for the repairs of these safe-end nozzle indications, and clarify whether
 
the overlay methodology required a flaw tolerance evaluation of the flaw indications and; if so, explain whether the analysis is a time-limited aging analysis (TLAA) for the application.
 
In the response to RAI B.2.1-4, part a, dated July 14, 2008, the applicant amended the LRA to 3-99 add the relevant experience of the ultrasonic inspection of the NIB and N2J recirculation nozzle-safe end welds that revealed indications which were determined to be flaws. These
 
welds are dissimilar metal welds and the indications were typical of SCC in Alloy 82/182 weld
 
material.
 
The applicant stated that the flaws were repaired using full-structural weld overlays, based on
 
the standard weld overlay defined in NUREG-0313, Revision 2, "Technical Report on Material
 
Selection and Processing Guidelines for BWR Coolant Pressure Boundary Piping," and the weld overlay design was based on the requirements of ASME Code Section XI, IWB-3640 and Code
 
Case N-504-2. The applicant further stated that the weld overlays were applied using Inconel
 
52, a material highly resistant to IGSCC, and that subsequent inspections performed in 2008
 
indicated no cracking in the weld overlays at the NIB and N2J nozzle-safe end weld locations.
 
In response to part b, the applicant stated:
 
The flaws were repaired using full structural weld overlays that were designed to bound
 
all cracking conditions in the nozzle-safe end (NOZ-SE) weld area, using the Standard
 
Weld Overlay defined in NUREG-0313, Revision 2. The weld overlay design was based on the requirements of ASME Section XI, IWB-3640 and Code Case N-504-2. The weld
 
overlay design conservatively assumed the flaws were through-wall and extended
 
entirely around the pipe. No credit was taken for any remaining ligament in the original
 
NOZ-SE welds. The weld overlays were applied using Inconel 52, a material highly
 
resistant to IGSCC. The overlay welding methods result in compressive loads on the
 
area beneath the overlay, thereby limiting the potential for further growth of the existing
 
flaws. The overlay design also included a crack initiation and growth analysis, which
 
demonstrated that the overlay will have a very low susceptibility for crack initiation and
 
growth during the life of repair, due to the high IGSCC-resistance of the Inconel 52 alloy
 
used in the overlay. Post-repair inspections assured the quality of the repair, and
 
ongoing inspection requirements for the overlay and the underlying base material will
 
identify any future degradation. The ASME Code required no flaw tolerance evaluations
 
to be performed as part of the design basis for these repairs. There were no design
 
basis analyses performed for the weld overlay repairs that constitute a TLAA.
 
The staff reviewed the applicant's response and noted that specific plant OE was identified. The
 
applicant also provided the methodology used to perform the weld overlay repair. The staff
 
concurs that use of Inconel 52 as weld material will provide a very low susceptibility for crack
 
initiation and growth. Since no design basis analyses were performed and because ongoing
 
inspections will be performed to manage aging, the staff finds that there are no TLAAs to be
 
evaluated. However, Paragraph (g) of the Code Case mandates performance of an evaluation
 
of the flaws that are left in place as part of the alternative repair weld overlay technology
 
required by ASME Code.
 
In follow-up RAI B.2.1-4R, dated October 27, 2008 the staff requested that the applicant explain
 
what it did to meet paragraph (g) of staff-approved ASME Code Case N-504-2, and whether a
 
flaw growth assessment was performed in accordance with the Code Case, to clarify whether
 
the flaw tolerance evaluation was effective for the remainder of the current licensed lives of
 
Units 1 and 2.
 
In the response to RAI B.2.1-4R, dated November 17, 2008, the applicant stated:
 
The weld overlay repairs for the SSES Unit 1 N1B and N2J recirculation 3-100 nozzle-to-safe-end welds were designed to the requirements of ASME Section XI, IWB-3640 and Code Case N-504-2. Additionally, the repairs were "full structural
 
overlays," or Standard Weld Overlays, as defined in Section 4.4 of NUREG-0313
 
Revision 2. As such, the overlay repairs were designed with the assumption that the
 
underlying flaw was entirely through-wall and completely around the circumference of
 
the component. No credit was taken for any remaining ligament in the repair location.
 
The design of the overlays provides the necessary wall thickness to satisfy the flaw
 
evaluation procedures of IWB-3640, in accordance with Code Case N-504-2
 
paragraph (f)(1), and ensures the structural adequacy of the component for all design
 
loading conditions. This design approach is consistent with hundreds of similar overlay
 
repairs on BWR recirculation nozzles and other IGSCC-susceptible components in the
 
industry since 1985.
 
When the overlays were designed, there was conclusive evidence from past and present
 
volumetric examinations that flaw growth had been arrested by the application of the
 
Mechanical Stress Improvement Process (MSIP) in 1993 (for the N2J) and 1995 (for the
 
N1B). The volumetric examination data was reviewed by PPL, General Electric, and
 
EPRI NDE experts. The consensus conclusion was that the flaws had not grown since
 
the application of MSIP. The lack of flaw growth between the time of MSIP application
 
and 2004 confirmed that the residual compressive stress in the welds from MSIP, combined with the benefits of hydrogen water chemistry implementation in
 
January 1999, had effectively eliminated further IGSCC. It was also recognized that weld
 
overlay repairs would impose additional compressive stress in the welds. Therefore, it
 
was concluded that there would be no, or negligible, flaw growth due to IGSCC into the
 
future. 
 
Since there was no flaw growth projected to exceed the assumed flaw in the overlay
 
design, a flaw growth assessment and a flaw tolerance evaluation to demonstrate the structural adequacy for a predicted flaw size at the end of a specific operating interval (e.g., 40 years or 60 years) were not necessary. The full structural overlay, as designed
 
with an assumed through-wall crack around the entire circumference in accordance with
 
IWB-3640 and Code Case N-504-2, will remain structurally adequate for the operating
 
life of the plant.
 
Code Case N-504-2 paragraph (g)(2) requires a weld repair evaluation to demonstrate
 
that the requirements of IWB-3640 are satisfied for the design life of the repair, considering potential flaw growth. As discussed above, the potential flaw growth was
 
determined to be zero, or negligible, such that the flaw assumed in the overlay design
 
remains bounding for the life of the component. Therefore, the calculations performed to
 
determine the required design size and thickness of the overlays serves as the
 
evaluation required by Code Case N-504-2 paragraph (g)(2). Since those calculations
 
are not dependent on any flaw growth assessm ents, they are not time-limited aging analyses (TLAA).
The staff reviewed the applicant's response and Code Case N-504-2 paragraph (g)(2) and
 
determined that the Code Case requires an assumed flaw size and a flaw growth analysis for
 
the life of the plant. The staff noted that, for the applicant's full structural overlay repairs, the
 
applicant assumed that the underlying flaw was entirely through wall and around the
 
circumference, and no credit was taken for any remaining ligament. The staff also noted that the
 
applicant indicated that the structural overlays place the flaw in the original weld material in
 
compression, such that the growth of the flaw is mitigated from growing into the weld overlay 3-101 repair material.
 
Based on the review, the staff finds the applicant's response to RAI B.2.1-4R acceptable
 
because the applicant has provided an acceptable basis for concluding that structural overlays
 
are an acceptable alternative repair for ASME Code Class piping components and that the
 
overlays need not be within the scope of a TLAA, because they are implemented pursuant to
 
staff-approved ASME Code Case and because the overlays place the original flaw in
 
compression, such that the flaws are mitigated from growing into the overlay weld repair
 
material. Therefore, the staff's concern described in RAI B.2.1-4R is resolved.
 
The staff confirmed that the OE program element satisfies the criterion defined in the GALL
 
Report and the guidance found in SRP-LR Section A.1.2.3.10. Therefore, the staff finds this
 
program element acceptable.
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary for the Inservice Inspection (ISI) Program in LRA Section A1.2.23, Commitment No. 1. The reviewed this section
 
and determines that the UFSAR supplement summary description for the Inservice Inspection (ISI) Program conforms to the staff's recommended UFSAR supplement SRP-LR Table 3.1-2.
 
The staff finds that the applicant has committed (Commitment No. 1) to ongoing implementation
 
of its Inservice Inspection (ISI) Program aging management of those in-scope components for which the AMP is credited and linked this commitment to UFSAR Supplement Summary
 
Section A.1.2.23 for the Inservice Inspection (ISI) Program. Based on this review, the staff finds
 
that UFSAR Supplement Summary Section A.1.2.23, when coupled to LRA Commitment No. 1, provides an acceptable UFSAR supplement summary description of the applicant's Inservice
 
Inspection (ISI) Program.
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d). 
 
Conclusion. On the basis of the audit and review of the applicant's Inservice Inspection (ISI)
Program and the applicant's responses to the staff's RAIs, the staff finds all program elements
 
consistent with the GALL Report. The staff concludes that the applicant has demonstrated that
 
effects of aging will be adequately managed so that the intended function(s) will be maintained
 
consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concludes that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d) and; therefore, is acceptable.
 
3.0.3.2.2  BWR CRD Return Line Nozzle Program 
 
Summary of Technical Information in the Application. In LRA Section B,2.6, the applicant described the BWR Control Rod Drive (CRD) Return Line Nozzle Program as an existing
 
program that is consistent with an exception with GALL AMP XI.M6, "BWR Control Rod Drive Return Line Nozzle." The applicant stated that the BWR CRD Return Line Nozzle Program
 
monitors the effects of cracking on the intended function of the CRD return line nozzle by performing ISIs in conformance with the ASME Code, Section XI, Subsection IWB, Table IWB
 
2500-1.
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also confirmed that the plant program contains all of the elements of the
 
referenced the GALL Report. The staff conducted onsite interviews with the applicant to confirm 3-102 these results.
 
Exception 1
 
The BWR CRD Return Line Nozzle Program takes an exception to the "acceptance criteria" program element to the GALL AMP XI.M6 to use a weld overlay methodology as an alternative corrective action repair technique for flaw indications that are detected in the CRD return line
 
nozzles or their pressure boundary welds, including the CRD return line cap-to-nozzle welds.
 
The staff noted the applicant indicated that the weld overlay repair methodology will be
 
implemented in accordance with the requirements of 10 CFR 50.55a. The staff also noted that
 
the applicant did not indicate that this exception was applicable to the "corrective actions" program element for the BWR CRD Return Line Nozzle Program. The ASME Code Section XI
 
currently does not include any weld overlay methodologies as acceptable ASME Code
 
Class repair techniques and nor does it include relief for use of non-Code weld overlay methods
 
has not yet been granted for either of the 10-Year ISI intervals applicable to Units 1 and 2, for
 
the period of extended operation. 
 
In RAI B.2.6-1, dated July 23, 2008, the staff requested that the applicant commit to perform an ASME Code Section XI repair of the leaking component, unless the weld overlay repair
 
methodology is submitted for staff review and approval and is granted in accordance with the
 
requirements of 10 CFR 50.55a(a)(3). The staff requested that the applicant provide the basis
 
for not applying the exception on the weld overlay methodology to the "corrective actions" program element in the GALL AMP XI.M6.
 
In its response to RAI B.2.6-1, dated August 22, 2008, the applicant amended the LRA to revise
 
the exception to the "acceptance criteria" element of LRA Section B.2.6 and to add to
 
Commitment No. 6 the following:
 
PPL will implement weld overlay repairs in accordance with ASME Section XI and
 
NRC-approved Code Cases. If no NRC-approved Code Case exists for the weld overlay, PPL will obtain NRC approval prior to implementing the repair in accordance with 10
 
CFR 50.55a.
 
The applicant also provided a basis for not including an exception to the "corrective actions" program element in the GALL AMP XI.M6, stating:
 
Any identified cracks or indications in the CRD return line nozzle are evaluated under the rules of ASME Section XI. If the evaluation determines that a repair is required, the design and implementation of the repair is governed by the SSES ASME Section XI
 
repair program, which requires the repair to meet Code requirements unless relief is
 
granted by the NRC. Furthermore, in accordance with the SSES Inservice Inspection (ISI) Program, when cracks or indications are identified, a condition report is written and, at that point, the SSES corrective action program also controls the resolution of the condition. Both the SSES ASME Section XI repair program and the SSES corrective
 
action program meet the requirements of 10 CFR 50, Appendix B.
The corrective action element of GALL XI.M6 includes the statement that "As discussed
 
in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions." Since the SSES ASME Section XI repair program and the SSES corrective action program both meet the
 
requirements of 10 CFR 50, Appendix B, the corrective actions that would be taken in 3-103 accordance with those programs are consistent with GALL.
 
Based on the review, the staff finds the applicant's response to RAI B.2.6-1 acceptable because
 
the applicant has included a commitment for the implementation of weld overlays. The staff
 
notes that the applicant evaluates any identified cracks or indications in compliance with ASME Code Section XI. The staff determines that the applicant's evaluation and repair is performed in accordance with ASME Code Section XI and along with the applicant's Corrective Action
 
Program, both meet the requirements of 10 CFR Part 50, Appendix B. Therefore, the staff's
 
concern described in RAI B.2.6.1 is resolved.
 
Based on the review, the staff finds the applicant's BWR CRD Return Line Nozzle Program acceptable because it conforms to the recommended GALL AMP XI.M6, with an exception. 
 
Operating Experience The staff reviewed the applicant's OE basis document for safety significant OE relevant to the aging management of CRD return line nozzle welds components.
 
The staff noted in the OE discussion, the applicant indicated that, prior to initial startup of
 
Units 1 and 2, the applicant cut and capped the CRD return line and the CRD return line nozzle
 
to eliminate CRD return line flow from the plant design. 
 
The staff finds this statement acceptable because it conforms to the criterion in the
 
"preventative actions" program element of the GALL AMP XI.M6 which states that cutting and capping of CRD return lines, without rerouting the return line flow, is an acceptable mitigation
 
technique for CRD return line nozzle programs.
The staff also noted that in the "operating experi ence" program element discussion for this AMP, the applicant stated that it has been implementing the required ASME Code Section XI
 
inspections and the recommended augmented NUREG-0619, "BWR Feedwater Nozzle and
 
Control Rod Driven Return Line Nozzle Cracking" inspections. The applicant further stated that
 
to date, inspections of the capped CRD return line nozzles and the required surface
 
examination and volumetric examinations did not i ndicate any evidence of flaw indications in the capped CRD return line nozzle inner blend radii or their associated ASME Code Class 1 welds.
 
The staff verified that the applicant had implemented the recommended augmented UT and/or
 
penetrate test (PT) inspections of the CRD return line cap-to-nozzle welds and nozzle inner
 
blend radii that required inspection during the 11th and 12th RFOs for Unit 1 (i.e , U111RIO and U112RIO) and during the 9th RFO for Unit 2 (i.e., U209RIO). The staff verified that the
 
applicant's UT and PT examinations of these CRD return line nozzle locations did not indicate
 
the presence of any recordable flaw indications in the nozzle welds or inner blend radii. 
 
Based on this review, the staff confirms that the applicant has been performing the augmented
 
UT and PT inspections of CRD return line nozzle inner blend radii and cap-to-nozzle welds in
 
accordance with its BWR CRD Return Line Nozzle Program. The staff further confirms that the
 
applicant's program has been implemented in acco rdance with an augmentation of the Inservice Inspection (ISI) Program requirements of ASME Code Section XI, as modified by the
 
recommended augmented inspection criteria in NUREG-0619. Based on this review, the staff
 
finds that the RFO and IRs provide acceptable confirmation that the applicant is implementing
 
the recommended augment inspections and that currently, there are no SSES-specific OE for
 
the CRD return line nozzles or their associated pressure boundary welds, including the
 
cap-to-nozzle welds.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10. Therefore, 3-104 the staff finds this program element acceptable.
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary for its BWR CRD Return Line Nozzle Program in LRA Section A.1.2.5, Commitment No. 6. The staff
 
reviewed this section and confirms that the UFSAR supplement summary description for the
 
BWR CRD Return Line Nozzle Program conforms to SRP-LR Table 3.1-2. The staff also
 
confirms that the applicant has committed (Commitment No. 6) to ongoing implementation of the
 
BWR CRD Return Line Nozzle Program for aging management of those SSES in-scope
 
components for which the AMP is credited and linked this commitment to UFSAR Supplement
 
Section A.1.2.23 for this AMP. In response to RAI B.2.6-1, dated August 22, 2008, the applicant
 
revised Commitment No. 6 to state that if no staff-approved Code Case exists for the weld
 
overlay; PPL will obtain staff approval, prior to implementing the repair pursuant to 10
 
CFR50.55a. 
 
Based on this review, the staff finds that UFSAR Supplement Section A.1.2.5, when coupled
 
with LRA Commitment No. 6, provides an acceptable UFSAR supplement summary description
 
of the applicant's BWR CRD Return Line Nozzle Program because it is consistent with the
 
UFSAR supplement summary description in the SRP-LR.
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of its review of the applicant's BWR CRD Return Line Nozzle Program and the applicant's response to the staff's RAI, the staff finds all program elements consistent
 
with the GALL Report. 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
 
the LRA credits it. 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 concludes that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d) and; therefore is
 
acceptable. 
 
3.0.3.2.3  BWR Penetrations Program 
 
Summary of Technical Information in the Application. In LRA Section B.2.8, the applicant described the existing BWR Penetrations Program as consistent, with an exception, with the GALL AMP XI.M8, "BWR Penetrations." The applicant stated that this program is used to
 
manage the effects of aging that are applicable to the RV penetration nozzle components and
 
their associated penetration welds. The applicant also stated that the exception is taken on the
 
"scope of program" program element in the GALL AMP XI.M8 to include the RV flange leakoff penetration nozzle, vessel drain penetration nozzle, CRD penetration nozzles, and incore flux
 
monitor penetration nozzles, as additional components that are within the scope of the AMP (i.e.
 
in addition to the standby liquid control (SLC) nozzles and RV instrument penetration nozzles). 
 
Staff Evaluation. During the audit and review, the staff confirmed the applicant
=s claim of consistency with the GALL Report. The staff reviewed the exception below to determine whether the AMP, with the exception, is adequate to manage the aging effects for which the
 
LRA credits it. The staff also confirmed that the plant program contains all of the elements of the
 
referenced GALL Report. The staff conducted onsite interviews with the applicant to confirm
 
these results.
3-105 Exception The staff noted that the applicant's program takes an exception to the "scope of program" program element to the GALL AMP XI.M8. In this exception, the applicant identified that the
 
BWR Penetrations Program is credited for managing the effects of aging for the vessel flange
 
leakoff penetration, RV drain penetrations, CRD penetrations, and incore flux monitor
 
penetrations, in addition to the SLR/core P nozzle and the RV instrumentation nozzles. 
 
The applicant's BWR Penetrations Program is based on the recommended augmented
 
inspection and flaw evaluation guidelines found in BWRVIP Proprietary Topical Report
 
Nos. TR-1007286 and TR-1007286, "BWR Vessel and Internals Project, BWR Standby Liquid
 
Control System/Core Plate P Inspection and Flaw Evaluation Guidelines (BWRVIP-27)" and "BWR Vessel and Internals Project, Instrument Penetration Inspection and Flaw Evaluation
 
Guidelines (BWRVIP-49), " respectively. The staff approved BWRVIP-27 in a SE dated
 
December 20, 1999. The staff approved BWRVIP-49 in a SE dated September 1, 1999 and
 
noted that the scope of BWRVIP-27 is limited to SLC/core plate P line nozzles and that the scope of BWRVIP-49 is limited to BWR instrument penetrations. 
 
In RAI B.2.8-1, dated July 23, 2008, the staff requested that the applicant provide its basis for extending the scope of the GALL AMP XI.M8 to the RV flange leakoff line penetrations, RV
 
drain penetrations, CRD penetrations, and incore flux monitor penetrations, and for concluding
 
that the scope of either the BWRVIP-27 or BWRVIP-49 recommendations are applicable to the
 
materials of fabrication, design aspects, and fabrication processes used in the fabrication of
 
these additional penetrations. 
 
In the response to RAI B.2.8-1, dated August 27, 2008, the applicant stated:
 
The basis for extending the scope of GALL AMP XI.M8 to the RV drain penetrations, CRD penetrations, and incore flux monitor penetrations is that GALL Chapter IV, item
 
IV.A 1-5 recommends crediting the BWR Penetrations Program and the BWR Water
 
Chemistry Program to manage cracking for these components. In addition to the RV
 
drain penetrations, CRD penetrations, and incore flux monitor penetrations, which are
 
named in GALL item IV.A1-5, PPL extended this program to the RV flange leak off
 
penetrations. While these penetrations are not named in GALL item IV.Al-5, the BWR
 
Penetrations Program, as specifically defined for SSES in the program basis document, is an appropriate program to credit for managing cracking for these penetrations.
The BWR Penetrations Program comparison to GALL, as stated in the program basis
 
document, includes the details for aging management for all penetrations within the
 
scope of the program. The program will inspect all in-scope penetrations in accordance with the requirements of ASME Section XI, augmented by the recommendations of
 
approved BWRVIP reports. Inspections are scheduled in accordance with ASME Section XI, and examination results are evaluated in accordance ASME Section XI, IWB-
 
3000. Acceptance of components for continued service is in accordance with ASME Section XI and, when applicable, BWRVIP guidance.
The SSES BWR Penetrations Program manages the CRD and flux monitor penetrations
 
in accordance with the NRC-approved guidance in BWRVIP-47-A and BWRVIP-74-A.
 
The RV flange leak off penetrations and the RV drain penetrations are being managed
 
by NRC-approved guidance in BWRVIP-74-A. Thus, all penetrations are being managed
 
by BWRVIP guidance that the NRC has previously approved as adequate for the period 3-106 of extended operation.
 
The staff reviewed the GALL Report, item IV.A1-5 and notes that it does include CRD stub
 
tubes, instrumentation, incore flux monitors and vessel drain line, and the recommended AMP to manage the aging effects is GALL AMP XI.M8. The staff also reviewed BWRVIP-47-A, and BWRVIP-74-A and concludes that these documents address CRD and flux monitor
 
penetrations and are applicable.
 
Based on the review, the staff finds the applicant's response to RAI B.2.8-1 acceptable because
 
the applicant has appropriately provided the basis for extending the scope of the GALL AMP XI.M8 to the RV flange leakoff line penetrations, RV drain penetrations, CRD penetrations, and incore flux monitor penetrations. Therefore, the staff's concern described in RAI B.2.8-1 is
 
resolved.
 
Review of License Renewal Applicant Action Items
 
In the SEs on Topical Report BWRVIP-27, BWRVIP-47, BWRVIP-49, and BWRVIP-74 the staff 
 
issued the following three renewal applicant action items common to the staff's evaluations on
 
the reports:
: 1. Applicants for license renewal will be responsible for describing any such commitments and identifying how such commitments will be controlled. Any
 
deviations from the aging management pr ograms within this BWRVIP report described as necessary to manage the effects of aging during the period of
 
extended operation and to maintain the functionality of the reactor vessel
 
components or other information presented in the report, such as materials of
 
construction, will have to be identified by the renewal applicant and evaluated on a
 
plant-specific basis in accordance with 10 CFR 54.21(a)(3) and (c)(1).
The applicant provided both the staff's renewal applicant action item descriptions and its
 
responses to these actions items in LRA Appendix C, Tables BWRVIP-27-A, BWRVIP-47-A, BWRVIP-49-A and BWRVIP-74-A. The applicant stated that the BWRVIP program
 
administratively requires (a license imposed r equirement) the applicant to implement the applicable BWRVIP inspection and flaw evaluation guidelines (including those in BWRVIP-27, BWRVIP-47, BWRVIP-49, and BWRVIP-74) at SSES and that procedures administratively
 
mandate the applicant to write a justification for any deviations from the recommended criteria in the applicable BWRVIP inspection and flaw evaluation guidelines. The applicant also stated it
 
has not yet identified any deviations from its implementation of the BWRVIP-27, BWRVIP-47, BWRVIP-49, and BWRVIP-74 inspection and flaw evaluation guidelines, and commits to further
 
implementation of the staff-approved versions of the BWRVIP-27, BWRVIP-47, BWRVIP-49, and BWRVIP-74 guidelines, in order to ensure that the aging effects applicable to the SLC/core
 
plate P nozzles, RV instrumentation nozzles and other RV nozzles within the scope of the
 
program will be managed, for the period of extended operation. 
 
The staff confirms that the applicant has provided a commitment (Commitment No. 8) for
 
continued implementation of the recommended inspection and flaw evaluation guideline
 
recommendations, and that the commitment has been placed on UFSAR Supplement
 
Section A.1.2.7. The staff finds that the applicant has adequately addressed the staff's renewal
 
applicant action item on BWRVIP-27, BWRVIP-47, BWRVIP-49, and BWRVIP-74 because it
 
clarified that SSES would not deviate from the recommended inspection and flaw evaluation
 
criteria, and because the applicant has committed to continued implementation of the guidelines 3-107 in these reports.
 
Based on this review, the staff concludes that the applicant has adequately addressed the
 
staff's first renewal applicant action item on BWRVIP-27, BWRVIP-47, BWRVIP-49, and
 
BWRVIP-74. Therefore, this renewal applicant action item is resolved.
: 2. Those applicants for license renewal referencing the BWRVIP-27 report for the DP/SLC vessel penetration/nozzle and safe end extensions shall ensure that the
 
programs and activities specified as necessary in the BWRVIP-27 document are
 
summarily described in the UFSAR supplement. Those applicants for license
 
renewal referencing the BWRVIP- 49 report for the instrument penetrations shall
 
insure that the programs and activities specified as necessary in the BWRVIP-49
 
report are summarily described in the UFSAR supplement." "Those applicants for
 
license renewal referencing the BWRVIP- 47 report for the lower plenum shall
 
insure that the programs and activities specified as necessary in the BWRVIP-47
 
report are summarily described in the UFSAR supplement.
The applicant stated that LRA Section A includes the UFSAR supplement for the BWR
 
Penetrations Program. The staff confirmed that the applicant provides the UFSAR supplement summary description for the BWR Penetrations Program in UFSAR Supplement
 
Section A.1.2.7. The staff also confirmed that LRA Section A.1.2.7 includes BWRVIP-27 and
 
BWRVIP-49. However, in response to RAI B.2.8-1, dated August 27, 2008, the applicant added
 
BWRVIP-47 and BWRVIP-74, which are not included in the UFSAR summary description. In a
 
follow-up RAI B.2.8-1R, dated October 17, 2008, the staff requested that the applicant address
 
this issue.
In the response to RAI B.2.8-1R, dated November 11, 2008, the applicant revised the LRA to
 
include BWRVIP-47-A and BWRVIP-74-A in the descriptions of the BWR Penetrations Program
 
in LRA Sections  A.1.2.7 and B.2.8. The applicant revised the last sentences of A.1.2.7 and
 
program description of B.2.7 as follows:
BWRVIP-27-A report addresses the standby liquid control system nozzle or housing, the
 
BWRVIP-47-A report addresses the control rod drive and flux monitor penetrations in the
 
lower plenum, the BWRVIP-49-A report provides guidelines for instrument penetrations, and the BWRVIP-74-A report addresses the reactor vessel flange leakoff penetrations
 
and the reactor vessel drain penetrations.
The staff reviewed the applicant response and notes that the applicant has appropriately
 
identified BWRVIP-47-A and BWRVIP-74-A in the program description and in the UFSAR
 
supplement. Based on this review, the staff finds the applicant response acceptable and
 
concludes that the applicant has adequately addressed the staff's second renewal applicant
 
action item on BWRVIP-27, BWR-47 and BWRVIP-49. Therefore, this renewal applicant action
 
item is resolved.
: 3. Those applicants for license renewal referencing BWRVIP-27 for the DP/SLC vessel penetration/nozzle and safe end extensions shall ensure that the inspection
 
strategy described in the BWRVIP-27 report does not conflict or result in any
 
changes to their technical specifications. Those applicants for license renewal
 
referencing BWRVIP-49 for the instrument penetrations shall ensure that the
 
inspection strategy described in the BWRVIP-49 document does not conflict or
 
result in any changes to their technical specifications." "Those applicants for license 3-108 renewal referencing BWRVIP-47 for the lower plenum shall ensure that the inspection strategy described in the BWRVIP-47 document does not conflict or
 
result in any changes to their technical specifications." If technical specification
 
changes do result, then the applicant should ensure that those changes are
 
included in its application for license renewal.
 
The applicant stated that its implementation of the inspection strategies in BWRVIP-27, BWRVIP-47 and BWRVIP-49 will not result in the need for any changes of the TS for either
 
Unit 1 or Unit 2. The staff reviewed the TS for Units 1 and 2 and confirmed that, while the
 
methods in BWRVIP-27, BWRVIP-47, and BWRVIP-49 may constitute alternative
 
staff-approved inspection guidelines for the ASME Code Class 1 RV penetration nozzle welds, the TSs for SSES do not include any requirements to implement the ASME Code Section XI ISI programs, neither do they include BWRVIP-27, BWRVIP-47 or BWRVIP-49 augmented
 
inspection program criteria. The staff also conf irmed that the applicant's TSs are derived from operational-, surveillance-, and administrative c ontrol-based requirements and that, instead, the Inservice Inspection (ISI) Program requirements and BWRVIP-27, BWRVIP-47, and BWRVIP-
 
49 augmented inspection process are implemented through the applicant's ASME Code Section XI ISI program, in accordance with 10 CFR 50.55a. Thus, based on this review, the staff
 
concludes that the applicant has provided an adequate basis for concluding that its
 
implementation of the guidelines in BWRVIP-27, BWRVIP-47, and BWRVIP-49 will not conflict
 
with or result in any necessary changes in the SSES TS. Based on this review, the staff
 
concludes that the applicant has adequately addressed the staff's third renewal applicant action
 
item on BWRVIP-27, BWRVIP-47, and BWRVIP-49. Therefore, this renewal applicant action
 
item is resolved.
 
In the SE for BWRVIP-27, the staff included an additional fourth renewal applicant action item.
 
In this action item, the staff stated that BWR applicants referencing the BWRVIP-27 report
 
should identify and evaluate the projected fatigue cumulative usage factors (CUFs) for their
 
SLC/core plate P nozzles as a potential TLAA for the application. The applicant stated that the only analysis on the SLC/core plate P nozzles that meets the definition of a TLAA is the CUF analysis for the SLC/core plate P nozzles and that the TLAA analysis for these nozzle components is provided in LRA Section 4.3.1. The staff confirmed that the applicant has
 
included its metal fatigue CUF analysis for the N-10 SLC/core plate P nozzles in LRA
 
Section 4.3.1 and that LRA Table 4.3-2 includes both the design basis CUFs and the 60-year
 
projected CUFs for N-10 SLC/core plate P nozzles. Based on this review, the staff finds that the
 
applicant has met this renewal applicant action item because, consistent with the action item, the applicant has identified the CUF analysis for these nozzles as a TLAA, and has provided
 
this TLAA in LRA Section 4.3.1. The staff evaluates this TLAA in SER Section 4.3.1. Therefore, this renewal applicant action item is resolved.
 
Based on the review of the exception, and resolution of the related RAI, the staff finds the BWR
 
Penetrations Program consistent with the program elements of GALL AMP XI.M8, with an exception and; therefore, is acceptable.
 
Operating Experience. The staff reviewed the applicant's "operating experience" program element discussions in the BWR Penetrations Program and in the license renewal basis
 
document for this AMP. The staff noted that the "operating experience" program element in the license renewal basis document indicated that the applicant had reviewed the last five Inservice
 
Inspection Outage Summary Reports for Units 1 and 2 and that the ISIs or augmented ISIs
 
performed on the penetration nozzles did not identify any relevant flaw indications. The staff
 
confirmed that, although the applicant has not yet identified any relevant indications for the 3-109 penetrations within the scope of this AMP, it has recorded flaw indications and initiated appropriate CR action requests on flaw indications identified in some of the RV internal
 
components. These actions are part of the applicant's in-vessel visual inspections performed on
 
its BWR RV internals, and which is another BWRVIP Report-based AMP. 
 
The staff finds the applicant's "operating experience" program element acceptable because the
 
applicant's augmented inspection process used to implement the BWRVIP-based augmented
 
inspections of the RV penetration nozzles and RV internals components has actual detected
 
and recordable RV internals indications that are within the scope of the BWR Vessel Internals
 
Program. This demonstrates that the applicant
's BWRVIP-based augmented inspection process for its RV penetration nozzles and RVI components is effective. The staff also finds the OE
 
acceptable because the applicant has committed (Commitment No. 8) to continued
 
implementation of the BWR Penetration Program and; implementation of the guidelines in
 
BWRVIP-27 for SLC/core plate  penetration nozzles, the BWRVIP-47 for CRD and flux monitor penetrations in the lower plenum, the BWRVIP-49 for RV instrument penetration nozzles, and
 
the BWRVIP-74 for RV flange leakoff penetrations and the RV drain penetrations.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10. Therefore, the staff finds this program element acceptable.
 
UFSAR Supplement. The applicant provided the UFSAR supplement summary for the BWR Penetrations Program in LRA Section A.1.2.7, Commitment No. 8. The staff reviewed this
 
section and notes that in response to RAI B.2-1R, dated November 11, 2008, the applicant
 
revised the UFSAR supplement to add BWRVIP-49 and BWRVIP-74. The staff confirms that
 
that applicant has committed (Commitment No. 8) to continued implementation of the
 
recommended inspection and flaw evaluation guideline recommendations. The staff finds that
 
the applicant's UFSAR supplement summary description for the BWR Penetrations Program, with this revision, conforms to the staff's recommended UFSAR supplement in SRP-LR
 
Table 3.1-2. 
 
Based on this review, the staff finds that UFSAR Supplement Section A.1.2.7, when coupled
 
with Commitment No. 8, provides an acceptable UFSAR supplement summary description of
 
the applicant's BWR Penetrations Program because it is consistent with the UFSAR supplement
 
summary description in the SRP-LR. 
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of its review of the applicant's BWR Penetrations Program and the applicant's response to the staff RAIs, the staff determines that those program elements for
 
which the applicant claimed consistency with the GALL Report are consistent. In addition, the
 
staff reviewed the exception and its justification and determines that the AMP, with the
 
exception, is adequate to manage the aging effects for which the LRA credits it. The staff
 
concludes that the applicant has demonstrated that effects of aging will be adequately managed
 
so that the intended function(s) will be maintained consistent with the CLB for the period of
 
extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR
 
supplement for this AMP and concludes that it provides an adequate summary description of the
 
program, as required by 10 CFR 54.21(d) and; therefore, is acceptable.
 
3-110 3.0.3.2.4  BWR Vessel Internals Program 
 
Summary of Technical Information in the Application. In LRA Section B.2.9, the applicant described the existing BWR Vessel Internals Program as consistent, with an enhancement, with the GALL AMP XI.M9, "BWR Vessel Internals." The applicant stated that this program is used to
 
manage cracking, loss of material, and reduction of fracture toughness for various
 
subcomponents of the RV internals.
 
Staff Evaluation. During the 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, is adequate to manage the aging effects for which the LRA
 
credits it. The staff noted that the program elements in the applicant's AMP claim of consistency with  the GALL Report were consistent with GALL AMP XI.M9, with the exception of the issue
 
identified below that the staff determined required additional clarification. The staff also
 
confirmed that the plant program contains all of the elements of the referenced the GALL
 
Report. The staff conducted onsite interviews with the applicant to confirm these results.
 
The staff noted that the scope of the BWR Vessel Internals Program includes Topical Report
 
BWRVIP-76, which has been approved by the staff and which provides the BWRVIP's
 
recommended inspection and flaw evaluation guidelines for BWR core shrouds. BWRVIP-76, Appendix C (a) provides guidance to evaluate structural integrity of the core shroud welds
 
exposed to neutron radiation during plant operation, (b) discusses the use of generic fracture
 
mechanics analyses for establishing inspection intervals for core shroud welds containing
 
cracks, and (c) provides the notch fracture toughness values for irradiated stainless steel
 
materials. The data in this appendix suggest that the fracture toughness values for stainless
 
steel materials tends to decrease with increasing exposure to neutron fluences greater than
 
1E21 n/cm 2 (E> 1 MeV). In August 2006, the BWRVIP issued staff-approved Topical Report No. BWRVIP-100-A, "Updated Assessment of the Fracture Toughness of Irradiated Stainless
 
Steel for BWR Core Shrouds," which discussed and provided updated fracture toughness
 
results for irradiated stainless steel materials. The BWRVIP 100-A report identified that the
 
fracture toughness values for irradiated stainless steel material may actually be lower than
 
those previously documented in the staff-approved version of BWRVIP-76. 
 
In RAI B.2.9-3, dated July 23, 2008, the staff requested that the applicant clarify whether the
 
results and recommendations in the staff-approved BWRVIP-100-A are within the scope of the
 
BWR Vessel Internals Program BWRVIP and; if yes, clarify how the recommendations in
 
BWRVIP-100-A will be used in conjunction with the recommendations in BWRVIP-76 for
 
evaluations of cracking in core shrouds. 
 
In the response to RAI B.2.9-3, dated August 27, 2008, the applicant stated that LRA
 
Sections  A.1.2.10 and B.2.9 state that the BWR Vessel Internals Program includes inspection
 
and flaw evaluation that conforms to the guidelines of applicable and staff-approved BWRVIP
 
reports. As such, BWRVIP-100-A is currently within the scope of the BWR Vessel Internals
 
Program. Under this AMP, the appliant is committed to following the current, staff-approved
 
BWRVIP guidance for managing cracking of the core shroud, during the period of extended
 
operation.
 
The applicant also stated that the current, staff-approved BWRVIP guidance for evaluating flaws
 
in the high-fluence core shroud welds is documented in BWRVIP-76, BWRVIP-99, and
 
BWRVIP-100-A and requires the use of the updated fracture toughness results for irradiated
 
stainless steel materials from BWRVIP-100-A. The applicant further stated that until 3-111 BWRVIP-76 Appendix C is revised as recommended in BWRVIP-100-A, only those shroud welds that have fluences less than 1E21 n/cm 2 will have their inspection intervals determined using BWRVIP- 76, Table 2-1. For shroud welds that have fluences greater than 1E21 n/cm 2 , the inspection intervals will be determined on a case specific basis, in accordance with the
 
guidance provided in BWRVIP-99 and BWRVIP-100-A.
 
Based on the review, the staff finds the applicant's response to RAI B.2.9-3 acceptable because
 
the applicant has adequately clarified its use of the latest staff approved BWRVIP-100A for core
 
shroud welds that have fluences greater than 1E21 n/cm 2 and BWRVIP-76 for core shroud welds that have fluences less than 1E21 n/cm
: 2. The staff determines that the applicant has satisfactorily described how it proposes to use BWRVIP-76 and BWRVIP-100 in conjunction
 
with each other and has committed to follow the current staff-approved BWRVIP guidance to
 
manage cracking of core shroud welds. Therefore, the staff's concern described in RAI B.2.9-3
 
is resolved.
 
In the review of the program basis document, the staff determined that the applicant is crediting
 
the BWR Vessel Internals Program to manage the aging effects of reduction in fracture
 
toughness for core shroud, core plate, top-guide components, orificed and peripheral fuel
 
support pieces, CRD tubes, jet pump assemblies and their subcomponents, and incore dry
 
tubes from the source range and intermediate range monitors. The staff has confirmed that the
 
program credits the augmented inspection and fl aw evaluation criteria in staff-approved BWRVIP topical reports as the basis for managing the aging effects applicable to SSES RV and
 
RV internal components. Loss (reduction) of fracture toughness is not an aging effect "per se,"
but, instead, refers to a change that may occur in the fracture toughness material property over
 
time.
 
In RAI B.2.9-4, dated July 23, 2008, the staff requested that the applicant explain how the
 
recommended BWRVIP report guidelines within the scope of the BWR Vessel Internals
 
Program BWRVIP, will accomplish adequate management of reduction of fracture toughness in
 
these RV internal components. The staff also requested that the applicant justify why the
 
applicable BWRVIP inspection and flaw evaluation guidelines for these RV internal components
 
are considered to be capable of managing reduction of fracture toughness in the components, and clarify the methodology or methodologies in these reports credited for management of this
 
aging effect.
 
In the response to RAI B.2.9-4, dated August 27, 2008, the applicant stated that the orificed fuel
 
support pieces are CASS, and reduction of fracture toughness is managed by the Thermal
 
Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS) Program, and not
 
by the BWR Vessel Internals Program, as shown in LRA Table 3.1.2-2. 
 
The applicant further stated:
 
The remaining reactor vessel (RV) internals components are the core shroud, core plate, top guide, fuel support pieces (peripheral), control rod guide tubes, jet pump assemblies, and incore dry tubes. These components are all addressed in specific BWRVIP reports.
 
The applicable BWRVIP inspection and flaw evaluation guidelines for these RV internal
 
components are considered to be capable of managing ROFT because the inspections
 
are designed to detect cracking, and, if cracking is detected, the inspection intervals will
 
be adjusted based on crack growth rates that are determined by evaluations that include
 
the effects of ROFT. The examination methods in the BWRVIP reports include ultrasonic
 
examination and visual examination of the RV internal components, when accessible, for 3-112 the detection of cracks. These same methods are credited for managing ROFT, since ROFT is managed as cracking is identified, evaluated, and monitored in components with fluence values exceeding the threshold for ROFT.
 
Based on the review, the staff finds the applicant's response to RAI B.2.9-4 acceptable because
 
the applicant has adequately explained that the BWRVIP guidelines provide examination
 
methods and evaluation techniques to detect cracking, and inspection intervals are adjusted
 
based on the results of the inspection. The staff finds that the guidelines will also manage
 
reduction of fracture toughness, since fluence is one of the key factors affecting the crack
 
growth rate, which increases as fluence increases the yield strength of the material (i.e.,
reduces fracture toughness). Therefore, the staff's concern described in RAI B.2.9-4 is resolved.
 
The staff noted that BWRVIP-76, Appendix C provides guidance to evaluate structural integrity
 
of the core shroud welds which is affected by the exposure to neutron radiation during the
 
service. In this appendix, the BWRVIP discusses the use of generic fracture mechanics
 
analyses for establishing inspection intervals for the core shroud welds with cracks, and
 
previous data suggests that the fracture toughness values tend to decrease when stainless
 
steel materials are exposed to neutron fluence. BWRVIP-76, Appendix C provides notch
 
toughness values which can be used for irradiated stainless steel materials.
 
In RAI B.2.9-5, dated July 23, 2008, the staff requested that the applicant clarify whether the
 
results and recommendations in the staff-approved BWRVIP-100-A are within the scope of the
 
BWR Vessel Internals Program and; if yes, clarify how the recommendations in BWRVIP-100-A
 
will be used in conjunction with the recommendations in BWRVIP-76 for evaluations of cracking
 
in core shrouds. 
 
In the response to RAI B.2.9-5, dated August 27, 2008, the applicant stated that its response to
 
RAI B.2.9-3, above, addresses RAI B.2.9-5. The staff acknowledges that RAI B.2.9-3 requested
 
the same information as RAI B.2.9-5 and finds that the applicant's response to RAI B.2.9-3 also
 
is acceptable for RAI B.2.9-5. Therefore, the staff's concern described in RAI B.2.9-5 is
 
resolved. 
 
Enhancement 1
 
The staff noted that the applicant's program indicated that the "scope of program" program
 
element for the BWR Vessel Internals Program will be enhanced to require augmented
 
inspection of the SSES top guide grid beams and beam-to-beam crevice slots. The
 
augmented inspections of these components will include completion of five percent of the
 
total population of grid beams and beam-to-beam cr evice slots within six years of entering the period of extended operation, with completion of an additional five percent within 12
 
years of entering the period of extended operation. The applicant stated that the scope of
 
inspections will focus on those grid beams and beam-to-beam crevice slots with neutron fluences projected to be greater than 5.0 x 10 20 n/cm 2 (E > 1.0 MeV) at 60 years.
 
The staff noted that GALL AMP XI.M9 indicates that the industry's augmented inspection and
 
flaw evaluation guidelines for BWR top guides and their subcomponents are provided in Topical
 
Report No. BWRVIP-26. The staff issued its SE on BWRVIP-26 in a letter to the BWRVIP dated
 
December 7, 2000. In this letter, the staff endorsed the BWRVIP's recommended augmented
 
inspection for BWR top guides and their subcomponents. However, these augmented inspection
 
guidelines did not provide any recommendations for BWR top guide grid beam locations and
 
beam-to-beam crevice slots. In the staff's updated GALL Report guidance, as described in the 3-113 GALL AMP XI.M9, the staff took the position that augmented inspections should be performed on the top guide grid beam and beam-to-beam crevice slots to address the potential for
 
irradiation-assisted stress corrosion cracking (IASCC) to occur in these top guide locations.
Specifically, the staff makes the following recommendation in GALL AMP XI.M9:
 
Alternatively, if the neutron fluence for the limiting top guide location is projected
 
to exceed the threshold for IASCC after entering the period of extended
 
operation, inspect 5% of the top guide locations (EVT-1) within six years after the
 
date projected for exceeding the threshold. An additional 5% of the top guide
 
locations will be inspected within twelve years after the date projected for
 
exceeding the threshold.
 
The staff's recommendation in the GALL AMP XI.M9 is predicated on the fact that an
 
applicant for license renewal of its BWR facility has not yet detected any signs of cracking
 
in the top guide grid beams and beam-to-beam crevice locations. The staff noted that the
 
applicant's proposed enhancement calling for augmented inspections of the SSES top
 
guide grid beam and beam-to beam locations conforms to the recommendations in GALL AMP XI.M9, as long as there has not been any evidence of cracking in these top guide
 
locations. 
 
In RAI B.2.9-1, dated June 12, 2008, the staff requested that the applicant clarify whether it had
 
performed any augmented inspections of the top guide grid beam and beam-to-beam crevice slot locations to date and; if so, summarize the inspection results of the augmented
 
examinations performed on these top guide components.
 
In its response to RAI B.2.9-1, dated July 14, 2008, the applicant stated:
 
The Unit 1 top guide beam and beam-to-beam crevice slot locations were inspected in
 
2004 during the thirteenth refueling outage. Twelve fuel cell locations were examined
 
using the VT-3 inspection method. The Unit 1 top guide was inspected again in 2008. At
 
that time, the top guide beam and beam-to-beam crevice slots at one cell location were
 
inspected using the EVT- 1 inspection method. No recordable indications were found in
 
either Unit 1 inspection.
 
The Unit 2 top guide beam and beam-to-beam crevice slot locations at twenty-one fuel
 
cell locations were inspected in the Unit 2 eleventh refueling outage in 2003 using the
 
VT-3 inspection method. In 2007, four additional fuel cell locations in the Unit 2 vessel
 
were inspected using the VT-3 inspection method. No recordable indications were found
 
in either Unit 2 inspection.
 
Based on the review, the staff finds the applicant's response to RAI B.2.9-1 acceptable because
 
the applicant has clarified that it has performed augmented inspections of the top guide grid
 
beam and beam-to-beam crevice slot locations and no recordable indications were found.
 
Therefore, the staff's concern described in RAI B.2.9-1 is resolved.
 
On the basis that the applicant has performed inspections of the top guide locations using
 
appropriate inspection techniques, and no recordable indications were found, the staff finds the
 
enhancement acceptable, because the implementation of the enhancement will make the applicant's program consistent with GALL AMP XI.M9. The staff verified that the applicant has
 
incorporated its enhancement of the BWR Vessel Internals Program in Commitment No. 9 in
 
LRA Table A-1 and was placed on UFSAR Supplement Section A.1.2.10.
3-114  However, in response to RAI 4.3-4, dated November 25, 2008, the applicant stated that since
 
the submittal of the LRA, the BWR Vessel Internals Program has been revised to include
 
requirements to inspect the top guide. The applicant further stated that the BWR Vessel
 
Internals Program now requires that at least 10 percent of the grid beam cells containing control
 
rod drives and/or blades will be inspected every twelve years, with at least five percent of the
 
inspections performed within the first six years of each twelve year interval. The applicant also
 
stated that the top guide locations to be inspected are those subject to neutron fluence levels
 
that exceed the IASCC threshold of 5.0E+20 n/cm 2 , and that the inspections will be performed using the enhanced visual inspection technique, EVT-1.
 
Furthermore, in response to RAI 4.3-4, the applicant stated that PPL will continue to perform
 
inspections on at least 10 percent of the top guide locations, every twelve years, during the
 
period of extended operation. The applicant accordingly revised the LRA to delete the
 
enhancement from LRA Section B.2.9, UFSAR Supplement Section A.1.2.10, and LRA Table A-
 
1 (Commitment No. 9).
 
In a teleconference held on December 18, 2008, the staff discussed with the applicant, the
 
degree of detail needed for implementing augmented inspections of top guide grid-to-beam and
 
beam-to-beam locations. In this teleconference, the staff established that the applicant would
 
need to commit to augmented inspections of the top guide locations or amend its response to
 
RAI 4.3-4. Any amended response to RAI 4.3-4 should discuss the corrective actions and
 
sample expansion criteria that the applicant would implement, if augmented inspections of the
 
top guide grid-to-beam and beam-to-beam locations detected cracking in the components. 
 
In a letter dated December 29, 2008, the applicant submitted a supplemental response
 
amending the LRA to include a commitment for augmented inspections of the top guide
 
grid-to-beam and beam-to-beam locations, in UUFSAR Supplement A.1.2.10. Specifically, the applicant committed to the following activities for the top guide grid-to-beam and beam-to-beam
 
locations:
PPL will continue to perform inspections on at least 10% of the top guide grid
 
beam cells containing control rod drives
/blades every twelve years during the period of extended operation, with at least 5% of the inspections being performed
 
within the first six years of each twelve year interval. The top guide locations to
 
be inspected are those subject to neutron fluence levels that exceed the IASCC
 
threshold of 5.0E+20 n/cm
: 2. The inspections will be performed using the enhanced visual inspection technique, EVT-1. 
 
The staff finds that the applicant's amendment for augmented inspection of the top guide
 
grid-to-beam and beam-to-beam locations acceptable because the applicant's commitment #9
 
for augmented inspection of these top guide locations is consistent with the staff's
 
recommended augmented inspection criteria for the locations in the "detection of aging effects" program element in GALL AMP XI.M9.
 
Review of License Renewal Applicant Action Items
 
LRA Appendix C provides the applicant's responses to the staff's renewal applicant action items
 
on the BWRVIP-based reports within the scope of the BWR Vessel Internals Program. The
 
applicant's program also includes an enhancement to perform augmented inspections of the 3-115 SSES top guide gird beam and beam-to-beam crevice slots. The staff evaluates the applicant's responses to the staff's renewal applicant action items later in this section.
 
The staff's renewal applicant action items for the BWRVIP Topical Reports within the scope of a
 
BWR Vessel Internals Program are provided in specific staff SEs issued to the BWRVIP with
 
respect to their inspection and flaw evaluation guidelines. 
 
The following table summarizes the topical reports within the scope of the applicant's BWR
 
Vessel Internals Program and the staff's SEs issued on these topical reports.
 
Component BWRVIP Topical Report Reference NRC SER Date SER Accession Number RV Components BWRVIP-74-A 10/18/01 ML012920549 Core Shroud
 
Support and Attachments BWRVIP-38 03/01/01 ML010600211 Core Shroud BWRVIP-76  Core Support Plate BWRVIP-25 12/07/00 ML003775989 Core Spray Lines and Spargers BWRVIP-18 12/07/00 ML003775973 Top Guide BWRVIP-26 12/07/00 ML003776110 Jet Pump Assemblies BWRVIP-41 05/01/01 ML011310322 RV Lower Plenum Components BWRVIP-47 12/07/00 ML003775765 The staff confirmed that the applicant has responded to the staff's renewal applicant actions
 
items on these BWRVIP reports in LRA Appendix C. The staff noted that the staff's first three
 
renewal applicant action items all dealt with: (a) identifying any deviations not conforming to the
 
BWRVIP's recommended guidelines in these topical reports, (b) identifying any TSs that may
 
require license amendments as a result implem enting the BWRVIP guideline recommendations, pursuant to 10 CFR 50.90, and (c) ensuring the UFSAR supplement for the BWR Vessel
 
Internals Program had incorporated a appropriate UFSAR supplement summary description for
 
the BWRVIP recommended activities.
 
The staff evaluated the applicant's responses to the first three renewal applicant action items.
 
With respect to the applicant's responses, the staff finds that the applicant had, in all cases, properly identified the renewal applicant action items and provided an acceptable basis for
 
responding to and resolving them.
Beyond the first three renewal applicant action items, the staff finds that the applicant had in all
 
cases properly identified the renewal applicant action items and provided an acceptable basis for responding to and resolving them, with the following exceptions:
 
In renewal applicant action item No. 5 on BWRVIP-25, the staff stated that "until such time as an
 
expanded technical basis for not inspecting the rim hold-down bolts is approved by the staff, applicants referencing the BWRVIP-25 report for license renewal should continue to perform
 
inspections of the rim hold-down bolts."
 
In response to renewal applicant action item No. 5 on BWRVIP-25, the applicant stated that the 3-116 re-inspection strategy for SSES currently does not include any further bolt inspections. The applicant stated that this strategy is justified by the results of the baseline inspections, which
 
found no crack indications, and a plant-specific analysis, which determined that adequate bolt
 
preload will be retained after 60 years of operation, even if the bolts contain cracks. The
 
applicant further stated that prior to entering the period of extended operation, PPL will either (a)
 
request staff approval of the justification for not inspecting the core plate hold-down bolts, (b)
 
implement a revised inspection strategy, appr oved by the staff, to ensure an adequate number of bolts are intact, and to prevent lateral displacement of the core plate, or (c) install core plate
 
wedges to structurally replace lateral load resistance provided by the bolts. 
 
The staff determines that the applicant has not included this re-inspection strategy commitment
 
in the LRA Table A-1. However, in response to RAI 4.7.3-1, dated October 18, 2007, the
 
applicant committed (Commitment No. 55) to either obtain staff approval for plant-specific
 
analyses to justify not inspecting the bolts or to install core plate wedges. 
 
On this basis, the staff finds that the applicant has properly addressed renewal applicant action
 
item No. 5 on BWRVIP-25 and provided an acceptable basis for responding to and resolving it.
 
In renewal applicant action item No. 4 for BWRVIP-26, the staff stated that "Due to IASCC
 
susceptibility of the subject safety-related components, applicants referencing the BWRVIP-26
 
report for license renewal should identify and evaluate the projected accumulated neutron
 
fluence as a potential TLAA issue." 
 
In response to renewal applicant action item No. 4 for BWRVIP-26, the applicant stated that
 
"accumulated neutron fluence for the top guide is not a TLAA for SSES. The top guide will
 
exceed the threshold fluence levels for IASCC identified in BWRVIP-26-A. The aging effect is
 
managed per the inspection recommendations in BWRVIP- 26-A. This strategy for managing
 
IASCC in the top guide addresses the issue raised in renewal applicant action item No. 4 on
 
BWRVIP-26 and will ensure that the proposed inspections will monitor for cracking in those top
 
guide locations that have the highest probability of initiating IASCC." 
 
The neutron fluence methodology for the RVs and RV internal components has been approved
 
by the staff and is assessed in SER Section 4.2.1. Based on this assessment, the staff
 
concludes that the applicant has taken a conservative approach to managing IASCC of the top
 
guides and further concludes that the applicant's aging management strategy is an acceptable
 
alternative to providing a beyond-CLB TLAA, as otherwise might have been done to satisfy
 
renewal applicant action item No. 4 on BWRVIP-26. Therefore, renewal applicant action item
 
No. 4 on BWRVIP-26 is considered resolved.
 
Operating Experience. The staff reviewed the applicant's "operating experience" program element discussions in the BWR Vessels Internals Program and in the license renewal basis
 
document for this AMP. The staff noted that the applicant has not identified any relevant
 
SSES-specific or generic OE in the "operating experience" program element discussion for the
 
BWR Vessels Internals Program. The staff also noted that the license renewal program
 
documents for this AMP does include several CRs/Action Requests that reported the
 
occurrence of flaw indications (cracks) in the core spray sparger brackets, core shroud
 
circumferential welds and some of jet pump a ssembly components (i.e., jet pump restrainers, wedges, and rods). The staff also observed that the applicant has dispositioned these flaw
 
indications as acceptable (i.e., "As-Is") for further service without the need for repair or
 
replacement of the components at this time. 
 
3-117 In RAI B.2.9-2, dated June 12, 2008, the staff requested that the applicant justify why the flaw indications in the core spray sparger brackets, core shroud welds, and jet pump assembly
 
components have not been identified as relevant OE for the BWR Vessels Internals Program, and explain its basis for leaving the flaws in these components in service (i.e., acceptable "As-Is") without repair or replacement of the impacted components. The staff also requested that the
 
applicant state, with a technical justification, what the inspection frequencies and sample sizes
 
will be for re-inspecting these RV internal components, during the period of extended operation.
 
In the response to RAI B.2.9-2, dated July 14, 2008, the applicant stated that PPL has identified
 
flaw indications in the core spray sparger brackets, core shroud welds, and jet pump assembly
 
components. The applicant also stated that all identified flaws allowed to remain in-service (i.e.,
acceptable "As-Is") have been evaluated in accordance with the applicable BWRVIP
 
documents. The applicant amended the LRA to add the relevant information to the "operating
 
experience" program element of LRA Section B.2.9 as follows:
 
For core shroud horizontal welds, initial indications were found in Units 1 and 2 in 1995.
 
Subsequent inspections were performed in each outage since 1995. Most of the
 
horizontal welds in both units exhibited some degree of cracking. To date, the flaws
 
detected have been evaluated using the methods and criteria defined in BWRVIP-76, and found structurally adequate until the next inspection. Future inspections are
 
scheduled for 2009 for Unit 2 and 2010 for Unit 1. Results of the inspection and
 
evaluation determine the frequency of the next inspection.
For core spray sparger brackets, a flaw was first identified in Unit 1 in 1996 and in Unit 2
 
in 1997. These flaws were reexamined in 2004 and 2005, and three more flaws were
 
identified in the shroud plate base metal area. These flaws were evaluated using the
 
guidance and criteria of BWRVIP-76 and found to have adequate structural margin. The
 
core spray sparger brackets are currently inspected in every outage. Inspections in 2004
 
and 2005 did not find any growth in the flaws.
The jet pump holddown beams on all Unit 1 and Unit 2 jet pumps were replaced in 1993
 
and 1994, respectively, in response to industry experience. In 2001, excessive jet pump
 
wedge wear and set screw gaps were observed on the Unit 2 jetpumps. Similar
 
observations were made in 2002 on Unit 1. In 2003 (for Unit 2) and 2004 (for Unit 1),
modifications were installed, including machining labyrinth seals in 20 jetpump inlet
 
mixers (to reduce flow induced vibration), replacing several wedges, and machining
 
several restrainer bracket pads. Subsequent inspections have revealed additional minor
 
wedge and rod wear. These components will continue to be monitored in accordance
 
with B WR VIP-41, and repairs or modifications made as required to ensure the jet
 
pumps are properly supported.
 
Based on the review, the staff finds the applicant's response to RAI B.2.9-2 acceptable because
 
the applicant has provided plant-specific operating experience relative to the BWR Vessel
 
Internals Program. The staff determines that the applicant will perform inspections on these
 
components at every outage, and the results will be evaluated using the guidance and criteria
 
provided in staff-approved BWRVIP documents t hat determine the next set of inspections.
Therefore, the staff's concern described in RAI B.2.9-2 is resolved.
 
The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10. Therefore, the staff finds this program element acceptable.
3-118  UFSAR Supplement. The applicant provided its UFSAR supplement summary for its BWR Vessel Internals Program in LRA Section A.1.2.10, Commitment No. 9. The staff confirms that
 
the UFSAR supplement summary description for the BWR Vessel Internals Program conforms
 
to the staff's recommended UFSAR supplement described in SRP-LR Table 3.1-2. The staff
 
also confirms that by letter dated December 29, 2008, the applicant has committed (Commitment No. 9) to the enhancement of t he program to implement augmented inspections of the SSES top guide grid beam and beam-to-beam crevice slot locations, during the period of
 
extended operation. The staff finds the applicant's commitment for the augmented inspections
 
of the top guide grid-to-beam and beam-to-beam locations are acceptable because they
 
conform to the staff's recommended augmented inspection criteria in the "detection of aging effects" program element in GALL AMP XI.M9.
 
Based on this review, the staff finds that UFSAR Supplement Section A.1.2.10, when coupled
 
with the letter dated November 25, 2008, provides an acceptable UFSAR supplement summary
 
description of the applicant's BWR Vessel Internals Program because it is consistent with the
 
SRP-LR and because the UFSAR supplement includes Commitment No. 9 on augmented
 
inspection bases for top guide grid-to-beam and beam-to-beam locations. 
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of the review of the applicant's BWR Vessel Internals Program and the applicant's response to the staff's RAIs, including deletion of the enhancement, the staff
 
finds all program elements consistent with the GALL Report. The staff concludes that the
 
applicant has demonstrated that effects of aging will be adequately managed so that the
 
intended function(s) will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement
 
for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d) and; therefore, is acceptable.
 
3.0.3.2.5  Bolting Integrity Program 
 
Summary of Technical Information in the Application. The LRA Section B.2.12 describes the existing Bolting Integrity Program as consistent, with five exceptions and one enhancement, with GALL AMP XI.M18, "Bolting Integrity." The Bolting Integrity Program includes, through
 
other credited programs, the periodic inspection of bolting for indication of degradation such as
 
leakage, loss of material, or cracking.
 
Prior to the period of extended operation, the Bolting Integrity Program will include a specific
 
precaution against the use of sulfur (sulfide) containing compounds as a lubricant for bolted
 
connections. 
 
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. During its on-site review, the staff reviewed the applicant's
 
on-site documentation supporting the applicant's conclusion that the program elements are
 
consistent with the elements in the GALL report. The staff also interviewed the applicant's
 
technical staff.
 
The staff reviewed the enhancement and exceptions to determine whether the AMP, is
 
adequate to manage the aging effects for which the LRA credits it.
3-119  In the LRA, the applicant stated that the AMP B.2.12 is an existing program that is consistent with GALL AMP XI.M18, "Bolting Integrity" with exceptions and an enhancement. The
 
exceptions affect the scope of program, preventiv e actions, parameters monitored or inspected, detection of aging effects, monitoring and trending, and acceptance criteria GALL Report
 
program elements. The enhancement affects t he preventive actions program element, and includes a precaution against using compounds containing sulfur as a lubricant for bolting.
 
During its on-site review, the staff reviewed the applicant's on-site documentation supporting the
 
applicant's conclusion that the program elements are consistent with the elements in the GALL
 
report. The staff interviewed the applicant's technical staff and reviewed on-site documents.
 
In comparing the program elements in the applicant's program to those in GALL AMP XI.M18, the staff found that the GALL Report "corrective actions" program element was not cited as
 
including an exception even though the bolting integr ity program does not explicitly address the guidelines outlined in EPRI NP-5769 as recommended by the GALL Report. By letter dated
 
June 30, 2008 the staff issued RAI B.2.12-2 requesting the applicant provide more information
 
on the basis for this exception.
 
By letter dated July 28, 2008, the applicant responded to RAI B.2.12-2 by stating that the AMP
 
B.2.12 follows the guidelines and recommendations of EPRI NP-5067 and EPRI TR-104213, instead of EPRI NP-5769 and NUREG-1339, and revised its AMP B.2.12 description in the LRA
 
to identify this as an exception to the corrective actions program element. Based on the
 
amendments made to the LRA, the staff found the applicant's response to be acceptable.
 
Exception 1 LRA Section B.2.12 states an exception to the following GALL Report program elements: scope of program, parameters monitored or inspect ed, detection of aging effects, monitoring and trending, and acceptance criteria. Specifically, the exception stated:
 
The inspection of structural bolting (including component support bolting) for indication of potential problems is accomplished under the Inservice Inspection (ISI) Program -
 
IWF and Structures Monitoring Program, consistent with the corresponding NUREG-
 
1801 items.
 
The staff reviewed the scope of the Bolting Integrity program in the GALL Report, and found that
 
it primarily applies to the ASME code piping and components, including high strength bolting
 
used in NSSS component supports where the actual yield strength is greater than 150 ksi. 
 
Other structural bolting used in supports, including expansion and anchor bolts are managed under ASME Code, Section XI, Subsection IWF (B.2.36) in accordance with GALL Report. The
 
applicant stated that there is no high strength bolting where the actual yield strength is greater
 
than 150 ksi. The staff finds that this 150 ksi limit is a specified value in the GALL Report
 
wherein structural bolting with a yield strength below this value is not included in the scope of
 
the AMP B.2.12. On the basis of its review as described above, the staff finds that this
 
exception is acceptable.
 
Exception 2
 
LRA Section B.2.12 states an exception to the following GALL Report program elements: scope
 
of program, and preventive actions. S pecifically, the exception stated:
3-120  The Bolting Integrity Program does not explicitly address the guidelines outlined in EPRI NP-5769 or as delineated in NUREG-1339. However, the Bolting Integrity Program
 
does rely on the recommendations of the manufacturer/vendor and the industry, contained in EPRI documents NP-5067 and TR-104213, and will include a precaution against the use of any sulfur (sulfide) containing compound as a lubricant. 
 
The staff reviewed the guidance documents, and determined that although EPRI TR-104213 is
 
a guidance document endorsed by this GALL AMP XI.M18, however the guidance document EPRI NP-5067 is not specifically endorsed. By letter dated June 30, 2008, the staff issued RAI
 
B.2.12-3 requesting additional information from the applicant detailing the differences between
 
the guidance documents. 
 
By letter dated July 28, 2008, the applicant responded to RAI B.2.13-3 by stating that although
 
the AMP B.2.12 follows the guidelines and recommendations of EPRI NP-5067 and EPRI TR-
 
104213, instead of EPRI NP-5769 and NUREG-1339, the Bolting Integrity Program still meets
 
the intent of the GALL Report recommendations. The applicant referenced a point-by-point
 
comparison of the two sets of documents dated April 1, 2005 (ML051020128). This comparison was previously accepted by the NRC, and found to adequately address the bolting guidelines in
 
the GALL Report. Based on the justification provided, the staff finds the applicant's response to
 
be acceptable.
 
Exception 3
 
LRA Section B.2.12 states an exception to the GALL Report program element parameters monitored or inspected. Specifically, the exception stated:
 
Loss of preload/loss of pre-stress is not an aging effect requiring management for SSES bolting since SSES systems operate below the 700 &deg;F threshold where stress relaxation
 
becomes a plausible age-related concern. Improper bolting application or maintenance
 
issues that might result in loss of preload are current plant operational (design)
 
concerns, as supported by site operating experience, and are not related to aging.
 
The staff reviewed the GALL Report and SRP-LR on the management of loss of preload, and
 
finds that the management of loss of preload is also addressed in the GALL Report program
 
element, preventive actions. Proper maintenance practices requiring the application of an
 
appropriate preload must exist. Additionally, the applicant states in its LRA that loss of preload
 
is not an aging effect requiring management since it does not reach the 700 o F threshold at which loss of preload due to thermal effects aging mechanism occurs. However, loss of preload
 
is identified in the GALL Report to include not only thermal effects, but also gasket creep and
 
self loosening as other aging mechanisms. The aging mechanisms of gasket creep and self
 
loosening are not properly discussed in this exception, and appears to imply that loss of preload
 
due to gasket creep and/or self loosening are not accounted for by the applicant. Therefore, by
 
letter dated September 23, 2008 the staff issued RAI B.2.12-5 requesting additional information
 
from the applicant regarding the management of loss of preload. 
 
By letter dated October, 22, 2008, the applicant responded to RAI B.2.12-5 by providing its
 
technical basis for the exclusion of the loss of preload aging effect by addressing the three
 
aging mechanisms which could lead to loss of preload- thermal effects, gasket creep, and self
 
loosening. The applicant referenced EPRI document 1010639 which states that "Loss of
 
preload is not an applicable aging effect". This document is not endorsed by the GALL AMP 3-121 XI.M18, and contradicts the GALL Report, which specifically identifies loss of preload as an aging effect with these three aging mechanisms. The staff recognizes that the conditions which
 
lead to loss of preload by thermal effects may not exist at SSES, and also that indications for
 
loss of preload are being monitored while monitoring for leakage, loss of material, and cracking.
However, the guidance from the GALL AMP XI.M18 and EPRI NP-5067, which the applicant
 
follows, indicates that loss of preload due to thermal effects, gasket creep, and self loosening is
 
in fact an aging effect requiring management. The staff finds that though it is possible to monitor
 
for indications of loss of preload such as leakage, the loss of preload aging effect still must be
 
an aging effect which is managed by the AMP B.2.12. However the applicant's response to part (c) of RAI B.2.12-5 appears to directly contradict this important distinction.
 
The staff discussed their concerns with the applicant in a teleconference on October 27, 2008.
 
By letter dated November 4, 2008, the applicant supplemented its response to RAI B.2.12-5, letter dated October, 22, 2008 by clarifying that although the loss of preload aging effect is not
 
included in any of the AMR line items in the LRA, the AMP B.2.12 still "provides for the
 
management of loss of preload for all in-scope, pressure-retaining bolted closures at SSES". 
 
With this distinction, the staff finds the applicant's response and exception to be acceptable.
 
Exception 4
 
LRA Section B.2.12 states an exception to the GALL Report program element monitoring and trending. Specifically, the exception stated:
 
Periodic inspection of bolting, other than of the Class 1, 2 and 3 bolting performed by the
 
Inservice Inspection (ISI) Program, is performed through the system Walkdown Program, including follow-up inspections if leakage is detected. The frequency of follow-
 
up inspections is established by engineering evaluation of the identified problem. SSES
 
operating experience has not shown a need for a set frequency (e.g., daily) applicable to
 
all cases involving bolting.
 
The staff reviewed the GALL Report "monitoring and trending" program element and found that
 
the recommendation for leak rate to be monitored on a particularly defined schedule was not
 
clear in the applicant's bolting integrity program. Therefore, by letter dated June 30, 2008, the
 
staff issued RAI B.2.12-1 requesting additional information on the applicant's leak rate
 
monitoring schedule. By letter dated July 28, 2008, the applicant stated that in cases of leakage on bolting connections for pressure retaining components (not covered by ASME Section XI), the
 
inspection frequency is determined by engineering evaluation of the problem. The applicant
 
stated that this is achieved at SSES through the plant minor deficiency monitoring program, which establishes the guidelines for identifying, monitoring, tracking, and disposition of minor
 
deficiencies, such as leaks, that are discovered during walk downs. For any leak, an evaluation
 
is completed to determine the actions required based on the severity of the leak and the
 
potential to impact normal operations and safety. Furthermore, if the leak rate changes, further
 
evaluation is performed to determine the actions required. Based on the justification provided, the staff found the applicant's response and exception to be acceptable.
 
Exception 5
 
LRA Section B.2.12 states an exception to the GALL Report program element acceptance
 
criteria. Specifically, the exception stated:
 
3-122 The program does not specify acceptance criteria for bolting. However, the Inservice Inspection (ISI) Program and the System Walkdown Program, through which the
 
periodic visual inspection of mechanical components within the scope of license renewal
 
are performed, do include acceptance criteria for evidence of degradation of
 
components, including the bolting.
 
The staff finds that the applicant properly addresses the intent of the GALL Report program
 
element acceptance criteria through the implement ation of its corrective action program as well as through the acceptance criteria identified in the Inservice Inspection Program and System
 
Walkdown Program. Therefore, the staff finds this exception to be acceptable.
 
Enhancement LRA Section B.2.12 states an enhancement to the GALL Report program element preventive actions. Specifically, the enhancement stated:
 
The program will include a specific precaution against the use of sulfure (sulfide)
 
containing compounds, such as molybdenum disulfide (MoS2), as a lubricant for
 
threaded fasteners (bolting), to further preclude the potential for stress corrosion
 
cracking.
 
The staff reviewed EPRI-5769, Volume 1, Section 11 and found that it specifically identifies
 
lubricants containing molybdenum disulfides as a common factor in several SCC related
 
failures. The applicant's enhancement directly addresses this issue, as it commits to include a
 
specific precaution against the use of compounds containing sulfur (sulfide), including
 
molybdenum disulfide (MoS 2), as a lubricant for bolting. When implemented prior to the period of extended operation, AMP B.2.12 will be consistent with the recommendations of GALL AMP XI.M18. On the basis of the guidance of the GALL Report, the staff finds this to be acceptable. 
 
Operating Experience:
The staff also reviewed the operating experience described in LRA Section B.2.12. The applicant stated that "No instances of cracking or age-related loss of
 
preload have been identified for bolting/fasteners, though some corroded bolting or facing
 
surfaces (e.g., from general corrosion or leakage) have been identified at SSES." To verify the
 
accuracy of this statement, the staff reviewed a sample of condition reports, 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. A 2002 condition report described the
 
degraded condition of a total of 26 corroded bolts on the A1 and A2 diesel generator
 
intercoolers. Upon further questioning of the applicant's staff and review of the CR, the staff
 
discovered that the applicant performed additional investigation and evaluation to determine the
 
root cause of the corroded bolts to be moisture and warm conditions. As a result, all 26 bolts
 
were replaced, and proper corrective actions were demonstrated. This report as well as other
 
condition reports reviewed by the staff during the audit helped to confirm the applicant's
 
statement above, and helped to demonstrate that pr oper corrective actions are taken to address bolting issues.
 
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.1.2.2, Commitment No. 12, the applicant provided the UFSAR Supplement for the Bolting Integrity Program. The staff reviewed this section and finds it 3-123 acceptable because it is consistent with the corresponding program description in SRP-LR Table 3.1-2.The staff determines that the information in the UFSAR supplement is an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
 
The staff verified that, Commitment No. 12 in the LRA Table A-1, includes a brief description of
 
the enhancement and committed to enhancing the program to include specific precautions
 
regarding the use of lubricants for threaded fasteners prior to the period of extended operation. 
 
==
Conclusion:==
 
The staff has reviewed the information provided in Section B.2.12 of the LRA Appendix B and additional information provided by the applicant by letters dated July 28, 2008, October 22, 2008 and November 4, 2008. On the basis of its review as discussed above, the
 
staff concludes that the applicant has demonstrated that those program elements for which the
 
applicant claimed consistency with the GALL Report are consistent with the GALL Report. 
 
In addition, the staff reviewed the exceptions and the associated justifications, and determined
 
that the AMP, with the exceptions, is adequate to manage the aging effects for which it is
 
credited. Also, the staff has reviewed the enhancement and confirmed that the implementation
 
of the enhancement prior to the period of extended operation would result in the existing AMP
 
being consistent with the GALL Report AMP to which it was compared. The staff concluded that
 
the applicant demonstrated that the effects of aging will be adequately managed so that the
 
intended functions of these components will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the
 
UFSAR supplement for this AMP and concluded that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.2.6  Piping Corrosion Program 
 
Summary of Technical Information in the Application. LRA Section B.2.13 describes the Piping Corrosion Program as an existing program that is consistent, with exceptions and enhancements, with GALL Report AMP XI.M20, Open-Cycle Cooling Water System. The applicant stated that this program fully meets the intent of NRC Generic Letter (GL) 89-13, "Service Water System Problems Affecting Sa fety-Related Equipment." The applicant further stated that the program is a combination of condition monitoring program (consisting of
 
inspections, surveillances, and testing to detect the presence of, and to assess the extent of, fouling and loss of material) and a mitigation program (consisting of chemical treatments and
 
cleaning activities to minimize fouling and loss of material).
 
Staff Evaluation. During the audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the applicant's on-site documentation supporting the
 
applicant's conclusion that the program elements are consistent with the elements in the GALL
 
report. The staff also interviewed the applicant's technical staff.
 
In comparing the elements in the applicant's program to those in the GALL AMP XI.M27, the staff noted that the program elements in the applicant's AMP claimed to be consistent with the
 
GALL were consistent with the corresponding program element criteria recommended in the program elements of GALL AMP XI.M20 with the exception of the "scope of program" program element aspect as identified below that the staff determined was in need of additional
 
clarification. The staff also confirmed that the plant program contains all of the elements of the
 
referenced GALL Report.
 
The staff reviewed the applicant's license renewal basis document and confirmed that the 3-124 program scope includes the systems and com ponents that could be affected by piping corrosion. 
 
In LRA Table 3.2.2-7, Standby Gas Treatment Sy stem (SGTS), the Piping Corrosion Program is credited for managing the aging effect of loss of material for loop seal piping and valve bodies.
 
However, a review of the license renewal basis document for the Piping Corrosion Program
 
indicated that SGTS is not included in the scope of the Piping Corrosion Program. The staff
 
issued RAI B.2.13-1 by letter dated May 30, 2008 requesting the applicant to justify why it is not
 
included and to justify how the Piping Corrosion Program will manage the aging effects of these
 
components in SGTS. 
 
In the letter dated June 30, 2008, the applicant responded to RAI B.2.13-1 by amending the
 
Piping Corrosion Program. This is discussed in the Enhancement 1 section.
 
The staff reviewed the exceptions and enhancements to determine whether the AMP, with the
 
exceptions and enhancements is adequate to manage the aging effects for which the LRA
 
credits it.
 
Exception 1
 
In LRA Section B.2.13, the applicant stated an exception to the "preventive actions" program
 
element that system components are lined or coated only where necessary to protect the underlying metal surfaces. The GALL AMP XI.M 20 recommends that system components are lined or coated. 
 
The staff reviewed the GALL Report Volume 2 Chapter VII for the Open-Cycle Cooling Water
 
System and noted that it includes piping, pi ping components and piping elements made of steel (with or without coatings), stainless steel and copper alloy materials. The GALL Report
 
recognizes that steel components may be coated or uncoated. Based on this review, the staff
 
finds the exception acceptable because the applicant is using materials that are appropriate for
 
the system and has lined or coated steel where necessary to protect the underlying material.
 
Exception 2
 
In LRA Section B.2.13, the applicant stated an exception to the "monitoring and trending"
 
program element that inspection frequencies are based on operating conditions and past history; flow rates, water quality, lay-up and heat exchanger design. The GALL AMP XI.M20
 
recommends testing and inspections be performed annually and during refueling outages.
 
The staff issued RAI B.2.13-5 by letter dated May 30, 2008 to request the applicant to confirm if
 
these frequencies are in accordance with the information provided in GL 89-13 concerning a
 
routine inspection and maintenance program and section D, "frequency of testing and
 
maintenance," in GL 89-13, Supplement 1, and if not, to justify why the GALL recommended
 
frequencies are not followed.
 
In the letter dated August 22, 2008, the applicant responded to RAI B.2.13-5 stating that the
 
inspection frequencies are in accordance with PPL commitments under NRC GL 89-13. The
 
applicant further stated that inspection and cleaning frequencies are based on PPL heat
 
exchanger's operating conditions and past history with flow rates, water quality, layup, and heat
 
exchanger design all being considered. The applicant further stated that the frequency has been
 
established in order to identify inherent problems before failures occur. In its response to GL 89-3-125 13 (PLA-3349, dated February 23, 1990), the applicant stated that "instead of conducting a testing program PPL committed to replacing the cooling coils of difficult to inspect heat
 
exchangers, laboratory testing of a fouled coil and a prototype of the replacement coil, and a
 
comprehensive program that includes scheduling of maintenance, methods of cleaning, inspection criteria, reporting, and personnel qualification. Based on past monitoring, PPL has
 
demonstrated that existing activities and their frequency have been acceptable to detect
 
degradation prior to the loss of component intended function and will remain adequate for the
 
period of extended operation. The frequency of inspections is in accordance with the
 
information provided in NRC GL 89-13."
 
The staff reviewed NRC GL 89-13 Supplement 1, Section III.D.3, which states, "Frequent
 
regular maintenance is an acceptable alternative to Recommended Action II, which calls for
 
heat exchanger performance testing. A licensee or applicant can choose to routinely maintain
 
the heat exchangers instead of testing them. Either the frequency of maintenance or the
 
frequency of testing should be determined to ensure that the equipment will perform the
 
intended safety functions during the intervals between maintenance or tests." The staff also
 
reviewed the applicant response to the NRC GL 89-13 and also reviewed the results of the
 
laboratory testing that the applicant had attached to GL 89-13 response. 
 
The staff noted that GL 89-13 Supplement 1 provides for regular maintenance and testing as an
 
alternate for performance testing. The staff also noted that the applicant performs periodic
 
inspection in accordance with its response to GL 89-13, has considered flow rates, water
 
quality, layup, and heat exchanger design when determining the frequency, and has addressed
 
appropriate inspection and acceptance criteria. The staff reviewed the plant OE and noted that
 
the applicant has identified and documented age related degradation as found during various
 
inspection activities. On this basis, the staff finds that the frequencies as established by the
 
applicant are appropriate and the Piping Corrosion Program will adequately manage age related
 
degradation through the period of extended operation. The staff finds the applicant response to RAI 2.13-5 to be acceptable and finds this exception to GALL AMP XI.M20 to be acceptable.
 
Exception 3
 
In the letter dated June 30, 2008, the applicant amended the application to include an additional
 
exception to the Piping Corrosion Program in the "scope of program" element as follows:
 
NUREG-1801 states that the guidelines of NRC GL 89-13 include a test program to
 
verify heat transfer capabilities. There is no test program at SSES to verify the heat
 
transfer capability. In response to GL 89-13, PPL conducted laboratory testing of cooling
 
coils to demonstrate adequate heat transfer capability.
 
The applicant had performed laboratory testing of a representatively fouled ECCS room cooler
 
cooling coil, and of prototypes representing replacement cooling coils, under post-accident
 
conditions that demonstrated adequate heat transfer capability. This is documented in PPL
 
correspondence to NRC via PLA-3776, dated June 11, 1992 that provided the 5/92
 
Confirmatory response to NRC GL 89-13. Additionally, the applicant has been monitoring heat
 
exchangers in response to GL 89-13 and has demonstrated that existing activities are able to
 
detect degradation prior to loss of component intended function and will remain adequate for the
 
period of extended operation.
 
The staff reviewed the above referenced applicant correspondence and the OE discussion that
 
was provided in the applicant's license renewal basis document for the Piping Corrosion 3-126 Program. On the basis that the applicant has met the GL 89-13 recommended actions and OE has demonstrated that the program activities can detect aging degradation prior to loss of
 
component intended function, the staff finds the applicant response acceptable and finds this exception to GALL AMP XI.M20 to be acceptable.
 
Based on the review, the staff finds the applicant's Piping Corrosion Program acceptable because it conforms to the recommended GALL AMP XI.M20, Open-Cycle Cooling Water
 
System with enhancements and exceptions.
 
Enhancement 1
 
In the letter dated June 30, 2008, the applicant responded to RAI B.2.13-1 that the LRA
 
Table correctly credited the Piping Corrosion Program and the basis document should have
 
included the SGTS loop seals in the scope of the Piping Corrosion Program.
 
The applicant amended the LRA Section B.2.13, Piping Corrosion Program with an
 
enhancement in the "scope of program" program element to include the STGS loop seals.
 
Similar changes were made to the UFSAR Supplement Section A.1.2.38 and the commitment
 
No.13 in LRA Table A-1. 
 
The applicant also stated that the internal environment for the loop seals is raw water from the
 
service water system and upon inclusion of the l oop seals within the scope of the program, they will be monitored and inspected for loss of material in accordance with the specifications.
 
The staff reviewed the response and the associated changes to the LRA and finds the response
 
and the changes acceptable because the applicant correctly added the SGTS loop seals to the
 
scope of the program. The staff concurs that with the inclusion of the loop seals within the
 
scope of the program, the Piping Corrosion Program will adequately manage the aging effects
 
of these components similar to the other servic e water system components that are included in the scope of this program. Based on this review, the staff finds the enhancement acceptable
 
because implementation of the enhancement will make the Piping Corrosion Program consistent with the GALL AMP XI.M20, Open-Cycle Cooling Water System.
 
Enhancement 2
 
In the letter dated October 21, 2008, in response to NRC regional inspection of the LRA, the
 
applicant added the following enhancement to the "monitoring and trending" program element of
 
LRA Section B.2.13.
 
The program will incorporate performance, documentation and trending of opportunistic
 
visual inspections (during normal maintenance/repair activities).
 
The applicant also revised the UFSAR supplement and Commitment No. 13 to include this
 
enhancement.
 
The staff reviewed the enhancement and associated changes and finds the response and the
 
changes acceptable because the implementation of the enhancement will make the Piping
 
Corrosion Program consistent with the GALL AMPXi.M20, Open-Cycle Cooling Water System for monitoring and trending of the inspection results.
 
The staff noted that the current "scope of program" program element, as described in the LRA, 3-127 does not include commitments for two GL 89-13 guidelines incorporated in GALL AMP XI.M20.
The specific components of the GL 89-13 program missing from the Piping Corrosion Program
 
are a system walkdown inspection to ensure compliance with the CLB and a review of
 
maintenance, operating, and training practices and procedures. The staff issued RAI B.2.13-2
 
by letter dated May 30, 2008 requesting the applicant to justify why this not an exception to the
 
GALL AMP.
 
In the letter dated June 30, 2008, the applicant responded to RAI B.2.13-2 that the program description for GALL AMP XI.M20 states that t he Open-Cycle Cooling Water System Program relies on implementation of the recommendations of GL 89-13. The applicant had provided
 
responses to GL 89-13 via a series of correspondence with the NRC. The recommended action
 
in GL 89-13 for system walkdown was documented in PPL correspondence to the NRC via
 
PLA-3349 dated February 23, 1990, and PLA-3489 dated December 14, 1990. PLA-3349 also
 
documented the recommended action for the review of the procedures. These two actions are
 
one-time actions arising out of GL 89-13 and are unrelated to aging management.
 
The staff reviewed the response and the referenced applicant correspondence and finds that
 
the applicant has taken the appropriate actions as recommended by GL 89-13 and is consistent with the GALL AMP XI.M20 program description and therefore has justified why an exception to
 
the GALL AMP is not required. Based on this review, the staff finds the applicant's response
 
acceptable.
 
In a response to GL 89-13, SSES took an exception to heat transfer capability testing. The GALL AMP XI.M20, in the parameters monito red/inspected program element, recommends testing to ensure heat transfer capabilities. In LRA section B.2.13, the applicant has not taken
 
an exception to this program element. The staff issued RAI B.2.13-3 by letter dated
 
May 30, 2008 requesting the applicant to justify why no exception is taken in the application.
 
In a letter dated June 30, 2008, the applicant responded to RAI B.2.13-3 that there is no test
 
program at SSES to verify heat transfer capability. The applicant amended the application to
 
include an additional exception to the Piping Corrosion Program in the "scope of program"
 
element. The staff evaluates this exception under Exception 3.
 
Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.13 and interviewed the applicant's technical personnel to confirm that the plant-specific OE did not
 
reveal any aging effects not bounded by the GALL Report. The staff also confirmed that
 
applicable aging effects and industry and plant-specific OE have been reviewed by the applicant
 
and are evaluated in the GALL Report. 
 
In the "operating experience" program element of LRA Section B.2.13, the LRA states that
 
SSES has programs in place with OE to demonstrate that the effects of aging on the service
 
water systems, and on the safety-related heat ex changers that they serve, will be effectively managed during the period of extended operation. The staff issued RAI B.2.13-4 by letter dated
 
May 30, 2008 requesting the applicant to provide some specific examples of issues that were
 
found in the condition reports. 
 
In the letter dated June 30, 2008, the applicant responded to RAI B.2.13-4 by providing several
 
specific examples of OE. These included service water piping leaks, UT pipe wall thickness
 
measurements that were below minimum requirements, tube wall erosion found during eddy
 
current testing, erosion damage on end covers of heat exchangers, pitting damage on stator
 
coolers and coatings damage on the waterbox divider. These were found during performance of 3-128 testing and inspections of piping and heat exchangers. The staff finds that the applicant has provided specific plant OE and taken the appropriate corrective action to demonstrate that the
 
effects of aging on the service water systems, and on the safety-related heat exchangers that they serve, will be adequately managed during the period of extended operation. Based on this
 
review, the staff finds the applicant response acceptable.
 
The staff also reviewed the applicant's "operating experience" described in the applicant's
 
license renewal basis document for the Piping Corrosion Program. The staff reviewed a sample
 
of condition reports and confirmed that the applicant had identified age related degradation and
 
implemented appropriate corrective actions. 
 
Furthermore, the staff confirmed that the applicant has addressed OE identified after the
 
issuance of the GALL Report. The staff finds that the applicant's Piping Corrosion Program, with
 
has been effective in identifying, monitoring, and correcting the effects of age related
 
degradation in service water piping systems and can be expected to ensure that effects of aging
 
will be adequately managed 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. In LRA Section A1.2.38, Commitment No. 13, the applicant provided the UFSAR supplement for the Piping Corrosion Program. The staff verified that the UFSAR
 
supplement summary description for the Piping Corrosion Program was in conformance with the
 
staff's recommended UFSAR supplement for the Open-Cycle Cooling Water System Program provided in Table 3.3-2 of the SRP-LR. 
 
In the letters dated June 30, 2008 and October 21, 2008, the applicant amended the UFSAR
 
supplement to include the enhancements to add Stand-By Gas Treatment System loop seals to the scope of the program and to incorporate performance, documentation and trending of
 
opportunistic inspections and revised Commitment No. 13 in Table A-1 accordingly. 
 
Based on this review, the staff finds that UFSAR supplement Section A1.2.38 as amended, provides an acceptable UFSAR supplement summary description of the applicant's Piping
 
Corrosion Program because it is consistent with those UFSAR supplement summary description
 
in the SRP-LR for the Open-Cycl e Cooling Water System Program.
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. Based on the review of the applicant's Piping Corrosion Program and the applicant's response to the staff RAIs, the staff finds all program elements consistent with the
 
GALL Report. In addition, the staff reviewed the exceptions and their justifications and
 
determines that the AMP, with the exceptions, is adequate to manage the aging effects for
 
which the LRA credits it. Also, the staff reviewed the enhancements and confirmed that its
 
implementation through Commitment No. 13 prior to the period of extended operation would
 
make the existing AMP consistent with the GALL Report AMP to which it was compared. The
 
staff concludes that the applicant has demonstrated that the effects of aging will be adequately
 
managed so that the intended function(s) will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the
 
UFSAR supplement as amended for this AMP and concludes that it provides an adequate 3-129 summary description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.2.7  Closed Cooling Water Chemistry Program 
 
Summary of Technical Information in the Application. LRA, Section B.2.14 describes AMP B.2.14 "Closed Cooling Water Chemistry Program" as an existing program that is consistent with the GALL AMP XI.M21 "Closed-Cy cle Cooling Water System" with an exception to the following program elements, "parameters monitored/inspected", "detection of aging
 
effects", "monitoring and trending" and "acceptance criteria." 
 
The applicant stated that this program is a mitigation program for damage due to loss of
 
material and cracking for components within the closed cooling water system or are
 
components that are served by the closing coo ling water system that are exposed to treated water. The applicant also stated that the program is consistent with EPRI water chemistry
 
guidelines that manage conditions that could lead to loss of material or cracking with the use of
 
proper monitoring and corrosion inhibitors. 
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the Gall Report. AMP XI.M21, "Closed-Cycle Cooli ng Water System" with an exception to the following program elements: parameters monitored/inspected, detection of aging effects, monitoring and trending and acceptance criteria.
 
In comparing the seven programs elements in the applicant's program to those in GALL AMP XI.M21, the staff noted that the program elements in the applicant's AMP claimed to be consistent with the GALL Report were consistent with the corresponding program element
 
criteria recommended in the program elements of GALL AMP XI.M21 with the exception of one (1) program element, "operating experience," and t hose exceptions taken by the applicant that the staff felt there was a need for additional clarification and for which RAIs were issued. The
 
staff also issued an RAI to clarify statements made by the applicant in LRA Section B.2.14
 
pertaining to a supplemental one-time inspection. The "operating experience" program element
 
is discussed separately below.
 
Based on the staff's review of LRA Section B.2.14, the staff noted that the applicant states that
 
the Closed Cooling Water Chemistry Program is supplemented by a one-time inspection to
 
ensure the effectiveness of the program, either the AMP B.2.22 "Chemistry Program Effectiveness Inspection" or the AMP B.2.24 "Heat Exchanger Inspection." The staff determined
 
that clarification was needed and, therefore, by letter dated July  10, 2008, the staff issued
 
RAI B.2.14-2 requesting the applicant to clarify if the appropriate one-time inspection will be
 
performed for all AMR Type-2 line items credited with using AMP B.2.14 and to identify which
 
one-time inspection, if any, will be used for any applicable AMR Type-2 line items that credit AMP B.2.14 for aging management. The applicant responded to RAI B.2.14-2, in a letter dated
 
August 12, 2008. The applicant clarified that the one-time inspection performed as part of the
 
AMP B.2.22, "Chemistry Program Effectivene ss Inspection" will be used to supplement AMP B.2.14, "Closed Cooling Water Chemistry Pr ogram" in all instances where AMP B.2.14 is credited for aging management in LRA Table-2 items, with the exception of the Diesel Jacket
 
Water Cooling System. The staff noted that the one-time inspection will not be performed on the
 
Diesel Jacket Water Cooling System because corrosion monitoring probes were installed to
 
identify actual corrosion rates. The staff further noted that these probes were installed following
 
an inspection performed at the same time as a 20-year overhaul of the system. The staff
 
confirmed that the applicant amended the LRA to indicate that AMP B.2.22 will supplement
 
AMP B.2.14, in order to perform a one-time inspection to identify degradation or confirm the lack 3-130 of degradation. On the basis of its review, the staff finds the applicant's response acceptable because the applicant has clarified that the AMP B.2.22, "Chemistry Program Effectiveness
 
Inspection" is the one-time inspection that will supplement AMP B.2.14, unless otherwise noted, which will be capable of identifying any evidence or confirm the lack of any degradation that is
 
occurring that may affect the intended functions of those components that credit AMP B.2.14 for
 
aging management, during the period of extended operation.
 
The staff reviewed the exception to determine whether the program, with exception, is adequate
 
to manage the aging effects for which it is credited.
 
Exception GALL AMP XI.M21 recommends the use of performance and functional testing to ensure the "acceptable functioning" of the closed cooling water system or components served by this system. The staff noted that the applicant's progr am takes an exception to the "parameters monitored/inspected" "detection of aging effects", "monitoring and trending" and "acceptance
 
criteria" program elements in that performanc e and functional testing will not be performed. 
 
The staff also noted that the applicant's program will monitor the emergency diesel generator
 
jacket water subsystem and heat-exchangers served by the closed cooling waters which are
 
supplemented by a one-time inspection to confirm the effectiveness of AMP B.2.14. Therefore, by letter dated July 10, 2008 (ML081890576) the staff issued RAI B.2.14-1 requesting the
 
applicant to clarify whether or not performance and functional testing are within the scope of the
 
closed cooling water chemistry program, and if not to provide the basis for not including them in
 
the scope of the program. The staff further asked the applicant in RAI B.2.14-1 to clarify whether the one-time inspection is being performed instead of the periodic inspections recommended in GALL AMP XI.M21 and if so, to justify how a one-time inspection is capable of accomplishing
 
the same tasks as the periodic inspections recommended by the GALL Report. Additionally, the
 
staff asked the applicant to clarify how a one-time inspection would be capable of trending
 
corrosion data for the components within scope of the program when only one round of
 
inspections are performed. 
 
The applicant responded to RAI B.2.14-1, in a letter dated August 12, 2008. In this letter the
 
applicant stated that the conditions that could lead to and the spread of loss of material and
 
cracking are managed by the proper control and monitoring of corrosion inhibitors in
 
accordance with EPRI water chemistry guidelines. The applicant further stated that system
 
parameters would only be affected when the degradation in the system had progressed to a
 
significant amount. The staff noted that the applicant will control the water chemistry in
 
accordance with EPRI guidelines, industry and plant-specific OE and periodic evaluation of the
 
water chemistry parameters. The staff noted that the applicant has performed a review of its
 
plant-specific OE, which indicated that the aging effects of loss of material and cracking are not
 
expected to occur and the Closed Cooling Water Chemistry Program has been effective is
 
mitigating these aging effects. The applicant stated in the LRA that they will be performing a
 
one-time inspection with the AMP B.2.22 "Chemistry Program Effectiveness Inspection" to
 
identify evidence or confirm the lack of any degradation that is occurring that may affect the
 
intended functions of these components during the period of extended operation. The applicant
 
stated that this one-time inspection will inspect a representative sample of components that are
 
exposed to low flow and stagnant areas where accumulation of contaminants might occur
 
making these components more susceptible to loss of material and components that are
 
exposed to temperatures greater than 140 o F which are susceptible to cracking. The staff noted that this one-time inspection will utilize a combination of volumetric and visual inspection 3-131 techniques (such as VT-1 or VT-3). The staff noted that in most cases the use of functional and performance testing will verify that the component's active functions can be accomplished. The
 
staff further noted that testing the active functions of components with performance and
 
functional testing are governed by the requirements of the Maintenance Rule (10 CFR 50.65).
 
By letter dated September 30, 2008 as a result of a NRC Regional Inspection the applicant
 
amended this exception in LRA Section B.2.14 in which the applicant clarified that periodic
 
inspections will not be performed, however bas ed on the implementation and inspection results from the one-time inspection that will be performed as part of AMP B.2.22 this may result in the
 
establishment of periodic inspection activities. On the basis of its review, the staff finds the
 
applicant's response acceptable because (1) the applicant will be monitoring and maintain the
 
water chemistry in accordance with EPRI guidelines (2) will be performing a one-time inspection in accordance with the recommendations of GALL AMP XI.M32 "One-Time Inspection" to
 
identify evidence or confirm the lack of any degradation that is occurring that may affect the
 
intended functions of the these components during the period of extended operation and (3) the
 
applicant may establish periodic activities based on the implementation and inspection results
 
from the one-time inspection performed as part of AMP B.2.22.
 
On the basis of its review, the staff finds the applicant's exception acceptable because (1) the
 
applicant will monitor and maintain water chemistry in accordance with the EPRI guidelines to
 
mitigate loss of material and cracking which has been proven to be successful based on plant-
 
specific OE, (2) the applicant will be performing a one-time inspection in accordance with the recommendations of GALL AMP XI.M32 "One-Time Inspection" for the aging effects of loss of
 
material and cracking, and (3) the applicant will be selecting representative sample of
 
components with low-flow and stagnant areas which are more susceptible to degradation
 
because of accumulating contaminants for the one-time inspections.
 
Operating Experience. The staff reviewed the applicant's OE described in the applicant's license renewal basis document for the Closed Cooling Water Chemistry Program. The
 
applicant stated in the LRA that this program incorporates EPRI closed cooling water guidelines
 
and also has been incorporating site-specific and industry wide OE. The staff noted that the
 
applicant performs periodic external and internal assessments of the program's performance to identify any strengths and adverse trends. 
 
During its review, the staff noted that the OE revealed issues with the diesel jacket water
 
corrosion/microbiological control in 1999 and some degradation of components were noted by
 
inspections during a 20-year overhaul during the same time period. The applicant took
 
corrective actions by flushing the jacket water and considered different biocide/corrosion
 
inhibitor treatments. The staff noted that the applicant installed instantaneous corrosion probes
 
to monitor corrosion rates. However the staff determined that additional information was needed
 
for its review and therefore, by letter dated July 10, 2008 the staff issued RAI B.2.14-3
 
requesting the applicant to clarify whether the addition of alternative biocides or corrosion
 
inhibitors was actually implemented as a corre ctive action for the diesel jack water system components that are exposed to closed cooling water. If so, clarify whether any supplemental
 
inspections have been performed since the time of the change in the biocide control compound
 
or corrosion inhibitor to verify its effectivene ss in managing microbiological organism growth or corrosion of the component surfaces that are exposed to closed cooling water; if not, and a
 
change in biocide control compound or corrosion inhibitors is planned, clarify when the change
 
will be performed and whether any supplemental inspections are planned to confirm its
 
effectiveness to mange microbiological organism growth or corrosion in the components. The applicant responded to RAI B.2.14-3, by letter dated August 12, 2008. The applicant stated that
 
during 1999 the biocide treatment used by SSES was glutaraldhyde, but was discontinued and 3-132 changed to the alternative biocide isothiazoline. The staff noted that this alternative biocide is currently in use and since its implementation in 1999, the more recent supplemental inspections
 
of the diesel generators have indicated no significant degradation. The applicant stated that the
 
supplemental inspections were performed to confirm the effectiveness of this new biocide
 
treatment. The applicant stated that the recent review in 2007 of the water chemistry samples
 
have shown that the chemistry parameters have been maintained in specification, corrosive
 
metal levels are low, and biological activity is negligible. On the basis of its review, the staff
 
finds the applicant's response acceptable because the applicant took corrective actions with the
 
use of alternate biocide treatments following the discovery of degradation in the diesel jacket
 
cooling water system and recent inspections have shown no significant degradation in the system.
 
The staff finds the applicant's Closed Cooling Water Chemistry Program has been effective in
 
identifying, monitoring and correcting the effects of aging and the existing program OE 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. The staff reviewed the UFSAR Supplement summary description that was provided in LRA Section A.1.2.13, Commitment No. 45, for the Closed Cooling Water Chemistry
 
Program. The staff verified that, in LRA Commitment No. 45 of UFSAR Supplement Table A-1, the applicant committed to the ongoing implementation of the Closed Cooling Water Chemistry
 
Program for aging management of those in-sc ope components that the AMP is credited. The staff also verified that the applicant has placed this commitment on UFSAR Supplement
 
summary description A.1.2.13 for the Closed Cooling Water Chemistry Program. 
 
Based on this review, the staff finds that UFSAR Supplement Section A.1.2.13 provides an
 
acceptable UFSAR Supplement summary description of the applicant's Closed Cooling Water
 
Chemistry Program because it is consistent with the UFSAR Supplement summary description
 
in the SRP-LR and because the summary description includes the bases for determining that
 
aging effects will be managed. Therefore, the staff concludes that the UFSAR supplement for
 
this AMP provides an adequate summary descr iption of the program, as described by 10 CFR 54.21(d).
 
Conclusion. On the basis of the review of the applicant's Closed Cooling Water Chemistry Program, the staff determines that those program elements for which the applicant claimed
 
consistency with the GALL Report are consistent. The staff reviewed the exception , the
 
justification and determined that the AMP, with the exception, is adequate to manage the aging
 
effects for which the LRA credits it. In addition the staff reviewed the applicant's responses to
 
the staff's RAI and its evaluation is documented above. The staff concludes that the applicant
 
has demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB for the period of extended operation, as
 
required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this
 
AMP and concludes that it provides an adequate summary description of the program, as
 
required by 10 CFR 54.21(d).
 
3.0.3.2.8  Fire Protection Program 
 
Summary of Technical Information in the Application. LRA Section B.2.16 describes the Fire 3-133 Protection Program as an existing program that is consistent with an exception with GALL Report AMP XI.M26, Fire Protection. The applicant stated that this program performs periodic visual inspections and functional tests, as appropriate, of fire dampers, fire barrier walls, ceilings
 
and floors, fire rated penetration seals (fire stops), fire wraps, fireproofing, and fire doors to
 
ensure that functionality and operability are maintained.
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the
 
exception, is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.M26, the staff noted that the
 
program elements in the applicant's AMP claimed to be consistent with GALL were consistent
 
with the corresponding program element criter ia recommended in the program elements of GALL AMP XI.M26 The staff also confirmed that t he plant program contains all of the elements of the referenced GALL Report. Onsite interviews were also held to confirm these results. 
 
The staff reviewed the exception to determine whether the AMP, with the exception, is adequate
 
to manage the aging effects for which the LRA credits it.
 
Exception 1
 
In the LRA, the applicant identified the following exception to the "scope", "parameters
 
monitored/inspected", "detection of aging effects", "monitoring and trending" and "acceptance
 
criteria" program elements:
 
With respect to the halon/carbon dioxide (CO2) suppression systems and the fuel oil
 
supply line for the diesel-driven fire pump, inspections and tests included in the Fire
 
Protection Program (and addressed in the Technical Requirements Manual) are not
 
credited with aging management but do provide for periodic observation of the related
 
components. While halon/CO2 and fuel supply line internal conditions are not directly
 
inspected or evaluated during these tests and inspections, they do provide indirect
 
confirmation of whether degradation has occurred, prior to a loss of function.
 
The staff issued RAI B.2.16-1 by letter dated May 30, 2008 requesting the applicant to provide
 
justification why these tests and inspections are not credited for license renewal, and why the
 
internal surfaces are not inspected.
 
In the letter dated June 30, 2008, the applicant stated in response to part a.1 of RAI B.2.16-1
 
that Halon/CO 2 spray nozzles, tubing and valve body fabricated from stainless steel and copper alloy are not susceptible to aging in indoor air environment. The staff reviewed the GALL Report
 
and noted that items VII.J-15 and V.F-3 identify no aging effects for stainless steel and copper
 
alloy material in indoor air external environment. The applicant stated in part a.2 of RAI B.2.16-1
 
that consistent with the GALL Report, there are no aging effects for material in a dry gas internal
 
environment. The staff reviewed the GALL Report and noted that items VII.J-4 and VII.J-19
 
identify no aging effect for a dry gas environment. The applicant further stated in part a.3 of
 
RAI B.2.16-1 that the System Walkdown Program is credited for managing the aging effects on the external surfaces of steel components in Halon/CO 2 system. The staff noted that this is consistent with the GALL Report that recommends the GALL AMP XI.M36, External Surfaces
 
Monitoring. 
 
The applicant finally stated in response to part b of RAI B.2.16-1 that for the diesel engine-3-134 driven fire pump, the Fuel Oil Chemistry and C hemistry Effectiveness Programs are credited to manage the aging effects. The staff reviewed LRA Table 3.3.2-13 and noted that aging effects
 
of copper tubing in a fuel oil environment is managed by the Fuel Oil Chemistry and Chemistry Effectiveness Inspection Programs, which is consistent with the GALL Report.
 
Because the applicant is consistent with the GALL Report recommendations, the staff finds the
 
applicant response acceptable and concurs that because there are no aging effects, the internal
 
surfaces of Halon/CO 2 system components do not need to be inspected and the internal surfaces of diesel engine-driven fire pump tubing are inspected as part of the sample population
 
in the Chemistry Effectiveness Inspection Program. Based on this review, the staff finds this
 
exception acceptable.
 
Based on the review of the exception, and resolution of the related RAI as described above, the
 
staff finds the Fire Program consistent with program elements of GALL AMP XI.M26, with acceptable exceptions, and therefore acceptable.
 
Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.16 and interviewed the applicant's technical personnel to confirm that the plant-specific OE did not
 
reveal any aging effects not bounded by the GALL Report. The staff also confirmed that
 
applicable aging effects and industry and plant-specific OE have been reviewed by the applicant
 
and are evaluated in the GALL Report. 
 
The staff also reviewed the applicant's OE described in the applicant's license renewal basis
 
document for the Fire Protection Program. The staff reviewed a sample of condition reports and
 
confirmed that the applicant had identified age related degradation and implemented
 
appropriate corrective actions. The staff found examples of fire door issues, penetration seal
 
cracking and fire door seal degradation. The staff noted that several condition reports have
 
been written against fire door degradation that determined that the fire door degradations were
 
related to human performance and inadequate fire door installation. Isolated cases of fire rated
 
penetration seal cracking and fire door seal degradation have also been identified. Corrective
 
actions included additional personnel training, repair, and/or replacement activities. The staff did
 
not find any age related degradation in Halon/CO 2 systems.
 
Furthermore, the staff confirmed that the applicant has addressed OE identified after the
 
issuance of the GALL Report. The staff finds that the applicant's Fire Protection Program, with
 
the corrective actions discussed in the LRA, has been effective in identifying, monitoring, and
 
correcting the effects of age related degradation in fire protection systems and can be expected
 
to ensure that the systems and components within the scope of this program will continue to perform their intended functions consistent with the current licensing basis for the period of
 
extended operation.
 
The 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 A1.2.18, Commitment No. 15, the applicant provided the UFSAR supplement for the Fire Protection Program. The staff verified that the UFSAR
 
supplement summary description for the Fire Protection Program was in conformance with the
 
staff's recommended UFSAR supplement for the Fire Protection Program provided in Table 3.3-
 
2 of the SRP-LR. In Table A-1, the applicant has committed via Commitment No. 15 to
 
implement the existing program thr ough the period of extended operation.
 
3-135 Based on this review, the staff finds that UFSAR supplement Section A1.2.18 provides an acceptable UFSAR supplement summary description of the applicant's Fire Protection Program
 
because it is consistent with those UFSAR supplement summary description in the SRP-LR for
 
the Fire Protection Program.
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of the review of the applicant's Fire Protection Program and the applicant's response to the staff's RAI, the staff finds all program elements consistent with the
 
GALL Report. 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 the LRA
 
credits it. The staff concludes that the applicant has demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d). 
 
3.0.3.2.9  Fire Water System Program 
 
Summary of Technical Information in the Application. LRA Section B.2.17 describes the Fire Water System Program as an existing program t hat is consistent with enhancements with the GALL Report AMP XI.M27, Fire Water System. The applicant stated that this program performs periodic inspection and testing of the water-based fire suppression systems including hydrant
 
and hose station inspections, fire main flushing, flow tests, and sprinkler inspections. The
 
applicant also stated that tests and inspections are generally in accordance with the applicable
 
National Fire Protection Association (NFPA) recommendations. 
 
Staff Evaluation. During its audit the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancements to determine whether the AMP, with the
 
enhancements is adequate to manage the aging effects for which the LRA credits it. In
 
comparing the elements in the applicant's program to those in the GALL AMP XI.M27, the staff noted that the program elements in the applicant's AMP which claimed to be consistent with the
 
GALL Report were consistent with the corresponding program element. However the "scope of
 
program" program element aspect as identified below the staff determined needed additional
 
clarification. The staff also confirmed that the plant program contains all of the elements of the
 
referenced the GALL Report. Onsite interviews were also held to confirm these results. 
 
The LRA credits the Fire Water System Program for managing loss of material for valve bodies (deluge) in the Standby Gas Treatment System (SGTS). However, the staff noted the STGS is
 
not included in the list of systems in the scope of this program, as identified in the program basis document. The staff issued RAI B.2.17-1 by letter dated May 30, 2008 requesting the
 
applicant to clarify why the SGTS is not in-scope.
 
In the letter dated June 30, 2008, the applicant responded to RAI B.2.17-1 by stating that the
 
SGTS components are included in the scope of t he Fire Water System Program. The applicant also stated that these components include piping and valves associated with deluge of the
 
charcoal absorbers. However, since LRA Table 3.2.2-7 only addressed deluge valves, the LRA
 
Table was amended to include carbon steel deluge piping. The applicant also stated that it
 
credited the Fire Water System Program to manage loss of material for internal surfaces in a
 
raw water environment, and the System Walkdow n Program to manage loss of material of 3-136 external surfaces in an indoor air environment. 
 
Because the added AMR line item is consistent with the GALL Report line VII.G-24 for internal
 
surfaces, and V.B-3 for external surfaces, the staff finds the addition of this line to be
 
acceptable. However, the response did not indicate whether the LRA will be amended to include
 
the SGTS within the scope of the program or provide justification why it was not included. The
 
staff issued a follow-up RAI B2.17-1R by letter dated July  23, 2008, to resolve this issue.
 
In the letter dated August 22, 2008, the applicant responded to RAI B2.17-1R  by stating that
 
LRA Section B.2.17, Fire Water System Program is an existing program. The specific systems within the scope of the program are not incl uded in the LRA, however, these systems are identified in the program basis document. The applicant acknowledged that the SGTS should
 
have been included in the program basis docum ent, but was inadvertently omitted. The applicant stated that the deluge valves and piping, located in the fire protection lines to the high
 
efficiency charcoal adsorber filters, were evaluated with SGTS but is subject to the raw water
 
environment of the fire protection system and therefore credited the Fire Water System Program. The applicant also stated that the SGTS deluge valves and piping are included in the
 
LRA Table 3.3.2-7, are identified in the Technical Requirements manual Table 3.7.3.2-1, and
 
are included in the fire water system procedure that performs the 18-month functional test and
 
the 18-month visual inspection of the SGTS deluge system.
 
The staff noted that the valves and piping in question are located in an environment of fire water
 
but evaluated in the SGTS aging management review, and that these lines are included in the
 
fire protection system testing and inspection procedures as per the requirements in the
 
Technical Requirements Manual. On this basis, the staff finds that enhancement to the program
 
is not needed and finds the applicant response to be acceptable.
 
LRA Table 3.3.2-13 credits the Fire Water System program to manage reduction in heat transfer
 
for heat exchanger tubes. However, LRA Section B.2.17 states that this program is consistent with the GALL AMP XI.M27, which focuses on managing the aging effect of loss of material and
 
not reduction in heat transfer. The staff issued RAI B.2.17-2 by letter dated May 30, 2008
 
requesting the applicant to justify how this program will manage reduction in heat transfer. 
 
In the letter dated June 30, 2008, the applicant responded to RAI B.2.17-2 by stating that upon
 
further consideration, the Heat Exchanger Inspection Program has been identified as a more
 
appropriate program for managing reduction of heat transfer for the diesel engine driven fire
 
pump heat exchangers. The applicant amended the LRA to credit the Heat Exchanger
 
Inspection Program in lieu of the Fire Wate r System Program. The evaluation of the Heat Exchanger Program is documented in SER Section 3.0.3.1.12.
 
The staff reviewed the enhancements to determine whether the AMP, with the enhancements, is adequate to manage the aging effects for which the LRA credits it.
 
Enhancement 1
 
In LRA Section B.2.17, the applicant added a program requirement in the "detection of aging
 
effects", "monitoring and trending", and "acceptance criteria" program elements to require
 
testing or replacement of sprinkler heads in service for 50 years
 
The GALL AMP XI.M27 recommends testing or replacement of sprinkler heads in service for 50
 
years. On the basis that the enhancement, when im plemented, will make the Fire Water System 3-137 Program consistent with the GALL Report, the staff finds the enhancement acceptable.
 
Enhancement 2
 
In LRA Section B.2.17, the applicant added a program requirement in the "parameters
 
monitored or inspected" and "detection of aging e ffects" program elements to perform ultrasonic testing of representative portions of above ground fire protection piping that are exposed to
 
water but do not normally experience flow. 
 
By letters dated June 30, 2008 in response to RAI B.2.17-3 and October 21, 2008, in response
 
to NRC regional inspection of the LRA, the applicant amended the LRA to revise enhancement
 
2 as follows:
 
Ultrasonic testing of representative portions of above ground fire protection
 
piping that are exposed to water but do not normally experience flow, are
 
associated with a dry-piping sprinkler system and may contain stagnant water, or
 
is pre-action or deluge piping that is normally dry, but may have been wetted and
 
not completely dry, will be performed after the issuance of the renewed license
 
but prior to the end of the current operating term and at reasonable intervals
 
thereafter, based on engineering review of the results.
 
The GALL AMP XI.M27 recommends wall thickness evaluations of fire protection piping using
 
non-intrusive testing (e.g., ultrasonic testing) to identify loss of material due to corrosion. By
 
performing this testing on piping that does not normally experience flow, or may contain
 
stagnant water or may have been wetted but not completely dry, the applicant has selected
 
locations that would experience a more aggressive internal environment than piping with full
 
flow. On the basis that the enhancement, when im plemented, will make the Fire Water System Program consistent with the GALL Report, the staff finds the enhancement acceptable.
 
Enhancement 3
 
By letter dated October 21, 2008, in response to NRC regional inspection of the LRA, the
 
applicant amended the LRA to add another enhancement as follows:
 
Also, within the 10-year period prior to the period of extended operation, at least
 
one visual inspection (opportunistic or focused) of the internal surface of buried
 
fire water piping will be performed. In addition, at least one inspection per year of
 
'wet' fire protection piping for wall thickness and pipe blockage will be performed
 
if no opportunistic inspection has been completed.
 
The applicant also revised the UFSAR supplement and the commitment list to include this
 
enhancement.
 
The GALL AMP XI.M27 recommends that as an alter native to non-intrusive testing, the plant maintenance process may include a visual inspection of internal surface of the fire protection
 
piping upon each entry to the system for routine or corrective maintenance. By performing the visual inspection on an opportunistic or focused basis on selected representative locations, and
 
on the basis that the enhancement, when implem ented, will make the Fire Water System Program consistent with the GALL Report, the staff finds the enhancement acceptable. 
 
Based on its review, the staff finds the applicant's Fire Water System Program acceptable 3-138 because it conforms to the recommended GALL AMP XI.M27, Fire Water System with enhancements. 
 
Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.17 and interviewed the applicant's technical personnel to confirm that the plant-specific OE did not
 
reveal any aging effects not bounded by the GALL Report. The staff also confirmed that
 
applicable aging effects and industry and plant-specific OE have been reviewed by the applicant
 
and are evaluated in the GALL Report. Furthermore, the staff confirmed that the applicant has
 
addressed OE identified after the issuance of the GALL Report. In the "operating experience"
 
element of LRA Section B.2.17, the LRA states that a search of condition reports was performed
 
for the Fire Protection System. When conditions were found that required correction they were
 
repaired in accordance with the site corrective action program. However, the applicant did not
 
provide any specific OE related to the Fire Water System Program. The staff issued RAI B.2.17-3 requesting the applicant to provide some specific examples of issues that were found in the
 
condition reports. 
 
In the letter dated June 30, 2008, the applicant responded to RAI B.2.17-3 by providing several
 
specific examples of plant OE. The applicant stated that small leaks were identified in different
 
fire protection piping, which were repaired or the piping replaced; and ultrasonic inspection was
 
performed on surrounding areas as part of the corrective action. 
 
On the basis that the applicant has identified specific examples of plant OE and corrective
 
actions taken, the staff finds the applicant response acceptable.
The staff reviewed some condition reports as part of the OE review and found that several CRs were written to address through wall leaks in fire water headers in the Circ water pumphouse
 
area. Stagnant water in low drainage locations inside the pumphouse was determined to be the
 
cause. The staff issued RAI B.2.17-4 requesting the applicant to address this issue, (a) to
 
determine what changes are proposed and (b) if these locations are included in the
 
representative sample picked for UT inspections for wall thickness measurements. 
 
In the letter dated June 30, 2008, the applicant responded to RAI B.2.17-4 by stating that no
 
changes were proposed to the fire water system to alleviate through wall leaks. The applicant
 
stated that the leaks were observed in piping that is normally dry, however, stagnant water
 
collected in low drainage locations, which made the piping system more susceptible to
 
corrosion. The applicant further stated any leaking piping is identified to engineering for
 
evaluation, including an operability evaluation. The applicant further stated that the Fire Water
 
System program manages the aging by performing evaluations of issues that are identified during station activities. The applicant amended LRA Section B.2.17, Fire Water System
 
Program, to revise the enhancement for wall thickness measurement by UT, to include
 
representative portions of above ground piping in the dry-pipe sprinkler system, which may
 
contain stagnant water. The applicant also revised the UFSAR Supplement and the
 
Commitment List to include the revised enhancement.
 
The staff reviewed the amendment and finds that with the changes to the enhancement to
 
include stagnant water locations in the representative sample for ultrasonic testing, the Fire
 
Water System Program will provide further a ssurance that aging effects are managed and these components will continue to perform their intended functions consistent with the current
 
licensing basis for the period of extended operation. Based on this review, the staff finds the
 
applicant response acceptable.
 
3-139 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.1.2.19, Commitment No. 46, and letters dated June 30, 2008, and October 21, 2008, the applicant provided the UFSAR supplement for the
 
Fire Water System Program. The staff verified that the UFSAR supplement summary
 
description for the Fire Water System Program was in conformance with the staff's
 
recommended UFSAR supplement for the Fire Wate r System Program provided in Table 3.3-2 of the SRP-LR.
 
The applicant committed to enhance its program to require testing or replacement of sprinkler
 
heads in service for 50 years, and to perform ul trasonic testing of representative portions of above ground fire protection piping that are exposed to water but do not normally experience
 
flow or are associated with a dry-pipe sprinkler system and may contain stagnant water, or is
 
pre-action or deluge piping that is normally dry, but may have been wetted and not completely
 
dry. The applicant also committed to enhance its program to perform within the 10-year period
 
prior to the period of extended operation, at least one visual inspection (opportunistic or
 
focused) of the internal surface of buried fire water piping, and at least one inspection per year
 
of 'wet' fire protection piping for wall thickness and pipe blockage if no opportunistic inspection
 
has been completed.
 
Based on this review, the staff finds that UFSAR supplement Section A.1.2.19 provides an
 
acceptable UFSAR supplement summary description of the applicant's Fire Water System
 
Program because it is consistent with those UFSAR supplement summary description in the
 
SRP-LR for the Fire Water System Program. 
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of the review of the applicant's Fire Water System Program, and the applicant's response to the staff's RAIs, the staff finds all program elements consistent with the
 
GALL Report. Also, the staff reviewed the enhancements and confirmed that their
 
implementation through Commitment No. 46 prior to the period of extended operation will 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 effects will be
 
adequately managed so that the intended functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed
 
the UFSAR supplement, as amended, for this AMP and concludes that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d). 
 
3.0.3.2.10  Buried Piping and Surveillance Program 
 
Summary of Technical Information in the Application. The LRA Section B.2.18 described the new Buried Piping Surveillance Program as consistent with GALL AMP XI.M28, "Buried Piping
 
and Tanks Surveillance," with an exception. This program consists of a prevention program (consisting of protective coatings and wrappings and a condition monitoring program (consisting of visual inspections). to manage the loss of material on external surfaces of piping with
 
damaged coatings.
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the 3-140 GALL Report. The staff also confirmed that the plant program contains all of the elements of the referenced GALL Report. Onsite interviews were also held to confirm these results.
 
In comparing the elements in the applicant's program to those in GALL AMP XI.M28, the staff noted that the program elements in the applicant's AMP claimed to be consistent with GALL
 
were consistent with the corresponding program element criteria recommended in the program elements of GALL AMP XI.M28 with the excepti on of the "scope of program" program element aspect as identified below.
 
The staff reviewed the exception to determine whether the AMP, with the exception will be
 
adequate to manage the aging effects for which the LRA credits 
 
Exception:
 
The applicant stated an exception to the "scope" program element stating that the "scope of
 
program" element is limited to the sections of buried Residual Heat Removal Service Water (RHRSW) and Emergency Service Water (ESW) common return header piping for which
 
damaged coatings are known to exist. Therefore, the applicant does not credit coatings in this
 
program for aging management. All other buried piping and tanks subject to aging management are managed by the Buried Piping and Tanks Inspection Program. The staff did not agree that
 
this is an exception to the GALL AMP because the GALL Report recommends either the use of
 
the Buried Piping and Tanks Surveillance Program or the Buried Piping and Tanks Inspection
 
Program for buried piping and tanks. The staff discussed this issue with the applicant and
 
followed up with RAI B.2.18-1 in a letter dated June 13, 2008, that asked the applicant to explain
 
why this is an exception to the GALL Report AMP. In the applicant's response to this RAI in a
 
letter dated July  14, 2008, the applicant agreed that this should not be an exception and
 
amended the LRA to state under "Exceptions to NUREG-1801," "None."
On the basis of the review, the staff concludes that the applicant's Buried Piping and Tanks
 
Surveillance Program provides assurance that either the aging effect is indeed not occurring, or
 
that the aging effect is occurring so slowly as not to affect the intended function of the
 
component or structure. The staff finds the applicant's Buried Piping Surveillance Program acceptable because it conforms to the recommended GALL AMP XI.M28, Buried Piping and
 
Tanks Surveillance Program following resolution of the RAI.
 
The staff has identified one additional area of concern that relates to the rectifiers and the
 
ground bed anodes and all other equipment associated with the implementation of this AMP.
 
The staff assumes that these components are not currently safety-related and are not covered
 
by the 10 CFR Appendix B program as discussed in Appendix B.1.3 of the LRA. RAI B.2.18-2
 
was issued to the applicant by a letter dated June 13, 2008, and requested the applicant to
 
clarify whether these components will remain nonsafety-related, but now fall under the 10 CFR
 
Part 50 Appendix B program, or whether they be upgraded to safety-related. In addition, the
 
staff asked the applicant to indicate whether the failure of one of these components will initiate a
 
technical specification limited condition of operation and whether there will be a commitment to
 
cover this equipment under the SSES 10 CFR Appendix B program. In its response dated July 
 
14, 2008, the applicant responded to RAI B.2.18-2 by stating that rectifiers, ground bed anodes, and other equipment in-scope for AMP B.2.18 are nonsafety-related and that failure of these
 
components does not result in entry into a technical specification limited condition of operation.
 
The applicant also stated that the cathodic protection system has no safety-related function but
 
are in-scope for license renewal under 10 CFR Part 54.4(a)(2). In the LRA Section B.1.3, the
 
applicant states:
3-141  "The elements of corrective actions, confirmati on process, and administrative controls in the SSES QA Program will be applied to each existing, enhanced, and new aging
 
management program and activity credited fo r license renewal, for both safety-related and nonsafety-related structures and components determined to require aging
 
management during the period of extended operation."
 
The staff noted the systems and components used as part of the Buried Piping Surveillance
 
Program are in-scope for 10 CFR Part 50 Appendix B. and there will be no changes to the LRA
 
as a result of this response.
 
The staff requested this information for clarification and the applicant's response addressed the
 
staff's questions and concerns. On the basis of its review, and because the applicant has
 
included all SSCs in-scope for license renewal under its existing 10 CFR Appendix B Program
 
regardless of safety classification, the staff finds the applicant's response acceptable.
 
Operating Experience. The staff also reviewed the applicant's OE, including a sample of condition reports, and interviewed the applicant's technical staff to confirm that the plant-specific
 
OE did not reveal any degradation not bounded by industry experience. In the application, the
 
applicant stated that there is no OE demonstrating the effectiveness of the program because it
 
is a new program.
 
The applicant stated that the Buried Piping Surveillance Program is a new program for which
 
there is no OE and that inspection methods will be consistent with accepted industry practices.
 
For this program and for other new AMPs where the applicant provided no current plant-specific
 
OE, the staff issued RAI B.2.1 by letter dated June 10, 2008 asking that the applicant commit to
 
provide documentation of plant-specific operating for staff review after the program has been
 
implemented, but prior to entering the period of extended operation.
 
In its letter dated July 8, 2008, the applicant stated that OE for new aging management
 
programs described in LRA Appendix B will be gai ned as these new programs are implemented during the period of extended operation. The applicant stated that results of tests, inspections, and other aging management activities conducted in accordance with these programs will be
 
subject to confirmation and corrective action elements of the Susquehanna 10 CFR Part 50, Appendix B, quality assurance program and that results will be subject to NRC review during regional inspections under existing NRC inspection modules. The applicant stated that these
 
new programs will be implemented prior to, and continue through, the period of extended operation and that OE will be gained for thes e programs as they are implemented. The applicant further stated that test and inspection results that do not meet acceptance criteria for
 
these new programs will be evaluated under the station's corrective action program, which includes requirements for identification of appropriate corrective actions and verification of the
 
effectiveness of corrective actions.
 
The staff noted that the applicant's statement that inspection methods will be consistent with
 
industry practices is consistent with the "operating experience" program element for GALL AMP XI.28. The staff also noted that post-approval site inspections provide an opportunity for
 
staff review and assessment of the effectiveness of the applicant's Buried Piping Surveillance
 
Program after the applicant has developed OE with that program. The staff concludes that the
 
corrective action program, based on internal and external plant OE, would capture OE in the
 
future to support the conclusion that the effects of aging are adequately managed. On this
 
basis, the staff confirmed that the "operating exper ience" program element satisfies the criterion 3-142 defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program element acceptable and concludes that a separate commitment is not necessary.
 
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.1.2.4, Commitment No. 16, the applicant provided the UFSAR supplement for the Buried Piping Surveillance Program. The staff reviewed this section
 
and determined that the information in the UFSAR Supplement provides an adequate summary
 
description of the program consistent with the SRP-LR and as required by 10 CFR 54.21(d)..
 
Conclusion. The staff has reviewed the information provided in Section B.2.18 of the LRA Appendix B and additional information provided by the applicant by letter dated July 14, 2008.
 
On the basis of its review as discussed above, the staff concludes that the applicant has
 
demonstrated that effects of aging of the buried piping will be adequately managed so that the
 
intended functions of these components 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
 
UFSAR supplement and concludes that it provides an adequate summary description of the
 
program, as required by 10 CFR 54.21(d).
 
3.0.3.2.11  Fuel Oil Chemistry Program 
 
Summary of Technical Information in the Application. LRA Section B.2.20 describes the existing Fuel Oil Chemistry Program as consistent, with exceptions, with GALL AMP XI.M30, "Fuel Oil Chemistry." The applicant stated that the program is a mitigation program that manages
 
potential aging effects for plant components in a fuel oil environment. The applicant also stated
 
that the program manages loss of material and cracking through monitoring and control of fuel
 
oil contamination, such as water or microbiological organisms, consistent with pertinent plant
 
technical specifications/requirements and American Society for Testing of Materials (ASTM)
 
standards. The applicant further stated that exposure to contaminants is minimized by verifying
 
the quality of new fuel oil before it enters the storage tanks and by periodic sampling to ensure
 
that the tanks are free of water and particulates.
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the applicant's aging management program (AMP) evaluation report for the Fuel Oil Chemistry Program, together with implementing procedures and supporting documentation related to the program. The staff did not identify any issues requiring
 
further resolution or clarification for elements of the program that the applicant claimed to be consistent with the corresponding program element criteria in GALL AMP XI.M30.
 
The applicant's Fuel Oil Chemistry Program, as described in the LRA, includes three (3)
 
exceptions to the GALL Report identified by the applicant. These exceptions affect the "scope of
 
program," the "parameters monitored/inspect ed" and "acceptance criteria," and the "monitoring and trending" program elements of the AMP. In response to an issue raised during a regional
 
inspection of the applicant's program, the applicant identified an additional exception to the
 
"acceptance criteria" program element and revised the LRA to identify this fourth exception. The
 
staff reviewed the four (4) exceptions to determine whether the AMP, with exceptions, is
 
adequate to manage the aging effects for which the LRA credits it. The staff's evaluation of the
 
exceptions is presented in the following paragraphs.
 
3-143 Exception 1 LRA Section B.2.20 states an exception to the "scope of program" program element. The applicant stated that although its Fuel Oil Chemistry Program largely focuses on fuel oil tanks, the program is also applicable to other components exposed to fuel oil, including the fuel oil
 
supply components of the diesel engine-driven fire pump. The applicant categorized expansion
 
of the Fuel Oil Chemistry Program to include oil supply components of the diesel engine-driven fire pump as an exception to the GALL Report.
 
In evaluating this exception, the staff noted that in the GALL Report the "scope of program" program element for GALL AMP XI.M30 focuse s exclusively on managing the aging of the interior surfaces of the diesel generator fuel oil supply tanks. The staff also noted that the
 
material, environment and potential aging effects are identical for both the diesel generator fuel
 
oil supply components and the diesel engine-driven fire pump fuel oil supply components and
 
that GALL Table VII.G, item VII.G-21 credits us e of the Fuel Oil Chemistry Program for aging management in the fire protection system. On the basis that the expanded scope of the
 
applicant's Fuel Oil Chemistry Program encom passes components with material, environment and potential aging effects identical to the components explicitly identified in the GALL Report, the staff finds the "scope of program" of the applicant's Fuel Oil Chemistry Program, including
 
this exception to the GALL Report, to be acceptable.
Exception 2
 
LRA Section B.2.20 states an exception to the "parameters monitored/inspected" and the
 
"acceptance criteria" program elements. The applicant stated that with respect to the test
 
described in ASTM Standard D2276-00, "Standard Test Method for Particulate Contaminant in
 
Aviation Fuel by Line Sampling," their program uses the 0.8 &#xb5;m pore size filter called out in the
 
ASTM standard, rather than the 3.0 &#xb5;m pore size filter recommended in the GALL Report's
 
description for this program element. 
 
The applicant categorized the use a filter pore size different from what is recommended in the
 
GALL Report as an exception to the "parameter s monitored/ inspected" and the "acceptance criteria" program elements as described in the GALL Report.
The staff reviewed ASTM Standard D2276-00 and noted that the standard provides a method
 
for gravimetric measurement of particulate matter in diesel fuel by comparing the weight of a test filter on which particulate matter is collected against the weight of a control filter through
 
which the filtered fuel is subsequently passed, then converting the measurements to milligrams of particulate per liter of filtered fuel. The standard states that tolerable levels of particulate
 
contaminants have not yet been established for all points in fuel distribution systems. Since
 
specific levels of particulate are not specified by the standard, the primary purpose of the test is
 
to ensure that particulate contamination is not increasing outside its normal operating range.
 
The staff noted that use of a filter with different pore size from what is recommended in the
 
GALL Report does not invalidate the test procedure, and that the applicant's use of a filter with
 
smaller pore size than what is recommended in the GALL Report provides a conservative
 
measurement of particulate concentration relative to the methodology recommended in the
 
GALL Report. Because the test methodology remains valid with the smaller pore filter and the
 
measurements with the smaller pore filter are conservative relative to the GALL Report's
 
recommendation, the staff finds the "parameters monitored/inspected" and the "acceptance
 
criteria" elements of the applicant's Fuel Oil Chemistry Program to be acceptable.
 
3-144 Exception 3
 
LRA Section B.2.20 states an exception to the "monitoring and trending" program element. The
 
applicant stated that an annual frequency for sampling of fuel for biological activity is used, along with monthly or quarterly sampling for other contaminants. This is an exception to the
 
GALL Report's recommendation that water and biological activity or particulate contamination
 
concentrations be monitored and trended in accordance with the plant's technical specifications
 
or at least quarterly.
 
The staff reviewed the applicant's technical specifications and technical requirements manual
 
and noted that sampling is specified to be done in accordance with industry standards, but no
 
specific frequency of sampling for biological activity is identified in those documents. The staff
 
issued RAI B.2.20-1 by letter dated June 23, 2008, asking the applicant what ASTM standard is
 
used to establish frequency for monitoring fuel oil for biological activity and to provide a basis
 
and technical justification for its current sampling frequency if no such standard exists or is
 
used.
 
The applicant responded in a letter dated July 17, 2008. In that letter the applicant provided the
 
following discussion in response to RAI B.2.20-1:
The schedule for sampling the emergency diesel generator fuel oil in the fuel oil
 
storage tanks for biological activity was changed from annually to quarterly
 
in 2007. No ASTM standard was identified since the sampling frequency now
 
matches the frequency recommended by GALL. The exception to monitoring and
 
trending is no longer needed and is deleted.
 
The following changes are made to the LRA to delete the monitoring and
 
trending exception for the Fuel Oil Chemistry Program.
The third bullet under the Exceptions to NUREG-1801, in Section B.2.20 (LRA
 
Page B-65) is revised by deletion [in its entirety].
On the basis that the applicant revised the fuel oil sampling frequency for biological activity to
 
be consistent with the recommendations in the GALL Report and revised the LRA to delete the
 
previously identified exception, the staff finds the "monitoring and trending" program element of the applicant's Fuel Oil Chemistry Program to be acceptable.
 
Exception 4
 
In a letter dated October 21, 2008, the applicant identified an additional exception to the
 
"detection of aging effects" program element. The applicant stated that ultrasonic (UT) thickness
 
measurements are not taken on the bottoms of the diesel generator fuel oil storage tanks
 
because the fuel oil storage tanks are buried and inaccessible; also internal surfaces are
 
coated, and coatings would have to be removed in order to perform UT examinations. The applicant stated that UT examinations of diesel generator fuel oil day tank bottoms will be
 
conducted as part of the Chemistry Program E ffectiveness Inspection. The applicant also made changes to LRA Section B.2.22, Chemistry Program Effectiveness Inspection, to state that the
 
bottom of at least two diesel generator fuel o il day tanks will be exami ned by UT measurements as part of the Chemistry Program Effectiveness Inspection AMP.
 
In the GALL Report the "detection of aging effects" program element states that degradation of 3-145 the diesel fuel oil tank cannot occur without exposure of the tank internal surfaces to contaminants such as water and microbiological organisms. The program element also states
 
that an ultrasonic thickness measurement of the tank bottom surfaces ensures that significant
 
degradation is not occurring. 
 
The staff noted that both the diesel generator fuel oil storage tanks and the diesel generator fuel
 
oil day tanks are made of carbon steel and are ex posed to an interior environment of fuel oil.
The staff noted that the interior surface of the storage tanks are provided with a protective
 
coating, but the coating is not credited in the LRA for aging mitigation; and the interior surfaces
 
of the day tanks are not coated. The staff also noted that both the fuel oil storage tanks and the
 
day tanks are designed so that the interior of the tanks can be visually inspected. The interior of
 
the fuel oil storage tanks is required by Technica l Specifications to be cleaned every ten years, and during the cleaning the surface condition of the tank interior is visually examined. The staff
 
noted that except for some additional straining and filtering as fuel oil is pumped from the
 
storage tanks to the day tanks, the interior environments of the storage tanks and the day tanks are identical; and because both tanks are made of carbon steel, aging effects in the storage
 
tanks and the day tanks would be similar. Because aging effects in the day tanks and in the
 
storage tanks are similar, the staff concluded that one-time UT of the bottoms of the day tanks
 
will provide a reasonable indication of whether wall thinning may be occurring in the storage
 
tank bottoms. In addition, the requirement for cleaning of the storage tanks every ten (10) years
 
and visual inspection of the interior of the storage tanks provides opportunity to detect any
 
degradation in the protective coating that would be an indication of potential degradation in the
 
storage tank steel bottoms. Because degradation of the steel storage tank bottoms would be
 
detected before failure of its intended function could occur, the staff concludes that UT
 
examination of the day tank bottoms provides an acceptable alternative to UT examination of the storage tank bottoms and that Exception 4 to the "detection of aging effects" program
 
element is acceptable.
 
Based on its review of the exceptions, and resolution of the related RAIs as described above, the staff finds the Fuel Oil Chemistry Program consistent with program elements of GALL AMP XI.M30, with acceptable exceptions, and therefore acceptable.
 
Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.20.
The applicant stated that review of plant-specific OE did not reveal a loss of component function
 
or fouling of subject components that contain fuel oil which could be attributed to an inadequacy
 
of the Fuel Oil Chemistry Program. The applicant also stated that fuel oil delivered to the site is
 
sampled and analyzed prior to addition to fuel oil storage tanks and periodically thereafter and
 
that water and sediment is removed, particulates are filtered, and biological activity is controlled. 
 
During the onsite audit, the staff reviewed the applicant's "operating experience" program
 
element for the Fuel Oil Chemistry Program. The staff reviewed selected procedures and
 
completed work packages related to periodic fuel oil chemistry testing and preventive
 
maintenance on components in the fuel oil storage system. The staff noted that the onsite
 
documentation supports the applicant's statements with regard to OE for the Fuel Oil Chemistry
 
Program and that the applicant's OE does not reveal any age related degradation not bounded
 
by industry experience. 
 
Based on this review, the staff finds that (1) the OE for this AMP demonstrates that the
 
applicant's Fuel Oil Chemistry Program is achieving its objective of maintaining fuel oil quality
 
and mitigating potential corrosion of components exposed to fuel oil, and (2) that the applicant is
 
taking appropriate corrective actions through implementation of this program.
3-146  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.1.2.21, Commitment No. 47, the applicant provided the UFSAR supplement for the Fuel Oil Chemistry Program. The staff noted that the UFSAR
 
supplement's description for the Fuel Oil Chem istry Program conforms with the recommended UFSAR supplement for this type of program as described in SRP-LR (NUREG-1800, Revision 1). The staff also noted that in Commitment No. 47 of LRA Table A-1, License
 
Renewal Commitments, the applicant committed to ongoing implementation of the Fuel Oil
 
Chemistry Program for aging management of applicable components during the period of extended operation. 
 
Based on this review, the staff finds that the UFSAR supplement summary in LRA
 
Section A.1.2.21 provides an acceptable description of the applicant's Fuel Oil Chemistry
 
Program because it is consistent with the UFSAR supplement summary description in the SRP-
 
LR for the Fuel Oil Chemistry Program.
 
The staff determines that the information in the UFSAR supplement is an adequate summary
 
description of the program as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of the review of the applicant's Fuel Oil Chemistry Program, including the LRA changes provided in response to RAI B.2.20-1, the staff finds that those program
 
elements for which the applicant claimed consistency with the GALL Report are consistent. In
 
addition, the staff reviewed the exceptions and their justifications and determined that the AMP, with the exceptions, is adequate to manage the aging effects for which the LRA credits it. The
 
staff concludes that the applicant has demonstrated that the effects of aging will be adequately
 
managed so that the intended function(s) will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the
 
UFSAR supplement for this AMP and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.2.12  Reactor Vessel Surveillance Program 
 
Summary of Technical Information in the Application. LRA Section B.2.21 describes the existing Reactor Vessel Surveillance Program as consistent, with exception, with GALL AMP XI.M31, "Reactor Vessel Surveillance."
 
The Reactor Vessel Surveillance Program, which manages reduction of fracture toughness for
 
the low-alloy steel RV shell and welds in the beltline region, is a condition-monitoring program
 
developed in response to 10 CFR Part 50 Appendix H, "Reactor Vessel Material Surveillance
 
Program Requirements," and part of the Integr ated Surveillance Program (ISP) described in BWRVIP-78, A BWR Integrated Surveillance Program Plan,@ BWRVIP-86-A, "BWR Vessel and Internals Project, BWR Integrated Surveillance Program Implementation,@ and BWRVIP-116, "BWR Vessel And Internals Project, Integrat ed Surveillance Program Implementation For License Renewal.
@ BWRVIP-116 extends the ISP to cover the period of extended operation.
The applicant will follow BWRVIP ISP requirements and apply ISP data to Susquehanna, Units 1 and 2. The staff approved the use of the BWRVIP ISP in place of a plant-specific
 
program.
3-147  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.
 
In LRA Appendix B, AMP B.2.21, the applicant described its AMP to manage irradiation
 
embrittlement of the reactor pressure vessel (RPV) through testing that monitors RPV beltline
 
material properties. The LRA stated that the RPV surveillance program will follow the
 
requirements of the BWRVIP ISP and will apply the ISP data to the Susquehanna units.
 
10 CFR Part 50, Appendix H requires that an ISP, which is used as a basis for a facility
=s RPV surveillance program, be reviewed and approved by the staff. The ISP to be used by the applicant is a program that was developed by the BWRVIP, and the applicant will apply the
 
BWRVIP ISP as the method by which the SSES units will comply with the requirements of
 
10 CFR Part 50, Appendix H.
 
The applicant has implemented the BWRVIP ISP based on the BWRVIP-78 report and the BWRVIP-86-A report. These reports are consistent with the GALL AMP XI.M31 for the period of
 
the current licenses. The staff concluded that the BWRVIP ISP in BWRVIP-78 and the
 
BWRVIP-86-A reports is acceptable for BWR licensee implementation provided that all
 
participating licensees use one or more compatible neutron fluence methodologies acceptable
 
to the staff for determining surveillance capsule and RPV neutron fluences. The staff
=s  acceptance of the BWRVIP ISP for the current term at SSES is documented in the staff
=s safety evaluation report (SER) dated February 6, 2003, which is addressed in SSES License Amendment 208. 
 
In addition, the BWRVIP developed an updated version of the ISP in the BWRVIP-116 report, which provides guidelines for an ISP to monitor neutron irradiation embrittlement of the RPV
 
beltline materials for all U.S. BWR power plants for the license renewal period. The BWRVIP
 
ISP identifies capsules that must be tested to monitor neutron radiation embrittlement for all
 
licensees participating in the ISP and identifies capsules that are available on a "contingency"
 
basis (deferred capsules). However, no guidance is provided in the BWRVIP-116 for continued
 
use, storage, or testing of deferred capsules. Table 3-3 of the BWRVIP-116 report indicates that
 
both SSES units have deferred capsules.
 
The applicant stated in LRA AMP B.2.21, and in the UFSAR supplement Section A.1.2.41, A Reactor Vessel Surveillance Program,@ that the Reactor Vessel Surveillance Program is part of the ISP described in BWRVIP-78, BWRVIP-86-A, and BWRVIP-116 and it will follow the requirements of the BWRVIP ISP. BWRVIP-116-A has not been issued yet. Therefore, following
 
the requirements of the BWRVIP ISP, as stated in LRA AMP B.2.21, may not obligate the
 
applicant to address the additional requirements in the SER on BWRVIP-116 dated
 
March 1, 2006. Hence, the staff issued RAI B.2.21-1, requesting that the applicant make a
 
commitment to address these additional requirements.
 
By letter dated October 18, 2007, the applicant stated in its response to RAI B.2.21-1 that it
 
would update AMP B.2.21 and UFSAR Section A.1.2.41 to include the commitment to address
 
the additional requirements that are specified in the March 1, 2006, SER. Hence, RAI B.2.21-1
 
is resolved.
 
Exception 3-148  LRA B.2.21 characterized the Susquehanna RPV surveillance program as consistent with NUREG-1801, Section XI.M31, "Reactor Vessel Surveillance," with an exception from the
 
NUREG-1801 guideline which requires that analyzed capsules be stored once the analysis is
 
complete. The staff does not accept this exception because analyzed specimens may be
 
reconstituted for future use during or beyond the current requested extended period of
 
operation. Hence, the staff issued RAI B.2.21-2, requesting the applicant remove this exception
 
to NUREG-1801. Further, since the BWRVIP-116 did not provide guidelines for storage of
 
deferred capsules, RAI B.2.21-2 also requested the applicant commit to the following:
 
If the SSES standby capsule is removed from the RPV without the intent to test
 
it, the capsule will be stored in manner which maintains it in a condition which
 
would permit its future use, including during the period of extended operation, if
 
necessary.
 
By letter dated October 18, 2007, the applicant made appropriate revisions to LRA AMP B.2.21, LRA UFSAR Section A.1.2.41, and LRA Table A-1, Commitment No. 18, to reflect the
 
elimination of the NUREG-1801 exception and the inclusion of the commitment cited above.
 
Hence, RAI B.2.21-2 is resolved.
 
On the basis of its review, the staff finds that the applicant has demonstrated that the effects of
 
aging due to loss of fracture toughness of the RPV beltline region will be adequately managed
 
by the SSES Reactor Vessel Surveillance Program, so that the intended functions will be
 
maintained consistent with the current licensing basis (CLB) for the period of extended 
 
operation, as required by 10 CFR 54.21(a)(3).
 
Operating Experience. LRA Section B.2.21 states that there have been capsule evaluations on Susquehanna, Units 1 and 2 prior to the BWRVIP ISP. Measured decreases in upper shelf
 
energy were consistently less than RG 1.99 projections. Measured Unit 1 RT NDT increases were slightly greater, within one standard deviation, than the RG 1.99 projections while measured
 
Unit 2 RT NDT increases were less.
 
The staff confirmed that the above description of the OE regarding SSES's evaluation of its
 
surveillance data from the Reactor Vessel Surve illance Program is correct. The fact that the measured decreases in USE were consistently less than RG 1.99 projections and measured
 
RT NDT increases were within one standard deviation of the RG 1.99 projections indicated that SSES's surveillance data testing results are consistent with industry OE.
 
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.1.2.41, Commitment No. 18, the applicant provided the UFSAR supplement for the Reactor Vessel Surveillance Program. The staff reviewed this
 
section and determines that the information in the revised UFSAR supplement is an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of the audit and review of the applicant
=s Reactor Vessel Surveillance Program, the staff determines that those program elements, for which the applicant claimed consistency with the GALL Report are consistent. The staff concludes that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended 3-149 function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this
 
AMP and concludes that it provides an adequate summary description of the program, as
 
required by 10 CFR 54.21(d).
 
3.0.3.2.13 Buried Piping and Tanks Inspection Summary of Technical Information in the Application. LRA Section B.2.30 describes the new Buried Piping and Tanks Inspection Program as consistent with GALL AMP XI.M34, "Buried
 
Piping and Tanks Inspection," with exceptions. This program is used to manage external
 
corrosion of buried piping and tanks by use of external coating where appropriated combined
 
with visual inspections of the external surfaces. The applicant stated that for tank bottoms, there
 
will be a one-time inspection to ensure that corrosion of the tank bottom is not occurring by
 
contact with soil.
 
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also confirmed that the plant program contains all of the elements of the
 
referenced the GALL Report program. Onsite interviews were also held to confirm these results.
 
The staff reviewed the exceptions to determine whether the AMP, with the exceptions, will be
 
adequate to manage the aging effects for which the LRA credits it .
 
Exception1
 
The applicant stated an exception to the "scope" program element, stating, in addition to steel (which includes cast iron) piping components and steel tanks, the scope of program includes
 
stainless steel piping components. The GALL AMP only considers steel piping and will be
 
updated to include additional materials in the next revision of GALL. Recent LRA reviews have shown that additional materials should be included in this AMP such as stainless steel, AL6XN
 
specialty steel, titanium alloys, aluminum alloys, and copper alloys. The staff noted that the
 
based on the applicant's plant-specific operating experience that uncoated stainless steel buried
 
piping has not experienced degradation. However the applicant has conservatively added the
 
buried stainless steel piping with-in the scope of this program to ensure that degradation has not
 
occurred. The staff noted that a visual inspection that will be performed by applicant on the
 
buried stainless steel piping with in 10-years of entering the period of extended operation will be
 
capable of detecting age-related degradation as a result of loss of material, consistent with the
 
GALL recommendations. The American Water Works Association standard for stainless steel
 
piping is AWWA C220, "Stainless Steel Piping." On the basis of its review, the staff finds the
 
applicant has conservatively included stainless steel piping in the scope of this program to be
 
inspected with in 10 years of entering the period of extended operation and that a visual
 
inspection of the external surface will be capable of detecting loss of material, and therefore this
 
exception is acceptable.
 
The applicant stated an exception to the "prev entive actions" program element, stating the buried fire protection piping components and the buried stainless steel piping components in the
 
Condensate Transfer and Storage System are not provided with any special coatings or wrappings in accordance with plant design specifications and consistent with plant operating
 
experience. The applicant stated in the LRA that buried piping in the Fire Protection System is
 
constructed using cast iron and ductile iron. It is not coated per the plant design specifications.
 
However the staff did not agree with the applicant for not coating this buried pipe, and has
 
issued RAI B.2.30-1 in a letter dated June 13, 2008, to investigate this staff concern. The 3-150 RAI B.2.30-1 stated that the GALL Report has certain requirements for coating buried piping and questioned the applicant's decision not to coat the cast iron and ductile iron fire protection
 
piping. By a letter dated July 14, 2008, the applicant responded to this RAI stating that the
 
National Fire Protection Association guidance in NFPA-24 only requires protective coatings of
 
ductile iron or cast iron piping when the piping is buried in aggressive soil. The applicant claimed
 
that the soil at SSES is non-aggressive (Chlorides less than 500 ppm, Sulfates less than 1500
 
ppm, and pH greater than 5.5). The staff does not agree with this response because the
 
definition for non-aggressive in the applicant's response is for steel reinforcing bar in sub surface
 
concrete and is not applicable to buried ductile iron or cast iron piping. In a letter dated
 
November 17, 2008, the applicant revised the response to RAI B.2.30-1. In the revised
 
response, the applicant agreed to conduct an opportunistic inspection of the buried stainless
 
steel and cast iron buried piping prior to entering the period of extended operation. Because this
 
will confirm that there is no loss of material for stainless steel and carbon steel piping, or if loss
 
of material is identified, the applicant will initiate corrective action, the staff finds that this is
 
acceptable.
 
Exception 2
 
LRA Section 3.3.4.1.13 states that the Fire Protection System piping will be inspected as part of
 
the Selective Leaching Inspection Program. However, the applicant's Buried Piping and Tanks
 
Inspection Program did not mention this. Therefore, the staff issued RAI B.2.30-2 in a letter
 
dated June 13, 2008, to follow up on this issue. In the applicant's response to the RAI in the
 
letter dated July 14, 2008, the applicant amended the Buried Piping and Tanks Inspection
 
Program to clarify that loss of material due to selective leaching for buried cast iron components
 
is managed by the Selective Leaching Inspecti on Program. This amendment satisfactorily addresses the staff's concern, and this item is closed.
 
By letter dated June 13, 2008, the staff asked the applicant if there was any uncoated carbon
 
steel piping in the fire protection system. By letter dated July 14, 2008, the applicant responded
 
that there is no uncoated carbon steel piping in the fire protection system. The staff finds that
 
because there is no uncoated carbon steel piping in the fire protection system, this issue is
 
resolved.
 
The staff reviewed those portions of the applicants Buried Piping and Tanks Inspection Program that the applicant claimed consistency with GALL AMP XI.M34 and found they are consistent
 
with this GALL AMP. On the basis of the review, the staff concludes that the applicant's Buried
 
Piping and Tanks Inspection Program provides assurance that either the aging effect is indeed
 
not occurring, or that the aging effect is occurring very slowly as not to affect the intended
 
function of the component or structure. The staff finds the applicant's Buried Piping and Tanks Inspection Program acceptable because it conforms to the recommended GALL AMP XI.M34, Buried Piping and Tanks Inspection Program consistent with program elements of GALL AMP XI.M34, with acceptable exceptions, and therefore acceptable
 
Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.30.
Additionally, the staff reviewed a sample of condition reports, 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. In the application, the applicant stated that
 
there is no operating experience with the effectiveness of the program because it is a new
 
program.
 
The applicant stated that the Buried Piping and Tanks Inspection is a new program for which 3-151 there is no operating experience and that inspection methods will be consistent with accepted industry practices. For this program and for other new AMPs where the applicant provided no
 
current plant-specific operating experience, the staff issued RAI B.2.1 asking that the applicant
 
commit to provide documentation of plant-specific operating for staff review after the program
 
has been implemented, but prior to entering the period of extended operation.
 
In its letter dated July 8, 2008, the applicant stated that operating experience for new aging
 
management programs described in LRA Appendix B will be gained as these new programs are implemented during the period of extended operation. The applicant stated that results of tests, inspections, and other aging management activities conducted in accordance with these
 
programs will be subject to confirmation and corrective action elements of the Susquehanna
 
10 CFR 50, Appendix B, Quality Assurance program and that results will be subject to NRC
 
review during regional inspections under existing NRC inspection modules. The applicant stated
 
that these new programs will be implemented prior to, and continue through, the period of
 
extended operation and that operating experience w ill be gained for these programs as they are implemented. The applicant further stated that test and inspection results that do not meet
 
acceptance criteria for these new programs will be evaluated under the station's corrective action program, which includes requirements for identification of appropriate corrective actions
 
and verification of the effectiveness of corrective actions.
 
The staff noted that the applicant's statement that inspection methods will be consistent with
 
industry practices is consistent with the "operating experience" program element for GALL AMP XI.M34. The staff also noted that post-approval site inspections provide an opportunity for staff review and assessment of the effectiveness of the applicant's Buried Piping and Tanks
 
Inspection Program after the applicant has developed operating experience with that program.
 
The staff concludes that the corrective action program, based on internal and external plant
 
operating experience, would capture operating experience in the future to support the
 
conclusion that the effects of aging are adequately managed. On this basis, 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 and concludes that a separate commitment is
 
not necessary.
 
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.1.8, Commitment No. 26, the applicant provided the UFSAR Supplement for the Buried Piping and Tanks Inspection Program. The staff reviewed
 
this section and determined that the information in the UFSAR Supplement does provide an
 
adequate summary description of the program consistent with the SRP-LR. The UFSAR
 
Supplement does cite the commitment (Commitment No. 26) to implement the program, and it does mention that the program must be implemented prior to the period of extended operation.
 
By letter dated June 13, 2008, the staff issued RAIs on the need to coat ductile iron and cast
 
iron piping, the need to mention that ductile iron and cast iron piping are included in the
 
Selective Leaching Inspection Program, and whether or not there is any uncoated carbon steel
 
piping in the fire protection system. By letters dated July 14, 2008 and November 17, 2008, the
 
applicant provided responses to these RAIs that the staff finds to be acceptable. 
 
3-152 The staff determines 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 the review of the applicant's Buried Piping and Tanks Inspection Program the staff determines that those program elements for which the applicant claimed
 
consistency with the GALL Report are consistent.
In addition, the staff reviewed the exceptions and their justifications and determined that the AMP, with the exceptions, is adequate to
 
manage the aging effects for which the LRA credits it. The staff concludes that the applicant has
 
demonstrated that the effects of aging will be adequately managed, so that the intended
 
functions of these components will be maintained consistent with the CLB for the period of
 
extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR
 
supplement for this AMP and concludes that it provides an adequate summary description of the
 
program, pending resolution of the open item, as required by 10 CFR 54.21(d).
 
3.0.3.2.14  System Walkdown Program Summary of Technical Information in the Application. LRA Section B.2.32 describes the existing System Walkdown Program as consistent with GALL AMP XI.M36 "External Surfaces Monitoring" with enhancements to the program el ements, "scope of program" and "detection of aging effects." 
 
The applicant's program is a condition monitoring program that manages for aging effects of
 
external surfaces and in some cases, internal surfaces, by observations and surveillance
 
activities for mechanical components in the scope of license renewal. The applicant states that
 
the System Walkdown Program will manage loss of material for metals in indoor/outdoor air and
 
ventilation environments and cracking and/or change in material properties for elastomers and
 
polymers exposed to indoor air or ventilation environments.
 
By letter dated August 12, 2008, October 21, 2008 and November 11, 2008 the applicant
 
amended its LRA to include additional enhancements and exceptions to the AMP B.2.32, Systems Walkdown Program.
 
Staff Evaluation. During the 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 is adequate to manage the aging effects for
 
which the LRA credits it. The staff's summary of its onsite review of AMP B.2.32, System
 
Walkdown Program, is documented in the staff's audit report. 
 
In comparing the seven (7) programs elements in the applicant's program to those in  GALL AMP XI.M36, the staff noted that the program elements in the applicant's AMP claimed to be consistent with GALL were consistent with the corresponding program element criteria
 
recommended in the program elements of GALL AMP XI.M36 with the exception of three (3) program elements: scope of program, detection of aging effects and OE, that the staff felt there
 
was a need for additional clarification and for which RAIs were issued. The "operating
 
experience" program element is discussed separately below.
 
The applicant states in LRA Section B.2.32 that this AMP will be credited to manage cracking
 
and/or change in material properties for elastomers and polymers that are exposed to indoor air and ventilation. The staff noted that GALL AMP XI.M36 "External Surfaces Monitoring" is only
 
applicable for steel components for loss of material and leakage. Therefore, by letter dated
 
July 10, 2008 the staff issued RAI B.2.32-4 requesting the applicant to justify the basis for 3-153 crediting the System Walkdown Program to manage cracking and changes to material properties for elastomer and polymer components. The applicant responded to RAI B.2.32-4 by
 
letter dated August 12, 2008. In its response, the applicant amended the LRA to include
 
exceptions and enhancements that were not prev iously identified in the LRA to address RAI B.2.32-4. The staff determined that the applicant has addressed RAI B.2.32-4.. 
 
In AMP B.2.19 the applicant states that paints, coatings, sealants and caulking will be monitored
 
under the Systems Walkdown Program. Upon the staff's review of LRA section B.2.32 and
 
associated plant basis documents, the staff noted that these materials were not included into
 
the scope of program for B.2.32. Therefore by letter dated July  10, 2008, the staff issued
 
RAI B.2.32-3 requesting the applicant clarify whether paints, coatings, sealants and caulking are
 
within the scope of AMP B.2.32 and if so, to clarify the inspection techniques that will be
 
credited to monitor for applicable aging effects. The applicant responded to RAI B.2.32-3, by
 
letter dated August 12, 2008. In its response letter the applicant stated that paints, coatings, sealants and caulking are not credited for preventing or mitigating the effects of aging and do
 
not perform an intended function as part of license renewal. The staff noted that since the
 
applicant does not credit these design features for aging management they are not required to
 
manage the aging effects that may affect paints, coating, sealants and caulking as part of
 
license renewal. However the applicant referred to its response to RAI B.2.19-1, which stated
 
that structural sealants and caulking are inspected as part of the Structural Monitoring Program.
 
The staff confirmed that sealants and caulking are inspected by the Structural Monitoring
 
Program for the Condensate and Refueling Water Storage Tanks. The staff noted that visual
 
inspections of the condition of paints and coatings on the external surfaces of the Condensate
 
and Refueling Water Storage Tanks will be a sign if degradation and corrosion maybe occurring
 
on the underlying material, but paints and coatings are not credited. Based on its review, the
 
staff finds the applicant's response acceptable because (1) the applicant has not credited paints
 
and coatings with preventing and mitigating aging of the underlying materials, and therefore
 
does not require aging management (2) the applicant will perform periodic visual inspections of
 
the external surfaces of the tanks, including paints and coatings, to determine the condition of
 
the underlying metallic material (3) the staff confirmed that sealants and caulking are inspected
 
and monitored by the Structures Monitoring Program.
 
Exception
 
The applicant responded to RAI B.2.32-4, by letter dated August 12, 2008. In its
 
response the applicant amended the LRA Section B.2.32 to include an exception to GALL AMP XI.M36. This exception was in regard to the addition of elastomer and
 
polymer components to the scope of the applicant's program. During its review the staff
 
also noted that the applicant had included stainless steel, copper alloy and aluminized
 
steel into the scope of its program; however, GALL AMP XI.M36 only recommends this program perform visual inspections on carbon steel components. Therefore by letter
 
dated October 17, 2008 the staff issued RAI B.2.32-5 requesting the applicant to justify
 
why the expansion in-scope of materials was not considered an enhancement and to
 
justify the basis for expanding the scope of materials. Also, by letter dated
 
October 17, 2008 the staff issued RAI B.2.32-4R requesting the applicant to clarify why the exception above was not identified as an enhancement to the GALL AMP XI.M36.
 
By letter dated November 11, 2008 the applicant responded to RAI B.2.32-5 by stating
 
that the expansion in the scope of metallic materials will be considered an exception and enhancement to GALL AMP XI.M36. The following exception was based on the
 
applicant's response to the staff's RAI B.2.32-4 and B.2.32-5:
 
3-154 Scope of Program, Parameters Monitored/Inspected, Detection of Aging Effects, Monitoring and Trending -
 
Elastomers and polymers are included within the scope of the Systems
 
Walkdown Program. The program is credited with managing cracking and
 
change in material properties for elastomers and polymers exposed to indoor air
 
or ventilation environments.
 
Copper alloy and stainless steel are included within the scope of the System
 
Walkdown Program. The program is credited with managing loss of material for
 
copper alloy and stainless steel exposed to indoor air, outdoor air or ventilation
 
environments.
 
The applicant responded to RAI B.2.32-4R and RAI B.2.32-5, by letter dated
 
November 11, 2008. In its response to RAI B.2.32-4R the applicant stated that the
 
expansion in the scope of materials for this program is considered an exception and
 
enhancement. The staff's evaluation of this exception and enhancement were
 
performed separately and are documented in this section of the SER. The staff noted
 
that the applicant has committed, by Commitment No. 28 as amended by letter dated
 
November 11, 2008, to enhance its program prior to the period of extended operation to
 
generate a routine activity to supplement the current existing plant program to include a
 
supplemental physical manipulation and/or prodding to inspect elastomer and polymer
 
components. The applicant stated in response to RAI B.2.32-4R that evidence of
 
chalking, cracking, crazing, discoloration and any physical distortion has occurring. The
 
staff noted that for the supplemental physical manipulation the applicant will identify
 
hardening, lack of resiliency, surface film or residue and unusual odors. The staff further
 
noted that any signs of the degradation identified by the visual inspection or physical
 
manipulation will be evaluated. The staff noted t hat the physical manipulation will aid the visual inspection in detecting age-related degradation because changes in material
 
properties and cracking can be detected during manipulation of elastomeric and
 
polymeric components by the relative inflexib ility of the component, or by the failure of the component to return to its previous shape or configuration. On the basis of its
 
review, the staff finds that the applicant will be capable of managing the effects of aging
 
for elastomers and polymers because the applicant (1) is crediting a visual examination
 
of elastomer and polymers and an inspection technique that includes physical
 
manipulation and/prodding of the components, which are capable of detecting the aging
 
effects of cracking and/or change in material properties and (2) any signs of degradation
 
will be evaluated by the applicant and addressed as part of their corrective actions
 
program.
 
In its response to RAI B.2.32-5 the applicant stated that for the aging effect and aging
 
mechanisms of concern, which include loss of material due to pitting, crevice and
 
galvanic corrosion, for copper alloy and stainless steel are similar to carbon steel, such
 
that a visual inspection will be effective in identifying loss of material. The applicant
 
stated that aluminized steel is considered to be equivalent to steel because the
 
aluminum coating is not credited. The staff determined that since the applicant does not
 
credit the aluminum coating, aluminized steel is equivalent to steel and does not need to
 
be includes in the expansion in the scope of materials. The staff noted that metallic
 
components, including copper alloy and stainless steel, would exhibit indications of loss
 
of material on the surface similar to steel and a visual inspection will be capable of
 
detecting age related degradation. The applicant further stated that the parameters 3-155 monitored by the visual inspection will include: corrosion, wastage of material, leakage to and from external surfaces, worn/flaking/oxide-coated surfaces, corrosion stains and
 
coating degradation. Furthermore, any signs of degradation that is present will be
 
evaluated to determine if the components are acceptable for continued operation. On the
 
basis of its review, the staff finds the applicant's response acceptable because (1) the
 
applicant will be performing visual inspections that are capable of detecting loss of
 
material in metallic components as they display indications of degradation similar to steel, for which GALL AMP XI.M36 was intended and (2) any signs of degradation will
 
evaluated.
 
On the basis of its review of the LRA and the applicant's responses to RAI B.2.32-4, RAI B.2.32-4R and RAI B.2.32-5, the staff finds the applicant's exception acceptable
 
because (1) the applicant will perform visual inspections during system walkdowns that
 
will be effective in identifying loss of material in other metallic components which exhibit
 
indications of degradation similar to steel, (2) the applicant will supplement the visual
 
inspection with a physical manipulation and/or prodding, which are adequate techniques
 
to detect change in material properties and cracking in elastomers and polymers (3) and
 
any degradation will be evaluated to ensure these metallic and non-metallic
 
components are acceptable for continued operation.
 
In its response to RAI B.2.32-5 the applicant stated that for the aging effect and aging
 
mechanisms of concern, which include loss of material due to pitting, crevice and
 
galvanic corrosion, for copper alloy and stainless steel are similar to carbon steel, such
 
that a visual inspection will be effective in identifying loss of material. The applicant
 
stated that aluminized steel is considered to be equivalent to steel because the
 
aluminum coating is not credited. The staff determined that since the applicant does not
 
credit the aluminum coating, aluminized steel is equivalent to steel and does not need to
 
be includes in the expansion in the scope of materials. The staff noted that metallic
 
components, including copper alloy and stainless steel, would exhibit indications of loss
 
of material on the surface similar to steel and a visual inspection will be capable of
 
detecting age related degradation. The applicant further stated that the parameters
 
monitored by the visual inspection will include: corrosion, wastage of material, leakage to
 
and from external surfaces, worn/flaking/oxide-coated surfaces, corrosion stains and
 
coating degradation. Furthermore, any signs of degradation that is present will be
 
evaluated to determine if the components are acceptable for continued operation. On the
 
basis of its review, the staff finds the applicant's response acceptable because (1) the
 
applicant will be performing visual inspections that are capable of detecting loss of
 
material in metallic components as they display indications of degradation similar to steel, for which GALL AMP XI.M36 was intended and (2) any signs of degradation will
 
evaluated.
 
On the basis of its review, the staff finds the applicant's exception acceptable because
 
the applicant will perform visual inspections during system walkdowns that will be
 
effective in identifying loss of material in other metallic components which exhibit
 
indications of degradation similar to steel and any degradation will be evaluated to
 
ensure these components are acceptable for continued operation.
 
Enhancement 1
 
In LRA Section B.2.32 the applicant states that the program element "scope of program" for the System Walkdown Program must be enhanced in order to be consistent with GALL XI.M36, 3-156 "External Surfaces Monitoring." By letter dated November 11, 2008 the applicant amended the LRA to include additional information to this enhancement. The applicant's enhancement to the
 
scope of program is as follows:
 
Scope of Program
 
The governing procedure for the System Walkdown Program must be revised to
 
add the listing of systems crediting the program for license renewal, and to
 
explicitly include other metals, copper alloy and stainless steel. A routine activity
 
to supplement the existing plant program must be generated to inspect
 
elastomers and polymers. 
 
In the program element "scope of program" for GALL XI.M36 "External Surfaces Monitoring", external surfaces are to be visually inspected components within scope. The additional
 
information in this enhancement, in regards to the additional metallic components and
 
elastomers, is evaluated by the staff in Exception #1 and Enhancement #4 in this section of the
 
SER. The staff reviewed LRA Section B.2.32 and finds the applicant's enhancement acceptable
 
because the applicant's procedure will be updated to include all systems that have credited this program for aging management based on the recommendations of GALL XI.M36. On the basis
 
of its review, as described above, the staff concludes that this enhancement is acceptable.
 
Enhancement 2
In LRA Section B.2.32 the applicant states that the program element "detection of aging effects"
 
for the System Walkdown Program must be enhanced in order to be consistent with GALL XI.M36. By letter dated October 21, 2008, the applicant amended its LRA based on a License
 
Renewal Regional Inspection, and in this amendment the applicant provided additional details
 
to this enhancement. The applicant's enhancement to the detection of aging effects is as follows
 
Detection of Aging Effects 
 
All of the systems to be added to the procedure contain mechanical components
 
whose external surfaces require aging management during the period of
 
extended operation. It may be determined by engineering evaluation that these
 
components do not require monitoring every two weeks, and the basis for a
 
different walkdown frequency may be documented on the appropriate procedure
 
form.
 
The governing procedure for the System Walkdown Program must be enhanced
 
to address the license renewal requirement for opportunistic inspections of
 
normally inaccessible components (e.g., those that are insulated), and those that
 
are accessible only during refueling outages.
 
For underground vaults, an initial sample of at least one vault/pit/manhole from
 
each grouping of components with identical material and environment
 
combinations will be inspected prior to entering the period of extended operation.
 
A representative sample of the entire population will be inspected within the first 6
 
years of the period of extended operation. Results of the inspection activities that
 
require further engineering evaluation/resolution (e.g., sample expansion and
 
inspection frequency changes if degradation is detected), if any, will be evaluated
 
using the corrective action process.
3-157  Based on its review, the staff determined additional information was needed to complete its
 
review that relates to the systems that will be added to the scope of the AMP B.2.32, the current
 
frequency of inspections, and the basis for changing the frequency. Therefore, by letter dated
 
July 10, 2008 the staff issued RAI B.2.32-2 requesting the applicant to identify the systems that
 
are within the scope of the AMP B.2.32 that are subject to the enhancements, to clarify the
 
current frequency of system walkdowns for different plant systems that are within the scope of
 
AMP B.2.32, and to provide the basis for changing the frequency of system walkdowns and
 
clarify the process used for changing these frequencies. The applicant responded to
 
RAI B.2.32-2, by letter dated August 12, 2008. The applicant provided a listing of the systems
 
that would be affected by this enhancement as requested by the staff. The applicant also
 
provided the frequency of walkdowns that are applicable to the scope of systems managed by this program. The staff noted that the frequencies being utilized by the applicant are consistent
 
with those recommendations provided in GALL AMP XI.M36, which are walkdowns that exceed once per refueling cycle for accessible locations, for locations inaccessible during normal plant
 
operation inspections are performed during the refueling outage, and for those locations that are
 
inaccessible during refueling outages and normal plant operation inspections will be performed
 
opportunistically. As stated in the "detection of aging effects" program element in the GALL
 
Report, the inspection frequency may be adjusted as needed based on the plant-specific
 
inspection results and industry experience. The applicant's proposal to adjust the inspection
 
frequency is consistent with the recommendations in the GALL Report, and is subject to an
 
engineering evaluation, approval by engineering supervision and is subject to a 10 CFR 50.59
 
review to determine if prior NRC approval is required for any frequency change. The applicant's
 
amendment that was provided by letter dated Oc tober 21, 2008 provided details on inspections that will be performed before and after the period of extended operation on those normally
 
inaccessible components that require opportunistic inspections, specifically samples of
 
underground vaults. The staff noted for these normally inaccessible locations, the applicant has
 
committed to inspect an initial sample before the period of extended operation and again within
 
6 years after the start of the period of extended operation. The staff further noted that the
 
applicant's approach is conservative because it requires the inspection at least within 6 years
 
after entering the period extended operation compared to an opportunistic inspection that may
 
potentially exceed 6 years. Based on its review, the staff finds the applicant's response and
 
enhancement acceptable because (1) the applicant's inspection frequency is consistent with the recommendations provided in GALL AMP XI.M36 (2) the applicant's ability to change the
 
inspection frequency of walkdowns is subject to a 10 CFR 50.59 review and (3) for underground
 
vaults the applicant's commitment to perform inspections in a specified time frame that is
 
conservative compared to a strictly opportunistic inspection.
 
On the basis of its review as described above, the staff concludes the applicant's enhancement
 
when implemented prior to the period of extended operation is acceptable.
 
Enhancement 3
 
By letter dated October 21, 2008, the applicant amended the LRA to provide an additional
 
enhancement. The applicant's enhancement to the detection of aging effects program element
 
is as follows:
 
Detection of Aging Effects
 
Also, within the 10 year period prior to the period of extended operation a visual
 
inspection and ultrasonic inspection of external surfaces of piping passing into 3-158 structures through penetrations (underground piping) will be performed, for those penetrations with a history of leakage. These inspections will be focused on
 
penetrations that are leaking at the time and will include a representative sample
 
of each material, environment combination from those piping systems within the
 
scope of license renewal (which includes those for the RHRSW, ESW, and Fire
 
Protection systems) that enter structures below grade.
 
The staff noted that the applicant has committed to perform a visual inspection of
 
external surfaces of piping passing into structures through penetrations (underground
 
piping) and in addition the applicant will conservatively perform an ultrasonic inspection
 
to identify degradation. Furthermore, the applicant committed to perform these
 
inspections prior to entering the period of extended operation to ensure detection of
 
degradation prior to component intended function being lost. The staff noted the
 
applicant's commitment, captured in Commitment No. 28, will require inspections of
 
these areas prior to the period of extended operation to ensure that degradation, if any, is
 
detected and corrected by the corrective actions program prior to entering the period of
 
extended operation. On the basis of its review, the staff finds the applicant's
 
enhancement acceptable because (1) the applicant will be performing a visual inspection
 
of the external surfaces of piping that enter structures below grade, which is consistent with the recommendations in GALL AMP XI.M36 and (2) the applicant will conservatively
 
perform an ultrasonic inspection in addition to the visual inspection to assist in the
 
detection of any degradation in those penetrations that are leaking and with a history of
 
leakage.
 
On the basis of its review, as described above and the applicant's enhancements when
 
implemented prior to the period of extended operation will make the applicant's Systems Walkdown Program consistent with the recommendations provided by GALL AMP XI.M36.
 
Enhancement 4
 
The applicant responded to RAI B.2.32-4, by letter dated August 12, 2008. In its response the
 
applicant amended the LRA Section B.2.32 to include the following enhancement, and
 
subsequently amended by letter dated November 11, 2008 to provide additional details:
 
Parameters Monitored/Inspected
 
A routine activity must be generated, and based at least in part on EPRI
 
1007933, "Aging Assessment Field Guide", to inspect elastomers and polymers
 
for cracking and/or change in material properties. Evidence of surface
 
degradation, such as cracking, or discoloration, as well as physical manipulation
 
and/or prodding, will be used as measures of material condition.
 
The staff noted that the applicant has expanded the scope of its System Walkdown Program to include elastomer and polymer components. The staff further noted that a visual inspection
 
alone would not have been capable of detecting aging effects such as cracking and/or change
 
in material properties for elastomers and polymers. Based on the applicant's amendment to
 
include this enhancement the staff noted that the applicant will not only utilize a visual
 
inspection for evidence of degradation, noticeable cracking or discoloration, but the applicant
 
will be supplementing the visual inspection with an appropriate physical manipulation and/or
 
prodding of the component. However, the staff felt that additional information was needed;
 
therefore, by letter dated October 17, 2008 the staff issued follow-up RAI B.2.32-4R Part B 3-159 requesting the applicant to clarify the acceptance criteria for the supplemental physical manipulation and/or prodding of polymers and elastomers. By letter dated November 11, 2008
 
the applicant responded to RAI B.2.32-4R by stating that the visual inspection of the elastomers
 
will determine if such things as chalking, cracking, crazing, discoloration and any physical
 
distortion is occurring. The staff noted that for the supplemental physical manipulation the
 
applicant will identify hardening, lack of resiliency, surface film or residue and unusual odors.
 
The staff further noted that any signs of the degradation identified by the visual inspection or
 
physical manipulation will be evaluated. The staff noted that the physical manipulation will aid the visual inspection in detecting age-related degradation because changes in material
 
properties and cracking can be detected during manipulation of elastomeric and polymeric
 
components by the relative inflexibility of the co mponent, or by the failure of the component to return to its previous shape or configuration. On the basis of its review, the staff finds that the
 
applicant will be capable of managing the effects of aging for elastomers and polymers because
 
the applicant (1) is crediting a visual examination of elastomer and polymers and an inspection
 
technique that includes physical manipulation and/prodding of the components, which is
 
capable of detecting the aging effects of cracking and/or change in material properties and (2)
 
any signs of degradation will be evaluated by the applicant and addressed as part of its
 
corrective actions program.
 
On the basis of its review, the staff finds the applicant's enhancement acceptable
 
because the applicant will perform visual inspections and a physical manipulation during
 
system walkdowns that will be effective in identifying change in material properties and 
 
cracking for elastomer and polymer components and any degradation will be evaluated
 
to ensure these components are acceptable for continued operation.
 
Enhancement 5
 
The applicant responded to RAI B.2.32-4 by letter dated August 12, 2008. In its
 
response the applicant amended the LRA Section B.2.32 to include the following
 
enhancement, which was supplemented by a letter dated November 11, 2008 to
 
indicate the specific routine activity:
 
Detection of Aging Effects
 
The routine activity to inspect elastomers and polymers, to include physical
 
manipulation and/or prodding, will be based on inspection of a representative
 
sample of components. The sample will be determined by engineering
 
evaluation with a focus on components considered to be most susceptible to
 
aging, such as due to their time in service, the severity of conditions during
 
normal plant operation, and any pertinent design margins.
 
The staff noted that the applicant is selecting a representative sample of elastomer and polymer
 
components. The applicant stated that this representative sample will be based on an
 
engineering evaluation which takes into consideration which components may be more
 
susceptible to aging. The staff further noted that such conditions as the amount of time the
 
component has been in service, the severity of the conditions and environments that the
 
component is exposed to during normal plant operation and other relevant design margins that
 
may be applicable are factored in as part of the applicant's engineering evaluation to select
 
components for the routine activity to inspect elastomers and polymers. 
 
3-160 On the basis of its review, the staff finds that the applicant's enhancement acceptable because (1) the applicant's representative samples of elastomer and polymer components for inspection
 
will be based on selecting those components that are more susceptible and likely to experience
 
age-related degradation and (2) the applicant will supplement its visual inspection with a
 
physical manipulation and/or prodding which will be capable of detecting cracking and/or
 
change in material properties in elastomers and polymers as discussed in Enhancement #4.
 
Operating Experience
. The staff also reviewed the applicant's OE described in the applicant's license renewal basis document for the System Walkdown Program. The staff noted during its review of the license renewal plant basis documents for this program, which the applicant
 
reviewed its plant OE action requests and condition reports for the most recent five-year period.
 
From the applicant's review of its database, it was revealed that leakage, damage, and
 
degradation are routinely identified by this program. The staff noted that subsequent to
 
identifying an issue with this program, corrective actions were taken in a timely manner, and a
 
loss of pressure boundary integrity did not occur due to aging effects that are within the scope
 
of this program. However, the staff felt that additional information was needed to complete its
 
review; therefore, by letter dated July  10, 2008 the staff issued RAI B.2.32-1 requesting the
 
applicant to identify the plant systems within the scope of this program that have had problems with age-related degradation and to also identify the specific age-related degradation that was
 
occurring in each instance. The staff further asked the applicant to clarify if the age-related
 
degradation has had any impact on the program's ability to manage aging and if the program
 
will need to be augmented or enhanced to ensure adequate aging management of these
 
systems. Finally, the staff asked the applicant to identify the corrective actions that were taken
 
to correct these issues associated with the problems in the plant systems in the scope of this
 
program.
The applicant responded to RAI B.2.32-1, by letter dated August 12, 2008. In this letter, the applicant stated that as part of the preparation of the LRA, a plant-specific search of Action
 
Requests and Condition Reports was performed of the most recent 5-year period for OE. The
 
applicant provided several examples of OE and the corrective actions that were taken in
 
response to the action request or condition report. The staff noted that one of the examples
 
provided by the applicant indicated the Instru ment Air piping had a crack downstream of an isolation valve. The applicant took corrective actions and replaced the cracked section of pipe.
 
Another example provided by the applicant indica ted that the enamel/wrap coating that normally protects the piping for the Circulating Water System was severely degraded on the piping that
 
extends above the ground near the base of the cooling towers. The applicant noted that the
 
portions of the pipe that had been exposed due to the coating degradation were corroded. The
 
staff noted that based on this discovery of the degraded coating and corroded piping the
 
applicant initiated corrective actions to take UT measurements of the piping to ensure that there
 
was sufficient and proper wall thickness before the piping was re-coated. As an added measure, the applicant excavated the buried portions of the corroded piping to ensure that the coating
 
was intact and that wall thinning and corrosion was not occurring in the buried portion of this
 
piping during the refueling outage that followed the initial discovery. Based on the staff's review
 
of the applicant's response and the OE that was provided, the staff finds the applicant's
 
response acceptable because the applicant's program was capable of detecting degradation
 
bounded by industry experience and then initiated corrective actions to resolve the discovered
 
degradation.
 
The staff confirmed that the "operating" experi ence" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds the program
 
element acceptable.
3-161  UFSAR Supplement. The staff reviewed the UFSAR Supplement summary description that was provided in LRA Section A.1.2.47, Commitment No. 28, for the System Walkdown Program. The staff verified that, in LRA Commitment No. 28 of UFSAR Supplement Table A-1, the applicant
 
committed to enhancing its program prior to the period of extended operation. By letters dated
 
August 12, 2008, October 21, 2008 and November 11, 2008, the applicant amended the LRA
 
include additional enhancements to AMP B.2.32. The staff confirmed the applicant amended
 
LRA Section A.1.2.47 and Commitment No. 28 to include a brief description of these
 
enhancements and has committed to implement these enhancements prior to the period of
 
extended operation. The staff also verified that the applicant has placed this commitment in
 
UFSAR Supplement summary description A.1.
2.47 for the System Walkdown Program. 
 
Based on this review, the staff finds that UFSAR Supplement Section A.1.2.47 provides an
 
acceptable UFSAR Supplement summary descr iption of the System Walkdown Program because it is consistent with those UFSAR Supplement summary descriptions in the SRP-LR
 
and because the summary description includes the bases for determining that aging effects will
 
be managed. The staff determines 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 the audit and review of the applicant's System Walkdown Program, the staff determines that those program elements for which the applicant claimed consistency
 
with the GALL Report are consistent. In addition, the staff reviewed the exception and its
 
justification and determines that the AMP, with the exception, is adequate to manage the aging
 
effects for which the LRA credits it. Also, the staff reviewed the enhancements and confirmed
 
that they will be implemented through Commitment No. 28 prior to the period of extended
 
operation. The staff concludes that the applicant has demonstrated that the effects of aging will
 
be adequately managed so that the intended function(s) will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.15  Lubricating Oil Analysis Program 
 
Summary of Technical Information in the Application. LRA Section B.2.33 of the LRA describes the existing program, "Lubricating Oil Analysis Program." as consistent with the GALL AMP XI.M39, "Lubricating Oil Analysis Pr ogram" with enhancement and exceptions. The LRA states this program is used to mitigate damage in components exposed to lubricating oil due to
 
loss of material and reduction of heat transfer due to fouling. The applicant stated that the
 
program manages the aging effects through monitoring that is consistent with manufacturer's
 
recommendations and standards for lubricating oil from the American Society for Testing of
 
Materials (ASTM). In addition, this program is supplemented with the Lubricating Oil Inspection, a one-time inspection program to verify its effectiveness. 
 
Staff Evaluation. The staff's summary of its onsite review of AMP B.2.33, Lubricating Oil Analysis Program, is documented in staff's audit report. For its onsite review, the staff reviewed
 
and compared the program elements of B.2.33 Lubr icating Oil Analysis Program with its corresponding elements of GALL AMP XI.M39, "Lubricating Oil Analysis Program." 
 
In comparing the seven (7) programs elements in the applicant's program to those in  GALL AMP XI.M39, the staff noted that the program elements in the applicant's AMP claimed to be consistent with the GALL Report were consistent with the corresponding program element 3-162 criteria recommended in the program elements of GALL AMP XI.M39 with the exception of those enhancements and exceptions taken by the applicant that the staff determined there was
 
a need for additional clarification and for which RAIs were issued. The staff reviewed the
 
exceptions and enhancement, to determine whether the AMP with the exceptions and
 
enhancement, is adequate to manage the aging effects for which the LRA credits it. The
 
operating experience program element is discussed separately below.
 
Exception
 
The Lubricating Oil Analysis Program includes two exceptions to the parameters monitored or inspection program element. The first exception is that the program does not perform a particle count on the Emergency Diesel Generator or Residual Heat Removal System pump motor oil
 
samples. Instead, the applicant performs direct read ferrography as stated in LRA section
 
B.2.33. The staff noted that direct read ferrography only measures ferrous particles whereas
 
particle counters measures both ferrous and non-ferrous particles. Thus, aging effects due to
 
non-ferrous particles may not be accounted for by ferrography. By letter dated July  10, 2008
 
the staff issued RAI B.2.33-1 in which the staff requested the applicant to justify why "direct read
 
ferrography" is an acceptable alternative to performance of periodic particular content counting.
 
By letter dated August 12, 2008, the applicant responded to RAI B.2.33-1, in which the applicant
 
stated that it performs a direct read ferrography on the diesel lube oil rather than particle
 
counting because of the way in which particle counting performs the test. The applicant
 
explained that the particle counters utilize optical devices that pass light through the lube oil
 
sample in order to count the particles. The staff noted that diesel lube oil is dark in color, and
 
the use of a particle counter on dark lube oils is difficult unless the sample lube oil is diluted in
 
order to allow more light to pass through the sample oil. The applicant stated that dilution of the
 
sample lube oil would create concerns if the diluents contain any contamination that may skew
 
the results from the particle counting. The staff further noted that the method of direct read
 
ferrography primarily measures the number of ferr ous particles per milliliter of fluid, which is normally due to mechanical wear of the system. The staff further noted that the applicant stated
 
it utilizes a spectrochemical testing which is capable of measuring up to twenty-one different
 
metals less than 10-microns in size. The staff noted that the intent of the recommendation of the GALL AMP XI.M39 to perform particle counting was to reveal abnormal wear rates or excessive corrosion. The staff finds that the applicant's use of direct read ferrography and spectrochemical
 
testing will be capable of revealing abnormal wear rates, excessive corrosion, and detect
 
changing trends in wear debris and contamination. On the basis of its review, the staff finds the
 
applicant's response acceptable as described above.
 
On the basis of its review, the staff finds the applicant's exception acceptable because with the
 
use of direct read ferrography and spectrochemical testing on dark diesel lubricating oil the
 
applicant will be capable of detecting abnormal wear rates, excessive corrosion and detect
 
changing trends in wear debris and contamination, which is consistent with the intent of the particle counting test that is recommended by GALL AMP XI.M39.
 
Exception 2
 
The second exception to this program is it does not determine the flash point for the HPCI, RCIC, or RHR motor oil samples. Instead, the applicant performs direct read ferrography, viscosity, total acid number, water content and metals content as stated in LRA section B.2.33.
 
The staff reviewed this exception and onsite documents for this program. The staff noted that
 
the tests that will be performed in lieu of the flash point testing are acceptable alternatives that
 
would allow the applicant to track the level of contaminants in the oil systems. The staff noted 3-163 that the intent of the GALL AMP XI.M39 is to maintain the oil systems contaminants within acceptable limits, which the applicant will be capable of doing by performing a direct read
 
ferrography, viscosity, total acid number, water content and metals content test. The staff
 
determined that the tests the applicant will be performing are consistent with the intent of GALL AMP XI.M39 and on this basis, the staff finds this exception acceptable. 
 
Enhancement 1
 
The Lubricating Oil Analysis Program includes an enhancement to the scope of the program
 
element. The applicant stated that the program will be enhanced to sample the lubricating oil
 
from the Control Structure Chiller when the oil is changed. 
 
In addition, the applicant further stated that a particle count and a check for water will be
 
performed on the drained oil from the Control Structure Chiller. 
 
As a result of the applicant's response to RAI B.2.25-1, in a letter dated August 12, 2008, the
 
applicant amended LRA Section B.2.33 and Commitment No. 48 so the program will be
 
enhanced to sample the lubricating oil from the Reactor Building Chiller when the oil is changed.
 
In addition, a particle count and a check for water will be performed on the drained oil from the Reactor Building Chiller. The staff noted that the scope of program element of GALL XI.M39
 
states that on a periodic basis, this program samples lubricating oil from plant components
 
subject to aging management review. Upon review of the site documents and the LRA, the staff determines the enhancement is consistent with scope of GALL XI.M39. On this basis, the staff
 
determines this enhancement is acceptable, for the Reactor Building Chiller and Control
 
Structure Chiller.
 
Operating Experience.
The staff also reviewed the operating experience described in LRA Section B.2.33. The applicant indicated that review of SSES operating experience did not reveal
 
a loss of component intended function for components exposed to lubricating oil from
 
inadequacy of the Lubricating Oil Analysis Program. In addition, the LRA stated that abnormal
 
lubricating oil conditions are promptly identified, evaluated, and corrected. The staff reviewed the operating experience identified in the GALL XI.M39 and noted that it states that no
 
instances of component failures from lubricating oil contamination have been identified as well.
 
In addition, the staff reviewed the onsite operating experience data and condition reports and
 
did not find any reports of component failures due to lubricating oil contamination. On this basis, the staff finds the operating experience data acceptable.
 
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.1.2.28, Commitment No. 48, the applicant provided the UFSAR Supplement summarizing the Lubricating Oil Analysis Program. The staff reviewed the
 
section of the UFSAR Supplement and determines that it is an adequate summary description
 
of the program, as required by 10 CFR 54.21(d).
 
The staff reviewed the UFSAR Supplement summary description that was provided in LRA
 
Section A.1.2.28 for the Lubricating Oil Analysis Program. The staff noted that in its response to
 
RAI B.2.25-1 and the associated amendments, the applicant did not amend LRA
 
Section A.1.2.28 to include the Reactor Building Chiller. The staff confirmed that by letter dated
 
September 26, 2008, the applicant amended LRA Section A.1.2.28 to include the Reactor 3-164 Building Chiller. The staff verified that, in LRA Commitment No. 48 of UFSAR Supplement Table A-1, the applicant includes a brief description of the enhancement and committed to
 
enhancing the program to include sampling from the Reactor Building Chiller and the Control
 
Structure Chiller and have the lubricating oils tested for water and for particle count and
 
implementing these enhancements prior to the period of extended operation. The staff also
 
verified that the applicant has placed this commitment on UFSAR Supplement summary
 
description A.1.2.28 for the Lubricating Oil Analysis Program. 
 
Based on this review, the staff finds that UFSAR Supplement Section A.1.2.28 provides an
 
acceptable UFSAR Supplement summary description of the Lubricating Oil Analysis Program
 
because it is consistent with those UFSAR Supplement summary descriptions in the SRP-LR
 
and because the summary description includes the bases for determining that aging effects will
 
be manage. Therefore, the staff concludes that the UFSAR supplement for this AMP provides
 
an adequate summary description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of its audit and review of the applicant's Lubricating Oil Analysis Program, the staff determines that those program elements for which the applicant claimed
 
consistency with the GALL Report are consistent.
In addition, the staff reviewed the exceptions and their justifications and determines that the AMP, with the exceptions, is adequate to
 
manage the aging effects for which the LRA credits it. The staff reviewed the enhancement and
 
confirmed that its implementation through Commitment No. 48 prior to the period of extended
 
operation would make the existing AMP consistent with the GALL Report AMP to which it was
 
compared. In addition, the staff reviewed the applicant's responses to the staff's RAI and its
 
evaluation is documented above. The staff concludes that the applicant has demonstrated that
 
the effects of aging will be adequately managed so that the intended function(s) will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concludes that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.2.16  Masonry Wall Program
 
Summary of Technical Information in the Application. LRA Section B.2.38 describes the existing Masonry Wall Program as consistent, with an enhancement, with the GALL AMP XI.S5, "Masonry Wall Program." This program will manage aging effects so that the evaluation basis established for each masonry wall within the scope of license renewal remains valid through the
 
period of extended operations.
 
The applicant stated that the program includes all masonry walls identified as performing
 
intended functions in accordance with 10 CFR 54.4. Included components are the 10 CFR
 
50.48 required masonry walls, radiation shielding masonry walls, and masonry walls with the
 
potential to affect safety-related components.
 
The applicant further stated that the Masonry Wall Program is implemented as part of the
 
Structures Monitoring Program. Masonry walls are visually examined at a frequency selected to
 
ensure there is no loss of intended function between inspections. 
 
3-165 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, is adequate to manage the aging effects for which it is credited
 
in the LRA.
 
The staff interviewed the applicant's technical staff and reviewed the associated bases documents for the AMP B.2.38 "Masonry Wall Progr am," which provides an assessment of the AMP elements' consistency with GALL AMP XI.S5. 
 
The staff noted that the Masonry Wall Program includes the guidance and lessons learned from
 
Office of Inspection and Enforcement Bulletin 80-11 (Masonry Wall Design, U.S. Nuclear
 
Regulatory Commission, May 8, 1980) and Information Notice 87-67 (Lesson Learned from
 
Regional Inspections of Licensee Actions in Response to IE Bulletin 80-11, U.S. Nuclear
 
Regulatory Commission, December 31, 1987), During the audit and review, the staff asked the
 
applicant for the visual examination frequency for the program and its technical basis. In its
 
response, the applicant stated that the inspection is implemented by the Structures Monitoring
 
Program and consists of visual inspection for cracking in joints, deterioration of penetrations, missing or broken blocks, missing mortar, and general mechanical soundness of steel supports.
 
The applicant also stated that visual inspections are conducted at least every five years to
 
ensure no loss of intended function between inspections. Based upon its review, the staff finds
 
the applicant's Masonry Wall Program, with the enhancement (Commitment No. 33) as described below, consistent with the program elements of GALL AMP XI.S5, "Masonry Wall
 
Program," and therefore acceptable 
 
The staff reviewed the enhancement to determine whether the AMP, with the enhancement, is
 
adequate to manage the aging effects for which it is credited in the LRA.
 
Enhancement
 
LRA Section B.2.38 states an enhancement to the "acceptance criteria" program element of the
 
Structures Monitoring Program procedure to specify that for each masonry wall, the extent of
 
observed masonry cracking and/or degradation of steel edge supports/bracing are evaluated to
 
ensure that the current evaluation basis is still valid. 
 
The staff reviewed the applicant's Masonry Wall Program, the Structures Monitoring Program, and their AERMs under the acceptance criteria program element of the Structures Monitoring
 
Program. The staff noted that visual examination of masonry walls is performed to identify
 
indications of cracking resulting from overstress due to applied loads, shrinkage, temperature
 
effects, or differential movement. Potential design non-conforming conditions identified during
 
the course of an inspection are noted and a condition report is initiated. Corrective actions are
 
taken if the extent of cracking and steel degradation is sufficient to invalidate the evaluation
 
basis. 
 
The responsible engineer identifies problems with structural performance, initiates structural
 
deficiency reports, and recommends corrective action. Acceptance criteria are established such
 
that corrective actions are initiated prior to loss of function. The staff found this enhancement
 
acceptable because when the enhancement is implemented, AMP B.2.38, "Masonry Wall Program," will be consistent with the GALL AMP XI.S5 and provide additional assurance that
 
the effects of aging will be adequately managed.
 
Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.38, 3-166 and "Operation Experience Review Report (Masonry Wall's section)", and interviewed the applicant's technical staff to confirm that the plant-specific OE has been reviewed by the
 
applicant and was evaluated as intended in the GALL Report. During its audit, the staff found
 
some minor indications that did not affect the structural integrity of any of the structures
 
reviewed. Furthermore, the staff confirmed that the applicant had addressed OE identified after
 
the issuance of the GALL Report. The staff finds that the applicant's Masonry Wall Program, with the corrective actions and enhancements discussed in the LRA, has been effective in
 
identifying, monitoring, and correcting the aging effects of masonry walls. The staff also
 
confirmed that plant-specific OE did not reveal any degradation not bounded by industry
 
experience. 
 
The staff confirmed that the A 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.1.2.31, Commitment No. 33, "Masonry Wall Program,"
the applicant provided the UFSAR supplement for the Masonry Wall Program. The staff
 
reviewed this section and determines that the information in the UFSAR supplement is an
 
adequate summary description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of its audit and review of the applicant's Masonry Wall Program, the staff determines that those program elements for which the applicant claimed consistency with
 
the GALL Report are consistent. In addition, the staff reviewed the enhancement and confirmed
 
that its implementation through Commitment No. 33 prior to the period of extended operation
 
would make the existing AMP consistent with the GALL Report AMP to which it was compared.
 
The staff concludes that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended function(s) will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed
 
the UFSAR supplement for this AMP and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.17  Structures Monitoring Program
 
Summary of Technical Information in the Application. LRA Section B.2.39 describes the existing Structures Monitoring Program as consistent, with enhancements, with GALL AMP XI.S6, "Structures Monitoring Program." In the LRA, the applicant stated that the program will manage aging effects such that loss of material, cracking, change of material properties, and loss of form
 
are detected by visual inspection prior to the loss of the structure's or component's intended
 
function(s). The applicant also stated that the program also implements the Masonry Wall
 
Program and the RG 1,127 Water Control Structures Inspection.
 
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 (Commitment No. 34) to determine whether the AMP, with the enhancements, is adequate to manage the aging
 
effects for which it is credited in the LRA. 
 
During its audit, the staff reviewed the applicant's onsite documentation supporting the
 
applicant's conclusion that the program elements are consistent with the elements in the GALL
 
Report. The staff interviewed the applicant's technical staff and reviewed the documents related
 
to the Structures Monitoring Program, including the license renewal program evaluation report in which the applicant assessed whether the program elements are consistent with GALL 3-167 AMP XI.S6. 
 
Enhancement 1
 
LRA Section B.2.39 states an enhancement to the "scope of program" program element in that
 
the Structures Monitoring Program procedure will be enhanced to include additional structures
 
requiring aging management and "structural component" for inspection includes each of the
 
component types identified as requiring aging management. 
 
The staff reviewed the applicant's Structures Monitoring Program, and its AERMs under the
 
scope of the Structures Monitoring Program. The staff noted that the Structures Monitoring
 
Program satisfies the monitoring requirements for plant structures that are within the scope of
 
the NRC Maintenance Rule (10 CFR 50.65). SSES structures and components that are within
 
the scope of license renewal monitored by the Structures Monitoring Program include the
 
following:
* Primary Containment
* Reactor Building
* Circulating Water Pumphouse and Water Treatment Building
* Control Structure
* Diesel Generator 'A, B, C & D' Building
* Diesel Generator 'E' Building
* Turbine Building
* Engineered Safeguards Service Water (ESSW) Pumphouse
* Spray Pond (includes Emergency Spillway and earthen embankment)*
* Clarified Water Storage Tank Foundation
* Condensate Storage Tank Foundation and Retention Basin
* Diesel Generator Fuel Oil Storage Tanks 'A, B, C, D & E' Foundation and Vault*
* Refueling Water Storage Tank Foundation
* Station Blackout component foundations and structures in the yard (Startup Transformers T-10 and T-20 and associated disconnect switches, ESS Transformers)*
* Cooling Tower Basins (Units 1 and 2)
* Duct banks, manholes, valve vaults (includes Spray Pond Valve Vault),
instrument pits, and piping trenches (structural component groups not identified as structure/building.
 
The staff found this enhancement acceptable because when the enhancement is implemented, AMP B.2.39, "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 2
 
LRA Section B.2.39 states an enhancement to the "parameters monitored or inspected"
 
program element in that the Structures M onitoring Program and excavation procedure will be enhanced to specify that, if the below grade structural or component become accessible
 
through excavation, the responsible engineer will inspect the exposed surfaces for age-related
 
degradation. The Structures Monitoring Program procedure will also be enhanced to specify that
 
the responsible engineer shall review the site ground and raw water chemistry data to validate 3-168 that the below-grade environment remains non-aggressive during the PEO. 
 
The staff reviewed the applicant's Structures Monitoring Program, and its AERMs under the
 
parameters monitored or inspected program elem ent of the Structures Monitoring Program. The staff noted that the chemical analysis of groundwater at WW-2 is non-aggressive, where pH >
 
5.5, Chloride < 500ppm, Sulfate < 1500ppm, as demonstrated in 2006: pH 6.11; Chloride 23.1
 
ppm; Sulfate 43.2 ppm and in 2007: pH 6.13; Chloride 40.4 ppm; Sulfate 54.6 ppm. The staff
 
also noted that the Structures Monitoring Program incorporates provisions for increased
 
monitoring described in RG 1.160. This includes clarifications for monitoring under
 
Paragraph (a)(1) of 10 CFR 50.65, including additional degradation-specific condition
 
monitoring and increased frequency of assessments until ongoing corrective actions are
 
complete and functional performance is assured. ACI 201.1R-68, "Guide for Making a Condition
 
Survey of Concrete in Service" is used as a source by the applicant for observing concrete
 
deterioration and surface conditions. The staff further noted that the applicant's assessments
 
are performed in accordance with ANSI/ASCE 11-90, Guideline for Structural Condition
 
Assessments of Existing Buildings, and consider the following:
* Function - Component design features, design basis, operational and maintenance history.
* Existing degradation conditions - Locations, extent, rates.
* Degradation effects upon structural or component function - Structural safety, containment, personnel safety, and protection of equipment. SSES does not employ a de-watering system in any of the site structures for control of settlement. If a below grade structural wall or structural component becomes accessible through excavation, a follow-up action is initiated for the responsible engineer to inspect the exposed.
 
The staff found this enhancement acceptable because when the enhancement is implemented, AMP B.2.39, "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
 
LRA Section B.2.39 states an enhancement to the "parameters monitored or inspected" and the
 
"acceptance criteria" program elements of the Structures Monitoring Program in that the
 
procedure will be enhanced to include a degradation mechanism for elastomers and an earthen
 
embankment inspection. 
 
The staff reviewed the applicant's Structures Monitoring Program, and its AERMs under the
 
parameters monitored or inspected, and acceptance criteria program elements of the Structures Monitoring Program. The staff found 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 elastomers and earthen
 
embankment inspection to the Structural Monitoring program acceptable because when the
 
enhancement is implemented, AMP B.2.39, "Structu res Monitoring Program," will be consistent with GALL AMP XI.S6 and provide additional assurance that the effects of aging will be
 
adequately managed.
 
Enhancement 4
 
LRA Section B.2.39 states an enhancement to the "scope of program" and "parameters
 
monitored or inspected" program elements of t he Structures Monitoring Program in that the 3-169 procedure will be enhanced to include RG 1.127 inspection elements for water control structures. 
 
The staff reviewed the applicant's Structures Monitoring Program, and its AERMs under the
 
scope of program and the parameters monitor ed or inspected program elements of the Structures Monitoring Program. The staff finds that the applicant omitted the acceptance criteria
 
program element enhancement for Water Control Structures, which should also have been
 
included as part of this enhancement. Therefore, RAI B.2.39-1 was issued. In the letter dated
 
July  8, 2008, the applicant indicated that the LRA Section B.2.39, Structures Monitoring
 
program, is amended to include the Acceptance Criteria for RG 1.127, Water Control Structures
 
Inspection. The staff reviewed the applicant's enhancement described above and its response 
 
to the RAI and found them acceptable, because when the enhancement is implemented, AMP B.2.39, "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 5
 
LRA Section B.2.39 states an enhancement to the "acceptance criteria" program element of, the
 
Structures Monitoring Program in that the procedure will be enhanced to specify that the extent
 
of observed masonry cracking and/or degradation of steel edge supports/bracing are evaluated, and corrective action is required to ensure that the current evaluation basis is still valid. 
 
The staff reviewed the applicant's Structures Monitoring Program and its AERMs under the
 
acceptance criteria program element of the Structures Monitoring Program. The staff noted that
 
inspection criteria used to assess the condition of structures and structural components include
 
the following:
* Concrete is inspected for loss of material, cracking and change in material properties aging effects.
* Masonry walls are inspected for cracking aging effect.
* Steel and other metals including threaded fasteners are inspected for loss of material and cracking aging effects.
* Elastomers are inspected for cracking and change in material properties aging effects.
* Earthen structures are inspected for loss of form aging effect.
 
The staff also noted that the applicant's responsible engineer identifies problems with structural
 
performance, initiates structural deficiency reports and recommends corrective action.
 
Acceptance criteria are typically established such that corrective actions are initiated prior to loss of function. The staff found this enhancement acceptable because when the enhancement
 
is implemented, AMP B.2.39, "Structures Moni toring Program," will be consistent with GALL AMP XI.S6 and provide additional assurance that the effects of aging will be adequately
 
managed.
Enhancement 6
 
In the letter dated September 23, 2008, the applicant added an enhancement to the "monitoring
 
and trending" program element the Structures Monitoring Program to include direction for
 
quantifying, monitoring and trending of inspection results; guidance for inspection reporting, data collection and documentation; acceptance criteria and critical parameters for monitoring
 
degradation and for triggering level of inspection and initiating of corrective action; and better 3-170 alignment with referenced Industry codes, standards and guidelines. The applicant also stated that the program will be enhanced to include specific qualification requirements for the
 
inspector. 
 
The staff reviewed the applicant's Structures Monitoring Program, the enhancement above, and
 
its AERMs under the monitoring and trending program element of the Structures Monitoring
 
Program. The staff found this enhancement acceptable because when the enhancement is
 
implemented, AMP B.2.39, "Structures Monito ring Program," will be consistent with GALL AMP XI.S6 and provide additional assurance that the effects of aging will be adequately
 
managed.
 
Operating Experience. The staff also reviewed the applicant's OE described in LRA Section B.2.39 and the applicant's Operation Experience Review Report, and interviewed the
 
applicant's technical staff to confirm that the plant-specific OE have been reviewed by the
 
applicant and is evaluated in the GALL Report. During its audit, the staff conducted a field walk-
 
down with the applicant's technical staff in the general areas and those listed in the LRA, e.g.,
the Engineered Safeguards Service Water (ESSW) pumphouse's roof membranes, expansion
 
joints and penetration leakage in the diesel generator building and the reactor building, and
 
water leakage at penetrations located below grade exterior walls, etc. In general, the staff
 
noticed some degradation. However, all of the observations are minor and acceptable per the
 
applicant's inspection procedures and within the guidance of the ACI 201.1R (Guide for Making
 
a Condition Survey of Concrete in Service) and ACI 349-3R (Evaluation of Existing Nuclear Safety-Related Concrete Structures) as recommended in the GALL Report. 
 
The staff also confirmed that the applicant has addressed OE identified after the issuance of the
 
GALL Report. The staff finds that the applicant's Structures Monitoring Program, with the
 
corrective actions discussed in the LRA, has been effective in identifying, monitoring, and
 
correcting the effects of aging on structures monitoring and the existing program OE revealed
 
no degradation not bounded by industry experience.
 
On the basis of its review of the OE and discussions with the applicant's technical staff, the staff
 
concluded that the applicant's Structures Monitoring Program will adequately manage the aging
 
effects that are identified in the LRA for which this AMP is credited. The staff confirmed that the
 
A 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.1.2.45, Commitment No. 34, the applicant provided the UFSAR supplement for the Structures Monitoring 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 the audit and review of the applicant's Structures Monitoring Program, the staff determines that those program elements for which the applicant claimed
 
consistency with the GALL Report are consistent. In addition, the staff reviewed the
 
enhancements and confirmed that their implementation through Commitment No. 34 prior to the
 
period of extended operation would make the existing AMP consistent with the GALL Report
 
AMP to which it was compared. The staff concludes that the applicant has demonstrated that
 
the effects of aging will be adequately managed so that the intended function(s) will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concludes that it provides an adequate summary description of the program, as required by 3-171 10 CFR 54.21(d).
3.0.3.2.18  Regulatory Guide 1.127 Water-Control Structures Inspection 
 
Summary of Technical Information in the Application. LRA Section B.2.40 describes the existing RG 1.127 Water-Control Structures Inspection as consistent, with enhancements, with GALL AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants." The
 
applicant stated that the program is implemented as part of the Spray Pond Inspection and
 
Structures Monitoring Program. 
 
The applicant also stated that, RG 1.127 Water-Control Structures are visually examined at a
 
frequency selected to ensure there is no loss of intended function between inspections.
 
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 (Commitment No. 35) to determine whether the AMP, with the enhancements, is adequate to manage the aging
 
effects for which it is credited by the LRA.
 
The staff interviewed the applicant's technical staff and reviewed the associated bases
 
documents for the AMP B.2.40 "RG 1.127 Water-Control Structures Inspection," which provides an assessment of the AMP elements' consistency with GALL AMP XI.S7.
 
The staff also reviewed those portions of the RG 1.127, Inspection of Water-Control Structures
 
Associated with Nuclear Power Plants Program for which the applicant claims consistency with GALL AMP XI.S7. 
 
Enhancement 1
 
LRA Section B.2.40 states an enhancement to the "scope of program" program element of the
 
Structures Monitoring Program in that the procedure will be enhanced to add the Spray Pond (including concrete liners, emergency spillw ay, riser encasements and earthen embankments) to its scope for inspection.
The staff reviewed the applicant's RG 1.127 Water-Control Structures Inspection and its AERMs
 
under the scope of program element. The staff noted that the ultimate heat sink for SSES
 
consists of a concrete lined Spray Pond and an ESSW Pumphouse housing four RHRSW
 
pumps and four ESW pumps which pump the water from the Spray Pond through their
 
respective loops and back to the Spray Pond through a network of sprays located in the Spray
 
Pond. The staff further noted that the Spray Pond is designed in accordance with seismic
 
category I requirements. Earthen embankments are provided along the Spray Pond to ensure a
 
minimum freeboard of 3 feet and to direct flood water away from safety-related facilities in a
 
controlled manner. They are managed by both the Spray Pond Inspection and the Structures
 
Monitoring Program. The staff also noted that 1) there are no water-control structures that fall
 
under the regulatory jurisdiction of the Federal Energy Regulatory Commission (FERC) or the
 
U.S. Army Corps of Engineers; 2) the Spray Pond Inspection includes a visual inspection of the
 
Spray Pond and performance of groundwater level monitoring, and is credited for managing loss
 
of material and cracking aging effects for the concrete lined Spray Pond and its appurtenances;
 
and 3) the Structures Monitoring Program that includes a visual inspection of the Spray Pond, ESSW Pump house, and earthen embankments, is credited for managing loss of material, cracking, and spalling. The staff's review determined that this enhancement is acceptable
 
because when the enhancement is implemented, the AMP B.2.40, "RG 1.127 Water-Control 3-172 Structures Inspection," will be consistent with the GALL AMP XI.S7 and provide additional assurance that the effects of aging will be adequately managed.
 
Enhancement 2
 
LRA Section B.2.40 states an enhancement to the "parameters monitored or inspected"
 
program element of the Structures Monitoring Program in that the procedure will be enhanced to include RG 1.127 Revision 1 Section C.2 inspection elements and degradation mechanisms for
 
water control structure inspection. 
 
The staff reviewed the applicant's RG 1.127 Water-Control Structures Inspection, RG 1.127
 
Revision 1 Section C.2 requirements, the Structures Monitoring Program, and their AERMs
 
under the parameters monitored or inspected pr ogram elements of the Structures Monitoring Program. The staff noted that the Spray Pond Inspection includes activities to inspect the
 
exposed and accessible external surfaces of the Spray Pond and its appurtenances to
 
determine material condition and to identify any signs of degradation that might affect its
 
structural integrity and operation adequacy. The staff also noted that the Structures Monitoring
 
Program monitors degradation mechanisms for the structure and structural components under investigation and that a potential degradation mechanism matrix is contained in SSES design
 
standards which includes degradation mechanisms that require monitoring for license renewal.
 
The SMP will be enhanced to include parameters monitored and inspected for water-control
 
structures in accordance with inspection elements listed in Section C.2 of RG 1.127 Revision 1.
 
The staff found this enhancement acceptable because when the enhancement is implemented, the AMP B.2.40, "RG 1.127 Water-Control Structures Inspection," will be consistent with GALL AMP XI.S7 and provide additional assurance that the effects of aging will be adequately
 
managed.
 
Enhancement 3
 
LRA Section B.2.40 states an enhancement to the "acceptance criteria" program element of the
 
Structures Monitoring Program in that the procedure will be enhanced to include acceptance criteria as delineated in GALL AMP XI.S7 for WCS. The applicant stated that evaluation criteria
 
provided in Chapter 5 of ACI 349.3R-96 provi des acceptance criteria (including quantitative criteria) for determining the adequacy of observed aging effects and specifies criteria for further
 
evaluation. 
 
The staff reviewed the applicant's RG 1.127 Water-Control Structures Inspection, Chapter 5 of
 
ACI 349.3R-96, the Structures Monitoring Program, and their AERMs under the acceptance
 
criteria program element of the Structures Monitoring Program. The staff noted that the
 
acceptance criteria for the Spray Pond Inspection uses the six (6) permanent piezometer wells (located in soil) along the perimeter of the Spray Pond; when the applicant determines that the
 
actual groundwater level has reached elevation 663 feet at any one of the six piezometer
 
locations, the following actions will be taken:
* NRC will be notified of the high (elevation 663') groundwater condition;
* Steps will be taken to identify the cause of the rise in the water level;
* An assessment of the safety impact of the occurrence will be performed;
* Appropriate actions will be taken based on the findings of the safety impact analysis. 
 
The staff further notes that the applicant's responsible engineer identifies problems with
 
structural performance, initiates structural deficiency reports, and recommends corrective
 
action. Acceptance criteria are established such that corrective actions are initiated prior to loss 3-173 of function.
 
The acceptance criteria for the Structures Monitoring Program include the following:
* Concrete is inspected for loss of material, cracking and change in material properties aging effects.
* Steel and other metals including threaded fasteners are inspected for loss of material and cracking aging effects.
* Elastomers are inspected for cracking and change in material properties aging effects.
* Earthen structures are inspected for loss of form aging effect. 
 
The staff found this enhancement acceptable because when the enhancement is implemented, AMP B.2.40, "RG 1.127 Water-Control Structures Inspection," will be consistent with the GALL AMP XI.S7 and provide additional assurance that the effects of aging will be adequately
 
managed.
 
Operating Experience. The staff also reviewed the applicant's OE described in LRA Section B.2.40, Operation Experience Review Report (RG 1.127 Water-Control Structures
 
Inspection's section), and interviewed the applicant's technical staff to confirm that the plant-
 
specific OE have been reviewed by the applicant. The applicant indicated that it found some
 
minor indications that did not affect the structural integrity of any of the structures reviewed. The
 
staff found that visual examinations conducted by the Spray Pond Inspection as implemented by the Structures Monitoring Program have not found any age-related problems or degraded conditions that could affect their intended function. The SSES RG 1.127 Water-Control
 
Structures Inspection has demonstrated that it provides assurance that aging effects are being
 
managed. The staff also confirmed that the applicant has addressed OE identified after the
 
issuance of the GALL Report. The staff finds that the applicant's RG 1.127 Water-Control
 
Structures Inspection Program, has been effective in identifying, monitoring, and correcting the
 
aging effects on WCS and that existing program OE revealed no degradation not bounded by
 
industry experience. The staff confirmed that the OE
@ 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.1.2.42, Commitment No. 35, the applicant provided the UFSAR supplement for the RG 1.127 Water-Control Structures Inspection. 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 the audit and review of the applicant's RG 1.127 Water-Control Structures Inspection, the staff determines that those program elements for which the applicant
 
claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the
 
enhancements and confirmed that their implementation through Commitment No. 35 prior to the
 
period of extended operation would make the existing AMP consistent with the GALL Report
 
AMP to which it was compared. The staff concludes that the applicant has demonstrated that
 
the effects of aging will be adequately managed so that the intended function(s) will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concludes that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
 
3-174 3.0.3.2.19  Fatigue Monitoring Program 
 
Summary of Technical Information in the Application. Section B.3.1 of the LRA describes the existing program, "Fatigue Monitoring Program (FMP)." The LRA describes this program as consistent with the GALL AMP X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary" with enhancements. The LRA states the purpose of the program is to manage the fatigue for all
 
Class 1 components. The FMP tracks the number and severity of critical thermal and pressure
 
transients for the selected reactor coolant system (RCS) components. The LRA indicates that
 
there is no exception for this program to the GALL AMP X.M1, however, enhancements will be implemented prior to the period of extended operation in order for this program to be consistent with the 10 elements described GALL AMP X.M1.
 
Staff Evaluation. The staff reviewed the technical information in the LRA to verify the consistency of this program to the GALL AMP X.M1 and to assess the adequacy of this
 
program. The staff review identified several areas where it needed additional information to
 
complete the review of the SSES FMP. The staff transmitted requests for additional information (RAIs) to the applicant by letters dated July 3, 2008 and October 22, 2008. The applicant
 
responded to the staff RAIs by letters dated August 1, 2008 and December 12, 2008.
 
The program description states that FMP monitors and tracks the number and severity of critical thermal and pressure transients for the selected RCS components. In RAI B.3.1-1, the staff
 
requested the applicant to describe how this tracking and monitoring is accomplished. 
 
The applicant's response indicated that the FMP is implemented by an approved engineering procedure. The critical plant transients are monitored using two methods. Some of the
 
transients are automatically counted using computer software analysis of specific plant
 
operating data such as temperatures, pressures and flow rates. Those events that cannot be
 
automatically counted are manually counted by review of plant data and operating logs. The applicant indicated that the SSES cycle counting procedure assumes that every event occurs at
 
the full design value. The staff finds this procedure provides an acceptable method to track
 
design transient cycles for comparison to the num ber of cycles used in the fatigue evaluation of ASME Class 1 components.
 
Section 4.3.1 of the LRA indicates that the design transients are monitored using the computer
 
software FatiguePro. In RAI B.3.1-2, the staff asked the applicant to confirm whether FatiguePro
 
is a part of the FMP and describe the role FatiguePro has in the FMP. In addition, the staff
 
asked the applicant to confirm whether FatiguePro is used for stress-based monitoring, and if
 
so, list the components that are stress-based monitored. 
 
The applicant's response indicated that FatiguePro software is used for stress-based fatigue (SBF) monitoring of the FW nozzle forgings, FW nozzle safe ends, and the CRD penetrations.
 
The applicant also indicated that FatiguePro is used to identify and count transient cycles from
 
the plant operating data. The transients that cannot be automatically counted are manually
 
entered into the FatiguePro database. FatiguePro is also used to calculate the fatigue
 
cumulative usage factor (CUF) at the limiting plant locations. 
 
Previous LRA reviews determined that FatiguePro may use simplifying assumptions in the SBF
 
evaluation. The staff issued a draft regulatory information summary (RIS) 2008-xx: "Fatigue
 
Analysis of Nuclear Power Plant Components," May 1, 2008 (73 FR 24094) which questioned
 
the conservatism of the simplifying assumptions used in the analysis methodology associated
 
with a Green's function that has been used for the detailed analysis of some components for 3-175 license renewal. In RAI B.3.1-7, the staff asked the applicant to provide the following information regarding the fatigue evaluation, including environmental fatigue effects at the
 
NUREG/CR-6260 locations:
Provide the details for the management of environmentally-assisted fatigue components during the period of extended operation, including the elements to the AMP such as
 
scope, qualification, method and frequency. For all locations where 60-year environmental CUF is below 1.0, clarify whether any of these values have been calculated using the Green's Function Methodology and if so
 
please describe the details of how Green's Function was used to calculate the CUF
 
values.
The applicant's response indicated that all eleven locations in LRA Table 4.3-3 will be managed
 
for environmentally-assisted fatigue by the SSES FMP. The applicant also indicated that the
 
environmental CUF at these locations would be updated once every fuel cycle and corrective actions would be initiated prior to the CUF reaching the allowable limit at the monitored
 
locations. The staff finds this response acceptable because the applicant will monitor the fatigue
 
usage on a periodic basis and initiate appropriate corrective actions prior to the fatigue CUF
 
exceeding its allowable limit.
 
The applicant's response indicated that the Green's Function Methodology was used for the
 
SBF monitoring of the FW nozzle forging and nozzle safe end. In its response to RAI B3.1-1, the applicant indicated that the SBF methodology had been benchmarked against the relevant
 
design basis stress report for each component. The staff requested that the applicant provide
 
additional information regarding the benchmarking of the methodology. In RAI 4.3-11, the staff
 
requested that the applicant provide the following additional information regarding the
 
benchmarking of the SBF methodology:
: a. Describe the procedure used to benchmark the SBF monitoring locations against the relevant design reports. List the transients used for the
 
benchmarking and indicate the design fatigue usage associated with each
 
transient.
: b. Discuss how the SSES SBF monitoring addresses the concern raised in proposed Regulatory Information Summary (RIS), "Fatigue Analysis of Nuclear
 
Power Plant Components," May 1, 2008 (73 FR 24094). Indicate whether any
 
additional benchmarking of the SSES SBF monitoring is planned. 
 
The applicant's response described the procedure used to benchmark the SBF fatigue
 
monitoring locations for the FW nozzle safe and the CRD penetration locations. The applicant
 
indicated that key transient pairings from the design basis stress reports were used to adjust the
 
Green's functions so the stresses from the Green's function bounded the stresses from the
 
design report. The adjustment assures that the Green's function stresses bounded the stresses
 
from the design report for the key transient pairings. 
 
The applicant also indicated that the benchmark calibrations were not performed for all possible
 
transient pairing scenarios. The applicant could not confirm that the benchmark calibration
 
procedure for the key transient pairings fully addressed all possible transient pairing scenarios.
 
Therefore, the applicant committed (Commitment No. 60) to either: (1) implement fatigue
 
monitoring software that satisfactorily addresses all issues raised in the proposed RIS, or (2)
 
perform a confirmatory ASME Code, Section III fatigue evaluation for the SBF monitored 3-176 locations to justify the existing FatiguePro methodology used at SSES Units 1 and 2. This commitment will be completed prior to the period of extended operation. The staff finds the
 
applicant's commitment adequately addresses the technical concern indentified in the draft RIS
 
and is acceptable.
 
Enhancement 1
 
The FMP has an enhancement to the GALL Report program elements "preventive actions, monitoring and trending." The LRA states that additional actions may be taken when sufficient
 
fatigue accumulation has occurred, if determined necessary to address fatigue-related
 
concerns. The staff found the above LRA statement does not provide sufficient details to
 
determine that FMP will prevent the design limit being reached. In RAI B.3.1-3, the staff asked
 
the applicant to explain what is meant by sufficient fatigue accumulation, describe the criteria
 
used to determine if further actions are required, and to provide the periodicity of the updates for
 
CUF values.
 
The applicant's response indicated that it had revised LRA Commitment No. 43 to include
 
specific action levels be determined for each monitored location. The revised commitment
 
requires the applicant to initiate actions at least 4 years prior to the projected CUF of any
 
monitored component reaching its allowable limit. In addition, the applicant committed to update
 
the fatigue calculation at least once every refueling cycle. The staff finds the applicant's revised
 
Commitment No. 43 provides adequate assurance that corrective actions will be initiated prior to
 
exceeding the allowable limit at any of the locations monitored by the SSES FMP.
 
The staff found this enhancement acceptable because when the enhancement is implemented, the applicant's program will be consistent with the recommendations of GALL AMP X.M1.
 
Enhancement 2
 
The FMP has an enhancement to the GALL Report program elements "preventive actions and acceptance criteria." This enhancement will address environmental effects on fatigue at specified locations in NUREG/CR-6260. The staff reviewed this enhancement and found that it
 
does not apply to the "preventive actions" and "acceptance criteria" elements of GALL AMP X.M1. These two elements in the GALL AMP relate to maintaining the fatigue usage factor
 
below the design limit and monitoring the plant transients. The enhancement therefore is not
 
applicable to these program elements. In RAI B3.1-4, the staff asked the applicant to explain
 
how this enhancement to address environmental effe cts is applicable to these two elements of GALL AMP X.M1. 
 
The applicant's response provided a revision to the FMP described in LRA Appendix B, Section B.3.1 and LRA Commitment No. 43 to clarify that the enhancements to address
 
environmental effects on fatigue at the NUREG/CR-6260 locations also include monitoring the
 
locations for environmental fatigue usage and acceptance criteria that the environmental fatigue
 
usage does not exceed the allowable limit. The staff finds the applicant's FMP revision acceptable because it satisfies GALL AMP X.M1. 
 
Consistent with the GALL Report X.M1, the FMP will provide for periodic updates of the fatigue
 
usage calculations. However, the LRA is not clear on the corrective actions that will be taken if
 
the updated CUF calculations are projected higher than the allowable limits. In RAI B.3.1-5, the
 
staff asked the applicant to state the exact actions that will be taken if FMP projects CUF values
 
higher than the allowable limit.
3-177  The applicant's response indicated that when an action level as defined in the response to
 
RAI B.3.1-3 is reached, an action request will be generated to require further engineering
 
evaluation of the monitored location. The engineering evaluation would attempt to demonstrate
 
that the CUF remains below the allowable limit through analysis refinements. If the analysis
 
cannot demonstrate that the CUF remains below the allowable limit, the applicant proposed the
 
following further options:
 
Repair the component  Replace the component  Manage the component through inspection and flaw tolerance
 
The applicant's proposed actions to perform an engineering evaluation to demonstrate the CUF
 
remains within its allowable limit or repair/replacement of the component are consistent with GALL AMP X1.M1 and are acceptable. The applicant's proposal to manage the component
 
through inspection and flaw tolerance would require NRC review and approval as stated in LRA
 
Commitment No. 43.
 
In the OE section of the FMP its states that industry OE has been factored into the SSES FMP, however this section does not list or describe the applicable OE that was reviewed by the applicant. The GALL Report X.M1 recommends that industry OE is reviewed as part of the
 
program and any applicable experience should be considered to be incorporated into the FMP.
 
In RAI B.3.1-6 the staff asked the applicant to list the documents reviewed and provide the
 
corresponding follow-up actions taken by SSES from any applicable experience. 
 
The applicant's response provided a list of documents reviewed as part of its FMP. These
 
documents included NRC bulletins and industry publications as well as other license renewal
 
applications relevant to fatigue of RCPB components. In addition, the applicant indicated that
 
SSES was an early participant in using fatigue monitoring of RCPB components and that SSES
 
maintains its participation in industry peer review groups. On the basis of the applicant's
 
response to RAI B3.1-6, the staff finds that the applicant has considered the relevant industry
 
experience related to the fatigue of RCPB components.
 
The staff found this enhancement acceptable because when the enhancement is implemented, the applicant's program will be consistent with the recommendations of GALL AMP X.M1.
 
UFSAR Supplement. 10 CFR 54.21(d) states that the UFSAR supplement for the facility must contain a summary description of the programs and activities for managing the effects of aging.
 
The staff did not find a UFSAR Supplement for the Fatigue Monitoring Program, B.3.1. In
 
RAI B.3.1-8, dated July 3, 2008, the staff asked the applicant to provide the UFSAR Supplement
 
for AMP B.3.1. 
 
In response to RAI B.3.1-8, dated August 1, 2008, the applicant provided an amendment to LRA
 
Appendix A to address the FMP. The amendment added a new Section A.1.2.49, Commitment
 
No. 43, which described the FMP, including the program enhancements that will be
 
implemented prior to the period of extended operation. In addition, the UFSAR Supplement
 
specifies corrective actions that will be impl emented if the fatigue usage at any monitored location is projected to exceed its design limit prior to the period of extended operation. The
 
staff reviewed the applicant's LRA amendment and finds that provides an adequate summary
 
description of the FMP.
 
3-178 The staff reviewed the UFSAR supplement and determines that it 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 Fatigue Monitoring Program, the staff determines that those program elements for which the applicant claimed consistency with the
 
GALL Report are consistent. The staff has reviewed the information provided in Section B.3.1 of
 
the LRA and additional information provided by the applicant by letters dated August 1, 2008
 
and December 12, 2008. Also, the staff reviewed the enhancements and confirmed that they
 
will be implemented through Commitment No. 43 prior to the period of extended operation. On
 
the basis of its review as discussed above, the staff concludes that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB for the period of extended operation, as
 
required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this
 
AMP and concludes that it provides an adequate summary description of the program, as
 
required by 10 CFR 54.21(d).
Conclusion. The staff has reviewed the information provided in Section B.3.1 of the LRA and additional information provided by the applicant by letters dated August 1, 2008 and
 
December 12, 2008. On the basis of its review as discussed above, the staff concludes that the
 
applicant has demonstrated that the effects of aging will be adequately managed so that the
 
intended function(s) will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement
 
for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.20 Fuse Holders Program Summary of Technical Information in the Application.
LRA Section B.2.50 describes the new Fuse Holders Program as consistent, with exception, with GALL AMP XI.E5, "Fuse Holders."
 
The applicant stated that this aging management program will manage increased connection
 
resistance due to fatigue of the fuse holder metallic clamp for fuse holders in the scope of the
 
program. This program will be used to ensure that the metallic clamps of the fuse holders are
 
not loosening due to removal and reinsertion of fuses.
 
In the LRA, Section 3.6.2.3.1, the applicant states that the fuse holders are located in metallic
 
electrical boxes (terminal boxes) which have covers that protect the interior of the box from the environment. The applicant also states that the boxes are not exposed to weather (they are located indoors at SSES); they are not exposed to chemical contamination or spills. Therefore, the applicant concluded that chemical contamination, corrosion, and oxidation are not
 
applicable aging effects for the metallic clamps of the fuse holders within the license renewal
 
scope at SSES. With respect to electrical transients and ohmic heating, the applicant states that
 
these fuses are not heavily loaded and do not experience frequent electrical and thermal
 
cycling. The power fuses with bolted connections used Belleville washers to maintain good
 
electrical contact in event of any differential thermal expansion. With respect to vibration, the
 
applicant states that the electrical boxes are mounted on walls; vibration is not an applicable
 
aging mechanism. 
 
Furthermore, the applicant states that inspection of a sample of the 20 in-scope metal electric
 
boxes containing the fuse holders showed no corrosion or evidence of water intrusion or
 
collection and the metallic electrical boxes were clean and dry. 
 
3-179 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 is adequate to manage the aging effects for which the LRA credits it.
 
The staff reviewed the applicant's claim of consistency with the GALL Report. The staff
 
reviewed and compared the "scope of program,"
"preventative actions," "parameters monitored/detected," "detection of aging effects," "monitoring and trending," "acceptance
 
criteria," and "operating experience" program elements of the AMP to the corresponding program element criteria in GALL AMP XI.E5, "Fuse Holders." 
 
Exception 1
 
LRA Section B.2.50 states an exception to t he "parameters monitored/inspected" program element of GALL AMP XI.E5 such that it monitors only the mechanical fatigue of the metallic
 
clamp portion of the fuse holder caused by removal and insertion of the fuse. The applicant
 
stated that none of the other aging effects/mechanisms identified in this GALL Report element
 
are applicable. The staff noted that the in-scope fuse holders are installed in metal terminal
 
boxes, which are separate from sources of vibration. Therefore, vibration is not an applicable
 
aging mechanism. The terminal boxes are locat ed inside the rooms that have a controlled environment that protects the panels from t he weather. They are not exposed to potential system leakage or spills. With regard to internal moisture, the applicant inspected a sample of
 
terminal boxes and found the surface condition of the terminal boxes showed no signs of
 
corrosion or water intrusion. Therefore, corrosion is not an applicable aging mechanism. With
 
respect to thermal ohmic heating or thermal cycling, these fuse holders are not used in heavy
 
loading (control powers). In addition, these fuse holders are bolted connections using Belleville
 
washers to prevent thermal expansion of different material. Based on this information, the staff
 
determines that ohmic heating, thermal cycling or electrical transients, vibration, chemical contamination, corrosion and oxidation are not applicable aging mechanisms/effects for the
 
metallic clamps of the fuse holders within the scope of license renewal at SSES. Therefore, the
 
staff finds that the exception to the "paramet ers monitored/inspected" element acceptable. 
 
The staff compared the programs elements in the applicant's program to those in GALL AMP XI.E5 and verified that the program elements were consistent. The staff found the
 
applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with
 
the exception described above.
 
Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.50.
The applicant stated that the Fuse Holders Program is a new program for which there is no
 
SSES-specific OE. The applicant also stated that during routine preventive maintenance
 
activities in 2005, a fuse holder in a Unit 1 FW control panel was identified as being slightly
 
warmer than other fuse holders in the same location due to loosening of the fuse holder metallic
 
clamps. The fuse holder was replaced, and post-maintenance testing, using thermography, confirmed the condition was corrected. In addition, the applicant stated that in 2004, a fuse
 
holder in a Unit 2 reactor building chiller control panel was identified as being slightly warmer
 
than other fuse holders in the same location due to loosening of the fuse holder metallic clamps.
 
The fuse holder was replaced, and post-maintenance testing, using thermography, confirmed
 
the condition was corrected. The condition was detected prior to loss of intended function in
 
both of these cases. 
 
The staff finds that the OE identified above demonstrates that the applicant's identification of
 
early problems with fuse holders and correction of them prior to loss of intended functions
 
provide assurance that the program will rema in effective in assuring that equipment is 3-180 maintained during the period of extended operation. 
 
The staff finds 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.1.2.51, Commitment No. 59, the applicant provides its UFSAR Supplement for the Fuse Holders Program. The staff reviewed the UFSAR supplement
 
and determines that it provides an adequate summary description of the program as required by
 
10 CFR 54.21(d). The applicant has committed to implement this AMP prior to the period of
 
extended operation.
 
Conclusion. On the basis of its review of the applicant's Fuse Holders Program, the staff determines that those program elements for which the applicant claimed consistency with the
 
GALL Report are consistent. In addition, the staff reviewed the exception and its 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 effects of
 
aging will be adequately managed so that the intended function(s) will be maintained consistent
 
with the CLB for the period of extended operation as required by 10 CFR 54.21(a)(3). The staff
 
also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.3  AMPs Not Consistent with or Not Addressed in the GALL Report In LRA Appendix B, the applicant identified the following AMPs as plant-specific:
* Area-Based Nonsafety-affecting Safety Inspection
* Leak Chase Channel Monitoring Activities
* Preventive Maintenance Activities - RCIC/HPCI Turbine Casings 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  Area-Based Nonsafety-Affecting Safety (NSAS) Inspection 
 
Summary of Technical Information in the Application. LRA Section B.2.46 describes the Area-Based NSAS Inspection Program as plant-specific. This program involves a one-time inspection of the internal surfaces of nonsafety-related components that are exposed to non-radioactive
 
drainage water or potable water environments. Also inspected are the internal surfaces of
 
copper alloys exposed to raw water from the spray pond/cooling tower. The applicant stated that
 
the one-time inspection will ensure that the structural integrity of nonsafety-related components
 
is maintained such that spatial interactions such as leakage will not result in the loss of intended
 
function of safety-related components during the period of extended operation.
 
Staff Evaluation. The staff reviewed the Area-Based NSAS Inspection against the AMP elements found in the GALL Report, in the SRP-LR Section A.1.2.3, and tin SRP-LR
 
Table A.1-1, focusing on how the program manages aging effects through the effective
 
incorporation of 10 program elements (i.e., "scope of program," "preventive actions,"
"parameters monitored or inspected," "detection of aging effects," "monitoring and trending,"
 
"acceptance criteria," "corrective actions," "confirmation process," "administrative controls," and 3-181 "operating experience"). 
 
The applicant indicated that the "corrective actions," "confirmation process," and "administrative
 
controls" program elements are part of the LRA Section B.1.3, Quality Assurance Program and
 
Administrative Controls. The staff's evaluation of LRA Section B.1.3 program is discussed in
 
SER Section 3.0.4. The remaining seven elements are discussed below.
 
Scope of Program LRA Section B.2.46, states that the scope of this program includes confirming the environmental
 
and/or internal surface conditions of nonsafety-related carbon steel, cast iron, copper alloy, and
 
stainless steel components in systems that contain non-radioactive equipment/area drainage
 
water or potable water, as well as for copper alloy components in systems that contain raw
 
water. The applicant further stated that if ammonia or ammonium compounds are found in
 
systems containing non-radioactive equipment/area drainage water or potable water, as well as
 
for copper alloy components in systems that contain raw water, a sample of copper alloy
 
components will be examined for evidence of SCC.
The staff reviewed the applicant's "scope of the program" program element against the criteria
 
in SRP-LR Section A.1.2.3.1 which states that "The specific program necessary for license
 
renewal should be identified. The scope of the program should include the specific structures
 
and components of which the program manages the aging."
 
The staff finds that the applicant identified the program necessary for license renewal and
 
specified the specific structures and components consistent with SRP-LR Section A.1.2.3.1.
 
The staff confirmed that the "scope of 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.
 
Preventive Actions
 
LRA Section B.2.46 states that no actions are taken as part of the Area-Based NSAS Inspection to prevent aging effects or to mitigate aging degradation.
 
The staff reviewed the applicant's "preventive actions" program element against the criteria in
 
SRP-LR Section A.1.2.3.2-2, which states that condition monitoring or performance monitoring
 
programs do not rely on preventive actions. 
 
Since this is a condition monitoring program, the staff concludes that this program does not rely
 
on preventive actions. The staff confirmed that the "preventive actions" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.2-2. The staff
 
finds this program element acceptable.
 
Parameters Monitored or Inspected LRA Section B.2.46 states that parameters inspected will include wall thickness and/or visual
 
evidence of internal surface degradation. If a mmonia or ammonium compounds are detected, the internal surfaces of copper alloy components will be inspected using visual or volumetric
 
inspection to detect SCC.
 
3-182 The staff reviewed the applicant's "parameters monitored or inspected" program element against the criterion in SRP-LR Section A.1.2.3.3-1, which states that, "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 applicant describes what kind of inspections will be conducted. The applicant also
 
discusses that degradation of these nonsafety-related systems and components (while not expected) are conducted to ensure that spatial interactions do not occur that could impair or
 
prevent a safety-related function. The applicant also states that a focused characterization of
 
conditions is warranted to provide confirmation of a lack of degradation or to serve as the basis
 
for recurring actions during the period of extended operation, if required.
 
The staff confirmed that the "parameters monitor ed or inspected" program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.3-1. The staff finds this
 
program element acceptable.
 
Detection of Aging Effects LRA Section B.3.46 states: "The Area-Based NSAS Inspection will use a combination of
 
established volumetric and visual examination techniques performed by qualified personnel on a
 
sample population of subject nonsafety-related components exposed to non-radioactive
 
equipment/area drainage water or potable water to identify evidence of a loss of material or to
 
confirm a lack thereof. The results of the inspection will be applied to all of the components
 
within the scope of the inspection activity."
 
The LRA also states: "If needed, based on engineering evaluation, the Area-Based NSAS
 
Inspection, will use a combination of established volumetric and visual examination techniques
 
performed by qualified personnel on a sample populat ion of select nonsafety-related systems, structures, and components. This program will use a combination of volumetric and visual
 
examination techniques on a sample population to identify evidence of loss of material or to
 
confirm lack of it. This program will also use a combination of volumetric and visual examination
 
techniques on a sample population to identify evidence of SCC or a lack of SCC."
 
The staff reviewed the applicant's "detection of aging effects" program element against the
 
criteria in SRP-LR Section A.1.2.3.4 which states that the inspections should be the proper
 
inspections to detect the anticipated aging effects. In addition, this program element should tell
 
when the inspections will be conducted and, if sampling is used, how the sample size will be
 
determined. Finally, the inspections should be concentrated in areas thought to be the most
 
susceptible to degradation.
 
The applicant stated that it will use industry accepted inspections using qualified inspectors. The
 
inspections will be conducted within 10 years of entering the period of extended operation. The
 
locations to be inspected will be selected based on engineering evaluation and will be
 
concentrated in areas thought to be the most susceptible to degradation.
 
The staff review finds that the applicant's program uses the proper types of inspections to detect
 
the kinds of aging anticipated. The selection of locations for inspection based on engineering
 
evaluation is also acceptable. Finally, selection of areas anticipated to have the most
 
degradation is also acceptable. 
 
The staff confirmed that the "detection of aging e ffects" program element satisfies the criterion 3-183 as defined in GALL Report and in SRP-LR Section A.1.2.3.4. The staff finds this program element acceptable.
 
Monitoring and Trending LRA Section B.2.46 states: "No actions are taken as part of the Area-Based NSAS Inspection to
 
monitor and/or trend inspection results. This is a one-time inspection used to determine if, and
 
to what extent, further actions such as monitoring and trending may be required. Results of
 
inspections, including follow-up inspections, are routinely evaluated through the site corrective
 
action process, if necessary."
 
The staff reviewed the "monitoring and trending" program element and found that the SRP-LR
 
Section A.1.2.3.5 is not applicable because this is a one-time inspection and there is no
 
monitoring and trending unless unanticipated degradation is detected.
 
The staff confirmed that the "monitoring and trending" program element does not satisfy the
 
criterion defined in SRP-LR Section A.1.2.3.5 because this is a one-time inspection so
 
monitoring and trending does not apply. The staff finds this program element acceptable.
 
Acceptance Criteria LRA Section B.2.46 states that there will be no unacceptable loss of material, wall thinning, or
 
SCC that could result in spatial interaction with safety-related components during the period of
 
extended operation, as determined by engineering evaluation.
 
The staff reviewed the applicant's "acceptance criteria" program element against the criteria in
 
SRP-LR Section A.1.2.3.6 which states that 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 and the program should include a methodology for analyzing the results against
 
applicable acceptance criteria.
 
The structures and components inspected as part of the NSAS Inspection Program are
 
nonsafety-related structures and components and this is a new program. However, the applicant
 
has identified appropriate acceptance criteria and how the age related degradation will be
 
evaluated. On the basis of its review, the staff finds this program element acceptable.
The staff confirmed that the "acceptance criteria" program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.6. The staff finds this program element
 
acceptable.
 
Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.26.
The applicant stated that the Area-Based NSAS Inspection is a new one-time inspection for which there is no OE indicating the need for an aging management program.
 
In a letter dated June 10, 2008  the staff issued RAI B.2-1 that is consistent with the statement
 
in the SRP-LR Section A.1.2.3.10, that the applicant make a commitment to provide OE in the
 
future to the staff for new AMPs to confirm their effectiveness for the period of extended
 
operation. In its letter dated July 8, 2008, the applicant responded to RAI B.2-1 and stated that
 
OE for new aging management programs described in LRA Appendix B will be gained as these
 
new programs are implemented during the peri od of extended operation. The applicant stated 3-184 that results of tests, inspections, and other aging management activities conducted in accordance with these programs will be subject to confirmation and corrective action elements
 
of the Susquehanna 10 CFR Part 50, Appendix B, quality assurance program and that results
 
will be subject to NRC review during regional inspections under existing NRC inspection
 
modules. The applicant further stated that one-time inspections will be performed prior to entry
 
to the period of extended operation to confirm the effectiveness of these aging management
 
programs, and that these programs are subject to review under NRC Inspection Procedure
 
71003, Post-Approval Site Inspection for License Renewal. 
 
The staff noted that post-approval site inspections provide an opportunity for staff review and
 
assessment of the effectiveness of the applicant's Area-Based NSAS Inspection Program after
 
the applicant has developed OE with that program. The staff concludes that the corrective
 
action program, based on internal and external plant OE, would capture OE in the future to
 
support the conclusion that the effects of aging are adequately managed. On this basis, the staff
 
finds the response acceptable.
 
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 that this program
 
element acceptable.
 
UFSAR Supplement. In LRA Section A.1.2.1, Commitment No. 40, the applicant provided the UFSAR supplement for Area Based Nonsafety Affecting Safety Inspection Program. The
 
applicant has committed to implementing the Area Based Nonsafety Affecting Safety Inspection
 
Program within the 10 year period prior to the period of extended operation.
 
The staff determines that the information in the UFSAR Supplement provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. On the basis of the review of the applicant's Area Based Nonsafety Affecting Safety Inspection Program including the applicant's response to the staff RAI, the staff concludes that
 
the applicant has demonstrated that the effects of aging will be adequately managed so that the
 
intended functions of these components will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the
 
UFSAR supplement for this AMP and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.3.2  Leak Chase Channel Monitoring Activities 
 
Summary of Technical Information in the Application. LRA Section B.2.47 describes the existing Leak Chase Channel Monitoring Activities as plant-specific. In the LRA, the applicant stated that
 
AMP B.2.47 is an existing plant-specific conditi on monitoring program consisting of observation and surveillance activities to detect leakage from the spent fuel pool and the fuel shipping cast
 
storage pool liners due to age-related degradation within the scope of license renewal.
 
Staff Evaluation. The staff reviewed the Leak Chase Channel Monitoring Activities against the AMP elements found in the GALL Report, in SRP-LR Section A.1.2.3, and in SRP-LR
 
Table A.1-1, focusing on how the program manages aging effects through the effective
 
incorporation of 10 program elements. The sta ff's evaluations on seven of these elements follow. Scope of the Program 3-185  LRA Section B.2.47 states that the program includes periodic monitoring of the spent fuel pool
 
and fuel shipping cask storage pool leak chase system. The applicant also stated that the
 
program is credited for supplementing the BWR Water Chemistry Program for managing loss of material aging effects for the spent fuel pool and fuel shipping cask storage pool liners.
 
The staff reviewed the applicant's "scope of the program" program element against the criteria
 
in SRP-LR Section A.1.2.3.1, which states that the scope of the program should include the
 
specific structures and components of which the program manages the aging. The staff found
 
the applicant has identified the specific structures and components of which the aging effects
 
are managed. On this basis, the staff finds the applicant's scope of the program acceptable.
 
The staff confirmed that the "scope of the progr am" 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.
 
Preventive Actions LRA Section B.2.47 states that no actions are taken as part of the program to prevent aging
 
effects or mitigate age-related degradation. 
 
The staff reviewed the "preventive actions" program element criterion in SRP-LR Section A.1.2.3.2 which states that conditi on monitoring programs do not rely on preventive actions, and thus, preventive actions need not be pr ovided. Therefore, this program element is acceptable because this is a condition monitoring program and there is no need for preventive
 
actions. 
 
Parameters Monitored or Inspected LRA Section B.2.47 states that the spent fuel pool and fuel shipping cask storage pool liner leak
 
detection drain valves are periodically opened and the leak rate estimated by the volumetric
 
method. The applicant also stated that this ensures evidence of leakage from the spent fuel
 
pool and fuel shipping cask storage pool liner is promptly identified and corrected if necessary. 
 
The applicant further stated that the program includes activities to cycle open and close spent fuel pool and fuel shipping cask storage pool liner drain valves and measure and report any
 
water collected to shift supervision.
 
The staff reviewed the "parameters monitored or inspected" program element against the criteria in SRP-LR Section A.1.2.3.3 which states that 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 staff found the program identifies the parameters to be
 
monitored or inspected and linked them to the degradation of the particular structures and
 
components intended functions by collecting, measuring and reporting any water collected to
 
the shift supervision for further action. 
 
This staff confirmed that the "parameters monitor ed or inspected" program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.3. The staff finds this program
 
element acceptable.
 
3-186 Detection of Aging Effects LRA Section B.2.47 states that the spent fuel pool and fuel shipping cask storage pool drain
 
valves are cycled and the volume of any water collected is measured. The applicant also stated
 
that estimating the time from start of opening valve until flow slows to a slow drip is also
 
performed for known leakage. 
 
The staff reviewed the "detection of aging effects" program element against the criteria in
 
SRP-LR Section A.1.2.3.4, which states that 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. The staff found the
 
applicant has identified the drain valves for the spent fuel pool and fuel shipping cask storage
 
are cycled and the volume of any water collected is measured as required under their CLB
 
design conditions. 
 
This staff confirmed that the "detection of aging e ffects" program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.4. The staff finds this program element
 
acceptable.
 
Monitoring and Trending
 
LRA Section B.2.47 states that leak chase channel monitoring activities are performed at least once quarterly. The applicant also stated that the routine task requires that any water collected
 
in excess of one pint is reported to shift supervision. Shift supervision will then notify Nuclear
 
System Engineering by an appropriate mechanism. The applicant further stated that data are
 
entered into the Shift Operations Management System log for trending purposes even if no leakage was identified.
The staff reviewed the applicant's "monitoring and trending" program element against the
 
criteria in SRP-LR Section A.1.2.3.5 which states that the 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.
The staff found that the "monitoring and trending" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.5 because the app licant provides predictability of the extent of degradation and thus effects timely corrective or mitigative actions e.g
., monitoring activities are performed at least once quarterly and evaluation of the results against the acc eptance criteria, and a prediction regarding the rate of degradation before a loss of stru ctures component intended function.
The staff confirmed that the "monitoring and trending" program element satisfies t he criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.5. The staff finds this program element acceptable.
Acceptance Criteria LRA Section B.2.47 states the acceptance criterion is less than one pint of measured leakage
 
from each liner leak chase drain valve. The applicant also stated that the one pint criterion is
 
based on SSES plant-specific historical accumulation of water at Unit 2 spent fuel pool drain
 
points. 
 
The staff reviewed the "acceptance criteria" program element against the criteria in SRP-LR
 
Section A.1.2.3.6 which states that the acceptance criteria of the program and its basis should 3-187 be described. The staff found that the "acceptance criteria" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.6 since; the applicant has provided the
 
predetermined criteria as quantitative inspections by personnel in accordance with the approved
 
site-specific programs. On this basis, the staff finds this program element acceptable.
 
Operating Experience. The staff also reviewed the applicant's OE described in LRA Section B.2.47, "Operation Experience Review Report (Leak Chase Channel Monitoring
 
Activities' section)", and to confirm that the plant-specific OE have been reviewed by the
 
applicant. The staff found that the Leak Chase Channel Monitoring Activities have indicated
 
small leakage in the Unit 2 spent fuel pool. The Unit 1 spent fuel pool and the common fuel
 
shipping cask storage pool liners have shown no leakage. The staff reviewed CR 94-251 (April 4, 1994) Reported leakage from Fuel Pool drain valves 253082A thru valves 253082E and found: for the first time in three months, valves 253082A has 40 gallons, and all of other valves (valves 253082B - valves 253082E were dry. However, on December 5, 2006, OPS PM S5477 (CR 830720) identified no leakage at valve 253082A, and therefore, the tracking and trending
 
was closed. The applicant noted in the LRA that, based on the expected leakage from this small
 
leak as well as minor drainage previously noted at liner drain valves "B" and "E," the inspection
 
frequency has been accelerated to monthly for the Unit 2 spent fuel pool. For the past five
 
years, the Unit 2 spent fuel pool liner leakage measurements have all been within the
 
acceptance criteria.
 
The staff confirmed that the A 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.1.2.27, Commitment No. 41, the applicant provided the UFSAR supplement for the leak Chase Channel Monitoring Activities. 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 technical review of the applicant's Leak Chase Channel Monitoring Activities, the staff concludes that the applicant has demonstrated that the effects of
 
aging will be adequately managed so that the intended function(s) will be maintained consistent
 
with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff
 
also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.3.3  Preventive Maintenance Activities - RCIC/HPCI Turbine Casings 
 
Summary of Technical Information in the Application. LRA Section B.2.48 describes the existing Preventive Maintenance Activities - RCIC/HPCI Turbine Casings as a plant-specific AMP. The applicant stated that this program manages loss of material due to general corrosion on internal
 
surfaces of RCIC and HPCI pump casings, and on piping and piping components such as
 
rupture disks and valve bodies made of carbon steel or cast iron.
 
Staff Evaluation. The staff reviewed the Preventive Maintenance Activities - RCIC/HPCI Turbine Casings as an existing program that is plant-specific. There is no corresponding AMP in the
 
GALL Report.
 
The staff reviewed the Preventive Maintenance Activities - RCIC/HPCI Turbine Casings
 
Program against the AMP elements found in SRP-LR Section A.1.2.3 and SRP-LR Table A.1-1, 3-188 focusing on how the program manages aging effects through the effective incorporation of 10 elements (i.e., "scope of program," "preventive ac tions," "parameters monitored or inspected,"
"detection of aging effects," "monitoring and trending," "acceptance criteria," "corrective actions,"
 
"confirmation process," "administrative controls," and "operating experience"). 
 
The applicant indicated that the "corrective actions," "confirmation process," and "administrative
 
controls" program elements are part of the LRA Section B.1.3, Quality Assurance Program and
 
Administrative Controls. The staff's evaluation of LRA Section B.1.3 program is discussed in
 
SER Section 3.0.4. The remaining seven elements are discussed below.
 
Scope of Program
 
LRA Section B.2.48 states that this program will manage loss of material due to general corrosion of the internal carbon steel and cast iron surfaces in the RICI and HPCI pump turbine
 
casings and in-scope piping and piping components in steam lines downstream from the steam admission valves that are exposed to ambient air during normal plant operation. The applicant
 
stated that this ambient air internal environment is untreated and will be moist as a result of
 
steam that has condensed and drained to the barometric condensers or vented to the drywell. 
 
The staff reviewed the applicant's "scope of the program" program element against the criteria
 
in SRP-LR Section A.1.2.3.1 which states that, "The specific program necessary for license
 
renewal should be identified. The scope of the program should include the specific structures
 
and components of which the program manages the aging."
 
In its letter dated October 21, 2008, in response to the NRC regional inspection of the LRA, the
 
applicant included an enhancement in the "scope of program" program element to include a
 
specific step to perform a visual inspection of the RCIC turbine casing. The staff finds the
 
enhancement acceptable because the enhancement provides details that makes the "scope of
 
program" program element satisfy the criterion defined in SRP-LR Section A.1.2.3.1. 
 
The staff finds this program element acceptable because it adequately describes the scope of
 
the program. 
 
The staff confirmed that the "scope of the program" (called the "scope of activity" in the LRA)
 
program element satisfies the criterion defined in SRP-LR Section A.1.2.3.1. The staff finds this
 
program element acceptable.
Preventive Actions
 
LRA Section B.2.48 states that no actions are taken as part of the Preventive Maintenance Activities - RCIC/HPCI Turbine Casings Program to prevent aging effects or to mitigate age-
 
related degradation.
 
The staff reviewed the applicant's "preventive actions" program element against the criteria in
 
SRP-LR Section A.1.2.3.2-2., which states that condition monitoring or performance monitoring
 
programs do not rely on preventive actions.
 
Since this is a condition monitoring program, the staff concludes that this program does not rely
 
on preventive actions.
 
The staff confirmed that the "preventive actions" program element satisfies the criterion defined 3-189 in SRP-LR Section A.1.2.3.2-2. The staff finds this program element acceptable.
Parameters Monitored or Inspected
 
LRA Section B.2.48 states that this program inspects the internal carbon steel surfaces of RCIC and HPCI pump turbine casings and the cast iron surfaces of the associated gland cases for
 
signs of degradation for evidence of loss of material.
 
The staff reviewed the applicant's "parameters monitored or inspected" program element against the criteria in SRP-LR Section A.1.2.3.3, which states that for a condition monitoring
 
program, the parameter monitored or inspected should detect the presence and extent of aging
 
effects. 
 
By letter dated July 9, 2008, the staff issued RAI B.2.48-1 asking the applicant to provide more
 
details of the types of inspections that will be conducted. Specifically, the staff asked the
 
applicant to provide the method used to inspect, the frequency of inspections, and the type of
 
data collected. By letter dated August 12, 2008, the applicant responded that the inspection of
 
RCIC and HPCI pump turbine internals, including the casings, is a skill-based visual inspection
 
performed by Mechanical Maintenance personnel. The inspection follows SSES procedures and
 
includes inspections for loose parts, mechanical damage, corrosion, erosion, pitting, scare
 
deposits, and other abnormal wear. The procedure for the HPCI turbine includes visual
 
inspection for the turbine casing which was not included in the RCIC turbine. A commitment (Commitment No. 42) has been added to the LRA committing to an enhancement to add the
 
visual inspection for the RCIC turbine. The applicant also stated that the frequency of
 
inspections will be a 10-year frequency and any deficiencies noted will be entered into the
 
corrective action program for evaluation.
 
The staff finds this program element acceptable, because in response to RAI B.2.48-1 the
 
applicant has appropriately identified the inspection methods, frequency of testing and the type
 
of data collected. 
 
The staff confirmed that the "parameters monitor ed or inspected" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff finds this program element acceptable.
 
Detection of Aging Effects
 
LRA Section B.2.48 states that this program will detect loss of material prior to any loss of component intended functions. 
 
The staff reviewed the applicant's "detection of aging effects" program element against the
 
criteria in SRP LR Section A.1.2.3.4, which states that 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, and data collection.
 
The staff concluded that there was insufficient information in the LRA for this program element.
 
By letter dated July 9, 2008, the staff issued RAI B.2.48-1 asking the applicant to provide more
 
details of the types of inspections that will be conducted. Specifically, the staff asked the
 
applicant to provide the method used to inspect, the frequency of inspections, and the type of
 
data collected. By letter dated August 12, 2008, the applicant responded that the answer to this 3-190 RAI is contained in the response to RAI B.2.48 discussed under the "parameters monitored or inspected" program element.
 
The staff finds this program element acceptable because it is a condition monitoring program
 
that uses inspection techniques to identify loss of material and the response to the RAI gives
 
adequate details of the inspection techniques.
 
In its letter dated October 21, 2008, in response to the NRC regional inspection of the LRA, the
 
applicant included an enhancement in the "detection of aging effects" program element to add
 
requirements to have inspections performed by qualified personnel using VT-3 or equivalent
 
inspection methods, and to document and trend inspection results.
 
The staff finds the enhancement acceptable because the applicant has provided qualifications
 
of personnel performing the visual inspections.
 
The staff confirmed that the "detection of aging e ffects" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.4. The staff finds this program element acceptable. 
 
Monitoring and Trending LRA Section B.2.48 states that "this is a condition monitoring program that uses visual
 
inspections to identify internal degradation of turbine casings. The observation of significant, unusual, or unexpected casing degradation is noted and is followed up by writing a condition
 
report. The condition report may result in a condition assessment or further inspection. The
 
disposition of the condition may result in a change in the frequency of inspection."
 
The SRP-LR Section A.1 2 3.5 states that: "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. Pl ant-specific and/or industry-wide OE may be considered in evaluating the appropriateness of the technique and frequency."
 
The staff finds that the "monitoring and trending" program element is acceptable because, in
 
response to RAI B.2.48-1, the applicant has supplied sufficient detail for the staff to find that
 
monitoring and trending activities have been described and any significant degradation will
 
result in a condition assessment that will determine if more frequent inspections are required.
 
In its letter dated October 21, 2008, in response to the NRC regional inspection of the LRA, the
 
applicant included an enhancement in the "monitoring and trending" program element to add
 
requirements to have inspections performed by qualified personnel using VT-3 or equivalent
 
inspection methods, and to document and trend inspection results.
 
The staff finds the enhancement acceptable because the applicant has indicated that qualified
 
personnel will document and trend inspection results, which make the "monitoring and trending"
 
program element, satisfy the criterion defined in SRP-LR Section A.1.2.3.5
 
The staff confirmed that the "monitoring and trendi ng" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.5. The staff finds this program element acceptable.
 
Acceptance Criteria
 
3-191 LRA Section B.2.48 states that the acceptance criteria for this program are no unacceptable visual indications of wall-thinning or loss of material. The applicant further stated that
 
unacceptable in this program involves a determination by engineering evaluation that the
 
components are degraded to the point that they may not be capable of performing their intended
 
function until the next scheduled inspection.
 
The staff reviewed the applicant's "acceptance criteria" program element against the criteria in
 
SRP-LR Section A.1.2.3.6 which states that 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 and the program should include a methodology for analyzing the results against
 
applicable acceptance criteria.
 
In its letter dated October 21, 2008, in response to the NRC regional inspection of the LRA, the
 
applicant included an enhancement in the "acceptance criteria" program element to establish specific acceptance criteria for inspection results, similar to those of ASME Section XI, IWE
 
3519.1, used for pump casing inspection.
 
The staff finds the enhancement acceptable because specific acceptance criteria are identified
 
in addition to the engineering evaluation for determining the extent of age related degradation.
 
The staff finds the "acceptance criteria" program element acceptable because the applicant has
 
identified the acceptance criteria and will use engineering evaluation to determine the extent of
 
degradation and the need for corrective action.
 
The staff finds that the "acceptance criteria" program element is acceptable because it satisfies
 
the recommendations in the SRP-LR Section A.1.2.3.6-1.
 
Operating Experience. The applicant stated in LRA Section B.2.48 that a search of plant-specific OE for the most recent five-year period, no loss of pressure boundary integrity was
 
identified that could be attributed to the applicable aging effects in the scope of this program.
 
The staff reviewed the applicant's "operating experi ence" program element against the criteria in SRP LR Section A.1.2.3.1, which states that OE with existing programs should be discussed.
 
The OE of aging management programs, including pas t corrective actions resulting in program enhancements or additional programs, should be considered.
 
The staff reviewed the applicant's OE described in LRA Section B.2.48. The applicant stated
 
that this program is consistent with industry practice and has proven effective in maintaining the
 
material condition of the RCIC and HPCI pump turbine casings. 
 
By letter dated July 9, 2008, the staff issued RAI B.2.48-2 asking the applicant to provide more
 
details of the types of inspections that will be conducted. Specifically, the staff asked the
 
applicant to explain how a monitoring program can ensure how monitoring for loss of material
 
will maintain the material condition. By letter dated August 12, 2008, the applicant responded
 
that the answer to RAI B.2.48-2 is contained in the response to RAI B.2.48-1 discussed under
 
the "parameters monitored or inspected" program element.
 
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 pending
 
acceptance of the response to RAI B.2.48-2.
3-192  UFSAR Supplement. In LRA Section A.1.2.39, Commitment No. 42, the applicant provided the UFSAR supplement for the Preventive Maintenance Activities - RCIC/HPCI Turbine Casings
 
Program. The staff reviewed this section and determined that the information in the UFSAR
 
Supplement does not provide an adequate summary description of the program consistent with
 
the SRP-LR.
 
By letter dated July  9, 2008, the staff issued RAI B.2.48-1 asking the applicant to provide more
 
details of the types of inspections that will be conducted. Specifically, the staff asked the
 
applicant to provide the method used to inspect, the frequency of inspections, and the type of
 
data collected. By letter dated August 12, 2008, in response to RAI B.2.48-1, the applicant
 
responded that the inspection of RCIC and HPCI pump turbine internals, including the casings, is a skill-based visual inspection performed by Mechanical Maintenance personnel. The
 
inspection follows SSES procedures and includes inspections for loose parts, mechanical
 
damage, corrosion, erosion, pitting, scare deposits, and other abnormal wear. In its letter dated
 
October 21, 2008, in response to the NRC regional inspection of the LRA, the applicant revised
 
the UFSAR supplement to include the following three enhancements:
 
A specific step to perform a visual inspection of the RCIC turbine casing  Performance of inspections by qualified personnel using VT-3 or equivalent inspection methods, and to document and trend inspection results  Specific acceptance criteria for inspections
 
The applicant has revised Commitment No. 42 to include these commitments. 
 
Based on acceptable responses to the RAI and on the amendment to the UFSAR supplement in
 
terms of the revision to the commitment list, the staff finds the UFSAR supplement is
 
acceptable.
 
The staff determines that the information in the UFSAR Supplement provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
 
Conclusion. The staff finds the applicant's Preventive Maintenance Activities - RCIC/HPCI Turbine Casings Program acceptable on the basis of its review as discussed above. The staff
 
finds that the program will adequately manage the aging effects so that the intended functions
 
will be maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and finds that
 
it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
 
3.0.3.3.4 Preventive Maintenance Activities - Main Turbine Casing
 
Summary of Technical Information in the Application. In its letter dated June 30, 2008 and September 26, 2008, the applicant added a plant-specific existing program, Section B.2.49, "Preventive Maintenance Activities - Main Turbine Casing," with an enhancement. 
 
The applicant stated that the Preventive Maintenance Activities - Main Turbine Casing will
 
manage loss of material due to FAC on the internal surfaces of the high pressure casing for the
 
main turbine.
 
Staff Evaluation. The staff reviewed the Preventive Maintenance Activities - Main Turbine Casing Program against the AMP elements found in the GALL Report, SRP-LR Section A.1.2.3, 3-193 and SRP-LR Table A.1-1, focusing its review on how the program manages aging effects through the effective incorporation of 10 elements (i.e., "scope of program," "preventive actions,"
"parameters monitored or inspected," "detection of aging effects," "monitoring and trending,"
 
"acceptance criteria," "corrective actions," "confirmation process," "administrative controls," and
 
"operating experience"). 
 
The applicant indicated that the "corrective actions," "confirmation process," and "administrative
 
controls" program elements are part of the LRA Section B.1.3, Quality Assurance Program and
 
Administrative Controls. The staff's evaluation of LRA Section B.1.3 program is discussed in
 
SER Section 3.0.4. The remaining seven elements are discussed below.
 
Enhancement
 
In LRA Section B.2.49, the applicant identified an enhancement to the program to specify that
 
the inspection of the high pressure turbine shell will consist of a visual inspection (VT-3 or
 
equivalent) and an ultrasonic examination for wall thickness. 
 
The staff reviewed the enhancement and determined that implementation of the enhancement
 
will add the inspection techniques necessary to adequately manage the aging effects of loss of
 
material due to FAC during the period of extended operation. As stated in "detection of aging
 
effects" program element above, visual ins pection will be performed to detect any age related degradation and if detected, ultrasonic inspection will be performed to determine the extent of
 
the degradation. Based on the review, the staff finds the enhancement acceptable.
 
Scope of Program:
In LRA Section B.2.49, the applicant stated that this program is credited for managing
 
loss of material due to FAC on the internal carbon steel surfaces of the high pressure
 
casing for the main turbine that is exposed to steam during normal plant operation.
The staff reviewed the applicant's "scope of program" program element  against the criteria in SRP-LR Section A.1.2.3.1, which states that the specific program
 
necessary for license renewal should be identified. The scope of the program should
 
include the specific structures and components of which the program manages the
 
aging. The staff concludes that since the applicant has identified the components for which this program manages aging. The staff confir med that the "scope of 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.
Preventive Actions:
In LRA Section B.2.49, the applicant stated that no actions are taken to prevent aging
 
effects or to mitigate age-related degradation.
The staff reviewed the applicant's "preventive actions" program element against the
 
criteria in SRP-LR Section A.1.2.3.2, which states that for condition or performance
 
monitoring programs, they do not rely on pr eventive actions and thus, this information need not be provided.
 
3-194 Since this is a condition monitoring program, the staff concludes that this program does not rely on preventive actions. The staff confir med 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.
Parameters Monitored or Inspected:
In LRA Section B.2.49, the applicant stated that the program inspects the  internal
 
carbon steel surfaces of the high pressure turbine casing for signs of degradation that
 
might be indicative of wall-thinning or loss of material. Inspections will consist of a combination of visual examination and non- destructive testing.
The staff reviewed the applicant's "parameters monitored or inspected" program element against the criteria in SRP-LR Section A.1.2.3.3, which states that for a condition monitoring program, the parameter monitored or inspected should detect the presence
 
and extent of aging effects.
Since this is a condition monitoring program, the applicant has appropriately identified
 
the parameter to be inspected and the method of inspection. The staff confirmed that the
 
"parameters monitored or inspected" program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.3. The staff finds this program element
 
acceptable.
 
Detection of aging effects
:  In LRA section B.2.49, the applicant stated that the program will rely on established NDE
 
techniques, including visual (VT-3 or equivalent) inspection of accessible surfaces and
 
ultrasonic inspections of selected locations by qualified personnel to identify surface
 
degradation and wall thickness. Inspections are performed on a nominal 10-year (12-
 
year maximum) frequency based on manufacturer recommendation.
The staff reviewed the applicant's "detection of aging effects" program element against
 
the criteria in SRP-LR Section A.1.2.3.4, which states that 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.
The staff reviewed the operating experience provided by the applicant and noted that
 
based on significant modification work performed on the high pressure turbines during
 
the last five years, no indication of pressure boundary wear was found on the high
 
pressure turbine outer casing. The staff finds that based on plant operating experience, the frequency of once every ten years based on manufacturer's recommendation is
 
acceptable. If visual inspection identifies aging degradation, ultrasonic inspection will be
 
performed to determine the extent of the degradation. 
 
The staff confirmed that the "detection of aging effects" program element satisfies the
 
criterion defined in the GALL Report and SRP-LR Section A.1.2.3.4. The staff finds this
 
program element acceptable.
3-195  Monitoring and Trending:
In LRA Section B.2.49, the applicant stated that this program is a condition monitoring
 
program that is performed by qualified individuals at established intervals through a
 
combination of visual inspection and ultrasonic testing. The applicant further stated that
 
if during the inspection, significant or unusual or unexpected casing deterioration is
 
observed, it will be documented on a condition report (CR); and based on analysis, the
 
CR may result in further inspection or change in frequency.
The staff reviewed the applicant's "monitoring and trending" program element against the criteria in SRP-LR Section A.1.2.3.5, which states that 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.
During the review process, the staff determined that monitoring and trending is not
 
described in enough detail to allow an assessment of the predictability of the extent of
 
degradation. As a result, the staff issued RAI B.2.49-1, by letter dated July  23, 2008, requesting the applicant to provide details describing the methods to assess remaining
 
component life for loss of material using inspection results such that timely mitigative
 
action can be made.
 
In its letter dated August 22, 2008, in response to RAI B.2.49-1 the applicant stated that
 
the inspection is conducted to evaluate the condition of the internal surfaces of the
 
turbine casing and looks for indications of corrosion, and should erosion be detected the
 
condition would be evaluated under the corrective action program, which would
 
determine the margin to minimum wall thickness, acceptability of current condition and
 
future actions including further monitoring and trending. The applicant also stated that
 
the inspection and evaluation of the results are performed in conjunction with the
 
equipment vendor representative who is present during the inspections. Furthermore, the results of the latest inspections conducted in 2003 and 2004, after 20 years of
 
service, found no signs of erosion and the casings were in excellent condition.
 
The staff reviewed the applicant's response and noted that enough information is
 
provided to conclude that the applicant would appropriately identify the degraded
 
condition, and if found, it would be evaluated along with the need for further monitoring
 
and trending. On this basis, the staff finds the response acceptable.
The staff confirmed that the "monitoring and trending" program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.5. The staff finds this
 
program element acceptable.
Acceptance Criteria:
In LRA Section B.2.49, the applicant stated that any indications or relevant conditions of
 
degradation will be evaluated. The inspection observations will be compared to
 
predetermined acceptance criteria. Inspection results that do not meet the acceptance
 
criteria will be entered into the corrective action program for evaluation.
 
3-196  The staff reviewed the applicant's "acceptance criteria" program element against the criteria in SRP-LR Section A.1.2.3.6, which states that 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.
The applicant did not provide specific acceptance criteria or its basis such as
 
comparison to design minimum wall or manufacturer suggested minimum wall in order to
 
provide the basis for evaluation. The staff issued RAI B.2.49-2 by letter dated
 
July 23, 2008 requesting the applicant to provide more details on how acceptance
 
criteria will be established.
 
In its letter dated August 22, 2008, in response to RAI B.2.49-2, the applicant stated that
 
the inspection is conducted to evaluate the condition of the internal surfaces of the
 
turbine casing and looks for indications of corrosion; and should erosion be detected the
 
condition would be evaluated under the corrective action program, which would
 
determine the margin to minimum wall thickness, acceptability of current condition and
 
future actions including further monitoring and trending. The applicant also stated that
 
the inspection and evaluation of the results rely on industry experience with the turbine
 
equipment and are performed in conjunction wi th the equipment vendor representative who is present during the inspections. Furthermore, the results of the latest inspections
 
conducted in 2003 and 2004, after 20 years of service, found no signs of erosion and the
 
casings were in excellent condition. 
 
The staff reviewed the applicant's response and noted that enough information is
 
provided to conclude that the applicant would appropriately identify the degraded
 
condition, and if found, it would evaluate the need for further corrective action. Since the
 
inspections are conducted in the presence of the equipment vendor representative, an
 
appropriate technical review will be performed on the inspection results. On this basis, the staff finds the response acceptable. 
 
The staff confirmed that the "acceptance criter ia" program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.6. The staff finds this program
 
element acceptable.
Operating Experience.
In LRA Section B.2.49, the applicant stated that a review of plant OE for the most recent five-year period did not reveal any age-related degradation for the main
 
turbine casing. The applicant further stated that both high pressure turbines have been the
 
object of significant modifications and the work associated with these modifications revealed
 
no indication of pressure boundary wear on the high pressure turbine outer casing.
The staff reviewed the applicant's "operating experience" program element against the
 
criteria in SRP-LR Section A.1.2.3.1, which states that OE with existing programs should be
 
discussed. The OE of aging management programs, including past corrective actions
 
resulting in program enhancements or additional programs, should be considered. The staff reviewed the OE provided by the applicant to confirm that the plant-specific OE did
 
not reveal any degradation not bounded by industry experience. 
 
3-197 The staff confirmed that the "operating experienc e" program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
UFSAR Supplement. In its letter dated September 26, 2008, the applicant provided the UFSAR supplement Section A.2.1.50, for the Preventive Maintenance Activities - Main
 
Turbine Casing Program. The applicant added Commitment No. 57 to enhance the program
 
to add the inspection techniques. The staff reviewed this section and determines that the
 
information in the UFSAR supplement provides 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 Preventive Maintenance Activities - Main Turbine Casing Program, including the applicant's responses to the RAIs
 
and the enhancement, the staff concludes that the applicant has demonstrated that the
 
effects of aging will be adequately managed so that the intended function(s) will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concludes that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.4  Quality Assurance Program Attribut es Integral to Aging Management Programs 3.0.4.1  Summary of Technical Information in the Application In Sections  A.1.2, A Aging Management Program and Activities,@ and B.1.3, A Quality Assurance Program and Administrative Controls,@ of the license renewal application (LRA), the applicant described the elements of corrective action, conf irmation process, and administrative controls that are applied to the AMPs for both safety-related (SR) and nonsafety-related components.
 
The SSES Operational Quality Assurance (OQA) Program is used which includes the elements
 
of corrective action, confirmation process, and administrative controls. Corrective actions, confirmation, and administrative controls are applied in accordance with the OQA Program
 
regardless of the safety classification of the components. Specifically, in Section A.1.2 and
 
Section B.1.3, respectively, the applicant stated that the QA Program implements the
 
requirements of 10 CFR Part 50, Appendix B, and is consistent with NUREG-1800, A Standard Review Plan for Review of license Renewal Applications for Nuclear Power Plants.
@  Section B.2, A Aging Management Programs,@ of the LRA provided an aging management review (AMR) summary for each unique component type or commodity group determined to require aging management during the period of extended operation.
3.0.4.2  Staff Evaluation Pursuant to 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects of
 
aging on SCs subject to an AMR will be adequately managed so that their intended functions
 
will be maintained consistent with the CLB for the period of extended operation. NUREG-1800, 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 control. 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:
 
3-198
* Corrective actions, including root cause determination and prevention of recurrence, should be timely;
* The confirmation process should ensure that preventive actions are adequate and that appropriate corrective actions have been completed and are effective; and,
* Administrative controls should provide a formal review and approval process.
 
NUREG-1800, Branch Technical Position IQMB-1 noted that those aspects of the AMP that
 
affect quality of safety-related SSCs are subject to the QA requirements of Appendix B to
 
10 CFR Part 50. Additionally, for nonsafety-related SCs subject to an AMR, the applicant's
 
existing Appendix B to 10 CFR Part 50 QA program 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:
 
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 aging management programs (AMPs) described in Appendix A, A Final Safety Analysis Report Supplement,@ and Appendix B, A Aging Management Programs,@ of the LRA, and the LRDs. The purpose of this review was to ensure that the quality assurance attributes (corrective action, confirmation process, and administrative controls) were consistent with the staff
=s guidance described in NUREG-1800, 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.1.2, and Appendix B, Section B.1.3, of the LRA are consistent with the staff=s position regarding quality assurance for aging management.
3.0.4.3  Conclusion On the basis of the NRC staff
=s evaluation, the staff concludes that the descriptions and applicability of the plant-specific AMPs and their associated quality attributes provided in Appendix A, Section A.1.2, and Appendix B, Section B.1.3 and Section B.2, of the LRA, are
 
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, Internals, and Reactor Coolant System This section of the SER documents the staff's review of the applicant's AMR results for the RV, RV internals, and reactor coolant system components and component groups of:
* Reactor Pressure Vessel
* Reactor Vessel Internals 3-199
* Reactor Coolant System Pressure Boundary 3.1.1  Summary of Technical Information in the Application LRA Section 3.1 provides AMR results for the RV, RV internals, and reactor coolant system
 
components and component groups. LRA Table 3.1.1, "Summary of Aging Management
 
Programs for Reactor Vessel, Reactor Vessel In ternals, and Reactor Coolant System Evaluated in Chapter IV of the GALL Report," is a summary comparison of the applicant's AMRs with
 
those evaluated in the GALL Report for the RV, RV internals, and reactor coolant system
 
components and component groups.
 
The applicant's AMRs evaluated and incorporated applicable plant-specific and industry OE 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 OE included a review of the GALL Report and OE 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 RV, RV internals, and reactor coolant
 
system 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 onsite 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 3.1.2.1.
 
In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which
 
further evaluation is recommended. The staff confirmed that the 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 OE 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
 
3-200  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 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
 
RV components:
 
flanges; nozzles;
 
penetrations; safe
 
ends; thermal
 
sleeves; vessel
 
shells, heads and welds (3.1.1-2)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and
 
environmental effects
 
are to be addressed
 
for Class 1
 
components  Yes 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
 
RCPB piping, piping
 
components, and
 
piping elements
 
exposed to reactor
 
coolant (3.1.1-3)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and
 
environmental effects
 
are to be addressed
 
for Class 1
 
components Yes TLAA Fatigue is a TLAA (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 SSES.  (See SER
 
Section 3.1.2.2.1)
Stainless steel and nickel alloy RV
 
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 FW/steam
 
environment
 
(3.1.1-6)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.1) 3-201 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel and stainless steel RCPB closure
 
bolting, head closure
 
studs, support skirts
 
and attachment welds, pressurizer
 
relief tank
 
components, 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 Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.1)
Steel; stainless steel; and nickel-alloy
 
RCPB piping, piping
 
components, piping
 
elements; flanges;
 
nozzles and safe
 
ends; pressurizer
 
vessel shell heads and welds; heater
 
sheaths and sleeves;
 
penetrations; and
 
thermal sleeves
 
(3.1.1-8)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and
 
environmental effects
 
are to be addressed
 
for Class 1
 
components Yes Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.1)
Steel; stainless steel; steel with nickel-alloy
 
or stainless steel cladding; nickel-alloy
 
RV components:
 
flanges; nozzles;
 
penetrations;
 
pressure housings;
 
safe ends; thermal
 
sleeves; vessel
 
shells, heads and welds (3.1.1-9)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and
 
environmental effects
 
are to be addressed
 
for Class 1
 
components Yes Not applicable Not applicable to BWRs (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 Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.1) 3-202 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 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 Inspection Yes BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22), or BWR Water Chemistry
 
Program (B.2.2)
 
and Inservice
 
Inspection (ISI)
 
Program (B.2.1) Consistent with GALL Report (See SER Section 3.1.2.2.2.1)
Steel steam
 
generator shell assembly exposed to secondary FW 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 BWRs (See SER
 
Section 3.1.2.2.2.1)
Steel and stainless
 
steel isolation
 
condenser
 
components exposed
 
to reactor coolant
 
(3.1.1-13)
Loss of material due to general (steel only),
pitting and
 
crevice corrosion Water Chemistry and One-Time InspectionYes Not applicable Not applicable to BWRs  (See SER
 
Section 3.1.2.2.2.2)
Stainless steel, nickel-alloy, and steel with nickel-alloy or
 
stainless steel
 
cladding RV flanges,
: nozzles, penetrations, safe
 
ends, vessel shells, heads and welds
 
(3.1.1-14)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time Inspection Yes BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22), or BWR Water Chemistry
 
Program (B.2.2)
 
and Inservice
 
Inspection (ISI)
 
Program (B.2.1),
or BWR Water Chemistry
 
Program (B.2.2) and BWR Vessel Internals
 
Program (B.2.9) Consistent with GALL Report (See SER Section 3.1.2.2.2.3) 3-203 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 RCPB
 
components exposed
 
to reactor coolant
 
(3.1.1-15)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time Inspection Yes BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22), or BWR Water Chemistry
 
Program (B.2.2)
 
and Inservice
 
Inspection (ISI)
 
Program (B.2.1) Consistent with GALL Report (See SER Section 3.1.2.2.2.3)
Steel steam
 
generator upper and lower shell and
 
transition cone
 
exposed to secondary FW 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 Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.2.4) Steel (with or without
 
stainless steel
 
cladding) RV beltline
 
shell, nozzles, and welds (3.1.1-17)
Loss of fracture toughness due
 
to neutron
 
irradiation
 
embrittlement TLAA, evaluated in accordance with 10 CFR Part 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) RV 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.2.21) Consistent with GALL Report (See
 
SER Section
 
3.1.2.2.3.2) 3-204 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 top head
 
enclosure vessel
 
flange leak detection
 
line (3.1.1-19)
Cracking due to SCC and IGSCC A plant-specific aging management
 
program is to be
 
evaluated. Yes BWR Water Chemistry
 
Program (B.2.2)
 
and Small Bore
 
Class 1 Piping
 
Inspection (B.2.31) Consistent with GALL Report (See SER Section 3.1.2.2.4.1)
Stainless steel
 
isolation condenser
 
components exposed
 
to reactor coolant
 
(3.1.1-20)
Cracking due to SCC and IGSCC Inservice Inspection (IWB, IWC, and IWD),
Water Chemistry, and plant-specific
 
verification program Yes Not applicable See SER Section 3.1.2.2.4.2 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 BWRs (See SER
 
Section 3.1.2.2.5)
Stainless steel and nickel alloy RV
 
internals components
 
exposed to reactor
 
coolant and neutron flux (3.1.1-22)
Loss of fracture toughness due
 
to neutron
 
irradiation
 
embrittlement, void swelling 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. No Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.6)
Stainless steel RV
 
closure head flange
 
leak detection line
 
and bottom-mounted
 
instrument guide
 
tubes (3.1.1-23)
Cracking due to SCC A plant-specific aging management
 
program is to be
 
evaluated. Yes Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.7.1)
Class 1 CASS
 
piping, piping
 
components, and
 
piping elements
 
exposed to reactor
 
coolant (3.1.1-24)
Cracking due to SCC Water Chemistry and, for CASS
 
components that do
 
not meet the
 
NUREG-0313
 
guidelines, a plant-
 
specific AMP Yes Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.7.2) 3-205 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel jet pump sensing line
 
(3.1.1-25)
Cracking due to cyclic loading A plant-specific aging management
 
program is to be
 
evaluated. Yes BWR Water Chemistry
 
Program (B.2.2)
 
and Small Bore
 
Class 1 Piping
 
Inspection (B.2.31) Consistent with GALL Report  (See SER Section 3.1.2.2.8.1)
Steel and stainless
 
steel isolation
 
condenser
 
components exposed
 
to reactor coolant
 
(3.1.1-26)
Cracking due to cyclic loading Inservice Inspection (IWB, IWC, and IWD) and
 
plant-specific
 
verification program Yes Not applicable See SER Section 3.1.2.2.8.2 Stainless steel and nickel alloy RV internals screws, bolts, tie rods, and hold-down springs
 
(3.1.1-27)
Loss of preload due to stress
 
relaxation 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. No Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.9)
Steel steam generator FW
 
impingement plate
 
and support exposed to secondary FW
 
(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 BWRs (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 BWR Vessels Internals (B.2.9),          Consistent with GALL Report (See SER Section
 
3.1.2.2.11) 3-206 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel RV internals components (e.g., Upper internals assembly, 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 SCC, IASCC 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. No Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.12) Nickel alloy and steel with nickel-alloy
 
cladding piping, piping component, piping elements, penetrations, nozzles, safe ends, and welds (other
 
than RV head);
 
pressurizer heater
 
sheaths, sleeves, diaphragm plate, manways and
 
flanges; core support
 
pads/core guide lugs
 
(3.1.1-31)
Cracking due to primary water
 
SCC 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. No Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.13)
Steel steam generator FW inlet
 
ring and supports
 
(3.1.1-32) Wall thinning due to FAC A plant-specific aging management
 
program is to be
 
evaluated. Yes Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.14) 3-207 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 RV
 
internals components
 
(3.1.1-33)
Changes in dimensions due to void swelling 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. No Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.15)
Stainless steel and nickel alloy reactor
 
CRD head penetration pressure
 
housings (3.1.1-34)
Cracking due to SCC and primary water
 
SCC 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. No Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.16.1)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 SCC and primary water
 
SCC 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. No Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.16.1) 3-208 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, stainless steel pressurizer spray head
 
(3.1.1-36)
Cracking due to SCC and primary water
 
SCC 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. No Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.16.2)
Stainless steel and nickel alloy RV
 
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 SCC, primary water SCC, IASCC 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. No Not applicable Not applicable to BWRs (See SER
 
Section 3.1.2.2.17) Steel (with or without
 
stainless steel
 
cladding) CRD return
 
line nozzles exposed
 
to reactor coolant
 
(3.1.1-38)
Cracking due to cyclic loading BWR Control Rod Drive Return Line
 
Nozzle No BWR CRD Return Line
 
Nozzle (B.2.6) Consistent with GALL Report Steel (with or without
 
stainless steel cladding) FW
 
nozzles exposed to
 
reactor coolant
 
(3.1.1-39)
Cracking due to cyclic loading BWR Feedwater Nozzle No BWR Feedwater Nozzle (B.2.5) Consistent with GALL Report 3-209 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel and nickel alloy
 
penetrations for CRD
 
stub tubes
 
instrumentation, jet
 
pump instrumentation, SLC, flux monitor, and drain line
 
exposed to reactor
 
coolant (3.1.1-40)
Cracking due to SCC, IGSCC, cyclic loading BWR Penetrations and Water ChemistryNo BWR Penetrations (B.2.8),     
 
BWR Water Chemistry (B.2.2) Consistent with GALL Report 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 SCC and IGSCC BWR Stress Corrosion Cracking and Water ChemistryNo BWR Stress Corrosion
 
Cracking (B.2.7),         
 
BWR Water Chemistry (B.2.2) Consistent with GALL Report Stainless steel and nickel alloy vessel
 
shell attachment welds exposed to
 
reactor coolant
 
(3.1.1-42)
Cracking due to SCC and IGSCC BWR Vessel ID Attachment Welds and Water ChemistryNo BWR Vessel ID Attachment
 
Welds (B.2.9),         
 
BWR Water Chemistry (B.2.2) Consistent with GALL Report Stainless steel fuel
 
supports and CRD
 
assemblies CRD
 
housing exposed to
 
reactor coolant
 
(3.1.1-43)
Cracking due to SCC and IGSCC BWR Vessel Internals and Water Chemistry No BWR Vessel Internals (B.2.9),         
 
BWR Water Chemistry (B.2.2)  Consistent with GALL Report Stainless steel and nickel alloy core
 
shroud, core plate, core plate bolts, support structure, top guide, core spray
 
lines, spargers, jet
 
pump assemblies, CRD housing, nuclear instrumentation
 
guide tubes
 
(3.1.1-44)
Cracking due to SCC, IGSCC, IASCC BWR Vessel Internals and Water Chemistry No BWR Vessel Internals (B.2.9),         
 
BWR Water Chemistry (B.2.2) ,   
 
Inservice
 
Inspection (B.2.1) Consistent with GALL Report 3-210 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel piping, piping components, and
 
piping elements
 
exposed to reactor
 
coolant (3.1.1-45) Wall thinning due to FAC Flow-Accelerated Corrosion No Flow-Accelerated
 
Corrosion
 
Program (B.2.11) Consistent with GALL Report Nickel alloy core
 
shroud and core
 
plate access hole
 
cover (mechanical
 
covers)
(3.1.1-46)
Cracking due to SCC, IGSCC, IASCC Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry No Not applicable Not applicable to SSES (See SER
 
Section 3.1.2.1.1)
Stainless steel and nickel-alloy RV
 
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 Addressed under item 3.1.1-14 (See
 
SER Section
 
3.1.2.1.1)
Steel and stainless
 
steel Class 1 piping, fittings and branch connections < NPS 4
 
exposed to reactor
 
coolant (3.1.1-48)
Cracking due to SCC, IGSCC (for stainless steel only), and
 
thermal and
 
mechanical
 
loading Inservice Inspection (IWB, IWC, and IWD),
Water chemistry, and One-Time Inspection
 
of ASME Code
 
Class 1 Small-bore
 
Piping No Inservice Inspection (ISI)
 
Program (B.2.1),
BWR Water Chemistry
 
Program (B.2.2),
and Small Bore
 
Class 1 Piping
 
Inspection (B.2.31), or Inservice Inspection (ISI)
 
Program (B.2.1)
 
and Small Bore
 
Class 1 Piping
 
Inspection (B.2.31) Consistent with GALL Report  (See SER Section 3.1.2.1.2.) Nickel alloy core
 
shroud and core
 
plate access hole cover (welded
 
covers)
(3.1.1-49)
Cracking due to SCC, IGSCC, IASCC 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 Inservice Inspection (B.2.1),     
 
BWR Water Chemistry (B.2.2)  Consistent with GALL Report Access hole covers do not have a crevice 3-211 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation High-strength low alloy steel top head
 
closure studs and
 
nuts exposed to air with reactor coolant
 
leakage (3.1.1-50)
Cracking due to SCC and IGSCC Reactor Head Closure Studs No Reactor Head Closure Studs
 
Program (B.2.3) Consistent with GALL Report 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 Thermal Aging and Neutron
 
Irradiation
 
Embrittlement of
 
CASS (B.2.10) Consistent with GALL Report Steel and stainless
 
steel RCPB (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 SCC, 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.2.12) Consistent with GALL Report Steel piping, piping
 
components, and
 
piping elements
 
exposed to closed cycle cooling water
 
(3.1.1-53)
Loss of material due to general, pitting and
 
crevice corrosion Closed-Cycle Cooling Water System No Not applicable Not applicable to SSES (See SER
 
Section 3.1.2.1.1) 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 SSES (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 C (> 482 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, ISI
 
requirements are
 
sufficient for
 
managing these
 
aging effects. ASME
 
Code Case N-481
 
also provides an
 
alternative for pump
 
casings. No Inservice Inspection (ISI)
 
Program (B.2.1)
Small Bore Class 1 Piping
 
Inspection (B.2.31) Consistent with GALL Report (See SER Section 3.1.2.1.3.)
3-212 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation 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 SSES (See SER
 
Section 3.1.2.1.1)
Cast austenitic
 
stainless steel
 
Class 1 piping, piping
 
component, and
 
piping elements and
 
CRD pressure
 
housings exposed to
 
reactor coolant > 250 C (> 482 F) (3.1.1-57)
Loss of fracture toughness due
 
to thermal aging
 
embrittlement Thermal Aging Embrittlement of
 
CASS No Not Applicable Not Applicable (See SER Section
 
3.1.2.1.1)
Steel RCPB external
 
surfaces exposed to air with borated water
 
leakage (3.1.1-58)
Loss of material due to boric acid
 
corrosion Boric Acid Corrosion No Not applicable Not applicable to BWRs Steel steam
 
generator steam
 
nozzle and safe end, FW nozzle and safe end, AFW nozzles
 
and safe ends
 
exposed to secondary FW/steam
 
(3.1.1-59) Wall thinning due to FAC Flow-Accelerated Corrosion No Not applicable Not applicable to BWRs Stainless steel flux thimble tubes (with or without chrome
 
plating)
(3.1.1-60)
Loss of material due to wear Flux Thimble Tube Inspection No Not applicable Not applicable to BWRs Stainless steel, steel
 
pressurizer integral
 
support exposed to air with metal
 
temperature up to 288 C (550 F) (3.1.1-61)
Cracking due to cyclic loading Inservice Inspection (IWB, IWC, and IWD) No Not applicable Not applicable to BWRs 3-213 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel, 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 Not applicable Not applicable to BWRs Steel RV flange, stainless steel and nickel alloy RV
 
internals exposed to
 
reactor coolant (e.g., upper and lower internals assembly, CEA shroud assembly, core support barrel, upper grid assembly, core support shield assembly, lower grid assembly)
 
(3.1.1-63)
Loss of material due to wear Inservice Inspection (IWB, IWC, and IWD) No Not applicable Not applicable to BWRs Stainless steel and steel with stainless steel or nickel alloy
 
cladding pressurizer
 
components
 
(3.1.1-64)
Cracking due to SCC, primary water SCC Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry No Not applicable Not applicable to BWRs Nickel alloy RV upper
 
head and CRD
 
penetration nozzles, instrument tubes, head vent pipe (top head), and welds
 
(3.1.1-65)
Cracking due to primary water
 
SCC Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry and Nickel-Alloy
 
Penetration Nozzles Welded to the Upper
 
Reactor Vessel
 
Closure Heads of
 
PWRs No Not applicable Not applicable to BWRs 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 BWRs 3-214 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation 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 Not applicable Not applicable to BWRs 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 SCC Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry No Not applicable Not applicable to BWRs Stainless steel, nickel alloy safety
 
injection nozzles, safe ends, and associated welds and
 
buttering exposed to
 
reactor coolant
 
(3.1.1-69)
Cracking due to SCC, primary water SCC Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry No Not applicable Not applicable to BWRs Stainless steel; steel with stainless steel
 
cladding Class 1
 
piping, fittings and
 
branch connections
< NPS 4 exposed to
 
reactor coolant
 
(3.1.1-70)
Cracking due to SCC, thermal
 
and mechanical
 
loading 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 BWRs High-strength low alloy steel closure head stud assembly exposed to air with
 
reactor coolant
 
leakage (3.1.1-71)
Cracking due to SCC; loss of
 
material due to wear Reactor Head Closure Studs No Not applicable Not applicable to BWRs 3-215 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Nickel alloy steam generator tubes and
 
sleeves exposed to secondary FW/steam
 
(3.1.1-72)
Cracking due to OD SCC and
 
intergranular
 
attack, loss of
 
material due to fretting and wear Steam Generator Tube Integrity and Water Chemistry No Not applicable Not applicable to BWRs Nickel alloy steam
 
generator tubes, repair sleeves, and
 
tube plugs exposed
 
to reactor coolant
 
(3.1.1-73)
Cracking due to primary water
 
SCC Steam Generator Tube Integrity and Water Chemistry No Not applicable Not applicable to BWRs Chrome plated steel, stainless steel, nickel alloy steam
 
generator anti-
 
vibration bars
 
exposed to secondary FW/steam
 
(3.1.1-74)
Cracking due to SCC, loss of
 
material due to
 
crevice corrosion and
 
fretting Steam Generator Tube Integrity and Water Chemistry No Not applicable Not applicable to BWRs Nickel alloy once-
 
through steam
 
generator tubes
 
exposed to secondary FW/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 BWRs Steel steam
 
generator tube
 
support plate, tube bundle wrapper
 
exposed to secondary FW/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 Not applicable Not applicable to BWRs Nickel alloy steam
 
generator tubes and
 
sleeves exposed to phosphate chemistry in secondary
 
FW/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 BWRs Steel steam
 
generator tube
 
support lattice bars
 
exposed to secondary FW/steam
 
(3.1.1-78) Wall thinning due to FAC Steam Generator Tube Integrity and Water Chemistry No Not applicable Not applicable to BWRs 3-216 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Nickel alloy steam generator tubes
 
exposed to secondary FW/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 BWRs Cast austenitic
 
stainless steel RV
 
internals (e.g., upper internals assembly, lower internal assembly, CEA
 
shroud assemblies, control rod guide tube assembly, core
 
support shield assembly, lower grid assembly)
 
(3.1.1-80)
Loss of fracture toughness due
 
to thermal aging
 
and neutron
 
irradiation
 
embrittlement Thermal Aging and Neutron Irradiation
 
Embrittlement of
 
CASS No Not applicable Not applicable to BWRs Nickel alloy or nickel-alloy clad steam
 
generator divider
 
plate exposed to
 
reactor coolant
 
(3.1.1-81)
Cracking due to primary water
 
SCC Water Chemistry No Not applicable Not applicable to BWRs Stainless steel steam generator primary
 
side divider plate
 
exposed to reactor
 
coolant (3.1.1-82)
Cracking due to SCC Water Chemistry No Not applicable Not applicable to BWRs Stainless steel; steel with nickel-alloy or
 
stainless steel
 
cladding; and nickel-alloy RV internals
 
and RCPB components exposed
 
to reactor coolant
 
(3.1.1-83)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry No Not applicable Not applicable to BWRs 3-217 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Nickel alloy steam generator
 
components such as, secondary side
 
nozzles (vent, drain, and
 
instrumentation)
 
exposed to secondary FW/steam
 
(3.1.1-84)
Cracking due to SCC Water Chemistry and One-Time Inspection
 
or Inservice Inspection (IWB, IWC, and IWD). No Not applicable Not applicable to BWRs Nickel alloy piping, piping components, and piping elements
 
exposed to air -
 
indoor uncontrolled (external)
 
(3.1.1-85) None None No None  Consistent with 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 GALL Report Steel piping, piping
 
components, and
 
piping elements in
 
concrete (3.1.1-87) None None No Not applicable Not applicable to SSES (See SER
 
Section 3.1.2.1.1)
The staff's review of the RV, RV internals, and reactor coolant system component groups followed any one of several approaches. One approach, documented in SER Section 3.1.2.1, reviewed AMR results for components that the applicant indicated are consistent with the GALL
 
Report and require no further evaluation. Another approach, documented in SER
 
Section 3.1.2.2, reviewed AMR results for components that the applicant indicated are
 
consistent with the GALL Report and for which further evaluation is recommended. A third
 
approach, documented in SER Section 3.1.2.3, reviewed AMR results for components that the
 
applicant indicated are not consistent with, or not addressed in, the GALL Report. The staff's
 
review of AMPs credited to manage or monitor aging effects of the RV, RV internals, and
 
reactor coolant system components is documented in SER Section 3.0.3.
 
3.1.2.1  AMR Results Consistent with the GALL Report LRA Section 3.1.2.1 identifies the materials, environments, AERMs, and the following programs
 
that manage aging effects for the RV, RV internals, and reactor coolant system components:
 
3-218
* Inservice Inspection (ISI) Program
* BWR Water Chemistry Program
* Reactor Head Closure Studs Program
* BWR Vessel ID Attachment Welds Program
* BWR Feedwater Nozzle Program
* BWR CRD Return Line Nozzle Program
* BWR Stress Corrosion Cracking (SCC) Program
* BWR Penetrations Program
* BWR Vessel Internals Program
* Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS)
Program
* Flow-Accelerated Corrosion (FAC) Program
* Bolting Integrity Program
* Closed Cooling Water Chemistry Program
* Reactor Vessel Surveillance Program
* Main Steam Flow Restrictor Inspection
* Small Bore Class 1 Piping Inspection
* System Walkdown Program
* Inservice Inspection (ISI) Program - IWF LRA Tables 3.1.2-1 through 3.1.2-3 summarize AMRs for the RV, RV internals, and reactor coolant system components and indicate AMRs cl aimed 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.
 
3-219 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 GA LL 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. 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 reviewed the LRA to confirm that the applicant: (a) provided a brief description of the
 
system, components, materials, and environments; (b) stated that the applicable aging effects were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the
 
reactor vessel, reactor vessel internals, and RCS components that are subject to an AMR. On
 
the basis of its audit and review, the staff determines that, for AMRs not requiring further
 
evaluation, as identified in LRA Table 3.1.1, the applicant's references to the GALL Report are
 
acceptable and no further staff review is required, with the exception of the following AMRs that
 
the applicant had identified were consistent with the AMRs of the GALL Report and for which
 
the staff felt were in need of additional clarification and assessment. The staff's evaluations of
 
these AMRs are providing in the subsection that follows
 
3.1.2.1.1 AMR Results Identified as Not Applicable 
 
In LRA Table 3.1.1, items 46, the applicant states that the corresponding AMR result line in the 3-220 GALL Report is not applicable because access hole covers are a welded design. The staff noted that the nickel alloy core shroud and core plate access hole cover is a mechanical design
 
for item 46. The staff reviewed the documentation supporting the applicant's AMR evaluation
 
and confirmed the applicant's claim that SSES does not have a mechanical access hole cover. 
 
Therefore, the staff agrees with the applicant's determination that the corresponding AMR result
 
line in the GALL Report is not applicable to SSES.
In LRA Table 3.1.1, item 47, the applicant states that the corresponding AMR result line in the GALL Report is addressesed under item 3.1.1-14. The staff reviewed the documentation
 
supporting the applicant's AMR evaluation in items 3.1.1-14, and no AMR line items roll up to
 
3.1.1-47. Therefore, the staff agrees with the applicant's determination that the corresponding
 
AMR result line in the GALL Report is not applicable to SSES.
 
In LRA Table 3.1.1, items 53, 54, 56 and 87, the applicant indicates that the corresponding
 
AMR result line in the GALL Report is not applicable because SSES does not have the
 
components for these items. The staff reviewed the documentation supporting the applicant's
 
AMR evaluation and confirmed the applicant's claim that SSES does not have these
 
components. Therefore, the staff agrees with the applicant's determination that the
 
corresponding AMR result line in the GALL Report is not applicable to SSES.
 
In LRA Table 3.1-1 line item 3.1.1-57, the applicant stated that loss of fracture toughness due to
 
thermal aging embrittlement for 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) is not applicable because these components are included in LRA Table 3.1-1
 
line items 3.3.1-51 and 3.1.1-55. 
 
The staff confirmed that the components listed under line item 3.1.1-57 are included in line
 
items 51 and 55. The applicant has proposed using the Thermal Aging and Neutron Irradiation
 
Embrittlement of CASS Program to manage the agi ng effects in line 3.1.1-51; and the Inservice Inspection, and Small Bore Class 1 Piping Inspection Programs to manage the aging effects in
 
line 3.1.1-55. Based on this review, the staff finds that Table 3.3.1, line item 3.1.1-57 is not
 
applicable.
 
3.1.2.1.2  Cracking due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking
 
In LRA Table 3.1.2-3, for stainless steel tubing in a treated water (reactor coolant) environment, the applicant specified use of the BWR Water Chemistry Program for managing the aging effect
 
of cracking due to SCC or IGSCC. For this AMR result line, the applicant referred to LRA
 
Table 3.1.1, item 3.1.1-48 and cited generic note E, indicating that the result is consistent with
 
the GALL Report for component, material, environment and aging effect but a different AMP is
 
used. The staff noted that for the same component, material and environment combination, the
 
GALL report recommends use of the Inservice Inspection (IWB, IWC and IWD) Program, the
 
Water Chemistry Program, and the One-Time Inspection of ASME Code Class 1 Small Bore
 
Piping for managing the aging effect of cracking due to SCC or IGSCC. The staff issued
 
RAI 3.1-4 by letter dated July 15, 2008, asking the applicant to provide technical justification that the AMP specified in the LRA provides adequate management of the aging effect during the
 
period of extended operation.
 
In a letter dated August 15, 2008, the applicant responded to RAI 3.1-4 by providing the
 
following response:
 
3-221 An inspection program is needed to confirm the effectiveness of the BWR Water Chemistry Program. LRA Table 3.1.2-3 is revised to credit the Inservice Inspection (ISI)
 
Program and the Small Bore Class 1 Piping Inspection in addition to the BWR Water
 
Chemistry Program to manage cracking for stainless steel tubing in treated water. This is
 
consistent with the combination of aging management programs identified in GALL
 
Report item IV.C1-1. Note A is applicable.
 
In LRA Table 3.1.2-3, for stainless steel condensing chambers, piping and fittings, valve bodies, and flow orifices in a treated water environment, the applicant specified use of the BWR Water
 
Chemistry Program and the Small Bore Class 1 Piping Inspection for managing the aging effect
 
of cracking due to SCC or IGSCC. For these AMR result lines, the applicant referred to LRA
 
Table 3.1.1, item 3.1.1-48 and cited generic note A, indicating that the result is consistent with
 
the GALL Report for component, material, environment, aging effect, and the AMP is consistent
 
with the GALL Report. The staff noted that for the same or similar components and the same
 
material and environment combination, the GALL report recommends use of the Inservice
 
Inspection (IWB, IWC and IWD) Program, the Water Chemistry Program, and the One-Time
 
Inspection of ASME Code Class 1 Small Bore Piping for managing the aging effect of cracking
 
due to SCC or IGSCC. The staff issued RAI 3.1-6 by letter dated July 15, 2008, asking the
 
applicant to provide technical justification that the applicant's recommended AMPs provide
 
adequate management of the aging effect during the period of extended operation and justify
 
why note A is appropriate for these AMR results lines.
 
In a letter dated August 15, 2008, the applicant responded to RAI 3.1-6 by providing the
 
following response:
 
The LRA Table 3.1.2-3 AMR result lines where the components are small bore piping
 
components made of stainless steel, the environment is "treated water (internal)," the
 
aging effect is cracking, and the AMPs are BWR Water Chemistry Program and Small
 
Bore Class 1 Piping Inspection are revised to also credit the Inservice Inspection (ISI)
 
Program. Also, the line entry for stainless steel tubing in LRA Table 3.1-2-3 is revised to
 
credit both the Inservice Inspection Program and the Small Bore Class 1 Piping
 
Inspection.
 
In total, there are 6 AMR line entries, covering stainless steel condensing chambers, flow orifices, piping and fittings <4 inch, tubing and valves exposed to treated water
 
subject to cracking and compared to GALL Repor t line item IV.C1-1. By crediting ISI for these entries and ISI and small bore inspection for the tubing, the credited programs are
 
consistent with GALL Report line item IV.C1-1. Note A is applicable.
 
The LRA is amended to make the necessary changes.
 
The staff reviewed all of the LRA changes that the applicant made in response to RAIs 3.1-4
 
and 3.1-6. The staff confirmed that the changes brought the applicant's AMR result lines into
 
consistency with the corresponding AMR results in the GALL Report. Because the applicant's
 
AMR results are consistent with the GALL Report, the staff finds the LRA changes and the
 
applicant's AMR results for LRA Table 3.1.1, Item 3.1.1-48 to be acceptable.
 
LRA Table 3.1.2-3 includes AMR result lines for carbon steel piping and fittings <4" nominal
 
pipe size (NPS) and for carbon steel valves <4" NPS in an environment of treated water and
 
with an aging effect of cracking. The applicant specified the Small Bore Class 1 Piping
 
Inspection, only, as the AMP to manage the aging effect of cracking for these components and 3-222 cites generic note H, indicating that the aging effect is not in the GALL Report for this component, material and environment combination. The staff noted that the components, material, environment and aging effect all appear to be consistent with GALL Report
 
item IV.C1-1, where the recommended AMPs are the ISI Program, the Water Chemistry Program, and the One-Time Inspection of ASME Class 1 Small Bore Piping. The staff issued
 
RAI 3.1-7 by letter dated July 15, 2008, asking the applicant to explain why note H was used for
 
these AMR results and to justify that the AMP specified by the applicant for these components
 
provides satisfactory aging management during the period of extended operation, comparable to the AMPs recommended in GALL Report line IV.C1-1.
 
In a letter dated August 15, 2008, the applicant responded to RAI 3.1-7 by providing the
 
following response:
 
GALL Report item IV.C1-1 is appropriate for comparison in the AMR result lines in the
 
LRA Table 3.1.2-3 for piping and fittings <4 inch and for valve bodies <4 inch, for which
 
the material is carbon steel, the environment is "treated water (internal)," and the aging
 
effect is cracking (due to thermal and mechanical loading).
 
The AMR results are consistent with GALL Report item IV.C1-1 for the material (steel),
environment (reactor coolant) and aging effect (cracking). The LRA is revised to credit
 
the Inservice Inspection (ISI) Program, in addition to the Small Bore Class 1 Piping
 
Inspection, to manage cracking for the components. While GALL Report item IV.C1-1
 
also credits Water Chemistry, it is not applicable here, since cracking due to stress
 
corrosion is not an aging effect for steel components. Therefore, crediting ISI and Small
 
Bore Class 1 Piping Inspection to manage cracking due to thermal and mechanical
 
loading is considered to be consistent with the recommendations of GALL Report
 
item IV.C1-1. However, since PPL is crediting only two of the three programs that are
 
listed in the GALL Report item, a note E, instead of note A, is used for the comparison to
 
the GALL Report.
 
The staff reviewed the applicant's response and the associated LRA changes. The staff noted
 
that the mechanism associated with the aging effect of cracking in these components is thermal
 
and mechanical loading, which is not strongly influenced by the water chemistry environment of
 
the components. Because there is no mitigating effect provided by the BWR Water Chemistry
 
Program for the aging mechanism of thermal and mechanical loading, the staff finds it
 
acceptable for the applicant not to credit the BWR Water Chemistry Program for these
 
components. Because the Small Bore Class 1 Piping Inspection provides for one-time
 
volumetric inspections that are capable of finding cracking due to thermal and mechanical
 
loading, and for piping <4 inch diameter the ISI program provides for periodic surface
 
examinations and for VT-2 examinations for leakage at every refueling outage. The staff finds
 
the applicant's LRA changes and the revised AMR results for carbon steel piping and fittings
 
<4 inch and for carbon steel valve bodies <4 inch in an environment of treated water with the
 
aging effect is cracking due to thermal and mechanical loading to be acceptable.
 
Based on the changes that the applicant made to the LRA in response to RAIs 3.1-4 and 3.1-6, the explanation provided in response to RAI 3.1-7, and the programs identified for managing the
 
subject aging effects, the staff determines that the applicant 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).
 
3-223 3.1.2.1.3  Loss of Fracture Toughness due to Thermal Aging Embrittlement 
 
In the discussion in LRA Table 3.1.1, item 3.1.1-55, the applicant stated that for CASS valve
 
bodies less than 4 inch NPS, the Small Bore Class 1 Piping Inspection is credited to manage
 
loss of fracture toughness. However, in the applicant's response to RAI B.2.31-1, documented
 
in the applicant's letter dated July 25, 2008, the applicant revised the discussion in item 3.1.1-55
 
to delete the statement that for CASS valve bodies less than 4 inch NPS, the Small Bore
 
Class 1 Piping Inspection is credited to manage loss of fracture toughness. Based on this
 
change, the applicant's Inservice Inspection Program is credited to manage loss of fracture
 
toughness due to thermal aging embrittlement for all CASS pump casings, pump covers, thermal barriers and valve bodies exposed to reactor coolant >250&#xba;C (>482&#xba;F), including CASS
 
valve bodies less than 4 inch NPS. This combination of components, material, environment, aging effect and aging management program is consistent with the recommendations in the
 
GALL Report for item 3.1.1-55. On this basis, the staff finds the applicant's change in the LRA
 
discussion for item 3.1.1-55 and the applicant's associated AMR results to be acceptable.
 
SER Section 3.1.2.1 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 OE 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 evaluates of aging management, as recommended
 
by the GALL Report, for the RV, RV internal s, and reactor coolant system components and provides information concerning how it will manage the following aging effects:
* cumulative fatigue damage
* loss of material due to general, pitting, and crevice corrosion
* loss of fracture toughness due to neutron irradiation embrittlement
* cracking due to stress corrosion cracking (SCC) and intergranular stress corrosion cracking (IGSCC)
* 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 3-224
* wall thinning due to FAC
* changes in dimensions due to void swelling
* cracking due to SCC and primary water SCC
* cracking due to SCC, primary water SCC, and irradiation-assisted SCC
* 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 3.1.2.2. 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.
 
3.1.2.2.2  Loss of Material Due to General, Pitting, and Crevice Corrosion 
 
The staff reviewed LRA Section 3.1.2.2.2 against the following criteria in SRP-LR
 
Section 3.1.2.2.2:
 
(1) LRA Section 3.1.2.2.2 addresses loss of material due to general, pitting, and crevice corrosion in BWR top head and top head nozzles and PWR steam generator shell
 
assembly. The applicant stated that the BWR Water Chemistry Program is
 
supplemented by the Inservice Inspection (ISI) Program for managing loss of material
 
due to general, pitting, and crevice corrosion for the steel RV upper head and the top
 
head nozzles exposed to reactor coolant. A one-time inspection is not credited. The
 
BWR Water Chemistry Program in association with the Small Bore Class 1 Piping
 
Inspection manages loss of material due to general, pitting, and crevice corrosion for
 
steel piping and valves less than 4 inches exposed to reactor coolant. The Small Bore
 
Class 1 Piping Inspection is a one-time inspection. Loss of material for a steam
 
generator shell assembly is only applicable to PWRs.
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 shell assembly exposed to
 
secondary FW and steam. Loss of material due to general, pitting, and crevice corrosion
 
also may occur in the steel top head enclosure (without cladding) top head nozzles (vent, top head spray or reactor core isolation cooling (RCIC), and spare) exposed to
 
reactor coolant. The existing program contro ls reactor water chemistry to mitigate corrosion. However, control of water chemistry does not preclude loss of material due to
 
pitting and crevice corrosion at locations with stagnant flow conditions; therefore, the
 
effectiveness of water chemistry control programs should be verified to ensure that
 
corrosion does not occur. The GALL Report recommends further evaluation of programs
 
to verify the effectiveness of water chemistry control programs. A one-time inspection of
 
selected components at susceptible locations is an acceptable method to determine
 
whether an aging effect is occurring or is slowly progressing such that the component's 3-225 intended functions will be maintained during the period of extended operation.
 
The staff reviewed all AMR result lines referring to LRA Table 3.1.1, item 3.1.1-11, and
 
to LRA Section 3.1.2.2.2.1. The staff noted that the AMR results can be divided into
 
three categories based upon the AMP proposed by the applicant: 1) AMR results where
 
loss of material is managed by the BWR Water Chemistry Program, alone; 2) AMR
 
results where loss of material is managed by a combination of the BWR Water Chemistry Program and the ASME Code Section XI Inservice Inspection (IWB, IWC, and
 
IWD) program; and 3) AMR results where loss of material is managed by a combination
 
of the BWR Water Chemistry Program and the Small Bore Class 1 Piping Inspection.
 
For the first and second category of these AMR results, the applicant cited generic note
 
E indicating that the material, environment and aging effect are consistent with the GALL
 
Report but a different aging management program is credited. For AMR results in the
 
third category, BWR Water Chemistry Program and Small Bore Class 1 Piping
 
Inspection, the applicant cited generic note C indicating that the component is different, but the material, environment, aging effect, and AMP are all consistent with the GALL
 
Report.
 
As a result of its review of the applicant's AMP B.2.31, Small Bore Class 1 Piping
 
Inspection, and the applicant's AMR results, the staff issued requests for additional
 
information in letters dated June 23, 2008, and July 15, 2008:
* RAI B.2.31-1 asked the applicant to reconcile inconsistencies related to the applicant's claim that the Small Bore Class 1 Piping Inspection is consistent with GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small Bore Piping."
* RAI 3.1-1 asked the applicant to justify how the BWR Water Chemistry Program, alone, would provide adequate aging management for loss of material for those AMR results where no inspection was specified to confirm effectiveness of the water chemistry program.
* RAI 3.1-2 asked the applicant to explain why confirmation of effectiveness of the BWR Water Chemistry Program is not needed with regard to managing the aging effect of loss of material in carbon steel main steam flow elements/restrictors exposed to treated water.
* RAI 3.1-3 asked the applicant to explain why generic note A or note C, indicating that the AMP used is consistent with the AMP recommended in the GALL Report, was used for multiple AMR result lines in Table 3.1.2-3 where the applicant proposed using the BWR Water Chemistry Program in combination with the Small Bore Class 1 Piping Inspection, but the GALL Report recommends GALL AMP XI.M2, "Water Chemistry," in combination with GALL AMP XI.M32, "One-Time Inspection," for managing loss of material.
 
The applicant responded to RAI B.2.31-1 in a letter dated July 25, 2008, and to RAIs
 
3.1-1, 3.1-2, and 3.1-3 in a letter dated August 15, 2008. In those responses, the
 
applicant revised all of the AMR results that referred to LRA Table 3.1.1, item 3.1.1-11, where the aging effect was managed either by the BWR Water Chemistry Program, alone, or by the BWR Water Chemistry Program in combination with the Small Bore
 
Class 1 Piping Inspection. In the revised AMR results, the applicant proposes to manage 3-226 loss of material for carbon steel components exposed to treated water with a combination of the BWR Water Chemistry Program and the Chemistry Program
 
Effectiveness Inspection. The staff finds that use of the BWR Water Chemistry Program
 
and the Chemistry Program Effectiveness Inspection is consistent with
 
recommendations in the GALL Report, and issues raised in RAIs B.2.31-1, 3.1-1, 3.1-2, and 3.1-3 were resolved by the applicant's changes to the LRA made in response to
 
these RAIs.
 
The staff reviewed the applicant's BWR Water Chemistry Program. The staff's
 
evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that the
 
applicant's BWR Water Chemistry Program provides mitigation for the aging effect of
 
loss of material due to general, pitting, and crevice corrosion. The staff reviewed the
 
applicant's Chemistry Program Effectiveness In spection. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the applicant's
 
Chemistry Program Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "One-Time Inspection." The
 
applicant's Chemistry Program Effectivene ss Inspection includes provisions for inspecting selected components in areas of low or stagnant flow and is capable of
 
detecting loss of material due to general, pitting, and crevice corrosion, if it should occur
 
in the selected components. Because the BWR Water Chemistry Program provides
 
mitigation and the Chemistry Program Effectiveness Inspection provides detection for
 
loss of material due to general, pitting, and crevice corrosion, the staff finds the
 
applicant's LRA changes and the applicant's use of the BWR Water Chemistry Program
 
and the Chemistry Program Effectiveness Inspection for managing loss of material due
 
to general, pitting, and crevice corrosion in steel components exposed to treated water in
 
the reactor vessel top head enclosure and in the reactor coolant system pressure
 
boundary to be acceptable.
 
For some components referring to LRA Table 3.1.1, item 3.1.1-11, the applicant credited
 
the Inservice Inspection (ISI) Program in lieu of a one-time inspection program to confirm
 
that the BWR Water Chemistry Program is effective in preventing loss of material due to
 
corrosion. The components where the ISI Program is credited are carbon steel or unclad
 
low alloy steel upper head components (dome, closure flange, and nozzles), and certain
 
reactor coolant pressure boundary piping and fittings, and valve bodies greater than 4
 
inches nominal pipe size. For all of these components, the applicant's ISI Program
 
requires volumetric and visual examinations. The staff reviewed the applicant's ISI
 
Program, and the staff's evaluation of that program is documented in SER Section
 
3.0.3.2.1. The staff found that the ISI Program is capable of detecting loss of material for
 
components of the reactor coolant pressure boundary, including piping, valves, and the
 
reactor pressure vessel. On the basis that the ISI Program's examination methodology is
 
capable of detecting loss of material in the subject components, the staff finds it
 
acceptable for the applicant to credit the ISI Program in lieu of a one-time inspection
 
program for confirming that the BWR Water C hemistry Program is effective in preventing loss of material due to corrosion in those components.
 
The staff confirmed in SRP-LR Table 3.1-1, Item 12, is only applicable to PWR plants. 
 
On the basis of its review, the staff concluded that because SSES is a BWR, SRP-LR
 
Section 3.1.2.2.2.1 is not applicable to SSES.
(2) LRA Section 3.1.2.2.2 addresses loss of material due to general, pitting, and crevice corrosion in isolation condenser components. The applicant stated that this aging effect 3-227 is not applicable because SSES design does not include an isolation condenser.
SRP-LR Section 3.1.2.2.2 states that loss of material due to pitting and crevice corrosion
 
may occur in stainless steel BWR isolation condenser components exposed to reactor
 
coolant. Loss of material due to general, pitting, and crevice corrosion may occur in steel
 
BWR isolation condenser components. The existing program controls reactor water
 
chemistry to mitigate corrosion. However, c ontrol 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 effectiv eness 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.
 
The staff verified in the UFSAR, Rev. 63 that SSES is a BWR that does not have an
 
isolation condenser.
 
On the basis of its review, the staff concluded that because SSES is a BWR without an
 
isolation condenser, SRP-LR Section 3.1.2.2.2.2 is not applicable to SSES.
 
(3) LRA Section 3.1.2.2.2 addresses loss of material due to general, pitting, and crevice corrosion in flanges, nozzles, penetrations, pressure housings, safe ends, and vessel
 
shells, heads, and welds. The applicant stated that the BWR Water Chemistry Program
 
is supplemented by the Inservice Inspection (ISI) Program for managing loss of material
 
due to crevice and pitting corrosion for the steel RV upper head closure flange and shell
 
closure flange with stainless steel cladding exposed to reactor coolant. A one-time
 
inspection is not credited. The BWR Water Chemistry Program alone is credited for
 
managing loss of material due to crevice and pitting corrosion of the steel RV shell rings, ID attachments and welds, bottom head, nozzles, safe ends, and CRD stub tubes and
 
housings with stainless steel cladding exposed to reactor coolant. A one-time inspection
 
is not credited. The BWR Water Chemistry Program in association with the Small Bore
 
Class 1 Piping Inspection or the Inservice Inspection (ISI) Program manages loss of
 
material due to pitting and crevice corrosion for stainless steel components of the
 
reactor coolant system (RCS) pressure boundary exposed to reactor coolant. The Small
 
Bore Class 1 Piping Inspection is a one-time inspection.
SRP-LR Section 3.1.2.2.2 states that loss of material due to pitting and crevice corrosion
 
may occur in stainless steel, nickel alloy, and steel with stainless steel or nickel alloy
 
cladding flanges, nozzles, penetrations, pressure housings, safe ends, and vessel
 
shells, heads, and welds exposed to reactor coolant. The existing program controls
 
reactor water chemistry to mitigate corrosion.
However, control of water chemistry does not preclude loss of material due to pitting and crevice corrosion at locations with
 
stagnant flow conditions; therefore, the effectiveness of water chemistry control
 
programs should be verified to ensure that corrosion does not occur. The GALL Report
 
recommends further evaluation of programs to verify the effectiveness of water
 
chemistry control programs. A one-time inspection of 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.
3-228  The staff reviewed all AMR results lines referring to LRA Table 3.1.1, items 3.1.1-14 or
 
3.1.1-15, and to LRA Section 3.1.2.2.2.3. The staff noted that the AMR results can be
 
divided into four categories based upon the AMPs proposed by the applicant: 1) AMR
 
results where loss of material is managed by the BWR Water Chemistry Program, alone;
: 2) AMR results where loss of material is managed by a combination of the BWR Water
 
Chemistry Program and the Small Bore Class 1 Piping Inspection; 3) AMR results where
 
loss of material is managed by a combination of the BWR Water Chemistry Program and the ASME Code Section XI Inservice Inspection (IWB, IWC, and IWD) program; and 4)
 
AMR results where loss of material is managed by a combination of the BWR Water
 
Chemistry Program and the BWR Vessel Internals Program. For AMR results in the first, third and fourth category, the applicant cited generic note E indicating that the material, environment and aging effect are consistent with the GALL Report but a different aging
 
management program is credited. For AMR results in the second category, BWR Water
 
Chemistry Program and Small Bore Class 1 Piping Inspection, the applicant cited
 
generic note A indicating that the component, material, environment, aging effect, and
 
AMP are all consistent with the GALL Report.
 
As a result of its review of the applicant AMP B.2.31, Small Bore Class 1 Piping
 
Inspection, and the applicant's AMR results, the staff issued requests for additional
 
information in letters dated June 23, 2008, and July 15, 2008:
* RAI B.2.31-1 asked the applicant to reconcile inconsistencies related to the applicant's claim that the Small Bore Class 1 Piping Inspection is consistent with GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small Bore Piping."
* RAI 3.1-1 asked the applicant to justify how the BWR Water Chemistry Program, alone, would provide adequate aging management for loss of material for those AMR results where no inspection was specified to confirm effectiveness of the water chemistry program.
 
The applicant responded to RAI B.2.31-1 in a letter dated July 25, 2008, and to RAI 3.1-
 
1 in a letter dated August 15, 2008. In those responses, the applicant revised all of the
 
AMR results that referred to LRA Table 3.1.1, items 3.1.1-14 or 3.1.1-15, where the
 
aging effect was managed either by the BWR Water Chemistry Program or by the BWR
 
Water Chemistry Program in combination with the Small Bore Class 1 Piping Inspection.
 
In the revised AMR results, the applicant proposes to manage loss of material for
 
stainless steel, nickel alloy, and steel with stainless steel or nickel-alloy clad components
 
exposed to treated water with a combination of the BWR Water Chemistry Program and
 
the Chemistry Program Effectiveness Inspection. The staff finds that use of the BWR
 
Water Chemistry Program and the Chemistr y Program Effectiveness Inspection is consistent with recommendations in the GALL Report.
 
The staff reviewed the applicant's BWR Water Chemistry Program. The staff's
 
evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that the
 
applicant's BWR Water Chemistry Program provides mitigation for the aging effect of
 
loss of material due to pitting and crevice corrosion. The staff reviewed the applicant's
 
Chemistry Program Effectiveness Inspection.
The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the applicant's Chemistry
 
Program Effectiveness Inspection is a one-time inspection that is consistent with the 3-229 GALL Report's recommendations for AMP XI.M32, "One-Time Inspection." The applicant's Chemistry Program Effectivene ss Inspection includes provisions for inspecting selected components in areas of low or stagnant flow and is capable of
 
detecting loss of material due to pitting and crevice corrosion, if it should occur in the
 
selected components. Because the BWR Water Chemistry Program provides mitigation
 
and the Chemistry Program Effectiveness In spection provides detection for loss of material due to pitting, and crevice corrosion, the staff finds the applicant's LRA changes
 
and the applicant's use of the BWR Water Chemistry Program and the Chemistry
 
Program Effectiveness Inspection for managing loss of material due to pitting, and
 
crevice corrosion for stainless steel, nickel alloy, and steel with stainless steel or nickel-
 
alloy clad components exposed to treated water in the reactor pressure vessel and in the
 
reactor coolant system pressure boundary to be acceptable.
 
For some components referring to LRA Table 3.1.1, items 3.1.1-14 and 3.1.1-15, the
 
applicant credited the Inservice Inspection (ISI) Program in lieu of a one-time inspection
 
program to confirm that the BWR Water Chem istry Program is effective in preventing loss of material due to pitting or crevice corrosion. The components where the ISI
 
Program is credited are stainless steel clad reactor vessel and upper head closure
 
flanges, stainless steel pump casings and covers, piping and valve bodies greater than 4
 
inch nominal pipe size and tubing, and steam line flow restrictors. For all of these
 
components, the applicant's ISI Program requires volumetric and visual examinations (except tubing where only visual examination is required). The staff reviewed the
 
applicant's ISI Program, and the staff's evaluat ion of that program is documented in SER Section 3.0.3.2.1. The staff found that the ISI Program is capable of detecting loss of
 
material for components of the reactor coolant pressure boundary, including piping, tubing, pump casings, valves, flow restrictors, and the reactor pressure vessel. On the
 
basis that the ISI Program's examination methodology is capable of detecting loss of
 
material in the subject components, the staff finds it acceptable for the applicant to credit
 
the ISI Program in lieu of a one-time inspection program for confirming that the BWR
 
Water Chemistry Program is effective in preventing loss of material due to corrosion in
 
those components.
 
For vessel internal components referring to LRA Table 3.1.1, item 3.3.1-14, the applicant
 
credited the BWR Vessel Internals Program in lieu of a one-time inspection program to
 
confirm that the BWR Water Chemistry Program is effective in preventing loss of
 
material due to pitting and crevice corrosion. The staff reviewed the applicant's BWR
 
Vessel Internals Program, and the staff's evaluation is documented in SER Section
 
3.0.3.2.4. The staff found that the BWR Vessel Internals Program is capable of detecting
 
loss of material due to pitting and crevice corrosion for stainless steel or nickel alloy
 
components that are within its scope. On the basis that the BWR Vessel Internals
 
Program is capable of detecting loss of material in the subject components, the staff
 
finds it acceptable for the applicant to credit the BWR Vessel Internals Program in lieu of
 
a one-time inspection program for confirming that the BWR Water Chemistry Program is
 
effective in preventing loss of material due to pitting and crevice corrosion in stainless
 
steel or nickel alloy reactor vessel internals.
 
(4) LRA Section 3.1.2.2.2 addresses loss of material due to general, pitting, and crevice corrosion in PWR steam generator upper and lower shell and transition cone. The
 
applicant stated that this aging effect is not applicable because SSES is a BWR.
SRP-LR Section 3.1.2.2.2 states that loss of material due to general, pitting, and crevice 3-230 corrosion may occur in the steel PWR steam generator upper and lower shell and transition cone exposed to secondary feedwater and steam.
 
The staff confirmed in SRP-LR Table 3.1-1, Item 16, is only applicable to PWR plants.
 
On the basis of its review, the staff concluded that because SSES is a BWR, SRP-LR
 
Section 3.1.2.2.2.4 is not applicable to SSES.
 
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 determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.1.2.2.3  Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement 
 
The staff reviewed LRA Section 3.1.2.2.3 against the following criteria in SRP-LR
 
Section 3.1.2.2.3:
 
(1) 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.
 
(2) LRA Section 3.1.2.2.3 addresses loss of fracture toughness due to neutron irradiation embrittlement in RV beltline shell, nozzle, and welds. The applicant stated that reduction
 
in fracture toughness due to radiation embrittlement could occur for RV beltline region
 
materials exposed to reactor coolant and neutron flux. A RV materials surveillance
 
program monitors radiation embrittlement of the steel RV beltline materials with stainless
 
steel cladding. The Reactor Vessel Surveillance Program, and the results of its
 
evaluation for license renewal, are presented in Appendix B of the LRA.
SRP-LR Section 3.1.2.2.3 states that loss of fracture toughness due to neutron
 
irradiation embrittlement may occur in BWR and PWR RV beltline shell, nozzle, and
 
welds exposed to reactor coolant and neutron flux. A RV materials surveillance program
 
monitors neutron irradiation embrittlement of the RV. 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.
 
LRA Section 3.1.2.2.3.1 provides the applicant's discussion on management of neutron
 
irradiation embrittlement TLAA. The applicant states that, "Certain aspects of neutron
 
irradiation embrittlement are time-limited aging analyses (TLAAs) as defined in 10 CFR 54.3. 
 
TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1). The evaluation of
 
this TLAA is addressed separately in Section 4.2 of the LRA.
 
3-231 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 determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.1.2.2.4  Cracking Due to Stress Corrosion Cracking and Intergranular Stress Corrosion
 
Cracking 
 
The staff reviewed LRA Section 3.1.2.2.4 against the following criteria in SRP-LR
 
Section 3.1.2.2.4:
 
(1) LRA Section 3.1.2.2.4 addresses cracking due to SCC and IGSCC in BWR top head enclosure vessel flange leak detection lines. The applicant stated that the RV flange leak
 
detection line at SSES is a Class 1 line that is normally dry. The stainless steel line is
 
evaluated for a treated water environment and is therefore susceptible to cracking due to
 
SCC. This aging effect is managed with a combination of the BWR Water Chemistry
 
Program and the Small Bore Class 1 Piping Inspection.
SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCC may occur in the
 
stainless steel and nickel alloy BWR top head enclosure vessel flange leak detection
 
lines. The GALL Report recommends that a plant-specific AMP be evaluated because
 
existing programs may not be capable of mitigating or detecting cracking due to SCC
 
and IGSCC.
 
The staff reviewed the applicant's BWR Water Chemistry Program. The staff's
 
evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that the
 
applicant's BWR Water Chemistry Program provides mitigation for the aging effect of
 
cracking caused by SSC or IGSCC in stainless steel piping exposed to treated water.
 
The staff reviewed the applicant's Small Bore Class 1 Piping Inspection program. The
 
staff's evaluation of this program, which is documented in SER Section 3.0.3.1.18, found
 
that the applicant's Small Bore Class 1 Piping Inspection program provides for a one-
 
time examination of ASME Code Class 1 sma ll bore piping using volumetric examination techniques that are capable of detecting piping cracks caused by SCC or IGSCC. Based
 
on the staff's determination that the BWR Water Chemistry Program provides mitigation
 
for the aging effect of cracking due to SCC or IGSCC, and the Small Bore Class 1 Piping
 
Inspection program provides detection of potential cracking due to SCC or IGSCC, the
 
staff finds the applicant's proposed AMPs for managing the aging effect of cracking in
 
the stainless steel flange leak detection lines to be acceptable.
 
(2) LRA Section 3.1.2.2.4 addresses cracking due to SCC and IGSCC in isolation condenser components. The applicant stated that this aging effect is not applicable
 
because SSES design does not include an isolation condenser.
SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCC may occur in
 
stainless steel BWR isolation condenser components exposed to reactor coolant. The
 
existing program controls reactor water chemistry to mitigate SCC and relies on ASME Code Section XI ISI; however, the exis ting program should be augmented to detect cracking due to SCC and IGSCC. The GALL Report recommends an augmented
 
program to include temperature and radioactivity monitoring of the shell-side water and 3-232 eddy current testing of tubes to ensure that component intended functions will be maintained during the period of extended operation.
 
SRP-LR Section 3.1.2.2.4.2 invokes the AMR Item 20 in Table 1 of the GALL Report, Volume 1 and AMR Item IV.C1-4 of the GALL Report, Volume 2 on management of
 
cracking due to SCC and IGSCC in stainless steel BWR isolation condenser
 
components that are exposed to the treated water environment of the reactor coolant. 
 
The staff reviewed the UFSAR for SSES. The staff determined that the UFSAR Chapter
 
6 indicates that, at SSES, each of the SSES units use a reactor core isolation cooling (RCIC) system as the system for isolati ng the reactor from the main steam system during operational transients and during postulated design basis accidents. The staff
 
verified that the units do not include isolation condensers. Based on this review, the
 
staff concludes that the recommendations in SRP-LR Section 3.1.2.2.4.2 and in GALL
 
AMR IV.C1-4 are not applicable to the SSES LRA, because the SSES plant designs
 
does not include isolation condenser systems.
 
Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.4 criteria. For those line items that apply to LRA Section 3.1.2.2.4, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.1.2.2.5  Crack Growth Due to Cyclic Loading 
 
LRA Section 3.1.2.2.5 addresses crack growth due to cyclic loading. The applicant stated that
 
this aging effect is not applicable because SSES is a BWR.
 
The staff reviewed LRA Section 3.1.2.2.5 against the criteria in SRP-LR Section 3.1.2.2.5 which
 
states that crack growth due to cyclic loading can occur in the reactor vessel shell forgings clad
 
with stainless steel using a high-heat-input welding process.
The staff confirmed in SRP-LR Table 3.1-1, Item 21, is only applicable to PWR plants.
On the basis of its review, the staff concluded that because SSES is a BWR, SRP-LR Section 
 
3.1.2.2.5 is not applicable to SSES.
 
3.1.2.2.6  Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement and Void
 
Swelling 
 
The staff reviewed LRA Section 3.1.2.2.6 against the criteria in SRP-LR Section 3.1.2.2.6.
 
LRA Section 3.1.2.2.6 addresses loss of fracture toughness due to neutron irradiation
 
embrittlement and void swelling. The applicant stated that this aging effect is not applicable
 
because SSES is a BWR.
 
Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.6 criteria is not applicable.
 
3.1.2.2.7  Cracking Due to Stress Corrosion Cracking 
 
3-233 The staff reviewed LRA Section 3.1.2.2.7 against the following criteria in SRP-LR Section 3.1.2.2.7:
 
(1) LRA Section 3.1.2.2.7 addresses cracking due to SCC in PWR stainless steel RV flange leak detection lines and bottom-mounted instrument guide tubes exposed to reactor
 
coolant. The applicant stated that this aging effect is not applicable because SSES is a
 
BWR. SRP-LR Section 3.1.2.2.7 states that cracking due to SCC may occur in the PWR
 
stainless steel RV flange leak detection lines and bottom-mounted instrument guide
 
tubes exposed to reactor coolant.
 
The staff reviewed the UFSAR for SSES. The staff determined that the UFSAR Chapter
 
1 indicates that the SSES reactors are General Electrical (GE) Model 4 BWRs with Mark
 
II containment structures. Based on this review, the staff concludes that the
 
recommendations in SRP-LR Section 3.1.2.2.7.1 are not applicable to the SSES LRA, because the SSES plants are not PWR designed reactors.
 
The staff confirmed in SRP-LR Table 3.1-1, Item 23, is only applicable to PWR plants.
 
Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.7.1
 
does not apply to SSES.
 
(2) LRA Section 3.1.2.2.7 addresses cracking due to SCC in Class 1 PWR cast austenitic stainless steel (CASS) reactor coolant system piping, piping components, and piping
 
elements exposed to reactor coolant. The applicant stated that this aging effect is not
 
applicable because SSES is a BWR.
 
SRP-LR Section 3.1.2.2.7 states that cracking due to SCC may occur in Class 1 PWR
 
cast austenitic stainless steel (CASS) reactor coolant system piping, piping components, and piping elements exposed to reactor coolant.
 
The staff reviewed the UFSAR for SSES. The staff determined that the UFSAR Chapter
 
1 indicates that the SSES reactors are General Electrical (GE) Model 4 BWRs with Mark
 
II containment structures. Based on this review, the staff concludes that the
 
recommendations in SRP-LR Section 3.1.2.2.7.2 are not applicable to the SSES LRA, because the SSES plants are not PWR designed reactors.
 
The staff confirmed in SRP-LR Table 3.1-1, Item 24, is only applicable to PWR plants.
 
Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.7.2
 
does not apply to SSES.
 
Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.7 criteria is not applicable.
 
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:
 
(1) LRA Section 3.1.2.2.8 addresses cracking due to cyclic loading in stainless steel BWR jet pump sensing lines. The applicant stated that for SSES, the jet pump instrumentation
 
lines inside the vessel are not subject to aging management review, as they do not 3-234 perform an intended function. The lines outside of the vessel are part of the RCS pressure boundary and are subject to aging management review for a reactor coolant
 
environment. Cracking of the stainless steel lines external to the vessel is managed with
 
a combination of the BWR Water Chemistry Program and the Small Bore Class 1 Piping
 
Inspection.
SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in the
 
stainless steel BWR jet pump sensing lines. The GALL Report recommends that a plant-
 
specific AMP be evaluated to ensure that this aging effect is adequately managed.
 
The staff reviewed the applicant's statement that the jet pump sensing lines inside the
 
reactor vessel are not subject to AMR. The staff noted that the jet pump sensing lines
 
inside the vessel are not part of the reactor coolant pressure boundary and that the
 
function of the jet pump sensing lines is to provide indication of jet pump flow, which is
 
not a license renewal intended function. Since the jet pump sensing lines inside the
 
reactor vessel are not part of the reactor coolant pressure boundary and are not required
 
to support a license renewal intended function, the staff finds the applicant's statement
 
that jet pump sensing lines inside the reactor vessel are not subject to AMR to be
 
acceptable.
 
The staff reviewed the applicant's BWR Water Chemistry Program. The staff's
 
evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that the
 
applicant's BWR Water Chemistry Program provides mitigation for the aging effect of
 
cracking caused by SSC in stainless steel piping exposed to treated water. The staff
 
reviewed the applicant's Small Bore Class 1 Piping Inspection program. The staff's
 
evaluation of this program, which is documented in SER Section 3.0.3.1.18, found that
 
the applicant's Small Bore Class 1 Piping Inspection program provides for a one-time
 
examination of ASME Code Class 1 small bor e piping using volumetric examination techniques that are capable of detecting piping cracks caused by SCC, IGSCC or cyclic
 
loading. Based on the staff's determination that the BWR Water Chemistry Program
 
provides mitigation for potential cracking and the Small Bore Class 1 Piping Inspection
 
program provides detection of cracks due to S CC, IGSCC or cyclic loading, should they occur, the staff finds the applicant's proposed AMPs for managing the potential aging
 
effect of cracking in the stainless steel jet pump sensing lines outside the reactor vessel
 
to be acceptable.
 
(2) LRA Section 3.1.2.2.8 addresses cracking due to cyclic loading in isolation condenser components. The applicant stated that this aging effect is not applicable because SSES
 
design does not include an isolation condenser.
SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in steel
 
and stainless steel BWR isolation condenser components exposed to reactor coolant.
 
The existing program relies on ASME Code Section XI ISI; however, the existing program should be augmented to detect cracking due to cyclic loading. The GALL
 
Report recommends an augmented program to include temperature and radioactivity monitoring of the shell-side water and eddy current testing of tubes to ensure that
 
component intended functions will be maintained during the period of extended
 
operation.
 
SRP-LR Section 3.1.2.2.8.2 invokes the AMR Item 26 in Table 1 of the GALL Report, Volume 1 and AMR Item IV.C1-5 of the GALL Report, Volume 2 on management of 3-235 cracking due to cyclical loading in steel and stainless steel BWR isolation condenser components that are exposed to the treated water environment of the reactor coolant. 
 
The staff reviewed the UFSAR for SSES. The staff determined that the UFSAR Chapter
 
6 indicates that, at SSES, each of the SSES units use a reactor core isolation cooling (RCIC) system as the system for isolati ng the reactor from the main steam system during operational transients and during postulated design basis accidents. The staff
 
verified that the units do not include isolation condensers. Based on this review, the
 
staff concludes that the recommendations in SRP-LR Section 3.1.2.2.8.2 and in GALL
 
AMR IV.C1-5 are not applicable to the SSES LRA because the SSES plant designs do
 
not include isolation condenser systems.
 
Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.8 criteria. For those line items that apply to LRA Section 3.1.2.2.8, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.1.2.2.9  Loss of Preload Due to Stress Relaxation 
 
The staff reviewed LRA Section 3.1.2.2.9 against the criteria in SRP-LR Section 3.1.2.2.9.
 
LRA Section 3.1.2.2.9 addresses loss of preload due to stress relaxation. The applicant stated
 
that this aging effect is not applicable because SSES is a BWR.
 
The staff reviewed the UFSAR for SSES. The staff determined that the UFSAR Chapter 1
 
indicates that the SSES reactors are General Electrical (GE) Model 4 BWRs with Mark II
 
containment structures. Based on this review, the staff concludes that the recommendations in
 
SRP-LR Section 3.1.2.2.9 are not applicable to the SSES LRA because the SSES plants are
 
not PWR designed reactors.
 
Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.9 criteria is not applicable.
 
3.1.2.2.10  Loss of Material Due to Erosion 
 
The staff reviewed LRA Section 3.1.2.2.10 against the criteria in SRP-LR Section 3.1.2.2.10.
 
LRA Section 3.1.2.2.10 addresses loss of material due to erosion in steam generators. The
 
applicant stated that this aging effect is not applicable because SSES is a BWR.
 
Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.10 does not
 
apply to SSES.
 
Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.1.2.2.10
 
criteria is not applicable.
 
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.
 
3-236 LRA Section 3.1.2.2.11 addresses cracking due to flow-induced vibration. The applicant stated that cracking due to flow-induced vibration for SSES stainless steel steam dryers exposed to
 
reactor coolant is managed by a combination of the BWR Vessel Internals Program and the
 
BWR Water Chemistry Program.
 
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 GALL Report recommends
 
further evaluation of a plant-specific AMP to ensure that this aging effect is adequately
 
managed.
 
SRP-LR Section 3.1.2.2.11 invokes the AMR Item 29 in Table 1 of the GALL Report, Volume 1
 
and AMR IV.B1-16 in the GALL Report, Volume 2 on management of cracking due to flow-
 
induced vibration stainless steel BWR steam dryers. 
 
The staff reviewed the information in LRA Section 3.1.2.2.11 and in LRA Table 3.1.2-2 against
 
the staff's recommended AMR guidance in SRP-LR Section 3.1.2.2.11 and in GALL AMR IV.B1-
: 16. The staff verified that in LRA Table 3.1.2-2, the applicant has included an AMR that aligns to
 
GALL AMR IV.B1-16, and that in the AMR, the applicant credits a combination Water Chemistry
 
Program and BWR Vessel Internals Program to manage cracking of the steam dryers that is
 
induced by flow-induced vibration. 
 
The staff noted that the aging mechanism of concern is a high cycle fatigue mechanism and that
 
this mechanism is not dependent on the concentrations of chemical impurities that could lead to
 
corrosive type of cracking, such stress corrosion cracking (SCC, including intergranular stress
 
corrosion cracking [IGSCC], primary water stress corrosion cracking [PWSCC]) and
 
intergranular attack (IGA). 
 
Thus, the staff noted that the applicant's crediting of the Water Chemistry Program did not
 
create a valid basis for aging management of cracking due to flow-induced vibrations because
 
flow-induced vibrations are a high-cycle fatigue phenomenon and are not dependent on the
 
control of water chemistry impurity concentrations.
 
The staff also noted that the applicant credited its BWR Vessel Internals Program (LRA AMP
 
B.2.9) for aging management and that the applicant's program is identified as a program that is
 
consistent with the recommended program elements of GALL AMP XI.M9, "BWR Vessel Internals," with an enhancement to perform augmented inspections of the SSES top guide grid
 
beam and beam-to-beam crevice slots. The staff reviewed GALL AMP XI.M9 and confirmed that, although the BWRVIP has submitted a number of BWRVIP topical reports on evaluation of
 
flow-induced vibrations in BWR steam dryers and on inspection of BWR steam dyers and
 
management of cracking that may result in BWR steam dryers as a result of flow-induced
 
vibrations, none of the BWRVIP reports on BWR steam dryer flow induced vibrations and
 
cracking have been approved to date or endorsed in GALL AMP XI.M9, "BWR Vessel Internals."
Thus the staff was of the opinion that the applicant's BWR Vessel Internals Program, in its
 
current form, did not provide a valid basis for managing cracking due to flow-induced vibrations
 
in the steam dryers because the applicant's program does not currently include any
 
enhancements and commitments to: (1) of perform flow-induced vibration high cycle fatigue flaw
 
growth calculations of the steam dryers, (2) establish the flaw evaluation and corrective action
 
recommendations on postulated steam dryer cracking, and (3) establish the augmented
 
inspection recommendations for the steam dryers (including the inspection methods and
 
frequency for the examinations to be performed).
 
3-237 In RAI 3.1.2.2.11-1 by letter dated July 23, 2008, the staff asked the applicant to justify its selection of the Water Chemistry Program and the BWR Vessel Internals Program for aging
 
management of cracking due to flow-induced vibrations of the steam dryers.
 
In its letter dated August 27, 2008, in response to RAI 3.1.2.2.11-1, the applicant stated that the
 
BWR Water Chemistry Program does not manage cracking due to flow-induced vibration. The
 
applicant revised the LRA to delete the BWR Water Chemistry Program from the line entry for
 
cracking of the steam dryers in LRA Table 3.1.2-2. The applicant stated the following for
 
crediting the BWR Vessel Internals Program to manage cracking of the steam dryers:
 
The technical basis for crediting the BWR Vessel Internals Program (BWRVIP) for
 
management of cracking due to flow-induced vibration in the steam dryers is that the
 
BWRVIP incorporates the best industry guidance that is currently available from
 
BWRVIP reports BWRVIP- 139, BWRVIP- 181, and BWRVIP- 182.
 
PPL will follow Section 6 of BWRVIP-139 when evaluating cracking in the steam dryer.
 
PPL has instrumented the newly designed steam dryer in Unit 1 to obtain data on the
 
actual stresses in the dryer during current licensed power at extended power uprate (EPU) conditions. Based on the measured stresses, PPL will perform a flow-induced
 
vibrational analysis. If any fatigue flaws are identified during the BWRVIP-required
 
inspections, PPL can accurately calculate flaw growth and establish re-inspection
 
intervals. 
 
Currently, there is no regulatory basis for management of cracking due to flow-induced
 
vibration in the steam dryers. GALL line item IV.B 1-16 recommends a plant-specific
 
program, which, in effect, acknowledges that there is no generically accepted or
 
approved program for management of flow-i nduced vibration of the steam dryers.
However, since the BWRVIP includes provisions to incorporate all approved BWRVIP
 
documents, or to file notice of exception, t he program requires its own modification if the NRC requires changes to BWRVIP- 139, BWRVIP- 181, and BWRVIP- 182 prior to their
 
approval. Consequently, there is no need to enhance AMP B.2.9, the BWR Vessel
 
Internals Program, at this time.
 
The staff reviewed the applicant response and noted that the applicant proposes to use
 
BWRVIP-139, Steam Dryer Inspection and Flaw Evaluation Guidelines, to manage the aging
 
effect of cracking in the steam dryers. The staff issued its safety evaluation on BWRVIP-139 in a
 
letter to the BWRVIP dated July 30, 2008. For re-inspection, the staff stated that the guidelines
 
below should be followed:
 
Each BWR licensee will determine the appropriate re-inspection approach according to GE SIL-644 or BWRVIP-139 in consideration of the steam dryer performance at its plant. License conditions associated with steam dryer monitoring programs in power uprate license amendments take precedence over the st eam dryer re-inspection provisions in GE SIL-644 or BWRVIP-139. The licensee will justify any adjustments to it s steam dryer re-inspection program where commitments exist to implement the re-inspec tion provisions in GE SIL-644 to support a power uprate license amendment or other activities. The licensee is expected to inform the NRC staff of significant changes to its steam dryer re-inspection program where the staff relied on the program in a regulatory
 
decision.
 
3-238 The staff finds the deletion of the Water Chemistry Program to be acceptable because flow-induced vibrations are a high-cycle fatigue phenomenon and are not dependent on the control
 
of water chemistry impurity concentrations.
 
The staff noted that the applicant has instrumented the dryer to obtain data on actual stresses
 
during extended power uprate conditions. Based on this data, the applicant plans to perform a
 
flow-induced vibrational analysis. The staff concludes that the applicant is implementing the
 
guidelines of BWRVIP-139 as accepted by the staff in its SE and on the basis that the
 
applicant's BWR Vessel Internals Program includes provisions to incorporate all approved
 
BWRVIP documents, and the BWR Vessel Internals Program has incorporated the guidelines of
 
BWRVIP-139, the staff finds the applicant response acceptable. 
 
Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.11 criteria. For those line items that apply to LRA Section 3.1.2.2.11, the staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.1.2.2.12  Cracking Due to Stress Corrosion Cracking and Irradiation-Assisted Stress
 
Corrosion Cracking 
 
The staff reviewed LRA Section 3.1.2.2.12 against the criteria in SRP-LR Section 3.1.2.2.12.
 
LRA Section 3.1.2.2.12 addresses cracking due to SCC and IASCC. The applicant stated that
 
this aging effect is not applicable because SSES is a BWR.
 
SRP-LR Section 3.1.2.2.12 states that cracking due to SCC and IASCC may occur in PWR
 
stainless steel reactor internals exposed to reactor coolant.
 
The staff confirmed in SRP-LR Table 3.1-1, Item 20, is only applicable to PWR plants.
 
Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.12 does not
 
apply to SSES.
 
Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.12 criteria is not
 
applicable.
 
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 primary water SCC (PWSCC). The applicant
 
stated that this aging effect is not applicable because SSES is a BWR.
 
SRP-LR Section 3.1.2.2.13 states that cracking due to primary water SCC (PWSCC) may occur
 
in PWR components made of nickel alloy and steel with nickel alloy cladding, including RCPB
 
components and penetrations inside the reactor coolant system such as pressurizer heater
 
sheathes and sleeves, nozzles, and other internal components.
 
The staff confirmed in SRP-LR Table 3.1-1, Item 31, is only applicable to PWR plants.
3-239  Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.13 does not
 
apply to SSES.
 
Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.13 criteria is not
 
applicable.
 
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 due to FAC in steam generators. The applicant
 
stated that this aging effect is not applicable because SSES is a BWR.
 
SRP-LR Section 3.1.2.2.14 states that wall thinning due to FAC may occur in steel FW inlet
 
rings and supports.
 
The staff confirmed in SRP-LR Table 3.1-1, Item 32, is only applicable to PWR plants.
 
Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.14 does not
 
apply to SSES.
 
Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.14 criteria is not
 
applicable.
 
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. The applicant
 
stated that this aging effect is not applicable because SSES is a BWR.
 
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 staff confirmed in SRP-LR Table 3.1-1, Item 33, is only applicable to PWR plants.
 
Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.15 does not
 
apply to SSES.
Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.15 criteria is not applicable.
 
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 due to SCC and primary water SCC on the primary coolant side of PWR steel steam generator upper and lower heads, tubesheets, 3-240 and tube-to-tube sheet welds made or clad with stainless steel. The applicant stated that this aging effect is not applicable because SSES is a BWR.
SRP-LR Section 3.1.2.2.16 states that cracking due to SCC may occur on the primary
 
coolant side of PWR steel steam generator upper and lower heads, tubesheets, and
 
tube-to-tube sheet welds made or clad with stainless steel. Cracking due to PWSCC
 
may occur on the primary coolant side of PWR steel steam generator upper and lower
 
heads, tubesheets, and tube-to-tube sheet welds made or clad with nickel alloy.
 
The staff reviewed the UFSAR for SSES. The staff determined that the UFSAR Chapter
 
1 indicates that the SSES reactors are General Electrical (GE) Model 4 BWRs with Mark
 
II containment structures. Based on this review, the staff concludes that the
 
recommendations in SRP-LR Section 3.1.2.2.16.1 are not applicable to the SSES LRA
 
because the SSES plants are not PWR designed reactors.
 
The staff confirmed in SRP-LR Table 3.1-1, Item 34 and Item 35, is only applicable to
 
PWR plants. Because SSES is a BWR, the staff finds that this item in SRP-LR Section
 
3.1.2.2.16.1 does not apply to SSES.
 
(2) LRA Section 3.1.2.2.16 addresses cracking due to SCC and primary water SCC on stainless steel pressurizer spray heads. The applicant stated that this aging effect is not
 
applicable because SSES is a BWR.
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 staff reviewed the UFSAR for SSES. The staff determined that the UFSAR Chapter
 
1 indicates that the SSES reactors are General Electrical (GE) Model 4 BWRs with Mark
 
II containment structures. Based on this review, the staff concludes that the
 
recommendations in SRP-LR Section 3.1.2.2.16.2 are not applicable to the SSES LRA
 
because the SSES plants are not PWR designed reactors.
 
The staff confirmed in SRP-LR Table 3.1-1, Item 36, is only applicable to PWR plants. 
 
Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.16.2
 
does not apply to SSES.
 
Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.16 criteria are not
 
applicable.
 
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, primary water SCC, and irradiation-
 
assisted SCC. The applicant stated that this aging effect is not applicable because SSES is a
 
BWR.
 
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 RV internals components.
3-241  The staff confirmed in SRP-LR Table 3.1-1, Item 37, is only applicable to PWR plants. Because
 
SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.17 does not apply to
 
SSES.
 
Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.17 criteria are not
 
applicable.
 
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 3.1.2-3, the staff reviewed additional details of the AMR results
 
for material, environment, AERM, and AMP combinations not consistent with or not addressed
 
in the GALL Report.
 
In LRA Tables 3.1.2-1 through 3.1.2-3, the applicant indicated, via notes F through J, which the
 
combination of component type, material, environment, and AERM does not correspond to a
 
line item in the GALL Report. The applicant prov ided 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.
 
3.1.2.3.1  Aging Management Review Results - Reactor Pressure Vessel - 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 pressure vessel component groups.
 
LRA Table 3.1.2-1 summarizes the results of AMRs for the Reactor Pressure Vessel low alloy
 
steel, nickel based alloy, and low alloy steel clad with stainless steel, exposed to indoor air (external) for the reactor vessel upper head closure flange, safe ends, nozzles, reactor vessel
 
bottom head flanges, reactor vessel shell rings, reactor vessel closure flange, and reactor
 
vessel upper head (dome). The applicant proposed no aging effect for this
 
material/environment combination and stated that no AMR is required. 
 
The applicant assigned note G for this material/environment combination. Note G states, "Environment not in NUREG-1801 for this component and environment combination." 
 
3-242 During the staff's review, the staff pointed out that the low alloy steel is at high temperature during operation preventing the accumulation of moisture and therefore, insignificant corrosion
 
will occur during this time period. The staff also pointed out that the only time that corrosion
 
could occur is during outages, and these would not be of sufficient duration to result in
 
significant corrosion.
 
During the staff's review, the staff pointed out that Stainless steels and nickel alloys are highly
 
resistant to corrosion in dry atmospheres in the absence of corrosive species (which would be
 
reflective of indoor uncontrolled air), as cited in Metals Handbook, Volumes 3 (p. 65) and 13 (p.555) (Ninth Edition, American Society for Metals International, 1980 and 1987). Components
 
are not subject to moisture in a dry air environment (and indoor uncontrolled air would have
 
limited humidity and condensation). Therefore, stainless steel in an indoor, uncontrolled air
 
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 concludes that there are no aging effects requiring management for these components
 
because of the dry environment for low alloy steel and no aging effect for the nickel alloys or
 
stainless steel cladding and stainless steel components in the Reactor Vessel, Reactor Vessel
 
Internals and Reactor Coolant System components within the scope of license renewal
 
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).
 
In LRA Table 3.1.2-1, the applicant proposed to manage cracking due to stress corrosion
 
cracking (SCC) in stainless steel cladding for low alloy steel in an environment of treated water
 
using the BWR Water Chemistry Program, alone. The applicant cited generic note H for these
 
AMR results, indicating that the aging effect is not in the GALL Report for this component, material and environment combination. The staff noted that the BWR Water Chemistry Program
 
does not include an inspection activity to confirm effectiveness of the program to mitigate the
 
aging effect and issued RAI 3.1-8 by letter dated July 15, 2008, asking the applicant why a
 
confirmatory AMP, such as the Water Chemistry Effectiveness Inspection, is not needed for
 
these components.
 
In a letter dated August 15, 2008, the applicant responded to RAI 3.1-8 by providing the
 
following response:
 
The LRA Table 3.1.2-1 is revised to credit the Chemistry Program Effectiveness
 
Inspection in addition to the BWR Water Chemistry Program for AMR result lines
 
addressing stainless steel cladding in treated water with an aging effect of "cracking -
 
SCC (cladding)."
 
The staff reviewed the applicant's response and the associated LRA changes. The staff
 
reviewed the applicant's BWR Water Chemistry Pr ogram. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water Chemistry Program
 
provides mitigation for the aging effect of cracking caused by SSC in stainless steel clad
 
components exposed to treated water. The staff reviewed the applicant's Chemistry Program
 
Effectiveness Inspection. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the Chemistry Program Effectiveness Inspection is a one-time 3-243 inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "One-Time Inspection." The Chemistry Program E ffectiveness Inspection includes examination methods that are capable of detecting cracking due to SCC. Because the BWR Water
 
Chemistry Program provides mitigation and t he Chemistry Program Effectiveness Inspection provides detection for cracking due to SCC, the staff finds the applicant's LRA changes and the
 
applicant's use of the BWR Water Chemistry Program and the Chemistry Program
 
Effectiveness Inspection for managing cracking due to SCC in the cladding of stainless steel
 
clad components exposed to treated water in the reactor pressure vessel to be acceptable.
 
In LRA Table 3.1.2-1, the applicant includes its plant-specific AMRs on management of cracking
 
- flaw growth in steel (carbon steel or alloy steel) reactor vessel (RV) components that are
 
unclad or have internal stainless steel or Nickel-alloy cladding under internal exposure to the
 
treated water environment of the reactor coolant:
 
RV upper heads, closure flanges, shells, and bottom heads  RV recirculation inlet nozzles, recirculation outlet nozzles, core spray nozzles, jet pump instrumentation nozzles,  RV main steam line nozzles and their safe ends,  RV head spray and spare nozzles, RV head vent nozzles, and their flanges  RV feedwater nozzle safe ends, and RV N11, N12, and N16 instrumentation nozzle safe ends  In these AMRs, the applicant identifies that cracking/flaw growth is an applicable aging effect
 
requiring management (AERM) for the internal component surfaces that are exposed to the
 
reactor coolant. In these AMRs, the applicant credits its Inservice Inspection Program with
 
management of cracking/flaw growth in the components.
 
The staff determined that the applicant conservatively identified cracking/flaw growth as an
 
applicable AERM for the internal component surfaces that are exposed to the treated water
 
environment of the reactor coolant. The staff noted that the applicant's aging effect
 
cracking/flaw growth corresponds to the phrase "crack initiation and growth" in the definition for cracking that is provided in GALL Table IX.E. Based on this determination, the staff finds that the applicant has conformed to the guidance for cracking in GALL Table IX.E. 
 
The staff also determined that the applicant has credited AMP B.2.1, Inservice Inspection
 
Program as the basis for managing cracking/flaw growth in the internal component surfaces that
 
are exposed to the treated water environment of the reactor coolant. The staff verified for the
 
RV components assessed in this section that the Inservice Inspection Program requires the
 
applicant to perform volumetric examinations of these components in accordance with the applicable volumetric and surface examination requirements in the ASME Code Section XI
 
Examination Categories B-A, B-D, or B-F, as invoked by 10 CFR 50.55a. The required
 
volumetric examinations use techniques (such as ultrasonic testing or radiography) that are capable of detecting cracks or imperfections throughout the thickness of the components. Thus, the inspections required by these examination categories are sufficient to detect and monitor for
 
crack initiation and growth that may be occurring in these RV components. On this basis, the
 
staff finds that the applicant has provided an acceptable basis for crediting the Inservice
 
Inspection Program for aging management of cra cking/flaw growth in these components as a result of exposure to the treated water environment of the reactor coolant. 
 
Based on this review, the staff also concludes the applicant has provided an acceptable basis
 
that demonstrates that the volumetric exami nations performed under the Inservice Inspection 3-244 Program will be capable of detecting and monitoring for cracking/flaw growth in these RV components. The staff's evaluation of the ability of the Inservice Inspection Program to manage
 
cracking in AMSE Code Class components is given in SER Section 3.0.3.2.1.
 
In LRA Table 3.1.2-1, the applicant includes its plant-specific AMR on management of cracking
 
- flaw growth in the alloy steel reactor vessel stabilizer brackets that are exposed externally to
 
an indoor air environment. In this AMR, the applicant identifies that cracking/flaw growth is an
 
applicable aging effect requiring management (AERM) for the external component surfaces that
 
are exposed to the indoor air environment. In th is AMR, the applicant credits its Inservice Inspection Program with management of cracki ng/flaw growth in the external component surfaces.
 
The staff determined that the applicant conservatively identified cracking/flaw growth as an
 
applicable AERM for the external RV stabilizer bracket surfaces that are exposed to indoor air.
 
The staff noted that the applicant's aging effect cracking/flaw growth corresponds to the phrase "crack initiation and growth" in the definition for cracking that is provided in GALL Table IX.E.
 
Based on this determination, the staff finds that the applicant has conformed to the guidance for cracking in GALL Table IX.E. 
 
The staff also determined that the applicant has credited AMP B.2.1, Inservice Inspection
 
Program as the basis for managing cracking/flaw growth in the RV stabilizer bracket surfaces
 
that are exposed externally to indoor air. The staff verified that, for the RV stabilizer brackets
 
assessed in this section, the Inservice Inspection Program requires that the applicant to perform
 
surface examinations of these components in accordance with the applicable volumetric and
 
surface examination requirements in the ASME Code Section XI Examination Category B-K, as invoked by 10 CFR 50.55a. The required volumetric examinations use techniques (penetrant
 
testing [PT] or magnetic particle test [MT]) that are capable of detecting potential cracks that
 
penetrate the external surfaces of the stabilizer bracket welds. Thus, the inspections required by this ASME Code Section XI examination category are sufficient to detect and monitor for crack
 
initiation and growth that may be occurring in the externals surfaces of the RV stabilizer
 
brackets. On this basis, the staff finds that the applicant has provided an acceptable basis for
 
crediting the Inservice Inspection Program for aging management of cracking/flaw growth in these components as a result of exposure to indoor air.
 
Based on this review, the staff also concludes that the Inservice Inspection Program is
 
acceptable for management of the applicable AERMs because the applicant has provided an
 
acceptable basis that demonstrates that the surface examinations performed under the
 
Inservice Inspection Program will be capable of detecting and monitoring for cracking/flaw
 
growth in the external RV stabilizer bracket surfaces that are exposed to indoor air. The staff's
 
evaluation of the ability of the Inservice In spection Program to manage cracking in AMSE Code Class components is given in SER Section 3.0.3.2.1.
 
In LRA Table 3.1.2-1, the applicant includes its plant-specific AMR on management of cracking
 
- flaw growth in the Nickel-alloy N9 CRD nozzle cap that is exposed internally to the treated
 
water environment of the reactor coolant. In this AMR, the applicant identifies that cracking/flaw
 
growth is an applicable aging effect requiring management (AERM) for the internal component
 
surfaces that are exposed to the reactor coolant. In this AMR, the applicant credits its BWR
 
CRD Return Line Program with management of cracking/flaw growth in the internal component
 
surfaces. 
 
The staff determined that the applicant conservatively identified cracking/flaw growth as an 3-245 applicable AERM for the internal CRD return line nozzle cap surfaces that are exposed to the reactor coolant. The staff noted that the applicant's aging effect cracking/flaw growth
 
corresponds to the phrase "crack initiation and growth" in the definition for cracking that is provided in GALL Table IX.E. Based on this determination, the staff finds that the applicant met
 
the guidance in SRP-LR 3.1.3.3 for identifying the applicable aging effects for these nozzle cap surfaces because the applicant has conformed to the guidance for cracking in GALL Table IX.E. 
 
The staff also determined that the applicant has credited AMP B.2.6, BWR CRD Return Line
 
Nozzle Program as the basis for managing cracking/flaw growth in the internal surfaces of the
 
CRD return line nozzle caps and their associated cap-to-nozzle circumferential welds that are
 
exposed to the reactor coolant. The staff verified that, for these nozzle caps, the applicant's
 
BWR CRD Return Line Nozzle Program is a program that is designed to manage cracking in the
 
CRD return lines nozzles and that the AMP is consistent with the staff's recommended program
 
elements for CRD return line nozzles in GALL AMP XI.M6, "CRD Return Line Nozzle," with an
 
exception to perform weld overlay methods for repairs of existing cracks in the nozzles. The
 
staff also verified that the scope of the AMP includes potential capping of the nozzles and their
 
associated cap-to-nozzle circumferential welds. The staff evaluates the ability of the BWR CRD
 
Return Line Nozzle Program to manage cracking in these components in SER Section
 
3.0.3.2.2. The staff evaluation includes an evaluation on the ability of the BWR CRD Return Line
 
Nozzle Program to manage cracking in the CRD return line nozzle cap cap-to-nozzle
 
circumferential welds and the exception to use weld overlay methods for repairs of cracking in
 
these welds. On this basis, the staff finds that the applicant has provided an acceptable basis
 
for crediting the BWR CRD Return Line Nozzle Program for aging management of cracking/flaw
 
growth in these components as a result of exposure to the reactor coolant.
 
In LRA Table 3.1.2-1 the applicant includes its plant-specific AMR items for managing cracking
 
and loss of material in the carbon steel reactor pressure vessel support skirt ring girders and
 
cracking in the high strength alloy steel reactor pressure vessel support skirt bolts that are
 
exposed to a indoor air environment. In these AMRs, the applicant credits its Inservice Inspection Program - IWF for aging management of these aging effects. The staff noted that the
 
applicant's Inservice Inspection Program - IWF is a condition monitoring program that is based on compliance with the requirements of 10 CFR 50.55a and the ASME Code Section XI, Subsection IWF for ASME Code Class components supports and that the applicant program is
 
based on conformance with the staff's recommended program elements in GALL AMP XI.S3, "ASME Section XI, Subsection IWF." Based on this review, the staff finds that the applicant has
 
provided an acceptable basis for crediting its Inservice Inspection Program -IWF to manage
 
cracking and loss of material in the reactor pressure vessel support skirt ring girders and
 
cracking of the reactor pressure vessel support skirt bolts because these components are
 
ASME Code Class 1 component supports. The staff evaluates the ability of the Inservice
 
Inspection Program - IWF to manage aging in ASME Code Class 1 components in SER Section
 
3.0.3.1.21
 
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  Aging Management Review Results - Reactor Vessel Internals - LRA Table 3.1.2-2 
 
The staff reviewed LRA Table 3.1.2-2, which summarizes the results of AMR evaluations for the 3-246 RV internals component groups.
 
In LRA Table 3.1.2-2, the applicant includes its plant-specific AMRs on management of
 
reduction in fracture toughness for the following stainless steel (including CASS) reactor vessel (RV) internal components that are exposed to the treated water environment of the reactor
 
coolant and an integrated neutron flux:
 
Core shroud (including upper, intermediate, and lower shroud shells and welds)  Core plate (including plate, beams, rim hold-down bolts and nuts, alignment assembly bolts and nuts and alignment pins)  Top guide components (including beams and rim, alignment pins, bolts, nuts, and hold down clamps)  Orificed and peripheral fuel support pieces  Control Rod Drive tubes  Jet pump assemblies and their subcomponents  Incore dry tubes from the source range and intermediate range monitors
 
In these AMRs, the applicant states that it credits its BWR Vessel Internals Program to manage
 
reduction of fracture toughness in the components. 
 
The staff noted that in Table IV.B1 of GALL Volume 2, the staff identifies that the following cast
 
austenitic stainless steel (CASS) BWR RV internal components may be subject to reduction of
 
fracture toughness as a result of thermal aging embrittlement and neutron irradiation
 
embrittlement:
 
Fuel supports and CRD drive assemblies - fuel orifice supports (GALL AMR IV.B1-9)  Jet pump assembly castings (GALL AMR IV.B1-11)
 
The staff noted that the applicant's plant-specific AMRs for these RV internal components
 
accounts for the fact that, even though the components were not fabricated from a stainless
 
steel casting method (i.e. the stainless steel components are made by forged or wrought
 
fabrication methods, and thus the components not subject to the phenomenon of thermal aging
 
embrittlement), the components are located in areas of high neutron flux and that the
 
components may be subject to reduction of fracture toughness as a result of exposure to a high
 
integrated neutron flux. Thus, the staff finds that the applicant has taken a conservative
 
approach relative to the information on management of fracture toughness in GALL Table IV.B1
 
for BWR RV internal components. 
 
The staff also noted that the applicant's AMRs did identify reduction (loss) of fracture toughness
 
as an applicable aging effect requiring management (AERM) for these RV internal components (as listed in the bullets above), implying that these RV internal components are exposed to a
 
high integrated neutron flux. The staff finds that the applicant's identification that reduction of
 
fracture toughness is an applicable AERM for these components to be acceptable because it is
 
in conformance with the aging effect discussion for loss of fracture toughness in GALL Table IX.E and the neutron irradiation embrittlement aging mechanism discussion in GALL Table IX.F
 
The staff noted, however, that the applicant had credited its BWR Vessel Internals Program to
 
manage reduction in fracture toughness in these RV internal components. The staff verified that
 
the applicant's BWR Vessel Internals Program is given in LRA Section B.2.9 and that the
 
program is identified as an AMP that is cons istent with the program elements in GALL AMP XI.M9, "BWR Vessel Internals, with an exception. The staff noted that this AMP credits the 3-247 augmented inspection and flaw evaluation criteria in NRC-approved BWRVIP topical reports as the basis for managing the aging effects that are applicable to BWR RV and RV internal
 
components. The staff noted that reduction in fracture toughness is not an aging effect "per se"
 
but instead refers to a change that may occur in the fracture toughness material property over
 
time. In its review of the applicant's BWR Vessel Internals Program, the staff noted that the
 
applicant credits the program with limited aging management of reduction of fracture toughness
 
in RV internal components. However, the staff determined that some additional information
 
would be needed to clarify how the recommended BWRVIP report guidelines within the scope of
 
AMP B.2.9, BWR Vessel Internals Program, would accomplish adequate management of
 
reduction of fracture toughness in these RV internal components. In RAI 3.1.2.3.2.1-1/B.2.9-4
 
by letter dated July 23, 2008, the staff asked the applicant to justify why the applicable BWRVIP
 
inspection and flaw evaluation guidelines are considered to be capable of managing reduction
 
of fracture toughness in these RV internals and to clarify the methodology or methodologies in
 
these reports that are credited for management of this aging effect.
 
In its response to RAI 3.1.2.3.2.1-1/B.2.9-4 dated August 27, 2008, the applicant stated that
 
"applicable BWRVIP inspection and flaw evaluation guidelines for RV internal components are
 
considered to be capable of managing reduction of fracture toughnss (ROFT) because the inspections are designed to detect cracking, and, if cracking is detected, the inspection intervals
 
will be adjusted based on crack growth rates that are determined by evaluations that include the
 
effects of ROFT. The examination methods in the BWRVIP reports include ultrasonic
 
examination and visual examination of the RV internal components, when accessible, for the detection of cracks. These same methods are credited for managing ROFT, since ROFT is
 
managed as cracking is identified, evaluated, and monitored in components with fluence values
 
exceeding the threshold for ROFT."
 
Because the BWRVIP guidelines provide examination methods and evaluation techniques to
 
detect cracking, and inspection intervals are adjusted based on the results of the inspection, the
 
staff finds that the guidelines will also manage ROFT, since fluence is one of the key factors
 
affecting the crack growth rate, which increases as fluence increases the yield strength of the
 
material (i.e., reduces fracture toughness). The staff reviewed the applicant's BWR Vessel
 
Internals Program and its evaluation is documented in SER Section 3.0.3.2.4. On this basis, the
 
staff finds the applicant response acceptable, and considers the issue closed.
 
On this basis, the staff finds that the applicant has provided an acceptable basis for crediting the
 
BWR Vessel Internals Program for aging management of reduction of fracture toughness in
 
these components as a result of exposure to treated water environment of the reactor coolant
 
and an integrated neutron flux.
 
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).
 
3.1.2.3.3  Aging Management Review Results - Reactor Coolant System Pressure Boundary -
 
LRA Table 3.1.2-3 
 
The staff reviewed LRA Table 3.1.2-3, which summarizes the results of AMR evaluations for the
 
reactor coolant system pressure boundary component groups.
 
3-248 In LRA Table 3.1.2-3, the applicant proposed to manage loss of material for steel material for driver mount, piping and fitting components exposed to an external environment of indoor air using the AMP B.2.32 "System Walkdown Program."  In addition, the applicant also proposed to
 
manage the loss of material for carbon steel valve bodies ( 4 and < 4 in.) components exposed to external environment of indoor air usi ng the AMP B.2.32 "System Walkdown Program."
 
The AMR line item credits the AMP B.2.32 "System Walkdown Program" to manage loss of
 
material for these components. The AMR line item cites Generic Note H, which indicates that
 
the aging effect is not addressed in GALL Report for this component, environment and material
 
combination. The staff's evaluation of the AMP B.2.32 "System Walkdown Program" is
 
documented in SER Section 3.0.3.2.15. The staff determined that this program is a condition
 
monitoring program that will detect the aging effect of loss of material for metals, including steel, by periodic surveillance activities and observations of components' external surfaces to detect
 
aging degradation that are with in the scope of license renewal. On the basis that the applicant
 
will be performing periodic visual inspections of these components, the staff finds the AMR
 
results for this line item acceptable.
 
In LRA Table 3.1.2-3, the applicant includes its plant-specific AMR on management of cracking
 
and flaw growth in the internal reactor recirculation pump thermal barrier surfaces that are
 
exposed to the treated, closed-cycle cooling wa ter environment. In these AMRs, the applicant identifies that cracking and flaw growth is an applicable aging effect requiring management (AERM) for the internal component surfaces that are exposed to the treated, closed-cycle
 
cooling water environment. In these AMRs, the applicant credits a combination of the Closed
 
Cooling Water Chemistry Program and BWR Stress Corrosion Cracking Program to manage
 
cracking and flaw growth in the internal thermal barrier surfaces that are exposed to the treated, closed-cycle cooling water environment.
 
The staff verified that the applicant had included a plant-specific AMR on cracking and flaw
 
growth in the internal surfaces of the reactor recirculation pump thermal barriers that are
 
exposed to the treated, closed-cycle cooling wa ter environment, and that, in this AMR, the applicant credited both its Closed Cooling Water Chemistry Program and BWR Stress Corrosion
 
Cracking Program to manage cracking and flaw growth in the internal component surfaces that are exposed to closed-cycle cooling water. 
 
The staff was initially of the opinion that it might not be appropriate to credit the BWR Stress
 
Corrosion Cracking Program for aging management of cracking and flaw growth in the internal
 
surfaces of the reactor recirculation pump thermal barriers because they may be located in
 
areas that are inaccessible for examination. 
 
In RAI 3.1.2.3.3.3-1, Part A dated July 23, 2008, the staff asked the applicant to identify the type
 
of examinations that will be used under the BWR Stress Corrosion Cracking Program to monitor
 
for and detect cracking and flaw growth in the internal surfaces of the recirculation pump
 
thermal barriers that are exposed to closed-cycle cooling water, and to clarify whether the
 
internal surfaces of the reactor recirculation pump thermal barriers are accessible for the
 
examination method that is credited for aging management.
 
The staff also noted that the applicant has credited the Closed Cooling Water Chemistry
 
Program to manage cracking and flaw growth in internal surfaces of these components. The
 
staff noted, however, that these components are made of alloy steel without internal stainless
 
steel or Nickel-alloy cladding. The staff noted that Closed Cooling Water Chemistry Program
 
would only be a valid program to credit for management of cracking/flaw growth if the 3-249 mechanisms inducing cracking and flaw growth were chemistry-related or corrosion-related cracking/flaw growth mechanisms, such as stress corrosion cracking (SCC and its forms such
 
as primary water stress corrosion cracking [PWSCC] or intergranular stress corrosion cracking
 
[IGSCC]) or intergranular attack (IGA). Thus, the staff was of the opinion that the Closed
 
Cooling Water Chemistry Program would only be a valid program to credit if the cracking/flaw
 
growth was induced by either SCC, PWSCC, IGSCC or IGA. In Part B, the staff asked the
 
applicant to clarify the aging mechanisms that could induce cracking and flaw growth in the
 
internal surfaces of the reactor recirculation pump thermal barriers, and based on these
 
mechanisms, to provide its basis why the Closed Cooling Water Chemistry is considered to be a
 
valid AMP for managing cracking and flaw growth in these components.
 
In its response to RAI 3.1.2.3.3.3-1, Part A dated August 27, 2008, the applicant stated that the
 
internal surfaces of the reactor recirculation pump thermal barrier consist of the bored channels
 
that provide the flowpath for the Reactor Building Closed Cooling Water (RBCCW). The
 
applicant also stated that these internal surfaces are inaccessible for inspection; as such, the
 
BWR Stress Corrosion Cracking (SCC) Program is not an appropriate aging management
 
program for cracking.
 
The applicant further stated that "an appropriate aging management approach is to credit the
 
Closed Cooling Water (CCW) Chemistry Progr am supplemented by the Chemistry Program Effectiveness Inspection (CPEI). As described in LRA Section B.2.14, these programs will
 
manage cracking for stainless steel components exposed to closed cooling water. Although the
 
internal surfaces of the reactor recirculation pump thermal barrier are inaccessible for
 
inspection, the CPEI will inspect other components of like material exposed to CCW to confirm
 
that cracking has been effectively mitigated or to detect any degradation that is occurring."
 
In response to RAI 3.1.2.3.3.3-1, Part B dated August 27, 2008, the applicant stated that "the
 
aging mechanism capable of inducing cracking and flaw growth in the internal surfaces of the
 
reactor recirculation pump thermal barriers is stress corrosion cracking (SCC). The pump
 
thermal barrier is susceptible to SCC because it is made of stainless steel and is subjected to a
 
closed cycle cooling water environment. Cracking due to SCC on the internal surfaces of the
 
thermal barrier is mitigated by water chemistry control via the Closed Cooling Water Chemistry Program. This is consistent with GALL item V II.C2-11, which is for stainless steel components exposed to closed cycle cooling water. The GALL item recommends the closed cooling water
 
program for management of cracking due to SCC. It is noted that there is no direct comparison
 
in GALL Section IV for the internal surfaces of the thermal barrier because GALL Section IV
 
does not address a closed cooling water environment.
 
The applicant revised Table 3.1.2-3 for CASS pump thermal barrier to delete BWRSCC
 
Program as the verification program for Closed Cycle Cooling Water Chemistry and instead
 
credits the Chemistry Program Effectiveness Inspection as the verification program. The applicant also revised the footnote H to footnote E.
 
The staff reviewed the applicant response and the changes to the LRA. The GALL Report item
 
VII.C2-11 addresses stainless components in an env ironment of closed cycle cooling water >
140 0 F with an aging effect of cracking due to SCC. For this line, the GALL Report recommends GALL AMP XI.M21, "Closed Cycle Cooling Wate r System," to manage the aging effects. The applicant is crediting its Closed Cycle Cooling Water System program, which is consistent with
 
the GALL Report recommendation, and, in addition, is crediting the Chemistry Program
 
Effectiveness Inspection. The staff evaluates the ability of the Closed Cycle Cooling Water
 
System Program and Chemistry Program Effect iveness Inspection to manage cracking in these 3-250 components in SER Sections 3.0.3.2.7 and 3.0.3.1.10 respectively. On the basis that the applicant is consistent with the GALL Report, the staff finds that applicant response acceptable
 
and concludes that the Closed Cycle Cooling Water System Program and Chemistry Program Effectiveness Inspection will adequately manage the aging effect of cracking due to SCC in
 
CASS reactor recirculation pump thermal barrier in an environment of closed cycle cooling
 
water > 140 0 F during the period of extended operation.
 
In LRA Table 3.1.2-3, the applicant includes its plant-specific AMR on management of
 
cracking/flaw growth in the unclad steel N15 reactor vessel (RV) drain nozzles that are exposed
 
internally to the treated water environment of the reactor coolant. In these AMRs, the applicant
 
identifies that cracking/flaw growth is an applicable aging effect requiring management (AERM)
 
for the internal component surfaces that are exposed to the treated water environment of the
 
reactor coolant. In these AMRs, the applicant credits a combination of BWR Water Chemistry
 
Program and the BWR Penetrations Program for management of cracking/flaw growth in the internal component surfaces that are exposed to the treated water environment of the reactor
 
coolant.
 
The staff verified that, in its AMR for managing cracking and flaw growth in the N15 RV drain
 
nozzles, the applicant credits a combination of its BWR Water Chemistry Program and the BWR
 
Penetrations Program to manage this aging effect. 
 
The staff verified that in AMP B.2.8 the applicant identifies that the BWR Penetrations Program
 
is credited for managing cracking that is projected to occur in the SSES RV penetration nozzles
 
and that the program is designated as an AMP that is consistent with the program elements in GALL AMP XI.M8, "BWR Penetrations," with an exception to include additional RV penetrations (including the N15 RV drain nozzles) within the scope of the program. In RAI B.2.8-1 by letter
 
dated July 23, 2008, the staff asked the applicant to provide its basis for extending the scope of
 
the BWR Penetrations Program to the RV drain nozzles. The scope of RAI B.2.8-1 is also applicable to the staff's assessment of the applicant's AMR item on cracking and flaw growth of
 
the N 15 RV drain nozzles and their associated nozzle-to-vessel welds.
 
The staff noted that the applicant has also credited the BWR Water Chemistry Program to
 
manage cracking and flaw growth in these com ponents. The staff noted, however, that these components are made of alloy steel without internal stainless steel or Nickel-alloy cladding. The
 
staff noted that BWR Water Chemistry Program would only be a valid program to credit for
 
management of cracking/flaw growth if the mec hanisms inducing cracking and flaw growth were chemistry-related or corrosion-related cracki ng/flaw growth mechanisms, such as stress corrosion cracking (SCC and its forms such as primary water stress corrosion cracking
 
[PWSCC] or intergranular stress corrosion cracking [IGSCC]) or intergranular attack (IGA).To
 
date, SCC or IGA have not been identified as aging mechanisms of concern for steel materials (including carbon steels and alloy steels). 
 
The staff noted that the N15 RV drain nozzles are designated as alloy steel nozzles without
 
stainless steel or Nickel-alloy cladding. Thus, the staff was of the opinion that the BWR Water
 
Chemistry Program would only be a valid program to credit if the cracking/flaw growth was induced by SCC, PWSCC, IGSCC or IGA. In RAI 3.1.2.3.3.4-1, Part A by letter dated July 23, 2008, the staff asked the applicant to clarify the weld material that was used to fabricate the
 
N15 RV drain nozzle-to-vessel welds. In RAI 3.1.2.3.3.4-1, Part B, the staff asked the applicant
 
to clarify the aging mechanisms that could induced cracking and flaw growth in the N15 RV
 
drain nozzles and their associated nozzle-to-vessel welds, and based on these mechanisms, to
 
provide its basis why the BWR Water Chemistry is considered to be a valid AMP for managing 3-251 cracking and flaw growth in these components.
 
In its response to RAI 3.1.2.3.3.4-1dated August 27, 2008, the applicant stated:
 
Part A. The NI 5 RV drain nozzles were constructed by boring a hole through the
 
bottom head of the reactor vessel and then welding a short length of a forged
 
pipe (nozzle) to the outside surface of the bottom head. The weld material
 
between the low alloy nozzle (SA-508 Class 1) and the low alloy vessel (SA-533
 
Grade B) is low alloy steel, compatible with the vessel and nozzle materials. The
 
weld consists of two parts; the weld buildup on the outside diameter of the
 
bottom head of the vessel, and the weld between the nozzle and the weld
 
buildup. The weld buildup material is E8018-G, trade name Atom Arc 8018NM, conforming to the current specification for E8018-NM1. The material for the weld
 
between the nozzle and the weld buildup is equivalent to E8018-NM, trade name Adcom 1NMM.
 
The line entry for drain nozzle N15 in LRA Table 3.1.2-1 (LRA page 3.1-45)
 
identifies the drain nozzle as low alloy steel with partial stainless steel (SS) clad.
 
The SS cladding is only on the inside diameter of the bottom head of the vessel, extending just slightly into the bore from the inside diameter of the vessel. There
 
is no cladding on the inside diameter of the vessel bore hole, the weld, or the
 
drain nozzle.
 
Part B. The aging mechanism that is capable of inducing cracking and flaw growth in the N15 RV drain nozzle and associated weld is crack initiation and
 
flaw growth due to thermal and mechanical loading. The BWR Water Chemistry
 
Program does not mitigate cracking caused by this mechanism. LRA Table 3.1.2-
 
1 and line item 3.1.1-40 in Table 3.1.1 are revised to remove the BWR Water
 
Chemistry Program from this entry.
 
The staff reviewed the applicant's response and finds, that because the material of the drain
 
nozzle is alloy steel, cracking is caused by thermal and mechanical loading, and BWR water
 
chemistry does not mitigate cracking caused by this mechanism. Therefore, the staff finds it
 
acceptable to delete the Water Chemistry Program from this line item. The BWR Penetration
 
Program includes inspection and flaw evaluation in conformance with the guidelines of NRC-
 
approved BWRVIP reports BWRVIP-49 and BWRVIP-27, and is consistent with the GALL AMP XI.M8. Therefore, based on the review of the BWR Penetrations Program as documented in
 
SER Section 3.0.3.2.3, the staff finds that the BWR Penetrations Program will adequately
 
manage the aging effect of cracking in the N15 penetration nozzle.
 
In LRA Table 3.1.2-3, the applicant proposed to manage cracking in carbon steel piping and
 
fittings (< 4 inch) and in carbon steel valves (<4 inch) in an environment of treated water using
 
the Small Bore Class 1 Piping Inspection, alone. The applicant cited generic note H for these
 
AMR results, indicating that the aging effect is not in the GALL Report for this component, material and environment combination. The staff noted that the component, material, environment and aging effect combination for these lines appears to be the same as in the
 
GALL Report line IV.C1-1 (where the material is stainless steel or steel). In a letter dated July
 
15, 2008, the staff issued RAI 3.1-7 asking the applicant to explain why note H was used for
 
these lines and to justify why the AMP proposed by the applicant provides acceptable aging
 
management for these components.
 
3-252 The applicant responded to RAI 3.1-7 in a letter dated August 15, 2008. In their response, the applicant revised the results for these two AMR result lines in LRA Table 3.1.2-3. In the revision, the applicant changed the GALL Report reference for these two lines from "N/A" to "IV.C1-1"
 
and changed the Table 1 item reference from "N/A" to "3.1.1-48." The applicant also changed
 
from citing note H to citing note E for these components and added the Inservice Inspection (ISI) Program as an additional AMP to manage the aging effect of cracking in these
 
components. The staff's evaluation of the applicant's response to RAI 3.1-7 and the related LRA
 
changes is documented in SER Section 3.1.2.1.2. 
 
In LRA Table 3.1.2-3 the applicant includes its plant-specific AMR items for managing cracking
 
in carbon steel piping, piping components, and piping elements, and valve bodies that are
 
greater or equal to than 4 inches in diameter and that are exposed to a treated water
 
environment. In these AMRs, the applicant credits its Inservice Inspection Program for aging management of cracking in the surfaces that are exposed to treated water. The staff noted that
 
the applicant's Inservice Inspection Program is a condition monitoring program that is based on compliance with the requirements of 10 CFR 50.55a and the ASME Code Section XI and that
 
the applicant's program is based on conformance with the staff's recommended program elements in GALL AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD." Based on this review the staff finds that the applicant has provided an acceptable
 
basis for crediting its Inservice Inspection Program to manage cracking in these components
 
because these components are ASME Code Class components. The staff evaluates the ability
 
of the Inservice Inspection Program to m anage aging in ASME Code Class components in SER Section 3.0.3.2.1
 
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 RV, RV internals, and reactor coolant system components within the
 
scope of license renewal and subject to an AMR will be adequately managed so that the
 
intended function(s) will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
 
3.2  Aging Management of Engineered Safety Features This section of the SER documents the staff's review of the applicant's AMR results for the
 
engineered safety features components and component groups of:
* Residual Heat Removal (RHR) System
* Reactor Core Isolation Cooling (RCIC) System
* Core Spray System
* High Pressure Coolant Injection (HPCI) System
* Containment and Suppression System
* Containment Atmosphere Control System
* Standby Gas Treatment System (SGTS)
 
3-253  3.2.1  Summary of Technical Information in the Application LRA Section 3.2 provides AMR results for the engineered safety features components and
 
component groups. LRA Table 3.2.1, "Summary of Aging Management Programs for
 
Engineered Safety Features Evaluated in Chapter V of the GALL Report," is a summary
 
comparison of the applicant's AMRs with those evaluated in the GALL Report for the
 
engineered safety features components and component groups.
 
The applicant's AMRs evaluated and incorporated applicable plant-specific and industry OE 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 OE included a review of the GALL Report and OE 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 engineered safety features
 
components within the scope of license renewal and subject to an AMR, will be adequately
 
managed so that the intended function(s) will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
 
The staff conducted an onsite audit of AMRs to ensure the 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.
 
In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which
 
further evaluation is recommended. The staff confirmed that the 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 OE to verify the applicant's claims.
 
Table 3.2-1 summarizes the staff's evaluation of components, aging effects or mechanisms, and
 
AMPs listed in LRA Section 3.2 and addressed in the GALL Report.
 
Table 3.2-1  Staff Evaluation for Engineered Safety Features Components in the GALL Report 3-254 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel and stainless steel piping, piping
 
components, and
 
piping elements in 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 GALL Report (See
 
SER Section
 
3.2.2.2.1) Steel with stainless
 
steel cladding pump
 
casing exposed to treated borated water
 
(3.2.1-2)
Loss of material due to cladding
 
breach A plant-specific 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 BWRs (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 InspectionYes Not applicable Not applicable. The applicant addressed
 
these components
 
under GALL Report
 
item number 3.2.1-5.(See SER Section 3.2.2.2.3.1)
Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to soil
 
(3.2.1-4)
Loss of material due to pitting
 
and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated. Yes Not applicable Not applicable to SSES (See SER
 
Section 3.2.2.2.3.2)
Stainless steel and
 
aluminum piping, piping components, and piping elements
 
exposed to treated water (3.2.1-5)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time InspectionYes BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report  (See SER Section 3.2.2.2.3.3)
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 Lubricating Oil Analysis Program (B.2.33) and
 
Lubricating Oil
 
Inspection
 
Program (B.2.25) Consistent with GALL Report (See SER Section 3.2.2.2.3.4) 3-255 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 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 (See SER Section 3.2.2.2.3.5)
Stainless steel
 
piping, piping
 
components, piping
 
elements, and tank
 
internal surfaces
 
exposed to
 
condensation (internal)
 
(3.2.1-8)
Loss of material due to pitting
 
and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated. Yes Not applicable See SER Section 3.2.2.2.3.6 Steel, stainless steel, and copper alloy heat
 
exchanger tubes
 
exposed to
 
lubricating oil
 
(3.2.1-9)
Reduction of heat transfer
 
due to fouling Lubricating Oil Analysis and One-Time InspectionYes Piping Corrosion Program (B.2.13) Consistent with GALL Report (See SER Section 3.2.2.2.4.1)
Stainless steel heat
 
exchanger tubes
 
exposed to treated water (3.2.1-10)
Reduction of heat transfer
 
due to fouling Water Chemistry and One-Time InspectionYes Heat Exchanger Inspection (B.2.24) Consistent with GALL Report (See SER Section 3.2.2.2.4.2)
Elastomer seals and
 
components in standby gas treatment system
 
exposed to air -
 
indoor uncontrolled
 
(3.2.1-11)
Hardening and loss of strength
 
due to elastomer
 
degradation A plant-specific aging management
 
program is to be
 
evaluated. Yes System Walkdown (B.2.32) Consistent with GALL Report (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 BWRs (See SER
 
Section 3.2.2.2.6) 3-256 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel drywell and suppression chamber spray system nozzle and flow orifice internal
 
surfaces exposed to
 
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 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 InspectionYes BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report  (See SER Section 3.2.2.2.8.1)
Steel containment
 
isolation piping, piping components, and piping elements
 
internal surfaces
 
exposed to treated water (3.2.1-15)
Loss of material due to general, pitting, and
 
crevice corrosion Water Chemistry and One-Time InspectionYes Not applicable Not applicable. The applicant addressed
 
these components
 
under GALL Report
 
item number
 
3.2.1-14. (See SER Section 3.2.2.2.8.2.)
Steel piping, piping
 
components, and
 
piping elements
 
exposed to
 
lubricating oil
 
(3.2.1-16)
Loss of material due to general, pitting, and
 
crevice corrosion Lubricating Oil Analysis and One-Time InspectionYes Lubricating Oil Analysis Program (B.2.33) and
 
Lubricating Oil
 
Inspection
 
Program (B.2.25) Consistent with GALL Report (See SER Section 3.2.2.2.8.3) Steel (with or without coating or wrapping)
 
piping, piping
 
components, and
 
piping elements
 
buried in soil
 
(3.2.1-17)
Loss of material due to general, pitting, crevice, and MIC Buried Piping and Tanks Surveillance
 
or
 
Buried Piping and Tanks Inspection No 
 
Yes Not applicable Not applicable to SSES (3.2.2.2.9)
Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to treated water > 60 C (> 140 F) (3.2.1-18)
Cracking due to SCC and IGSCC BWR Stress Corrosion Cracking and Water ChemistryNo BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22)  Consistent with GALL Report (See SER Section 3.2.2.1.4) 3-257 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
 
(3.2.1-19) Wall thinning due to FAC Flow-Accelerated Corrosion No Flow-Accelerated
 
Corrosion (B.2.11) Consistent with GALL Report Cast austenitic
 
stainless steel piping, piping components, and piping elements
 
exposed to treated water (borated or unborated) > 250 C (> 482 F) (3.2.1-20)
Loss of fracture toughness due
 
to thermal aging
 
embrittlement Thermal Aging Embrittlement of
 
CASS No Not applicable Not applicable.  (See SER Section
 
3.2.2.1.1)
High-strength steel
 
closure bolting exposed to air with steam or water
 
leakage (3.2.1-21)
Cracking due to cyclic loading, SCC Bolting Integrity No Bolting Integrity Program (B.2.12) Consistent with GALL Report 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 Bolting Integrity Program (B.2.12) Consistent with GALL Report 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.2.12) Consistent with GALL Report Steel closure bolting
 
exposed to air -
 
indoor uncontrolled (external)
 
(3.2.1-24)
Loss of preload due to thermal
 
effects, gasket
 
creep, and self-
 
loosening Bolting Integrity No Not applicable Consistent with GALL Report Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to closed cycle cooling water > 60 C (> 140 F) (3.2.1-25)
Cracking due to SCC Closed-Cycle Cooling Water System No Not applicable Not applicable to SSES  (See SER
 
Section 3.2.2.1.1) 3-258 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 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 SSES (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 BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report (See SER Section 3.2.2.1.5.) 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 BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report (See SER Section 3.2.2.1.5.) 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 BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report (See SER Section 3.2.2.1.5.)
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 Piping Corrosion (B.2.13), and
 
Heat Exchanger
 
Inspection (B.2.24) Consistent with GALL Report (See SER Section 3.2.2.1.2)
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 System Walkdown (B.2.32), and Supplementary Piping/Tank
 
Inspection (B.2.28) Consistent with GALL Report (See SER Section 3.2.2.1.3) 3-259 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 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 Preventive Maintenance
 
Activities -
 
HPCI/RCIC Turbine Casings (B.2.48),
System Walkdown (B.2.32), and Supplementary Piping/Tank
 
Inspection (B.2.28)  Consistent with GALL Report (See SER Section 3.2.2.1.3)
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 SSES (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 Addressed under 3.2.1-32 (See SER
 
Section 3.2.2.1.1)
Steel containment
 
isolation piping and
 
components internal
 
surfaces exposed to raw water
 
(3.2.1-35)
Loss of material due to general, pitting, crevice, and MIC, and
 
fouling Open-Cycle Cooling Water System No Not applicable Not applicable to SSES (See SER
 
Section 3.2.2.1.1)
Steel heat exchanger
 
components exposed to raw water
 
(3.2.1-36)
Loss of material due to general, pitting, crevice, galvanic, and
 
MIC, and fouling Open-Cycle Cooling Water System No Piping Corrosion Program (B.2.13)  Consistent with 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 MIC Open-Cycle Cooling Water System No Not applicable Not applicable to SSES (See SER
 
Section 3.2.2.1.1)
Stainless steel
 
containment isolation
 
piping and
 
components internal
 
surfaces exposed to raw water
 
(3.2.1-38)
Loss of material due to pitting, crevice, and
 
MIC, and fouling Open-Cycle Cooling Water System No Not applicable Not applicable to SSES (See SER
 
Section 3.2.2.1.1) 3-260 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel heat exchanger
 
components exposed to raw water
 
(3.2.1-39)
Loss of material due to pitting, crevice, and
 
MIC, and fouling Open-Cycle Cooling Water System No Piping Corrosion Program (B.2.13) Consistent with GALL Report 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 Piping Corrosion Program (B.2.13) Consistent with GALL Report 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 Selective Leaching Inspection
 
Program (B.2.29) Consistent with 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 Selective Leaching Inspection
 
Program (B.2.29) Consistent with GALL Report 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 SSES (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 SSES (See SER
 
Section 3.2.2.1.1)
Aluminum, copper alloy > 15% Zn, and
 
steel external
 
surfaces, bolting, and
 
piping, piping
 
components, and
 
piping elements exposed to air with borated water
 
leakage (3.2.1-45)
Loss of material due to Boric acid
 
corrosion Boric Acid Corrosion No Not applicable Not applicable to BWRs 3-261 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 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 BWRs Cast austenitic
 
stainless steel piping, piping components, and piping elements
 
exposed to treated borated water > 250 C (> 482 F) (3.2.1-47)
Loss of fracture toughness due
 
to thermal aging
 
embrittlement Thermal Aging Embrittlement of
 
CASS No Not applicable Not applicable to BWRs 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 C (> 140 F) (3.2.1-48)
Cracking due to SCC Water Chemistry No Not applicable Not applicable to BWRs 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 Not applicable Not applicable to BWRs Aluminum piping, piping components, and piping elements
 
exposed to air -
 
indoor uncontrolled (internal/external)
 
(3.2.1-50) None None No None Consistent with GALL Report Galvanized steel
 
ducting exposed to
 
air - indoor controlled (external)
 
(3.2.1-51) None None No None Consistent with GALL Report 3-262 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 - indoor
 
uncontrolled (external), lubricating oil, raw water, treated water, or treated borated water
 
(3.2.1-52) None None No None Consistent with GALL Report Stainless steel, copper alloy, and nickel alloy piping, piping components, and piping elements
 
exposed to air -
 
indoor uncontrolled (external)
 
(3.2.1-53) None None No None Consistent with 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 SSES (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 Not applicable Not applicable to SSES (See SER
 
Section 3.2.2.1.1)
Steel, stainless steel, and copper alloy
 
piping, piping
 
components, and
 
piping elements
 
exposed to gas
 
(3.2.1-56) None None No Not applicable Not applicable to SSES (See SER
 
Section 3.2.2.1.1)
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 BWRs  The staff's review of the engineered safety features 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 3-263 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 engineer ed safety features 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 engineered safety features components:
* BWR Water Chemistry Program
* Flow-Accelerated Corrosion (FAC) Program
* Bolting Integrity Program
* Piping Corrosion Program
* Fire Water System Program
* Chemistry Program Effectiveness Inspection
* Heat Exchanger Inspection
* Lubricating Oil Inspection
* Supplemental Piping/Tank Inspection
* Selective Leaching Inspection
* System Walkdown Program
* Lubricating Oil Analysis Program
* Preventive Maintenance Activities - RCIC/HPCI Turbine Casings LRA Tables 3.2.2-1 through 3.2.2-7 summarize AMRs for the engineered safety features 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.
 
3-264 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 GA LL 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. 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 reviewed the LRA to confirm that the applicant: (a) provided a brief description of the
 
system, components, materials, and environments; (b) stated that the applicable aging effects were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the
 
engineered safety features ESF components that are subject to an AMR. On the basis of its
 
audit and review, the staff determines that, for AMRs not requiring further evaluation, as
 
identified in LRA Table 3.2.1, the applicant's references to the GALL Report are acceptable and
 
no further staff review is required, with the exception of the following AMRs that the applicant
 
had identified were consistent with the AMRs of the GALL Report and for which the staff felt
 
were in need of additional clarification and assessment. The staff's evaluations of these AMRs
 
are providing in the subsections that follows. 
 
3.2.2.1.1 AMR Results Identified as Not Applicable 
 
In LRA Table 3.2.1, item 20, the applicant indicates that the corresponding AMR result line in
 
the GALL Report is not applicable because there are no CASS components in the ESF systems
 
for SSES that are exposed to treated water > 250&deg;C (>482&deg;F). The staff reviewed the
 
documentation supporting the applicant's AMR evaluation and confirmed the applicant's claim
 
that SSES do not have ESF CASS components in the environment stated above. Therefore, the staff finds the corresponding AMR result line in the GALL Report is not applicable to SSES.
 
In LRA Table 3.2.1, item 25, the applicant states that the corresponding AMR result line in the 3-265 GALL Report is not applicable because there are no stainless steel piping and piping components in the ESF systems for SSES that are exposed to closed-cycle cooling water >
 
60&deg;C (>140&deg;F). The staff reviewed the documentation supporting the applicant's AMR
 
evaluation and confirmed the applicant's claim that SSES does not have this commodity group
 
in the ESF System. Therefore, the staff finds the corresponding AMR result line in the GALL
 
Report is not applicable to SSES.
 
In LRA Table 3.2.1, item 26, the applicant states that the corresponding AMR result line in the
 
GALL Report is not applicable because there are no steel piping and piping components in the
 
ESF systems for SSES that are exposed to closed-cycle cooling water. The staff reviewed the
 
documentation supporting the applicant's AMR evaluation and confirmed the applicant's claim
 
that this line item is not applicable to SSES. Therefore, the staff agrees with the applicant's
 
determination that the corresponding AMR result line in the GALL Report is not applicable to
 
SSES.
 
In LRA Table 3.2.1, item 33, the applicant states that the corresponding AMR result line in the
 
GALL Report is not applicable the ESF systems include no steel encapsulation components. 
 
The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed
 
the applicant's claim. Therefore, the staff agrees with the applicant's determination that the
 
corresponding AMR result line in the GALL Report is not applicable to SSES.
 
In LRA Table 3.2.1, item 34, the applicant states that the corresponding AMR result line are
 
addressed under item 3.2.1-32. The staff reviewed the documentation supporting the
 
applicant's AMR evaluation in items 3.1.1-32, and no SESS AMR line items roll up to 3.1.1-34. 
 
Therefore, the staff agrees with the applicant's determination that the corresponding AMR result
 
line in the GALL Report is not applicable to SSES.
 
In LRA Table 3.2.1, item 35, the applicant indicates for that the corresponding AMR result line, there are no steel containment isolation piping or components exposed to raw water in the ESF
 
systems for SSES. In addition, the applicant indicated that this item is applied to loop seal
 
valves exposed to raw water in the SGTS. The staff reviewed the documentation supporting the
 
applicant's AMR evaluation and confirmed the applicant's claim that SSES has no steel
 
containment isolation piping or components exposed to raw water in the ESF System. In
 
addition, the staff reviewed the Table 2 items which correspond to loop seal valves exposed to
 
raw water in the SGTS, and finds the applicant's management of these line item components
 
consistent with the GALL Report. Therefore, the staff agrees with the applicant's treatment of
 
line item 3.2.1-35.
 
In LRA Table 3.2.1, items 37 and 38, the applicant states that the corresponding AMR result line
 
in the GALL Report is not applicable because there are no stainless steel piping, piping
 
components, or piping elements exposed to raw water in the ESF Systems, and no stainless
 
steel containment isolation piping or components exposed to raw water in the ESF Systems
 
respectively. The staff reviewed the documentation supporting the applicant's AMR evaluation
 
and confirmed the applicant's claim that SSES has no in-scope stainless steel piping, piping
 
components, piping elements, containment isolati on piping or components in the ESF Systems.
Therefore, the staff agrees with the applicant's determination that the corresponding AMR result
 
lines in the GALL Report is not applicable to SSES.
 
In LRA Table 3.2.1, item 43, the applicant indicates for this corresponding AMR result line in the
 
GALL Report, there are no gray cast iron pi ping, piping components, or piping elements exposed to soil in the ESF systems. The staff reviewed the documentation supporting the 3-266 applicant's AMR evaluation and confirmed the applicant's claim that no SSES components in the ESF systems align to this item. Therefore, the staff agrees with the applicant's
 
determination that the corresponding AMR result line in the GALL Report, and finds this line
 
item as not applicable to SSES.
 
In LRA Table 3.2.1, item 44, the applicant states that the corresponding AMR result line in the
 
GALL Report is not applicable because there are no gray cast iron motor coolers exposed to
 
treated water in the ESF systems. The staff reviewed the documentation supporting the
 
applicant's AMR evaluation and confirmed the applicant's claim that SSES has no in-scope gray
 
cast iron motor coolers exposed to treat water in the ESF Systems. Therefore, the staff agrees
 
with the applicant's determination that the corresponding AMR result line in the GALL Report is
 
not applicable to SSES.
 
In LRA Table 3.2.1, item 54, the applicant states that the corresponding AMR result line in the
 
GALL Report is not applicable because there are no steel components exposed to indoor air (controlled) environments in ESF systems.
The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed that no components under this commodity group exist in the ESF. Therefore, the staff agrees with the applicant's determination that the
 
corresponding AMR result line in the GALL Report is not applicable to SSES.
 
In LRA Table 3.2.1, item 55, the applicant states that the corresponding AMR result line in the
 
GALL Report is not applicable because there are no steel or stainless steel components
 
embedded in concrete in the ESF Systems. The staff reviewed the documentation supporting
 
the applicant's AMR evaluation and confirmed the applicant's claim. Therefore, the staff agrees
 
with the applicant's determination that the corresponding AMR result line in the GALL Report is
 
not applicable to SSES.
 
In LRA Table 3.2.1, item 56 the applicant states that the corresponding AMR result line in the
 
GALL Report is not applicable because there are no steel, stainless steel, or cooper alloy
 
components in the ESF systems for SSES that are exposed to gas. The staff reviewed the
 
documentation supporting the applicant's AMR evaluation and confirmed the applicant's claim
 
that SSES has no in-scope steel, stainless steel, or cooper alloy components in the ESF that
 
are exposed to gas. Therefore, the staff agrees with the applicant's determination that the
 
corresponding AMR result line in the GALL Report is not applicable to SSES.
 
3.2.2.1.2  Reduction of Heat Transfer due to Fouling
 
In LRA Table 3.2.2.-1, the applicant stated that reduction of heat transfer of RHR heat
 
exchanger copper alloy tubes in an external environment of treated water is managed by the Piping Corrosion Program.
 
The staff noted that the applicant applied note E to this item. The applicant referenced Table
 
3.2-1, item 3.2.1-30 and GALL Report Volume 2, item V.A-11. The staff reviewed the AMR
 
results lines that reference note E and determines that the component type, material, environment, and aging effect are consistent with the GALL Report. However, the staff noted that where the GALL Report recommends AMP XI.M 21, "Closed-Cycle Cooling Water System," the applicant proposed using the Piping Corrosion Program. The staff also noted that the
 
internal environment of the tubes is raw water and the heat exchanger is part of the GL 89-13
 
Program. 
 
The GALL recommended AMP XI.M21, Closed-Cycl e Cooling Water System, recommends 3-267 preventive measures to minimize corrosion and testing and inspection to monitor the effects of corrosion. The staff reviewed the Piping Corrosion Program, which includes preventive
 
measures such as chemical treatment and cleaning, and testing and inspection on a periodic
 
basis as per the commitments in response to NRC Generic Letter 89-13. Based on this review, the staff finds that the Piping Corrosion program will adequately manage the aging effect of
 
reduction of heat transfer of copper alloy heat exchanger tubes in an external environment of
 
treated water for the period of extended operation.
 
In LRA Tables 3.2.2.-2 and 3.2.2-4, the applicant states that reduction of heat transfer of RCIC
 
and HPCI heat exchanger copper alloy tubes in an internal environment of treated water is
 
managed by the Heat Exchanger Inspection Program.
 
The staff noted that the applicant applied note E to this item. The applicant referenced Table
 
3.2-1, item 3.2.1-30 and GALL Report Volume 2, item V.A-11. The staff reviewed the AMR
 
results lines that reference note E and determines that the component type, material, environment, and aging effect are consistent with the GALL Report. However, the staff noted that where the GALL Report recommends AMP XI.M 21, "Closed-Cycle Cooling Water System," the applicant proposed using the Heat Exchanger Inspection Program.
 
The GALL recommended AMP XI.M21, Closed-Cycl e Cooling Water System, recommends preventive measures to minimize corrosion and testing and inspection to monitor the effects of
 
corrosion, whereas the applicant is proposing only a one-time inspection activity. The staff
 
issued RAI 3.2.2.1-1 dated July 23, 2008 requesting the applicant to justify how the one-time
 
heat exchanger inspection activity by itself will manage the aging effect of reduction in heat
 
transfer, without preventive measures to minimize corrosion, such as maintaining treated water
 
chemistry control.
 
In its response to RAI 3.2.2.1-1dated August 22, 2008, the applicant stated that as indicated in
 
Tables 3.2.2-2 and 3.2.2-4, the BWR Water Chemistry Program is credited for managing loss of
 
material for copper alloy heat exchanger tubes exposed to treated water. The applicant also
 
stated that since the BWR Water Chemistry Program does not contain measures for detection
 
of aging effects through inspection, it is not credited for managing reduction in heat transfer;
 
however, it is recognized that the same prev entive actions by which the water chemistry program manages loss of material also mitigates the conditions that could result in reduction in
 
heat transfer. The applicant further stated that due to the BWR water chemistry control, fouling
 
of heat exchanger tubes is not expected to occur. Therefore, the applicant concluded that as
 
stated in LRA Section B.2.24, the Heat Exchanger Inspection will provide direct evidence as to
 
whether, and to what extent, reduction in heat transfer has occurred, or is likely to occur, that
 
could result in a loss of intended function.
 
The staff noted that in LRA Tables 3.2.2-2 and 3.2.2-4, the BWR Water Chemistry Program is
 
credited for managing loss of material of RCIC turbine oil coolers and HPCI lube oil coolers. For
 
these same coolers, the applicant has credited Heat Exchanger Inspection Program for
 
reduction of heat transfer. On the basis that water chemistry is maintained to minimize corrosion
 
and fouling, the staff finds the use of Heat Exchanger Inspection Program acceptable for
 
managing the aging effects of reduction of heat transfer for copper alloy heat exchanger tubes
 
exposed to treated water and finds the applicant response acceptable. The evaluation of the
 
Heat Exchanger Program is documented in SER Section 3.0.3.1.12.
 
3.2.2.1.3  Loss of material due to general corrosion
 
3-268 In LRA Table 3.2.1, Item 3.2.1-32, addresses loss of material due to general corrosion for steel piping and ducting components and internal surfaces exposed to air (indoor uncontrolled
 
[internal]) in the Standby Gas Treatment System. The GALL Report recommends GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" to
 
manage this aging effect. The AMR line items in LRA Table 2 that reference this line item in
 
GALL Report Table 1 cite Generic Note E, indicating that the AMR line items are consistent with
 
GALL Report material, environment, and aging effect, but a different aging management
 
program is credited. The staff reviewed the AMR results lines that reference note E and
 
determines that the material, environment, and aging effect are consistent with the GALL
 
Report.
 
The staff reviewed the applicant's AMP B.2.32 "System Walkdown Program" and its evaluation
 
is documented in SER Sections 3.0.3.2.15. The staff determined that this aging management
 
program which include surveillance activities and observations that are adequate to manage
 
loss of material due to general corrosion for steel components exposed to ventilation (internal)
 
addressed by this AMR are consistent with those activities recommend by GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components". However
 
the applicant is crediting the AMP B.2.32, which performs visual inspections of the external
 
surfaces only, for the internal surfaces of fan and filter housings, piping, valve bodies, plenums, and SGTS filter unit enclosures. The staff felt that additional information was needed and
 
therefore, by letter dated July 23. 2008 the staff issued RAI 3.x.2.1-1 requesting the applicant to
 
justify the basis for crediting AMP B.2.32, which performs visual inspections of external surfaces
 
only, for the internal surfaces of steel ventilation system enclosures and for piping components
 
in ventilation environments. 
 
In its response to RAI 3.x.2.1-1 dated August 22, 2008, the applicant stated that the internal
 
ventilation environment of that these com ponents are exposed to is the same as the environment the external surfaces are exposed to because this system is normally in a standby mode in which the relevant temperature and humidity is the same on the external and internal
 
surface. The staff noted that crediting an external visual inspection for managing aging of the
 
internal surface if the environments are the same is consistent with the recommendations given in the program element, "scope of program", of GALL AMP XI.M36 "External Surfaces
 
Monitoring", in which a visual inspection of the external surfaces may be representative of the
 
internal surfaces if the environment is the same for the external and internal surfaces. The staff
 
noted that internal surfaces of the Standby Gas Treatment System filter unit enclosure and
 
piping may experience a different environment at the air/water interface of the mist eliminator
 
loop seal, so the applicant is supplementing the AMP B.2.32 "System Walkdown Program" with
 
the AMP B.2.28 "Supplemental Piping/Tank Inspection" and the staff confirmed that the AMP
 
B.2.28 will provide verification if degradation has occurred on the internal surfaces of these
 
components and the effectiveness of the AMP B.2.32 "System Walkdown Program" for
 
managing loss of material. On the basis of its review, the staff finds the applicable portion of the
 
applicant's response that references GALL Item V.B-1 to be acceptable because (1) the
 
environments of the external surface and internal surface is the same and consistent with the 
 
recommendations provided in GALL that an visual inspection of the external surface can be
 
credited for managing aging of the internal surfaces if the environments are the same and (2)
 
the applicant has credited a one-time inspection to verify if degradation has occurred  and the
 
effectiveness of the Systems Walkdown Program when the environment of the external surface may be different than the environment of the internal surface. On this basis, the staff finds the
 
AMR results for this line item acceptable.
 
In LRA Tables 3.2.2-1 and 3.2.2-2, the applicant states that loss of material of RHR and RCIC 3-269 steel piping in an internal environment of vent ilation and external environment of indoor air is managed by the Supplementary Piping/Tank Inspection Program.
 
The staff noted that the applicant applied note E to this item. The applicant referenced Table
 
3.2-1, items 3.2.1-31 and 3.2.1-32 and GALL Report Volume 2, items VD2-16 and VD2-2. The
 
staff reviewed the AMR results lines that reference note E and determines that the component
 
type, material, environment, and aging effect are consistent with the GALL Report. However, the staff noted that where the GALL Report recommends AMP XI.M39, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," and AMP XI.M36, "External
 
Surface Monitoring", the applicant proposed using the Supplementary Piping/Tank Inspection
 
Program. 
 
The LRA also references footnote 0203, which states that the environment is an aggressive
 
air/water interface in the suppression pool. The staff determined that in this environment, loss of
 
material is due to general, crevice and pitting corrosion. The Supplementary Piping/Tank
 
Inspection Program uses a combination of volu metric and visual examination techniques to identify evidence of loss of material or lack thereof. The staff's evaluation of the Supplementary
 
Piping/Tank Inspection Program is documented in SER Section 3.0.3.1.16. Because the
 
Supplementary Piping/Tank Inspection is performed at very specific locations of air/water interface, and employs more conservative ins pection techniques than the visual inspection of Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components and the
 
External Surfaces Monitoring Program, the staff finds that the Supplementary Piping/Tank
 
Inspection Program will adequately manage the aging effects of loss of material in this
 
aggressive environment.
 
In Table 3.2.2-5, the LRA states that loss of material of containment and suppression system
 
steel downcomers in an external environment of indoor air is managed by the Supplementary Piping/Tank Inspection Program.
 
The staff noted that the applicant applied note E to this item. The applicant referenced           
 
Table 3.2-1, item 3.2.1-31 and GALL Report Volume 2, item VB-3. The staff reviewed the AMR
 
results lines that reference note E and determines that the component type, material, environment, and aging effect are consistent with the GALL Report. However, the staff noted
 
that where the GALL Report recommends AMP AMP XI.M36, "External Surface Monitoring", the applicant proposed using the Supplementary Piping/Tank Inspection Program. 
 
The LRA also references footnote 0212, which states that the environment is an aggressive
 
air/water interface in the suppression pool. The staff determined that in this environment, loss of
 
material is due to general, crevice and pitting corrosion. The Supplementary Piping/Tank
 
Inspection Program uses a combination of volu metric and visual examination techniques to identify evidence of loss of material or lack thereof. The staff's evaluation of the Supplementary
 
Piping/Tank Inspection Program is documented in SER Section 3.0.3.1.16. Because the
 
Supplementary Piping/Tank Inspection is perform ed at very specific locations, and employs more conservative inspection techniques than t he visual inspection of External Surfaces Monitoring Program, the staff finds that the Supplementary Piping/Tank Inspection Program will
 
adequately manage the aging effects of loss of material in this aggressive environment.
 
In Table 3.2.2-7, the LRA states that loss of material of standby gas treatment system steel filter
 
unit enclosure and skimmer surge tanks in an inte rnal environment of ventilation is managed by the Supplementary Piping/Tank Inspection Program.
 
3-270 The staff noted that the applicant applied note E to this item. The applicant referenced Table 3.2-1, item 3.2.1-32 and GALL Report Volume 2, item V.B-1. The staff reviewed the AMR
 
results lines that reference note E and determines that the component type, material, environment, and aging effect are consistent with the GALL Report. However, the staff noted that where the GALL Report recommends AMP XI.M39, "Inspection of Internal Surfaces in
 
Miscellaneous Piping and Ducting Components," the applicant proposed using the
 
Supplementary Piping/Tank Inspection Program. 
 
The LRA also references footnote 0215, which states that the environment is an aggressive
 
air/water interface in the suppression pool. The staff determined that in this environment, loss of
 
material is due to crevice and/or pitting corrosion and MIC (at the airwater interface in the mist
 
eliminator loop seals), and galvanic corrosion (at contact points with the mist eliminator housing.
 
The Supplementary Piping/Tank Inspection Program uses a combination of volumetric and
 
visual examination techniques to identify evidence of loss of material or lack thereof. The staff's
 
evaluation of the Supplementary Piping/Tank Inspection Program is documented in SER
 
Section 3.0.3.1.16. Because the Supplementary Piping/Tank Inspection is performed at very
 
specific locations, and employs more conserva tive inspection techniques than the visual inspection of Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components
 
Program, the staff finds that the Supplementary Piping/Tank Inspection Program will adequately
 
manage the aging effects of loss of material in this aggressive environment.
 
LRA Table 3.3.1, line items 3.2.1-32 addresses the results of an AMR for Steel piping and
 
ducting components exposed internal air - indoor uncontrolled. The applicant addresses cast
 
iron and carbon steel piping, pump casings, rupture disks and valve bodies in the Reactor Core
 
Isolation Cooling System and High Pressure C oolant Injection System. The applicant states that the aging effect requiring management is loss of material and proposes to use the
 
Preventive Maintenance Activities - RCIC/HPCI Turbine Casings to manage the effects of
 
aging.
 
The applicant has indicated generic note E for this line item which is consistent with the GALL
 
report for material, environment, and aging effec t, but a different aging management program. The staff noted that the GALL Report recommends GALL AMP XI.M38, "Inspection of Internal
 
Surfaces in Miscellaneous Piping and Ducting Components" for GALL AMR Item V.D2-16. The staff noted that the GALL AMP XI.M38 recommends periodic visual inspections during
 
maintenance and surveillance activities to detect age-related degradation, such as loss of
 
material due to general corrosion.
 
The staff's evaluation of the AMP B.2.48 is documented in SER Section 3.0.3.3.3. The staff
 
noted that this program is a plant-specific program that performs a periodic visual inspection of
 
the carbon steel and cast iron internal surfaces of the RCIC and HPCI pump turbine casings (and gland cases) and the in-scope piping and piping components in steam lines downstream
 
from the steam admission valves, by qualified personnel. The staff noted that the visual
 
inspections being performed will detect rust, discoloration and other signs of degradation that
 
may be indicative of wall-thinning and loss of material. The staff further noted that if
 
unacceptable visual indications of wall-thinning or loss of material the applicant will initiate
 
appropriate corrective actions. The staff determined that a visual inspection will be capable of
 
detecting loss of material, which is consistent with the inspection techniques recommended by GALL AMP XI.M38. On the basis that the applicant will be performing periodic visual
 
inspections on the components with in the scope of this program and will initiate appropriate
 
corrective actions if unacceptable loss of material or wall-thinning has occurred, the staff finds
 
the AMR results for this line item acceptable.
3-271  3.2.2.1.4  Cracking due to Stress Corrosion Cracking (SCC) and Intergranular Stress Corrosion 
 
Cracking (IGSCC) 
 
LRA Tables 3.2.2-2 and 3.2.2-4 address stainless steel tubing in an environment of treated
 
water greater than 60&#xba;C (>140&#xba;F) in the reactor core isolation cooling (RCIC) system and in the
 
high pressure coolant injection (HPCI) system. The applicant specified the BWR Water
 
Chemistry Program, alone, to manage the aging effect of cracking due to SCC or IGSCC. For
 
these AMR result lines, the applicant referred to LRA Table 3.2.1, item 3.2.1-18, and cited
 
generic note A, indicating that the results are consistent with the GALL Report. The applicant
 
also included a plant-specific note stating that these results apply only to stainless steel tubing
 
in the steam supply to RCIC and HPCI pump turbines up to the steam admission valves that are
 
maintained at temperature >140 &#xba;F.
 
The staff noted that for the corresponding line in SRP-LR Table 3.2-1 and in GALL Report, Volume 1, Table 2, the recommended AMPs are the BWR Stress Corrosion Cracking program
 
and the Water Chemistry program. The staff also noted that the BWR Stress Corrosion
 
Cracking program applies only to stainless steel piping components that are greater than 4 inch
 
nominal pipe size; and therefore, it is not applicable for stainless steel tubing. Because the
 
applicant did not recommend an inspection activity to confirm effectiveness of the BWR Water
 
Chemistry program in mitigating cracking in the stainless steel tubing exposed to treated water, the staff issued RAI 3.2-1, in a letter dated July 15, 2008, asking the applicant to provide a
 
technical justification that confirmation of BWR Water Chemistry Program effectiveness is not
 
needed for these components, and to justify the use of generic note A for these AMR results.
 
In its response to RAI 3.2-1 dated August 15, 2008, the applicant provided the following
 
response:
 
For the AMR results listed in LRA Tables 3.2.2-2 and 3.2.2-4 for stainless steel tubing in
 
a treated water environment and with an aging effect of cracking, verification of the
 
effectiveness of the BWR Water Chemistr y Program is needed. The Chemistry Program Effectiveness Inspection provides confirmation of the effectiveness of the BWR Water
 
Chemistry Program in managing the effects of aging, including cracking of susceptible
 
materials. Also, as discussed below, the use of note A is not appropriate.
 
These AMR results are compared to GALL Report, item V.D2-29, for which the AMP is identified as GALL AMP XI.M7, "BWR Stress Corrosion Cracking," and GALL AMP XI.M2, "Water Chemistry." As described in plant specific note 0207, the BWR
 
Stress Corrosion Cracking program is applicable only to stainless steel piping (>
4 inch), pump casings, valve bodies, and reactor vessel attachments containing reactor coolant
 
at >200&#xba;F. Therefore, the BWR Stress Corrosion Cracking program is not credited with
 
managing cracking of stainless steel tubing exposed to treated water in the RCIC and
 
HPCI systems. Instead, the BWR Water C hemistry Program and the Chemistry Program Effectiveness Inspection are credited, and note E is used instead of note A.
 
LRA Tables 3.2.1, 3.2.2-2, and 3.2.2-4, and the plant-specific note 0207 for the tables in
 
LRA Section 3.2 are revised to reflect these results.
 
The staff reviewed the applicant's response and the associated LRA changes. The staff
 
reviewed the applicant's BWR Water Chemistry Pr ogram. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water Chemistry Program 3-272 provided mitigation for the aging effect of cracking due to SCC and IGSCC. The staff reviewed the applicant's Chemistry Program Effectiveness Inspection. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the Chemistry Program
 
Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "One-Ti me Inspection." The Chemistry Program Effectiveness Inspection includes provisions for inspecting selected components in areas of low
 
or stagnant flow and includes methodology that is capable of detecting cracking due to SCC
 
and IGSCC, if it should occur in the selected components. Because the BWR Water Chemistry
 
Program provides mitigation and the Chemistr y Program Effectiveness Inspection provides detection for cracking due to SCC or IGSCC, the staff finds the applicant's proposed AMPs for
 
managing the aging effect of cracking due to SCC or IGSCC in stainless steel tubing exposed to
 
treated water >60&#xba;C (>140&#xba;F) in the RCIC system and in the HPCI system to be acceptable. On
 
this basis, the staff finds that the issue raised in RAI 3.2-1 is resolved by the applicant's
 
changes in the LRA.
 
3.2.2.1.5  Loss of Material due to General, Pitting, Crevice, and Galvanic Corrosion 
 
LRA Table 3.2.2-1 addresses carbon steel residual heat removal (RHR) heat exchanger shells, shell covers and tube sheets in a treated water environment. The applicant specified use of the
 
BWR Water Chemistry Program, alone, for managing the aging effect of loss of material due to
 
general, pitting, crevice, and galvanic corrosion. For these AMR results the applicant referred to
 
LRA Table 3.2.1, Item 3.2.1-27, and cited generic note E, indicating that the result is consistent
 
with the corresponding GALL Report item for material, environment and aging effect, but a
 
different AMP is credited. The staff noted that for the corresponding line in SRP-LR Table 3.2-1 and in GALL Report, Volume 1, Table 2, the recommended AMP is GALL AMP XI.M21, "Closed-Cycle Cooling Water System," which includes both preventive measures, such as control of water chemistry to minimize corrosion and SSC, and testing and inspection to monitor
 
the effect of corrosion and SSC on the intended function of the components.
 
LRA Table 3.2.2-2 addresses stainless steel reactor core isolation cooling (RCIC) turbine lube
 
oil cooler tubes, tube sheets and channels in a treated water environment. The applicant
 
specified use of the BWR Water Chemistry Program, alone, for managing the aging effect of
 
loss of material due to pitting, and crevice corrosion. For these AMR results the applicant
 
referred to LRA Table 3.2.1, Item 3.2.1-28, and cited generic note E, indicating that the result is
 
consistent with the corresponding GALL Report item for material, environment and aging effect, but a different AMP is credited. The staff noted that for the corresponding line in SRP-LR
 
Table 3.2-1 and in GALL Report, Volume 1, Table 2, the recommended AMP is GALL AMP XI.M21, "Closed-Cycle Cooling Water System,"
which includes both preventive measures, such as control of water chemistry to minimize corrosion and SSC, and testing and inspection to
 
monitor the effect of corrosion and SSC on the intended function of the components.
 
LRA Tables 3.2.2-1, 3.2.2-2, 3.2.2-3 and 3.2.2-4 address copper alloy piping and piping
 
components and heat exchanger tubes in the RHR system, turbine lube oil heat exchanger
 
tubes, tube sheets and channels in the RCIC system, piping and piping components in the core
 
spray system, and lube oil heat exchanger tubes, tube sheets and channels in the high pressure
 
coolant injection (HPCI) system; all of t hese components are in a treated water environment.
The applicant specified use of the BWR Water Chemistry Program, alone, for managing the
 
aging effect of loss of material due to pitting, crevice and galvanic corrosion. For these AMR
 
result lines, the applicant referred to LRA Table 3.2.1, item 3.2.1-29 and cited generic note E, indicating that the result is consistent with the corresponding GALL Report item for material, environment and aging effect, but a different AMP is credited. The staff noted that for the 3-273 corresponding line in SRP-LR Table 3.2-1 and in GALL Report, Volume 1, Table 2, the recommended AMP is GALL AMP XI.M21, "Clos ed-Cycle Cooling Water System," which includes both preventive measures, such as control of water chemistry, to minimize corrosion
 
and SSC, and testing and inspection to monitor the effect of corrosion and SSC on the intended
 
function of the components.
 
For the AMR results described in the preceding paragraphs, because the applicant proposed
 
use of the BWR Water Chemistry Program, alone, and no inspection activity was credited to
 
monitor effectiveness of the water chemistry program, the staff issued RAI 3.2-2, in a letter
 
dated July, 15, 2008, addressing these AMR results and asking the applicant to justify why an
 
inspection is not performed to verify the effectiveness of the water chemistry program and
 
confirm that loss of material is not occurring in these components.
 
In a letter dated August 15, 2008, the applicant responded to RAI 3.2-2 by providing the
 
following response:
 
For the AMR results listed in LRA Tables 3.2.2-1, 3.2.2-2, 3.2.2-3 and 3.2.2-4 that
 
reference the LRA Table 1 items 3.2.1-27, 3.2.1-28 or 3.2.1-29, verification of the
 
effectiveness of the BWR Water Chemistr y Program is needed. The Chemistry Program Effectiveness Inspection will provide confirmation of the effectiveness of the BWR Water
 
Chemistry Program in managing the effects of aging, including loss of material.
 
LRA Tables 3.2.1, 3.2.2-1, 3.2.2-2, 3.2.2-3, and 3.2.2-4 are revised to reflect these
 
results.
The staff reviewed the applicant's response and the associated LRA changes. The staff
 
reviewed the applicant's BWR Water Chemistry Pr ogram. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water Chemistry Program
 
provides mitigation for the aging effect of loss of material due to general, pitting, crevice, and
 
galvanic corrosion. The staff reviewed the app licant's Chemistry Program Effectiveness Inspection. The staff's evaluation of this program, which is documented in SER
 
Section 3.0.3.1.10, found that the Chemistry Program Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "One-
 
Time Inspection." The Chemistry Program Effe ctiveness Inspection includes provisions for inspecting selected components in areas of low or stagnant flow and is capable of detecting
 
loss of material due to general, pitting, crevice, and galvanic corrosion, if it should occur in the
 
selected components. Because the BWR Water Chemistry Program provides mitigation and the
 
Chemistry Program Effectiveness Inspection prov ides detection for loss of material due to general, pitting, crevice, and galvanic corrosion, the staff finds the applicant's LRA changes and
 
the applicant's proposed AMPs for managing the aging effect of aging effect of loss of material
 
due to general, pitting, crevice, and galvanic corrosion in steel, stainless steel, and copper alloy
 
components exposed to closed-cycle cooling wate r in the residual heat removal system, the reactor core isolation cooling system, the core spray system, and the high pressure coolant
 
injection system to be acceptable. On this basis, the staff finds that the issue raised in RAI 3.2-2
 
is resolved by the applicant's changes in the LRA.
SER Section 3.2.2.1
 
== 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 OE 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 3-274 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).
 
3.2.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended In LRA Section 3.2.2.2, the applicant further evaluates of aging management, as recommended
 
by the GALL Report, for the engineered safety f eatures components and provides information concerning how it will manage the following aging effects:
* cumulative fatigue damage
* loss of material due to cladding
* loss of material due to pitting and crevice corrosion
* reduction of heat transfer due to fouling
* hardening and loss of strength due to elastomer degradation
* loss of material due to erosion
* loss of material due to general corrosion and fouling
* loss of material due to general, pitting, and crevice corrosion
* loss of material due to general, pitting, crevice, and MIC
* 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 and cladding breach. The applicant stated that
 
this aging effect is not applicable because SSES is a BWR.
 
SRP-LR Section 3.2.2.2.2 states that loss of material due to cladding breach may occur in PWR
 
steel pump casings with stainless steel cladding exposed to treated borated water.
 
The staff confirmed in SRP-LR Table 3.2-1, Item 2, is only applicable to PWR plants.
 
3-275 Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.2.2.2.2 does not apply to SSES.
 
Based on the above, the staff concludes SRP-LR Section 3.2.2.2.2 criteria are not applicable.
 
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 pitting and crevice corrosion in containment isolation piping, piping components, and piping elements at locations with
 
stagnant flow conditions. The applicant stated that containment isolation piping and
 
components were grouped with similar piping having the same material, environment, aging effects, and aging management program(s). As stated in Table 3.2.1, the SSES
 
components matching the description of LRA item number 3.2.1-03 were included in the
 
evaluation of components for LRA item number 3.2.1-05. Refer to Section 3.2.2.2.3.3 for
 
the details of the evaluation of aging management for these components.
SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosion
 
may occur on internal surfaces of stainless steel containment isolation piping, piping
 
components, and piping elements exposed to tr eated 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 progr ams 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.
 
Because the grouped components have identical material, environment, aging effect and
 
aging management program(s) recommended in the GALL Report, the staff finds the
 
applicant's grouping of components from LRA Table 3.2.1, item 3.2.1-3, with
 
components in LRA Table 3.2.1, item 3.2.1-5, for the purpose of AMR evaluation to be
 
acceptable. On this basis, the staff finds it acceptable for the applicant to designate LRA
 
Table 3.2.1, item 3.2.1-3 as not applicable.
 
(2) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in piping, piping components, and piping elements exposed to soil. The applicant stated
 
that this aging effect is not applicable because there are no stainless steel piping, piping
 
components, or piping elements exposed to soil in the ESF systems for SSES.
SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosion
 
may occur in stainless steel piping, piping components, and piping elements exposed to
 
soil. The GALL Report recommends further evaluation of a plant-specific AMP to ensure
 
that the aging effect is adequately managed.
 
LRA table 3.2.1 states that there are no SSES components comparable to LRA item
 
number 3.2.1-04. The applicant stated that there is no buried stainless steel piping or 3-276 piping components in the ESF Systems and the staff verified the applicant's statement by a review of plant boundary drawings. The staff reviewed LRA Section 2.3.2 and
 
verified that SSES does not have support systems with-in the scope of license renewal
 
that contain the piping, piping components and piping elements fabricated from stainless
 
steel exposed to soil. The applicant stated that no further evaluation is necessary and
 
the staff agrees with that because there is no buried stainless steel piping or piping
 
components in the ESF Systems.
 
Based on the staff's review as described above and of LRA Section 3.2 and found that
 
there were no stainless steel piping, piping components and piping elements exposed to
 
soil. On the basis of this review, the staff finds that SRP-LR Section 3.2.2.2.3.2 is not
 
applicable to SSES.
 
(3) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in BWR piping, piping components, and piping elements exposed to treated water. The
 
applicant stated that loss of material due to pitting and crevice corrosion for stainless
 
steel piping components exposed to treated wa ter in ESF Systems is managed by the BWR Water Chemistry Program and the Chem istry Program Effectiveness Inspection.
There are no aluminum piping components subj ect to aging management review in ESF Systems. The BWR Water Chemistry Progr am manages aging effects through periodic monitoring and control of contaminants.
The Chemistry Program Effectiveness Inspection will provide a verification of the effectiveness of the BWR Water Chemistry
 
Program to manage loss of material due to pitting and crevice corrosion through
 
examination of stainless steel ESF components.
SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosion
 
may occur in BWR stainless steel and aluminum piping, piping components, and piping
 
elements exposed to treated water. The existing AMP monitors and controls water
 
chemistry for BWRs to mitigate degradation.
However, control of water chemistry does not preclude loss of material due to pitting and crevice corrosion at locations with
 
stagnant flow conditions; therefore, the effectiveness of water chemistry control
 
programs should be verified to ensure that corrosion does not occur. The GALL Report
 
recommends further evaluation of programs to verify the effectiveness of water
 
chemistry control programs. A one-time inspection of 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 applicant's BWR Water Chemistry Program. The staff's
 
evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that the
 
BWR Water Chemistry Program provides mitigation for the aging effect of loss of
 
material due to general, pitting, and crevice corrosion. The staff reviewed the applicant's
 
Chemistry Program Effectiveness Inspection.
The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the Chemistry Program
 
Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "One-Time Inspection." The Chemistry
 
Program Effectiveness Inspection includes provisions for inspecting selected
 
components in areas of low or stagnant flow and is capable of detecting loss of material
 
due to pitting and crevice corrosion, if it should occur in the selected components. Based
 
on the applicant's use of a one-time inspection consistent with the recommendations of
 
the GALL Report, the staff finds the applicant's proposed AMPs for managing the 3-277 potential aging effect of loss of material due to pitting and crevice corrosion in stainless steel piping components exposed to treated water in the ESF systems to be acceptable.
 
(4) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in piping, piping components, and piping elements exposed to lubricating oil. The applicant
 
stated that loss of material for stainless steel or copper alloy piping components
 
exposed to lubricating oil is managed by the Lubricating Oil Analysis Program. The Lubricating Oil Analysis Program manages aging effects through periodic monitoring and
 
control of contaminants, including water. The Lubricating Oil Inspection will provide a
 
verification of the effectiveness of the Lubricating Oil Analysis Program to manage loss
 
of material due to crevice and pitting corrosion through examination of stainless steel or
 
copper alloy 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 evaluated the Lubricating Oil Analysis Program and the Lubricating Oil
 
Inspection Program, and the evaluations are documented in SER Sections 3.0.3.2.15
 
and 3.0.3.2.13, respectively. The staff reviewed the applicant's Lubricating Oil Analysis
 
Program and determined that this program includes periodic sampling and analysis of
 
lubricating oil to maintain contaminants within acceptable limits. The staff finds that
 
these activities are consistent with the recommendations in the GALL Report and are
 
adequate to manage loss of material due to pitting and crevice corrosion in copper alloy
 
and stainless steel piping, piping components, and piping elements exposed to
 
lubricating oil. The staff verified that the applicant has credited its Lubricating Oil
 
Inspection Program to verify the effectiveness of the Lubricating Oil Analysis Program to manage this aging effect for ECCS system. The applicant's AMPS are consistent with
 
those recommended for aging management in SRP-LR Section 3.2.2.2.3, Item #4 and in
 
GALL AMR Items V.D1-24 and V.D2-22. 
 
(5) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in partially encased tanks exposed to raw water. The applicant stated that this aging effect
 
is not applicable because there are no outdoor stainless steel tanks in the ESF systems
 
for SSES.
SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosion
 
may occur in partially encased stainless steel tanks exposed to raw water due to
 
cracking of the perimeter seal from weathering. The GALL Report recommends further
 
evaluation to ensure that the aging effect is adequately managed. The GALL Report
 
recommends that a plant-specific AMP be evaluated because moisture and water can
 
egress under the tank if the perimeter seal is degraded.
3-278  The staff reviewed the applicant's Updated Final Safety Analysis Report (UFSAR)
 
Rev.63 updated in September 2007, to determine the tanks that are relied upon as part
 
of the ESF Systems. Based on the staff's review, the Condensate Storage Tanks are
 
the primary source of water and then transferred to the suppression pool for the ESF
 
Systems. The staff noted from its review that the condensate storage tanks for both Unit
 
1 and 2 are located outdoors but are not made of stainless steel. The staff verified that
 
both tanks are made of carbon steel.
 
Based on the staff's review of the applicant's UFSAR, the staff agrees with the
 
applicant's determination that item #5 of SRP-LR Section 3.2.2.2.3 does not apply to
 
SSES ESF systems because there are no stainless steel tanks located outdoors that are
 
relied upon by the ESF systems.
 
(6) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in piping, piping components, piping elements, and tanks exposed to internal
 
condensation. The applicant stated that this aging effect is not applicable because there
 
are no stainless steel piping, piping components, piping elements, and tank internal
 
surfaces exposed to condensation in the ESF systems for SSES.
SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosion
 
may occur in stainless steel piping, piping components, piping elements, and tanks
 
exposed to internal condensation. The GALL Report recommends further evaluation of a
 
plant-specific AMP to ensure that the aging effect is adequately managed.
 
SRP-LR Section 3.2.2.2.3.6 invokes AMR Item 8 in Table 2 of the GALL Report, Volume
 
1, and AMR Items V.D-2 in the GALL Report, Volume 2, as applicable to stainless steel
 
piping, piping components, piping elements, and tanks exposed to internal condensation
 
in BWR emergency core cooling systems. 
 
The staff reviewed the LRA Table 2s AMR Results for ESF systems and noted that there
 
are no stainless steel piping, piping components, piping elements, and tank internal
 
surfaces exposed to condensation in the ESF systems for SSES. Therefore, the staff
 
concludes that this item is not applicable.
 
Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.2.2.2.3 criteria. For those line items that apply to LRA Section 3.2.2.2.3, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.2.2.2.4  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 in heat exchanger tubes exposed to lubricating oil. The applicant stated that For those heat
 
exchangers within the scope of Generic Letter (GL) 89-13 for SSES, the Piping
 
Corrosion Program is credited with managing fouling of heat exchanger tubes exposed 3-279 to lubricating oil. For heat exchangers not within the scope of GL 89-13, the Lubricating Oil Analysis Program will manage reduction in heat transfer of heat exchanger tubes exposed to lubricating oil.
 
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 Piping Corrosion Program is credited for RHR system motor oil cooler tubes in
 
Table 3.2.2-1. The corresponding GALL Report Volume 2 line item is V.D2-11. For this
 
line item, the GALL Report recommends GALL AMP XI.M39, "Lubricating Oil Analysis", and an effectiveness verification program such as one-time inspection. 
 
Although the external surface of the motor oil cooler tubes is lubricating oil, the internal
 
environment is raw water and this cooler is part of the GL 89-13 program. Therefore, the
 
applicant credits the Piping Corrosion Program. The staff noted that the Piping Corrosion
 
Program is a combination of condition monitoring program (consisting of inspections, surveillances, and testing to detect the presence of, and to assess the extent of, fouling
 
and loss of material) and a mitigation program (consisting of chemical treatments and
 
cleaning activities to minimize fouling and loss of material). The staff's evaluation of the
 
Piping Corrosion program is documented in SER Section 3.0.3.2.6. Because the Piping
 
Corrosion Program includes both the chemistry treatment and cleaning for mitigation and
 
inspection for verification, the staff finds that the Piping Corrosion Program will
 
adequately manage the aging effects of reduction of heat transfer through the period of
 
extended operation. 
 
The Lubricating Oil Analysis Program and Lubric ating Oil Inspection Program is credited for RCIC turbine lube oil cooler tubes in Table 3.2.2-2, lube oil cooler tubers in Table
 
3.2.2-4 and heat exchanger tubes in Table 3.3.2-9. The corresponding GALL Report
 
Volume 2 line item is V.D2-11. For these line items, the GALL Report recommends GALL AMP XI.M39, "Lubricating Oil Analysis
", and an effectiveness verification program such as one-time inspection. 
 
The staff evaluated the Lubricating Oil Analysis Program and the Lubricating Oil
 
Inspection Program, and the evaluations are documented in SER Sections 3.0.3.2.15
 
and 3.0.3.2.13, respectively. The staff reviewed the applicant's Lubricating Oil Analysis
 
Program and determined that this program includes periodic sampling and analysis of
 
lubricating oil to maintain contaminants within acceptable limits. The staff finds that
 
these activities are consistent with the recommendations in the GALL Report and are
 
adequate to manage reduction in heat transfer due to fouling in copper alloy and
 
stainless steel heat exchanger tubes exposed to lubricating oil. The staff verified that
 
the applicant has credited its Lubricating Oil Inspection Program to verify the 3-280 effectiveness of the Lubricating Oil Analysis Program to manage this aging effect. The applicant's AMPs are consistent with those recommended for aging management in
 
SRP-LR Section 3.2.2.2.4, Item #1 and in GALL AMR Items V.D1-9 and V.D2-11.
 
(2) LRA Section 3.2.2.2.4 addresses reduction of heat transfer due to fouling in heat exchanger tubes exposed to treated water. The applicant stated that the Heat
 
Exchanger Inspection activity is a one-time inspection that will detect and characterize
 
reduction in heat transfer of stainless steel heat exchanger tubes exposed to treated
 
water. 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.
 
The LRA references this section to RCIC turbine lube oil cooler tubes in the reactor core
 
isolation cooling system and the corresponding GALL Report Volume 2 line item is V.D2-
: 13. For this line item, the GALL Report recommends GALL AMP XI.M21, Closed-Cycle Cooling Water System Program. The GALL AMP XI.M21, Closed-Cycle Cooling Water System, recommends preventive measures to minimize corrosion and testing and inspection to monitor the effects of corrosion, whereas the applicant is proposing only a
 
one-time inspection activity. The staff issued RAI 3.2.2.2.4.2-1 by letter dated July 23, 2008 requesting the applicant to justify how the one-time heat exchanger inspection
 
activity by itself will manage the aging effect of reduction in heat transfer, without
 
preventive measures to minimize corrosion, such as maintaining treated water chemistry
 
control.
 
In its response to RAI 3.2.2.2.4.2-1 dated August 22, 2008, the applicant stated that the
 
BWR Water Chemistry Program is credited for managing loss of material for stainless
 
steel heat exchanger tubes exposed to treated water. The applicant also stated that
 
since the BWR Water Chemistry Program does not contain measures for detection of
 
aging effects through inspection, it is not credited for managing reduction in heat
 
transfer; however, it is recognized that the same preventive actions by which the water
 
chemistry program manages loss of material also mitigates the conditions that could
 
result in reduction in heat transfer. The applicant further stated that due to the BWR
 
water chemistry control, fouling of heat exchanger tubes is not expected to occur.
 
Therefore, the applicant concluded that as stated in LRA Section B.2.24, the Heat
 
Exchanger Inspection will provide direct evi dence as to whether, and to what extent, reduction in heat transfer has occurred, or is likely to occur, that could result in a loss of
 
intended function.
 
The staff confirmed that in LRA Table 3.2.2-2, BWR Water Chemistry Program is
 
credited for managing loss of material of RCIC turbine oil coolers. For these same
 
coolers, the applicant has credited the Heat Exchanger Inspection Program for reduction
 
of heat transfer. The staff's evaluation of the Heat Exchanger Program is documented in
 
SER Section 3.0.3.1.12. The Heat Exchanger Inspection Program uses visual (VT-3 or 3-281 equivalent) or remote visual inspection techni ques to verify the absence of, or to identify the extent of fouling on the tube surfaces. On the basis that water chemistry is
 
maintained to minimize corrosion and fouling, the staff finds the use of the Heat
 
Exchanger Inspection Program acceptable for managing the aging effects of reduction of
 
heat transfer for stainless steel heat exchanger tubes exposed to treated water and finds
 
the applicant response acceptable.
Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.2.2.2.4 criteria. For those line items that apply to LRA Section 3.2.2.2.4, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.2.2.2.5  Hardening and Loss of Strength Due to Elastomer Degradation 
 
The staff reviewed LRA Section 3.2.2.2.5 against the criteria in SRP-LR Section 3.2.2.2.5.
 
LRA Section 3.2.2.2.5 addresses hardening and loss of strength due to elastomer degradation.
 
The applicant stated that the System Walkdown Program is credited with managing degradation
 
due to aging of the visible external surfaces, and in some cases the internal surfaces, of these
 
components.
 
SRP-LR Section 3.2.2.2.5 states that hardening and loss of strength due to elastomer
 
degradation may occur in elastomer seals and components of the BWR standby gas treatment
 
system ductwork and filters exposed to air -  indoor uncontrolled. The GALL Report
 
recommends further evaluation of a plant-specific AMP to ensure that these aging effects are
 
adequately managed.
 
SRP-LR Section 3.2.2.2.5 invokes AMR Item 11 in Table 2 of the GALL Report, Volume 1, and
 
AMR Items V.B-4 in the GALL Report, Volume 2, as applicable to elastomeric seals and
 
components in SGTS. In these AMRs, the staff identifies that hardening and loss of strength
 
due to elastomer degradation may occur in elastomeric seal or component surfaces that are
 
exposed either internally or externally to uncontrolled indoor air. In these AMRs, the GALL Report recommends that a plant-specific agi ng management program is to be evaluated and credited to manage hardening and loss of strength in the elastomer seal surfaces that are
 
exposed either internally or externally to indoor air.
 
The staff noted that in the applicant's AMR for these components, as given in LRA Table 3.2.2-
 
7, the applicant identified that the flexible connections in the SGTS ductwork are the applicable
 
SGTS components falling within the scope of this assessment and that neoprene is the
 
applicable elastomeric material (rubber). The applicant also identified that the neoprene flexible
 
connections are exposed internally to a ventila tion environment and externally to uncontrolled indoor air. The applicant stated that is credi ting its Systems Walkdown Program to manage hardening and loss of strength in these materials.
 
The staff noted that, in AMP B.2.32, the applicant stated that the purpose of the System
 
Walkdown Program is, in part, to manage cracking and/or change in material properties for
 
elastomers (neoprene and rubber) and polymers (Teflon) that are exposed to indoor air or ventilation environments. The staff noted the GALL AMP XI.M36, "External Surfaces
 
Monitoring," is the program in the GALL Report that corresponds to the applicant's System 3-282 Walkdown Program. The staff reviewed the pr ogram description and program elements for GALL AMP XI.M36 and noted that the scope of this AMP is currently limited to the inspection of
 
steel (i.e., carbon steel, alloy steel, or cast iron) components in order to manage: (1) loss of
 
material that may occur in the steel components as a result of general corrosion, pitting
 
corrosion, or crevice corrosion, or (2) cracking in the coatings that may line the external surfaces of these steel components. The staff noted that GALL AMP XI.M36, "External Surfaces
 
Monitoring," does not apply to elastomeric components or to the management of hardening or
 
loss of strength in elastomeric components. Thus, the staff had several issues with the
 
applicant's AMR for the SGTS neoprene flexible connections and with crediting the Systems Walkdown Program to manage hardening and loss of strength in these elastomeric
 
components.
 
With respect to the first issue taken on the applicant's AMR, the staff noted that in the
 
applicant's AMRs on management of changes in material properties for the neoprene flexible
 
SGTS connections, the applicant credited it s Systems Walkdown Program with aging management of both the internal surfaces that are exposed to the ventilation environment and the external surfaces that are exposed to the uncontrolled indoor air environment. In contrast, the staff noted that scope of GALL AMP XI.M36, "External Surfaces Monitoring," does not
 
include elastomeric components nor does it apply to the management of changes in material
 
properties (such as hardening and loss of strength) that may occur in elastomeric components.
 
The staff also noted the "scope of program" program element in GALL AMP XI.M36, "External Surfaces Monitoring," states that programs corresponding to GALL AMP XI.M36 may only be
 
applied to internal surfaces if the "material and environment combinations are the same for
 
internal and external surfaces such that external surface condition is representative of internal
 
surface condition, and that when credited for internal surfaces, "the program should describe
 
the component internal environment and the credi ted similar external component environment inspected." In RAI B.2.32-4 by letter dated July 23, 2008, the staff asked the applicant to justify
 
its basis for crediting the System Walkdow n Program to manage cracking and changes in material properties that may occur in the external surfaces of in-scope components that are
 
fabricated from either an elastomeric or polymeric material. The staff also asked the applicant to
 
clarify how a visual examination alone from the external surfaces of these materials would be
 
capable of detecting the following aging effects: (1) a tightly configured crack that penetrates the
 
external surface of the component, (2) a subsurface crack or a crack that only penetrates the
 
internal surface of the materials, and (3) a change in a material property, such as a potential
 
change in the hardness property or strength property for the elastomer or polymer material used
 
to fabricate the component. RAI B.2.32-4 is relevant to the acceptance of the applicant's internal
 
and external surface AMRs for the neoprene flexible SGTS connections. The applicant's RAI
 
B2.32-4 response is evaluated and accepted by the staff and documented in SER Section
 
3.0.3.2.14.
 
With respect to the second issue taken on the applicant's AMR, the staff noted that in AMP
 
B.2.32, System Walkdown Program, the applicant credits the program, in part, for aging
 
management of both cracking and changes in material properties for elastomer (i.e., neoprene
 
or rubber) and plastic (polymer) components that are exposed to uncontrolled indoor air or
 
ventilation environments. The staff noted, however, that in LRA Table 3.2.2-7, the applicant did not provide either a plant specific AMR or enhanced AMR aligning to GALL AMR V.B-4 that
 
identified cracking as an applicable aging effect requiring management for the flexible neoprene
 
SGTS connections that are exposed internally to the ventilation environment or externally to the uncontrolled indoor air environment. In RAI #3.2.2.2.5-1 by letter dated July 23, 2008, the staff
 
asked the applicant to justify why LRA Table 3.2.2-7 did not include any AMRs on cracking of
 
the neoprene flexible SGTS connections that are exposed internally to the ventilation 3-283 environment or externally to the uncontroll ed indoor air environment, when LRA AMP B.2.32 implies that cracking could occur in these neoprene components. Alternatively, if cracking is an
 
applicable aging effect requiring management for the internal and external surfaces of these
 
flexible SGTS connections, the staff requested the applicant in the RAI to amend the LRA to
 
include AMR's that identify cracking as an AERM for the internal and external surfaces of the
 
components, and to clarify which AMP or AMPs would be credited with the management of
 
cracking in the neoprene flexible SGTS connection surfaces that are exposed to uncontrolled
 
indoor air and to the ventilation environment. 
 
In its response to RAI 3.2.2.2.5-1 dated August 27, 2008, the applicant stated that in Table
 
3.2.2-7, cracking was inadvertently omitt ed from the "Aging Effect Requiring Management" column. The applicant amended the LRA to revise Table 3.2.2-7 to add the aging effect of
 
cracking for neoprene flexible connections in an internal environment of ventilation and an
 
external environment of indoor air, and credit ed the System Walkdown Program to manage this aging effect. The applicant also revised LRA Section 3.2.2.2.5 to state that because the relevant
 
conditions for aging that exist in the internal environment are essentially the same as those that
 
exist in the external environment, the System Walkdown Program is also credited with managing degradation due to aging of the internal surfaces.
 
The staff finds the response acceptable because the applicant added the aging effect of
 
cracking for neoprene flexible connections and ex plained why the System Walkdown Program, which is for inspection of external surfaces, is also credited for managing degradation of internal
 
surfaces of the flexible connections. The staff' s review of the System Walkdown Program is documented in SER Section 3.0.3.2.14. 
 
Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.2.2.2.5 criteria. For those line items that apply to LRA Section 3.2.2.2.5, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.2.2.2.6  Loss of Material Due to Erosion 
 
The staff reviewed LRA Section 3.2.2.2.6 against the criteria in SRP-LR Section 3.2.2.2.6.
 
LRA Section 3.2.2.2.6 addresses loss of material due to erosion. The applicant stated that this
 
aging effect is not applicable because SSES is a BWR.
 
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.
 
The staff confirmed in SRP-LR Table 3.2-1, Item 12, is only applicable to PWR plants.
 
Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.2.2.2.6 does not
 
apply to SSES.
 
Based on the above, the staff concludes SRP-LR Section 3.2.2.2.6 criteria are not applicable.
 
3.2.2.2.7  Loss of Material Due to General Corrosion and Fouling 3-284  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. The
 
applicant stated that this aging effect is not applicable because SSES nozzles used for
 
containment spray are formed of stainless steel. Stainless steel flow elements are used in place
 
of flow orifices.
 
SRP-LR Section 3.2.2.2.7 states that loss of material due to general corrosion and fouling may
 
occur on steel drywell and suppression chamber spray system nozzle and flow orifice internal
 
surfaces exposed to air - indoor uncontrolled and may cause plugging of the spray nozzles and
 
flow orifices. This aging mechanism and effect will apply since the spray nozzles and flow
 
orifices are occasionally wetted even though th is system is mostly on standby. The wetting and drying of these components can accelerate corrosion and fouling. The GALL Report
 
recommends further evaluation of a plant-specific AMP to ensure that the aging effect is
 
adequately managed.
 
SRP-LR Section 3.2.2.2.7 invokes AMR Item 13 in Table 2 of the GALL Report, Volume 1, and
 
AMR Items V.D-1 in the GALL Report, Volume 2, as applicable to steel drywell and suppression
 
chamber spray system nozzle and flow orifice internal surfaces exposed to air - indoor
 
uncontrolled in BWR emergency core cooling systems.
 
The staff finds this item is not applicable because SSES nozzles and flow elements used for
 
containment spray are made of stainless steel, which has no aging effects requiring
 
management in an air-indoor uncontrolled environment as identified by the GALL Report item V.F-12.
 
Based on the above, the staff concludes SRP-LR Section 3.2.2.2.7 criteria are not applicable.
 
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 in BWR piping, piping components, and piping elements. The applicant stated
 
that loss of material due to general, pitting, and crevice corrosion for steel piping
 
components exposed to treated water is managed by the BWR Water Chemistry
 
Program and the Chemistry Program Effectiveness Inspection. The BWR Water
 
Chemistry Program manages aging effects through periodic monitoring and control of
 
contaminants. The Chemistry Program E ffectiveness Inspection will provide a verification of the effectiveness of the BWR Water Chemistry Program to manage loss of
 
material due to general, pitting, and crevice corrosion through examination of 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 BWR steel piping, piping components, and piping elements
 
exposed to treated water. The existing AMP monitors and controls water chemistry for
 
BWRs to mitigate degradation. However, control of water chemistry does not preclude
 
loss of material due to general, pitting, and crevice corrosion at locations with stagnant
 
flow conditions; therefore, the effectiveness of water chemistry control programs should 3-285 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.
 
The staff reviewed the applicant's BWR Water Chemistry Program. The staff's
 
evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that the
 
BWR Water Chemistry Program provides mitigation for the aging effect of loss of
 
material due to general, pitting and crevice corrosion. The staff reviewed the applicant's
 
Chemistry Program Effectiveness Inspection.
The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the Chemistry Program
 
Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "One-Time Inspection." The Chemistry
 
Program Effectiveness Inspection includes provisions for inspecting selected
 
components in areas of low or stagnant flow and is capable of detecting loss of material
 
due to general, pitting or crevice corrosion, if it should occur in the selected components.
 
Based on the applicant's use of a one-time inspection consistent with the
 
recommendations of the GALL Report, the staff finds the applicant's proposed AMPs for
 
managing the potential aging effect of loss of material due to general, pitting or crevice
 
corrosion in steel piping, piping components and piping elements exposed to treated
 
water in the ESF systems to be acceptable.
 
(2) LRA Section 3.2.2.2.8 addresses loss of material due to general, pitting, and crevice corrosion in piping, piping components, and piping elements exposed to treated water.
 
The applicant stated that containment isolation piping and components are grouped with
 
similar piping having the same material, environment, aging effects, and aging
 
management program(s). As stated in Table 3.2.1, the SSES components matching the
 
description of LRA item number 3.2.1-15 are included in the evaluation of components
 
for LRA item number 3.2.1-14. Refer to Section 3.2.2.2.8.1 for the details of the
 
evaluation of aging management for these components.
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 degradation. However, control of water
 
chemistry does not preclude loss of material due to general, pitting, and crevice
 
corrosion at locations with stagnant flow conditions; therefore, the effectiveness of water
 
chemistry control programs should be verified to ensure that corrosion does not occur.
 
The GALL Report recommends further evaluation of programs to verify the effectiveness of water chemistry control programs. A one-time inspection of 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.
 
Because the grouped components have identical material, environment, aging effect and
 
aging management program(s) recommended in the GALL Report, the staff finds the
 
applicant's grouping of components from LRA Table 3.2.1, item 3.2.1-15, with
 
components in LRA Table 3.2.1, item 3.2.1-14, for the purpose of AMR evaluation to be
 
acceptable. On this basis, the staff finds it acceptable for the applicant to designate LRA 3-286 Table 3.2.1, item 3.2.1 15 as not applicable.
 
(3) LRA Section 3.2.2.2.8 addresses loss of material due to general, pitting, and crevice corrosion in piping, piping components, and piping elements exposed to lubricating oil.
 
The applicant stated that loss of material for steel piping components exposed to
 
lubricating oil is managed by the Lubricati ng Oil Analysis Program. The Lubricating Oil Analysis Program manages aging effects through periodic monitoring and control of
 
contaminants, including water. The Lubricating Oil Inspection will provide a verification of
 
the effectiveness of the Lubricating Oil Analysis Program to manage loss of material due
 
to general, pitting, and crevice corrosion through examination of 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 evaluated the Lubricating Oil Analysis Program and the Lubricating Oil
 
Inspection Program, and the evaluations are documented in SER Sections 3.0.3.2.15
 
and 3.0.3.2.13 respectively. The staff reviewed the applicant's Lubricating Oil Analysis
 
Program and determined that this program includes periodic sampling and analysis of
 
lubricating oil to maintain contaminants within acceptable limits. The staff finds that
 
these activities are consistent with the recommendations in the GALL Report and are
 
adequate to manage loss of material due to general, pitting and crevice, corrosion in
 
steel piping, piping components, and piping elements exposed to lubricating oil. The
 
staff verified that the applicant has credited its Lubricating Oil Inspection Program to
 
verify the effectiveness of the Lubricating Oil Analysis Program to manage this aging effect for ECCS system. The applicant's AMPS are consistent with those recommended
 
for aging management in SRP-LR Section 3.2.2.2.8, Item #3 and in GALL AMR Item
 
V.D2-30.
Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.2.2.2.8 criteria. For those line items that apply to LRA Section 3.2.2.2.8, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.2.2.2.9  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 due to general, pitting, crevice, and MIC. The 3-287 applicant stated that this aging effect is not applicable because there are no steel piping, piping components, or piping elements exposed to soil in the ESF systems for SSES.
 
SRP-LR Section 3.2.2.2.9 states that loss of material due to general, pitting, crevice, and MIC
 
may occur in steel (with or without coating or wrapping) piping, piping components, and piping
 
elements buried in soil. Buried piping and tanks inspection programs rely on industry practice, frequency of pipe excavation, and OE 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 OE with buried components to ensure that loss of material does not occur.
 
The staff reviewed the UFSAR for SSES and verified that the SSES design does not include
 
any ESF components that are buried or are exposed to soil. Based on this review, the staff
 
concludes that the applicant has provided an acceptable basis for concluding that the staff's
 
guidance in SRP-LR Section 3.2.2.2.9, and the AMR items in GALL referenced by this SRP-LR
 
section, because the ESF design does not include any components that are exposed to a soil
 
environment or that are buried.
 
Based on the above, the staff concludes SRP-LR Section 3.2.2.2.9 criteria is not applicable.
 
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 through 3.2.2-7, the staff reviewed additional details of the AMR results
 
for material, environment, AERM, and AMP combinations not consistent with or not addressed
 
in the GALL Report.
 
In LRA Tables 3.2.2-1 through 3.2.2-7, the applicant indicated, via notes F through J that the
 
combination of component type, material, environment, and AERM does not correspond to a
 
line item in the GALL Report. The applicant prov ided 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.
 
3.2.2.3.1  Aging Management Review Results - Residual Heat Removal System -
 
LRA Table 3.2.2-1 
 
3-288 The staff reviewed LRA Table 3.2.2-1, which summarizes the results of AMR evaluations for the RHR system component groups.
 
In LRA Table 3.2.2-1, the applicant proposed to manage loss of material in copper alloy heat
 
exchanger tubes and tube sheets in an internal environment of raw water by using the Piping
 
Corrosion Program. The applicant referenced footnote G for this line item indicating that
 
environment is not in the GALL Report for this component. However, the staff noted that GALL
 
Report item VII.C1-3 has the same com ponent, material, environment and aging effect combination and recommends GALL AMP XI.M20, Open-Cycle Cooling Water System. The applicant's Piping Corrosion Program is consistent with GALL AMP XI.M20. The staff's
 
evaluation of the Piping Corrosion Program is documented in SER Section 3.0.3.2.6. On the
 
basis that this line item is consistent with GALL Report line item VII.C1-3, the staff finds that the
 
Piping Corrosion Program will adequately manage the aging effect of loss of material in copper
 
alloy heat exchanger tubes and tube sheets in an internal environment of raw water through the
 
period of extended operation.
 
In LRA Table 3.2.2-1, the applicant proposed to manage reduction of heat transfer in copper
 
alloy heat exchanger tubes in an internal environment of raw water by using the Piping
 
Corrosion Program. The applicant referenced footnote G for this line item indicating that
 
environment is not in the GALL Report for this component. However, the staff noted that GALL
 
Report item VII.C1-6 has the same com ponent, material, environment and aging effect combination and recommends GALL AMP XI.M20, Open-Cycle Cooling Water System. The applicant's Piping Corrosion Program is consistent with GALL AMP XI.M20. The staff's
 
evaluation of the Piping Corrosion Program is documented in SER Section 3.0.3.2.6. On the
 
basis that this line item is consistent with GALL Report line item VII.C1-6, the staff finds that the
 
Piping Corrosion Program will adequately manage the aging effect of reduction of heat transfer
 
in copper alloy heat exchanger tubes in an internal environment of raw water through the period
 
of extended operation.
 
In LRA Table 3.2.2-1, the applicant proposed to manage loss of material in nickel based alloy
 
heat exchanger tube plugs in an internal environment of raw water by using the Piping
 
Corrosion Program. The applicant referenced footnote G for this line item indicating that
 
environment is not in the GALL Report for this component. The staff noted that nickel based
 
alloy is not included in the GALL Report, however, it is a similar material to the copper alloy
 
material identified in GALL Report item VII.C-3 for the same component, environment and aging
 
effect combination. The GALL Report recommends AMP XI.M20, Open-Cycle Cooling Water System, for item VII.C3. The applicant's Piping Co rrosion Program is consistent with GALL AMP XI.M20. The staff's evaluation of the Piping Corrosion Program is documented in SER Section
 
3.0.3.2.6. On the basis that line item in Table 3.2.2-1 is similar to the GALL Report item VII.C-3, the staff finds that the Piping Corrosion Program will adequately manage the aging effect of loss
 
of material in nickel based alloy heat exchanger tube plugs in an internal environment of raw
 
water through the period of extended operation.
 
In LRA Table 3.2.2-1, the applicant proposed to manage loss of material of carbon steel piping
 
in an external environment of indoor air by using the Supplementary Piping/Tank Inspection Program. The applicant referenced footnote "H" for this line item indicating that aging effect is
 
not in NUREG-1801 for this component, material and environment combination. The applicant
 
also referenced footnote 0203 indicating that this is in an aggressive air/water interface
 
environment.The definition of footnote "H" implies t hat these line items are not consistent with GALL Report. However, the LRA has also referenced GALL Report item V.D2-2 and Table
 
3.2.1, line item 3.2.1-31. The staff issued RAI 3.2.2.3.1-1 in a letter dated July 23, 2008, to 3-289 request the applicant to justify why a GALL Report and Table 1 item is identified if the line item is not consistent with the GALL Report.
 
In its letter dated August 22, 2008, in response to RAI 3.2.2.3.1-1, the applicant responded that
 
the note H was used incorrectly in LRA Table 3.2.2-1; instead, note E should have been used.
 
The applicant also stated that this is consistent with the use of note E for a similar component, material and environment combination in Table 3.2.2-2. The applicant revised the LRA Table
 
3.2.2-1 to change the note from note H to Note E. The evaluation of this line item is documented
 
in SER Section 3.2.2.1.3.
 
In LRA Tables 3.2.2-1 the applicant proposed to manage cracking in copper alloy piping and
 
piping components in an environment of treated water by using the BWR Water Chemistry
 
Program, alone. The applicant cited generic note H for these AMR results, indicating that the
 
aging effect is not in the GALL Report for this component, material and environment
 
combination. In a letter dated July 15, 2008, the staff issued RAI 3.2-3, applicable for these
 
AMR results and for similar AMR results in LRA Tables 3.2.2-3, 3.3.2-3, 3.3.2-25, and 3.4.2-3.
 
The RAI asked the applicant to provide a technical justification as to why an inspection program, such as the Chemistry Program Effectiveness Inspection is not needed to confirm that the BWR
 
Water Chemistry Program is effective in preventing the aging effect.
 
In a letter dated August 15, 2008, the applicant responded to RAI 3.2-3 by providing the
 
following response:
 
For the five AMR results lines listed in LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, 3.3.2-25, and 3.4.2-3, where the material is copper alloy, the environment is treated water (internal), and the aging effect is cracking, verification of the effectiveness of the BWR
 
Water Chemistry Program is needed. The Chem istry Program Effectiveness Inspection will provide confirmation of the effectiveness of this program in managing the effects of aging, including cracking in susceptible materials.
 
LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, 3.3.2-25, and 3.4.2-3 are revised to reflect these
 
results.
The staff reviewed the applicant's response and the associated LRA changes. The staff
 
reviewed the applicant's BWR Water Chemistry Pr ogram. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water Chemistry Program
 
provides mitigation for the aging effect of cracking due to stress corrosion cracking. The staff
 
reviewed the applicant's Chemistry Program Effe ctiveness Inspection. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the Chemistry
 
Program Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "O ne-Time Inspection." The Chemistry Program Effectiveness Inspection includes provisions for inspecting selected components in areas of low
 
or stagnant flow and uses examination techniques that are capable of detecting cracking, if it
 
should occur in the selected components. Because the BWR Water Chemistry Program
 
provides mitigation and the Chemistry Program Effectiveness Inspection provides detection of the aging effect if it should occur, the staff finds the applicant's proposed AMPs for managing
 
the potential aging effect of cracking due to stress corrosion cracking in copper alloy piping and
 
piping components exposed to treated water in the residual heat removal system to be
 
acceptable. On this basis, the staff finds that the issue raised in RAI 3.2-3 is resolved by the
 
applicant's LRA changes.
 
3-290 LRA Table 3.2.2-1 summarizes the results of AMRs for the Residual Heat Removal System heat exchangers tube plugs constructed from nickel based alloy which do not have an external
 
surface in contact with an environment. Therefore, the environment, aging effect requiring
 
management, and AMRs are not applicable. The staff agrees with this position because these
 
components do not have an external surface in contact with an environment because their external surface is in contact with the inside of the heat exchanger tubes.
 
The applicant has listed a number of component, material, environment combinations as N/A.
 
Table 3.0-1, "Internal Environments," defines N/A as "N/A internal is used for components for
 
which an internal environment is not applicable (e.g., strainer screens, heat exchanger fins, flow
 
elements)." Table 3.0-2, "External Environments," defines N/A external as "N/A is used for
 
components for which an external environment is not applicable (e.g., tube plugs)."
 
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  Aging Management Review Results - Reactor Core Isolation Cooling -
 
LRA Table 3.2.2-2 
 
The staff reviewed LRA Table 3.2.2-2, which summarizes the results of AMR evaluations for the
 
reactor core isolation cooling component groups.
 
In LRA Table 3.2.2-2, the applicant proposed to manage cracking in copper alloy turbine lube oil
 
cooler tubes in an internal environment of treat ed water by using the Heat Exchanger Inspection Program. The applicant referenced footnote H for this line item indicating that aging effect is not
 
in NUREG-1801 for this component, material and environment combination.
 
The Heat Exchanger Inspection will use volumetric (RT or UT) to verify the absence of, or to
 
identify the extent of, SCC on the internal surfaces of the copper alloy (admiralty brass) tubes
 
that are exposed to the treated water environmen
: t. The staff's evaluation of the Heat Exchanger Inspection Program is documented in SER Section 3.0.3.1.12. Because the treated water
 
environment is less than 140oF, cracking in copper alloy components is of very low probability, and therefore, the staff finds a one-time inspection activity that performs volumetric examination
 
to verify the absence of cracking is an adequate aging management program. On this basis, the
 
staff finds the Heat Exchanger Inspection Program will adequately manage the aging effects of
 
cracking in copper alloy heat exchanger tubes in an internal environment of treated water
 
through 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).
 
3.2.2.3.3  Aging Management Review Results - Core Spray System - LRA Table 3.2.2-3 
 
The staff reviewed LRA Table 3.2.2-3, which summarizes the results of AMR evaluations for the
 
core spray system component groups.
3-291  In LRA Tables 3.2.2-3 the applicant proposed to manage cracking in copper alloy piping and
 
piping components in an environment of treated water by using the BWR Water Chemistry
 
Program, alone. The applicant cited generic note H for these AMR results, indicating that the
 
aging effect is not in the GALL Report for this component, material and environment
 
combination. In a letter dated July 15, 2008, the staff issued RAI 3.2-3, applicable for these
 
AMR results and for similar AMR results in LRA Tables 3.2.2-1, 3.3.2-3, 3.3.2-25, and 3.4.2-3.
 
The RAI asked the applicant to provide a technical justification as to why an inspection program, such as the Chemistry Program Effectiveness Inspection is not needed to confirm that the BWR
 
Water Chemistry Program is effective in preventing the aging effect.
 
In a letter dated August 15, 2008, the applicant responded to RAI 3.2-3 by providing the
 
following response:
 
For the five AMR results lines listed in LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, 3.3.2-25, and 3.4.2-3, where the material is copper alloy, the environment is treated water (internal), and the aging effect is cracking, verification of the effectiveness of the BWR
 
Water Chemistry Program is needed. The Chem istry Program Effectiveness Inspection will provide confirmation of the effectiveness of this program in managing the effects of aging, including cracking in susceptible materials.
 
LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, 3.3.2-25, and 3.4.2-3 are revised to reflect these
 
results.
The staff reviewed the applicant's response and the associated LRA changes. The staff
 
reviewed the applicant's BWR Water Chemistry Pr ogram. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water Chemistry Program
 
provides mitigation for the aging effect of cracking due to stress corrosion cracking. The staff
 
reviewed the applicant's Chemistry Program Effe ctiveness Inspection. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the Chemistry
 
Program Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "O ne-Time Inspection." The Chemistry Program Effectiveness Inspection includes provisions for inspecting selected components in areas of low
 
or stagnant flow and uses examination techniques that are capable of detecting cracking, if it
 
should occur in the selected components. Because the BWR Water Chemistry Program
 
provides mitigation and the Chemistry Program Effectiveness Inspection provides detection of the aging effect if it should occur, the staff finds the applicant's proposed AMPs for managing
 
the potential aging effect of cracking due to stress corrosion cracking in copper alloy piping and
 
piping components exposed to treated water in the core spray system to be acceptable. On this
 
basis, the staff finds that the issue raised in RAI 3.2-3 is resolved by the applicant's LRA
 
changes.
 
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR
 
results of material, environment, AERM, and AMP combinations not evaluated in the GALL
 
Report. The staff finds that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended function(s) will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.2.2.3.4  Aging Management Review Results - High Pressure Coolant Injection System -
 
LRA Table 3.2.2-4 
 
3-292 The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for the high pressure coolant injection system component groups.
 
In LRA Table 3.2.2-4, the applicant proposed to manage cracking in copper alloy turbine lube oil
 
cooler tubes in an internal environment of treat ed water by using the Heat Exchanger Inspection Program. The applicant referenced footnote H for this line item indicating that aging effect is not
 
in NUREG-1801 for this component, material and environment combination.
 
The Heat Exchanger Inspection will use volumetric (RT or UT) to verify the absence of, or to
 
identify the extent of, SCC on the internal surfaces of the copper alloy (admiralty brass) tubes
 
that are exposed to the treated water environmen
: t. The staff's evaluation of the Heat Exchanger Inspection Program is documented in SER Section 3.0.3.1.12. Because the treated water
 
environment is less than 140 o F, cracking in copper alloy components is of very low probability, and therefore, the staff finds a one-time inspection activity that performs volumetric examination
 
to verify the absence of cracking is an adequate aging management program. On this basis, the
 
staff finds the Heat Exchanger Inspection Program will adequately manage the aging effects of
 
cracking in copper alloy heat exchanger tubes in an internal environment of treated water
 
through the period of extended operation.
 
In LRA Table 3.2.2-4, the applicant identifies that there are no applicable aging effects requiring
 
management (AERMs) for synthetic rubber flexible connections (hoses) in the high pressure
 
coolant injection (HPCI) system under either inte rnal exposure to the lubricating oil environment or external exposure to the indoor air environment.
 
The staff noted in the LRA, the applicant appeared to take inconsistent approach to aging
 
management of elastomeric, rubber, polymeric, and glass components in the application
 
because some AMRs for these types of materials the applicant had identified that cracking and
 
changes in material properties were applicable aging effects requiring management (AERMs),
whereas in other AMRs the applicant concluded that AERMs were not applicable to the
 
components. In RAI 3.2.2.3-1 by letter dated July 23, 2008, the staff asked the applicant to
 
consolidate its approach to management of aging in the elastomeric, rubber, polymeric, and
 
glass ESF system components with the agi ng management approach that the applicant had taken for these types of components in the auxiliary systems. In RAI 3.2.2.3-1, Part A, the staff asked the applicant to justify why it had not identified any AERMs for HPCI synthetic rubber
 
component surfaces that are exposed to lubricating oil and to indoor air when cracking and
 
changes in materials had been identified as applicable aging effects for: (1) neoprene and
 
rubber components in the primary containment atmosphere circulation system under exposure to indoor air and to ventilation air, (2) neoprene/fiberglass components in the reactor building
 
HVAC system under exposure to indoor air and to ventilation air, and (3) for Teflon piping in the
 
sampling system (changes in material properties only) under exposure to indoor air. In RAI
 
3.3.2.3-1, Part B, the staff asked the applicant to identify those material properties and aging
 
effects that could be impacted by exposure of thes e synthetic rubber materials to the lubricating oil and indoor air environments.
 
In its letter dated August 27, 2008, in response to RAI 3.2.2.3-1, the applicant provided
 
justification for no aging effects requiring management for HPCI synthetic rubber components
 
that are exposed to lubricating oil and indoor air environment. The applicant stated that a
 
change in material properties and subsequent cracking of elastomers, such as synthetic rubber, could result from exposure to ionizing radiation, high temperatures, or ultraviolet radiation or ozone. 
 
3-293 The applicant also stated the following:
Ionizing radiation is an aging mechanism only if the total integrated dose (TID)
 
exceeds 10E6 rads. The synthetic rubber components are located in the HPCI
 
pump rooms where the maximum expected TID for 60 years, is 5.3x10E4 rads, which is significantly lower than the threshold limit. Similarly, thermal exposure is
 
an applicable aging mechanism if the components are exposed for prolonged
 
periods to a temperature of 95 o F or higher. The ambient air temperature in the HPCI pump rooms is 60 o F to 100 o F. Since there are no significant sources of heat within these rooms, it is reasonable to assume that external surface
 
temperature of the synthetic rubber components will not exceed 95 o F for a prolonged period of time. 
 
Ultraviolet radiation and ozone are aging mechanisms only if the surface is
 
exposed to ultraviolet radiation and ozone. Furthermore, synthetic rubber has
 
excellent resistance to ultraviolet radiation and ozone. The indoor air and
 
lubricating air environments contain no significant sources of ultraviolet radiation
 
or ozone. 
 
The applicant also stated that aging effects were identified for elastomer components in the
 
other systems identified in the RAI because t he components in those systems are expected to be exposed to TID greater than 10E6 rads exte rnally and to temperatures greater than 95 o F.
The applicant concluded that since stressors such as ionizing radiation, high temperatures, ultraviolet radiation, and ozone are not likely to be present in the HPCI pump rooms, therefore, no aging effects are identified for the synthetic rubber components exposed to indoor air and
 
lubricating oil environments.
 
In response to Part B of the RAI, the applicant indicated that based on the justification provided
 
above, no material properties are impacted by expos ure of the synthetic rubber materials in the HPCI system to the lubricating oil and indoor air environments. However, the applicant did state
 
that material properties if impacted would include hardening, loss of strength, and in some
 
cases cracking. 
 
The staff reviewed the applicant response and also reviewed the GALL Report, Chapter IX, Definitions for elastomer materials. In the GALL Report, Chapter IX.C, under definition of
 
elastomers, it states that hardening and loss of strength of elastomers can be induced by
 
elevated temperatures (greater than 95 o F), and additional aging factors such as exposure to ozone, oxidation, and radiation. On the basis that the applicant has addressed the aging factors
 
and identified that in the HPCI pump room where these components are located, will not be
 
exposed to these aging factors for a prolonged period of time, and because the GALL Report
 
also addresses these aging factors, the staff finds the applicant response acceptable and
 
considers this issue closed.
 
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).
3-294  3.2.2.3.5  Aging Management Review Result s - Containment and Suppression System -
LRA Table 3.2.2-5 
 
The staff reviewed LRA Table 3.2.2-5, which summarizes the results of AMR evaluations for the
 
containment and suppression system component groups. The staff determined that all AMR evaluation results in LRA Table 3.2.2-5 are consistent with the GALL Report.
 
3.2.2.3.6  Aging Management Review Results - Containment Atmosphere Control System -
LRA Table 3.2.2-6 
 
The staff reviewed LRA Table 3.2.2-6, which summarizes the results of AMR evaluations for the
 
containment atmosphere control system component groups. The staff determined that all AMR
 
evaluation results in LRA Table 3.2.2-6 are consistent with the GALL Report.
 
3.2.2.3.7  Aging Management Review Resu lts - Standby Gas Treatment System -
LRA Table 3.2.2-7 
 
The staff reviewed LRA Table 3.2.2-7, which summarizes the results of AMR evaluations for the
 
standby gas treatment system component groups.
 
In LRA Table 3.2.2-7, the applicant proposed to manage loss of material for galvanized steel
 
material for ductwork components exposed to an ex ternal environment of outdoor air using the SSES AMP B.2.32 "System Walkdown Program."  The staff noted that the applicant amended
 
its LRA by letter dated September 26, 2008 to add this AMR line item to LRA Table 3.2.2-7.
 
The AMR line item credits the AMP B.2.32 "System Walkdown Program" to manage loss of
 
material for these components. The AMR line item cites Generic Note H, which indicates that
 
the aging effect is not addressed in GALL Report for this component, environment and material
 
combination. The staff's evaluation of the AMP B.2.32 "System Walkdown Program" is
 
documented in SER Section 3.0.3.2.15. The staff determined that this program is a condition
 
monitoring program that will detect the aging effect of loss of material for metals, including steel, by periodic surveillance activities and observations of components' external surfaces to detect
 
aging degradation that are with in the scope of license renewal. On the basis that the applicant
 
will be performing periodic visual inspections of these components, the staff finds the AMR
 
results for this line item acceptable.
 
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR
 
results of material, environment, AERM, and AMP combinations not evaluated in the GALL
 
Report. The staff finds that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended function(s) will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.2.3  Conclusion The staff concludes that the applicant has provided sufficient information to demonstrate that
 
the effects of aging for the engineered safety features 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).
 
3-295 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:
* Building Drains Nonradioactive System
* Containment Instrument Gas System
* Control Rod Drive Hydraulic System
* Control Structure Chilled Water System
* Control Structure HVAC Systems
* Cooling Tower System
* Diesel Fuel Oil System
* Diesel Generator Buildings HVAC Systems
* Diesel Generators System
* Domestic Water System
* Emergency Service Water System
* Essw Pumphouse HVAC System
* Fire Protection System
* Fuel Pool Cooling And Cleanup System And Fuel Pool And Auxiliaries
* Neutron Monitoring System
* Primary Containment Atmosphere Circulation System
* Process And Area Radiation Monitoring System
* Radwaste Liquid System
* Radwaste Solids Handling
* Raw Water Treatment System
* Reactor Building Chilled Water System
* Reactor Building Closed Cooling Water System
* Reactor Building HVAC System
* Reactor Nonnuclear Instrumentation System
* Reactor Water Cleanup System
* Rhr Service Water System
* Sampling System
* Sanitary Drainage
* Service Air System
* Service Water System
* Standby Liquid Control System
* Turbine Building Closed Cooling Water System
* Reactor Recirculation System (NSAS portions)
* Reactor Vessel and Auxiliaries System (NSAS portions) 3.3.1  Summary of Technical Information in the Application LRA Section 3.3 provides AMR results fo r the auxiliary system s components and component groups. LRA Table 3.3.1, "Summary of Agi ng Management Programs fo r Auxiliary Systems Evaluated in Chapter VII of the GALL Report," is a summary comparison of the applicant's
 
AMRs with those evaluated in the GALL R eport for the auxiliary systems components and component groups.
 
The applicant's AMRs evaluated and incorporated applicable plant-specific and industry OE 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 3-296 industry OE included a review of the GALL Report and OE 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 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).
 
The staff conducted an onsite 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 onsite 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 OE 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 Systems Components in the GALL Report Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel 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 Not applicable Not applicable to SSES (See SER
 
Section 3.3.2.2.1) 3-297 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation 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 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. The applicant addressed
 
these components
 
under GALL Report
 
item number
 
3.3.1-52. (See SER Section 3.3.2.2.2)
Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to sodium
 
pentaborate solution > 60 C (> 140 F) (3.3.1-4)
Cracking due to SCC Water Chemistry and One-Time InspectionYes Not applicable Not applicable. The normal operating
 
temperature of the Standby Liquid Control System is below 140&#xba;F; and
 
therefore, cracking
 
due to SCC is not an
 
aging effect requiring
 
management. (See SER Section 3.3.2.2.3.1)
Stainless steel and
 
stainless clad steel
 
heat exchanger
 
components exposed to treated water > 60 C (> 140 F) (3.3.1-5)
Cracking due to SCC A plant-specific aging management
 
program is to be
 
evaluated. Yes Not applicable Not applicable. The applicant does not
 
have stainless steel
 
or stainless steel
 
clad heat exchangers
 
exposed to treated water >60&#xba;C
(>140&#xba;F). RWCU
 
heat exchangers which are exposed to
 
this environment are
 
carbon steel. (See SER Section 3.3.2.2.3.2) 3-298 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel diesel engine exhaust
 
piping, piping
 
components, and
 
piping elements
 
exposed to diesel
 
exhaust (3.3.1-6)
Cracking due to SCC A plant-specific aging management
 
program is to be
 
evaluated.
Yes Supplemental Piping and Tanks Inspection
 
Program (B.2.28) See SER Section 3.3.2.2.3.3 Stainless steel non-
 
regenerative heat
 
exchanger
 
components exposed
 
to treated borated water > 60 C (> 140 F) (3.3.1-7)
Cracking due to SCC and cyclic
 
loading Water Chemistry and a plant-specific
 
verification program.
 
An acceptable
 
verification program
 
is to include
 
temperature and radioactivity
 
monitoring of the shell side water, and eddy current testing
 
of tubes. Yes Not applicable Not applicable to BWRs (See SER
 
Section 3.3.2.2.4.1)
Stainless steel
 
regenerative heat
 
exchanger
 
components exposed
 
to treated borated water > 60 C (> 140 F) (3.3.1-8)
Cracking due to SCC and cyclic
 
loading Water Chemistry and a plant-specific
 
verification program.
The AMP is to be augmented by verifying the absence
 
of cracking due to SCC and cyclic
 
loading. A plant-
 
specific aging
 
management
 
program is to be
 
evaluated. Yes Not applicable Not applicable to BWRs (See SER
 
Section 3.3.2.2.4.2)
Stainless steel high-
 
pressure pump
 
casing in PWR
 
chemical and volume control system
 
(3.3.1-9)
Cracking due to SCC and cyclic
 
loading Water Chemistry and a plant-specific
 
verification program.
The AMP is to be augmented by verifying the absence
 
of cracking due to SCC and cyclic
 
loading. A plant-
 
specific aging
 
management
 
program is to be
 
evaluated. Yes Not applicable Not applicable to BWRs (See SER
 
Section 3.3.2.2.4.3) 3-299 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation High-strength steel closure bolting exposed to air with steam or water
 
leakage.
(3.3.1-10)
Cracking due to SCC, cyclic
 
loading Bolting Integrity. The AMP is to be augmented by
 
appropriate
 
inspection to detect
 
cracking if the bolts are not otherwise
 
replaced during
 
maintenance. Yes Not applicable Not Applicable. High strength steel bolting
 
is not used in the auxiliary systems.
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 System Walkdown Program (B.2.32) Consistent with GALL Report  (See SER Section 3.3.2.2.5.1)
Elastomer lining
 
exposed to treated water or treated borated water
 
(3.3.1-12)
Hardening and loss of strength
 
due to elastomer
 
degradation A plant-specific aging management
 
program is to be
 
evaluated. Yes Not Applicable See SER Section 3.3.2.2.5.2 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 BWR Water Chemistry
 
Program (B.2.2) Consistent with the GALL Report (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 Lubricating Oil Analysis Program (B.2.33) and
 
Lubricating Oil
 
Inspection
 
Program (B.2.25) Consistent with GALL Report (See SER Section 3.3.2.2.7.1)
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 Not applicable Not applicable (See SER Section 3.3.2.2.7.1)
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 Not applicable Not applicable (See SER Section 3.3.2.2.7.1) 3-300 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation 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 BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report  (See SER Section 3.3.2.2.7.2)
Stainless steel and
 
steel diesel engine
 
exhaust piping, piping components, and piping elements
 
exposed to diesel
 
exhaust (3.3.1-18)
Loss of material/general (steel only),
pitting and
 
crevice corrosion A plant-specific aging management
 
program is to be
 
evaluated. Yes System Walkdown Program (B.2.32)
See SER Section 3.3.2.2.7.3 Steel (with or without coating or wrapping)
 
piping, piping
 
components, and
 
piping elements
 
exposed to soil
 
(3.3.1-19)
Loss of material due to general, pitting, crevice, and MIC Buried Piping and Tanks Surveillance
 
or
 
Buried Piping and Tanks Inspection No 
 
Yes Buried Piping and Tanks
 
Surveillance (B.2.18) and
 
Buried Piping and Tanks
 
Inspection (B.2.30) Consistent with GALL Report  (See
 
SER Section
 
3.3.2.2.8)
Steel piping, piping
 
components, piping
 
elements, and tanks
 
exposed to fuel oil
 
(3.3.1-20)
Loss of material due to general, pitting, crevice, and MIC, and
 
fouling Fuel Oil Chemistry and One-Time
 
Inspection Yes Fuel Oil Chemistry
 
Program (B.2.20) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report (See SER Section 3.3.2.2.9.1)
Steel heat exchanger
 
components exposed
 
to lubricating oil
 
(3.3.1-21)
Loss of material due to general, pitting, crevice, and MIC, and
 
fouling Lubricating Oil Analysis and One-Time InspectionYes Lubricating Oil Analysis (B.2.33) and
 
Lubricating Oil
 
Inspection (B.2.25)  Consistent with GALL Report (See
 
SER Section
 
3.3.2.2.9.2) Steel with elastomer
 
lining or stainless
 
steel cladding piping, piping components, and piping elements
 
exposed to treated water and treated borated water
 
(3.3.1-22)
Loss of material due to pitting
 
and crevice corrosion (only
 
for steel after
 
lining/cladding
 
degradation) Water Chemistry and One-Time InspectionYes Not Applicable See SER Section 3.3.2.2.10.1 3-301 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel and steel with stainless
 
steel cladding heat
 
exchanger
 
components exposed to treated water
 
(3.3.1-23)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time Inspection Yes Closed Cooling Water Chemistry
 
Program (B.2.14) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Closed Cooling Water Chemistry
 
Program (B.2.14) Consistent with GALL Report (See SER Section 3.3.2.2.10.2)
Stainless steel and aluminum piping, piping components, and piping elements
 
exposed to treated water (3.3.1-24)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time Inspection Yes BWR Water Chemistry
 
Program (B.2.2),
and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22), or BWR Water Chemistry
 
Program (B.2.2),
or Closed Cooling Water Chemistry
 
Program (B.2.14) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report (See SER Section 3.3.2.2.10.2) Copper alloy HVAC
 
piping, piping
 
components, piping
 
elements exposed to
 
condensation (external)
 
(3.3.1-25)
Loss of material due to pitting
 
and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated. Yes System Walkdown (B.2.32), Cooling
 
Units Inspection (B.2.23), and
 
Selective
 
Leaching Inspection (B.2.29) Consistent with GALL Report  (See SER Section 3.3.2.2.10.3) Copper alloy piping, piping components, and piping elements
 
exposed to
 
lubricating oil
 
(3.3.1-26)
Loss of material due to pitting
 
and crevice
 
corrosion Lubricating Oil Analysis and One-Time InspectionYes Lubricating Oil Analysis Program (B.2.33) and
 
Lubricating Oil
 
Inspection
 
Program (B.2.25) Consistent with GALL Report (See SER Section 3.3.2.2.10.4) 3-302 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation 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 System Walkdown (B.2.32),   
 
Cooling Units
 
Inspection (B.2.23), and
 
Supplemental Piping/Tank
 
Inspection (B.2.28) Consistent with the GALL Report (See SER Section 3.3.2.2.10.5) Copper alloy fire
 
protection piping, piping components, and piping elements
 
exposed to
 
condensation (internal)
 
(3.3.1-28)
Loss of material due to pitting
 
and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated. Yes Not Applicable See SER Section 3.3.2.2.10.6 Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to soil
 
(3.3.1-29)
Loss of material due to pitting
 
and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated. Yes Not applicable See SER Section 3.3.2.2.10.7 Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to sodium
 
pentaborate solution
 
(3.3.1-30)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time InspectionYes BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report (See SER Section 3.3.2.2.10.8) Copper alloy piping, piping components, and piping elements
 
exposed to treated water (3.3.1-31)
Loss of material due to pitting, crevice, and
 
galvanic corrosion Water Chemistry and One-Time InspectionYes BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report (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 MIC Fuel Oil Chemistry and One-Time
 
Inspection Yes Fuel Oil Chemistry
 
Program (B.2.20) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with the GALL Report (See SER Section 3.3.2.2.12.1) 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 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 MIC Lubricating Oil Analysis and One-Time InspectionYes Lubricating Oil Analysis Program (B.2.33) and
 
Lubricating Oil
 
Inspection
 
Program (B.2.25) Consistent with GALL Report (See SER Section 3.3.2.2.12.2)
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 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 to BWRs (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 SSES (See SER
 
Section 3.3.2.1.1)
Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to treated water > 60 C (> 140 F) (3.3.1-37)
Cracking due to SCC, IGSCC BWR Reactor Water Cleanup System No BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report (See SER Section 3.3.2.1.2)
Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to treated water > 60 C (> 140 F) (3.3.1-38)
Cracking due to SCC BWR Stress Corrosion Cracking and Water ChemistryNo Not applicable  Addressed in line item 3.3.1-37 (See
 
SER Section
 
3.3.2.1.1) 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 Amendments Staff Evaluation Stainless steel BWR spent fuel storage racks exposed to treated water > 60 C (> 140 F) (3.3.1-39)
Cracking due to SCC Water Chemistry No Not applicable Not applicable because spent fuel pool water
 
temperature is maintained well below 60C (<140F). This component, material, environment
 
combination does not
 
exist, and the aging
 
effect identified in the
 
GALL Report does not apply.
Steel tanks in diesel fuel oil system
 
exposed to air -
 
outdoor (external)
 
(3.3.1-40)
Loss of material due to general, pitting, and
 
crevice corrosion Aboveground Steel Tanks No Not applicable Not applicable to SSES. High-strength steel
 
closure bolting exposed to air with steam or water
 
leakage (3.3.1-41)
Cracking due to cyclic loading, SCC Bolting Integrity No Bolting Integrity Program (B.2.12) Consistent with GALL Report 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 Bolting Integrity Program (B.2.12) Consistent with GALL Report 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.2.12) Consistent with GALL Report Steel compressed air system closure
 
bolting exposed to
 
condensation
 
(3.3.1-44)
Loss of material due to general, pitting, and
 
crevice corrosion Bolting Integrity No Bolting Integrity Program (B.2.12) Consistent with GALL Report 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.2.12) Consistent with 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 Amendments Staff Evaluation Stainless steel and stainless clad steel
 
piping, piping
 
components, piping
 
elements, and heat
 
exchanger
 
components exposed to closed cycle
 
cooling  water > 60 C (> 140 F) (3.3.1-46)
Cracking due to SCC Closed-Cycle Cooling Water System No Closed Cooling Water Chemistry
 
Program (B.2.14) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report (See SER Section 3.3.2.1.3)
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 Chemistry
 
Program (B.2.14), or Closed Cooling Water Chemistry
 
Program (B.2.14) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report (See SER Section 3.3.2.1.4)
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 Chemistry
 
Program (B.2.14) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report (See SER Section 3.3.2.1.5.)
Stainless steel; steel with stainless steel
 
cladding heat
 
exchanger
 
components exposed to closed cycle cooling water
 
(3.3.1-49)
Loss of material due to MIC Closed-Cycle Cooling Water System No Not applicable Not applicable to SSES (See SER
 
Section 3.3.2.1.1)
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 Chemistry
 
Program (B.2.14) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report (See SER Section 3.3.2.1.6.)
3-306 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, 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 Chemistry
 
Program (B.2.14) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report (See SER Section 3.3.2.1.7)
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 Heat Exchanger Inspection (B.2.24) Consistent with GALL Report Steel compressed air system piping, piping
 
components, and
 
piping elements
 
exposed to
 
condensation (internal)
 
(3.3.1-53)
Loss of material due to general
 
and pitting
 
corrosion Compressed Air Monitoring No Area-Based NSAS Inspection (B.2.46) See SER Section 3.3.2.1.9 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 Area-Based NSAS Inspection (B.2.46) See SER Section 3.3.2.1.9 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 System Walkdown Program (B.2.32) Consistent with GALL Report Steel HVAC ducting
 
and components
 
external surfaces
 
exposed to air -
 
indoor uncontrolled (external)
 
(3.3.1-56)
Loss of material due to general
 
corrosion External Surfaces Monitoring No Fire Water System Program (B.2.17) Consistent with GALL Report Steel piping and
 
components external
 
surfaces exposed to
 
air - indoor
 
uncontrolled (External)
 
(3.3.1-57)
Loss of material due to general
 
corrosion External Surfaces Monitoring No System Walkdown Program (B.2.32) Consistent with GALL Report 3-307 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel external surfaces exposed to
 
air - indoor
 
uncontrolled (external), air -
 
outdoor (external),
and condensation (external)
 
(3.3.1-58)
Loss of material due to general
 
corrosion External Surfaces Monitoring No System Walkdown Program (B.2.32) and
 
Selective
 
Leaching Inspection
 
Program (B.2.29) Consistent with GALL Report 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 System Walkdown Program (B.2.32) Consistent with GALL Report 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 applicable Addressed in line item 3.3.1-58 (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 (B.2.16) Consistent with the GALL Report Aluminum piping, piping components, and piping elements exposed to raw water
 
(3.3.1-62)
Loss of material due to pitting
 
and crevice
 
corrosion Fire Protection No Not applicable Not applicable to SSES (See SER
 
Section 3.3.2.1.1)
Steel fire rated doors
 
exposed to air -
 
outdoor or 
 
air - indoor
 
uncontrolled
 
(3.3.1-63)
Loss of material due to wear Fire Protection No Fire Protection (B.2.16) Not Consistent with GALL Report  (See SER Section 3.5.2.3.10)
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 Fuel Oil Chemistry
 
Program (B.2.20) and Fire
 
Protection
 
Program (B.2.16) Consistent with GALL Report 3-308 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Reinforced concrete structural fire barriers
- walls, ceilings and
 
floors exposed to air
- 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 Not applicable Evaluated in LRA Table 3.5 (See SER
 
Section 3.3.2.1.1)
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 Not applicable Evaluated in LRA Table 3.5 (See SER
 
Section 3.3.2.1.1)
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 Not applicable Evaluated in LRA Table 3.5 (See SER
 
Section 3.3.2.1.1)
Steel piping, piping
 
components, and
 
piping elements exposed to raw water
 
(3.3.1-68)
Loss of material due to general, pitting, crevice, and MIC, and
 
fouling Fire Water System No Fire Water System Program (B.2.17) Consistent with GALL Report Stainless steel
 
piping, piping
 
components, and
 
piping elements exposed to raw water
 
(3.3.1-69)
Loss of material due to pitting
 
and crevice
 
corrosion, and
 
fouling Fire Water System No Fire Water System Program (B.2.17) Consistent with GALL Report Copper alloy piping, piping components, and piping elements exposed to raw water
 
(3.3.1-70)
Loss of material due to pitting, crevice, and
 
MIC, and fouling Fire Water System No Fire Water System Program (B.2.17) Consistent with GALL Report Steel piping, piping
 
components, and
 
piping elements
 
exposed to moist air
 
or condensation (internal)
 
(3.3.1-71)
Loss of material due to general, pitting, and
 
crevice corrosion Inspection of Internal Surfaces in
 
Miscellaneous Piping
 
and Ducting
 
Components No Supplemental Piping/Tank
 
Inspection
 
Program (B.2.28) Consistent with GALL Report 3-309 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 HVAC ducting and components
 
internal surfaces
 
exposed to
 
condensation (internal)
 
(3.3.1-72)
Loss of material due to general, pitting, crevice, and (for drip
 
pans and drain
 
lines) MIC Inspection of Internal Surfaces in
 
Miscellaneous Piping
 
and Ducting
 
Components No Systems Walkdown program (B.2.32) Consistent with GALL Report (See SER Section 3.3.2.1.8)
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 Crane Inspection
 
Program (B.2.15) Consistent with GALL Report 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 Not applicable Evaluated in LRA Table 3.5 (See SER
 
Section 3.3.2.1.1)
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 Evaluated in LRA Table 3.5 (See SER
 
Section 3.3.2.1.1)
Steel piping, piping
 
components, and
 
piping elements (without lining/
coating or with
 
degraded lining/coating) exposed to raw water
 
(3.3.1-76)
Loss of material due to general, pitting, crevice, and MIC, fouling, and
 
lining/coating
 
degradation Open-Cycle Cooling Water System No Piping Corrosion Program (B.2.13) Consistent with GALL Report Steel heat exchanger
 
components exposed to raw water
 
(3.3.1-77)
Loss of material due to general, pitting, crevice, galvanic, and
 
MIC, and fouling Open-Cycle Cooling Water System No Piping Corrosion Program (B.2.13) Consistent with GALL Report Stainless steel, nickel alloy, and copper alloy piping, piping components, and piping elements exposed to raw water
 
(3.3.1-78)
Loss of material due to pitting
 
and crevice
 
corrosion Open-Cycle Cooling Water System No Piping Corrosion Program (B.2.13) Consistent with GALL Report 3-310 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 raw water
 
(3.3.1-79)
Loss of material due to pitting
 
and crevice
 
corrosion, and
 
fouling Open-Cycle Cooling Water System No Piping Corrosion Program (B.2.13) Consistent with GALL Report 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 MIC Open-Cycle Cooling Water System No Piping Corrosion Program (B.2.13) Consistent with GALL Report Copper alloy piping, piping components, and piping elements, exposed to raw water
 
(3.3.1-81)
Loss of material due to pitting, crevice, and
 
MIC, and fouling Open-Cycle Cooling Water System No Piping Corrosion Program (B.2.13) Consistent with GALL Report Copper alloy heat
 
exchanger
 
components exposed to raw water
 
(3.3.1-82)
Loss of material due to pitting,
: crevice, galvanic, and
 
MIC, and fouling Open-Cycle Cooling Water System No Piping Corrosion Program (B.2.13) Consistent with GALL Report Stainless steel and copper alloy heat
 
exchanger tubes exposed to raw water
 
(3.3.1-83)
Reduction of heat transfer
 
due to fouling Open-Cycle Cooling Water System No Piping Corrosion Program (B.2.13) Heat Exchanger Inspection (B.2.24) Consistent with GALL Report  (See SER Section 3.3.2.1.10) Copper alloy
> 15% Zn piping, piping components, piping elements, and
 
heat exchanger
 
components exposed to raw water, treated water, or closed cycle cooling water
 
(3.3.1-84)
Loss of material due to selective
 
leaching Selective Leaching of Materials No Selective Leaching Inspection
 
Program (B.2.29) and
 
Cooling Units
 
Inspection
 
Program (B.2.23) Consistent with GALL Report 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 Selective Leaching Inspection
 
Program (B.2.29) Consistent with GALL Report
 
3-311 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 Structural steel (new fuel storage rack assembly) exposed
 
to air - indoor
 
uncontrolled (external)
 
(3.3.1-86)
Loss of material due to general, pitting, and
 
crevice corrosion Structures Monitoring Program No Not applicable Not applicable to SSES 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 to BWRs Aluminum and copper alloy
> 15% Zn piping, piping components, and piping elements exposed to air with borated water
 
leakage (3.3.1-88)
Loss of material due to boric acid
 
corrosion Boric Acid Corrosion No Not applicable Not applicable to BWRs 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 Not applicable Not applicable to BWRs Stainless steel and steel with stainless
 
steel cladding piping, piping components, piping elements, tanks, and fuel
 
storage racks
 
exposed to treated borated water > 60 C (> 140 F) (3.3.1-90)
Cracking due to SCC Water Chemistry No Not applicable Not applicable to BWRs 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 Not applicable Not applicable to BWRs 3-312 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 Galvanized steel piping, piping
 
components, and
 
piping elements
 
exposed to air -
 
indoor uncontrolled
 
(3.3.1-92) None None No None Consistent with GALL Report Glass piping elements exposed to
 
air, air - indoor
 
uncontrolled (external), fuel oil, lubricating oil, raw water, treated water, and treated borated water (3.3.1-93) None None No None Consistent with GALL Report 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 GALL Report Steel and aluminum piping, piping
 
components, and
 
piping elements
 
exposed to air -
 
indoor controlled (external)
 
(3.3.1-95) None None No None Consistent with GALL Report Steel and stainless steel piping, piping
 
components, and
 
piping elements in
 
concrete (3.3.1-96) None None No None Consistent with GALL Report Steel, stainless steel, aluminum, and copper alloy piping, piping components, and piping elements
 
exposed to gas
 
(3.3.1-97) None None No None Consistent with GALL Report
 
3-313 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 copper alloy
 
piping, piping
 
components, and
 
piping elements
 
exposed to dried air
 
(3.3.1-98) None None No None Consistent with GALL Report Stainless steel and copper alloy
< 15% Zn piping, piping components, and piping elements exposed to air with borated water
 
leakage (3.3.1-99) None None No Not applicable Not applicable to BWRs  The staff's review of the auxiliary systems component groups followed any one of several approaches. One approach, documented in SER Section 3.3.2.1, reviewed AMR results for
 
components that the applicant indicated are consistent with the GALL Report and require no
 
further evaluation. Another approach, documented in SER Section 3.3.2.2, reviewed AMR
 
results for components that the applicant indicated are consistent with the GALL Report and for
 
which further evaluation is recommended. A third approach, documented in SER
 
Section 3.3.2.3, reviewed AMR results for components that the applicant indicated are not
 
consistent with, or not addressed in, the GALL Report. The staff's review of AMPs credited to
 
manage or monitor aging effects of the auxilia ry 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 for t he auxiliary systems components:
* BWR Water Chemistry Program
* Flow-Accelerated Corrosion (FAC) Program
* Bolting Integrity Program
* Piping Corrosion Program
* Closed Cooling Water Chemistry Program
* Fire Water System Program
* Buried Piping Surveillance Program
* Fuel Oil Chemistry Program
* Chemistry Program Effectiveness Inspection
* Cooling Units Inspection
* Heat Exchanger Inspection
* Lubricating Oil Inspection
* Monitoring and Collection System Inspection
* Supplemental Piping/Tank Inspection
* Selective Leaching Inspection
 
3-314
* Buried Piping and Tanks Inspection Program
* System Walkdown Program
* Lubricating Oil Analysis Program
* Area-Based NSAS Inspection LRA Tables 3.3.2-1 through 3.3.2-34 summarize AMRs for the auxilia ry 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 GA LL 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. The staff audited these line items to
 
verify consistency with the GALL Report. The staff also determined whether the credited 3-315 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 reviewed the LRA to confirm that the applicant: (a) provided a brief description of the
 
system, components, materials, and environments; (b) stated that the applicable aging effects were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the
 
engineered safety features ESF components that are subject to an AMR. On the basis of its
 
audit and review, the staff determines that, for AMRs not requiring further evaluation, as
 
identified in LRA Table 3.3.1, the applicant's references to the GALL Report are acceptable and
 
no further staff review is required, with the exception of the following AMRs that the applicant
 
had identified were consistent with the AMRs of the GALL Report and for which the staff felt
 
were in need of additional clarification and assessment. The staff's evaluations of these AMRs
 
are providing in the subsections that follows. 
 
3.3.2.1.1 AMR Results Identified as Not Applicable 
 
In LRA Table 3.3.1, item 36, the applicant states that the corresponding AMR result line in the
 
GALL Report is not applicable because Boraflex is not used as a neutron absorber for spent
 
fuel racks at SSES. The staff reviewed the documentation supporting the applicant's AMR
 
evaluation and confirmed the applicant's claim that SSES has no Boraflex as neutron absorber, and uses Boral instead. Therefore, the staff agrees with the applicant's determination that the
 
corresponding AMR result line in the GALL Report is not applicable to SSES.
 
In LRA Table 3.3.1, items 39, the applicant states that for this corresponding AMR result lines in
 
the GALL Report, cracking due to SCC was not identified as an aging effect requiring
 
management for stainless steel spent fuel storage racks because the temperature of the spent
 
fuel pool is maintained well below 140&#xba;F. The staff reviewed the documentation supporting the
 
applicant's AMR evaluation and confirmed the applicant's claim that spent fuel temperature is
 
maintained below 140 &#xba;F. In addition, the staff noted that SCC rarely occurs in austenitic
 
stainless steel below 140 &#xba;F (Metals Handbook, 1988). Therefore, the staff agrees finds that the
 
corresponding AMR result lines in the GALL Report is not applicable to SSES.
In LRA Table 3.3.1, item 40, the applicant states that the corresponding AMR result line in the
 
GALL Report is not applicable because steel tanks in the Diesel Fuel Oil System are buried. 
 
The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed
 
the applicant's claim that SSES has no steel tanks exposed to outdoor air in the Diesel Fuel Oil
 
System. Therefore, the staff agrees with the applicant's determination that the corresponding
 
AMR result line in the GALL Report is not applicable to SSES.
In LRA Table 3.3.1, items 60, the applicant indicates that for this corresponding AMR result
 
lines in the GALL Report, steel components that are exposed to air - outdoor (external) are
 
evaluated in item 3.3.1-58. The staff reviewed the documentation supporting the applicant's
 
AMR evaluation and confirmed the applicant's cl aim that the components under this commodity group are addressed under item 3.3.1-58. In addition, steel components that are externally
 
exposed to outdoor air are managed by the System Walkdown Program, which is consistent with the GALL Report for this item 3.3.1-60. Therefore, the staff agrees with the applicant's 3-316 determination that the corresponding AMR result lines in the GALL Report are evaluated elsewhere in the application.
 
In LRA Table 3.3.1, items 49 and 62, the applicant indicates the component or the aging effects
 
for these line items is not applicable. The staff reviewed the documentation supporting the
 
applicant's AMR evaluation and confirmed the applicant's claim that the components and the
 
aging effect under this commodity group are not applicable to SSES. On this basis, the staff
 
agrees with the applicant's corresponding AMR result line in the GALL Report is not applicable
 
to SSES .     
 
In LRA Table 3.3.1, items 65, 66 and 67, the applicant states that for these corresponding AMR
 
result lines in the GALL Report, cracking and spalling were not identified as an aging effects
 
requiring management for reinforced concrete structural fire barriers exposed to indoor or
 
outdoor uncontrolled air. The staff reviewed the documentation supporting the applicant's AMR
 
evaluation and noted that reinforced concrete structural fire barriers were evaluated in the
 
following tables: Table 3.5.2-2, 3.5.2-3, 3.5.2-4, 3.5.2-5, 3.5.2-6, 3.5.2-7, and 3.5.2-8. In
 
addition, the staff noted that though the applicant did not identified cracking and spalling as
 
aging effects, the applicant did manage the components with Structure Monitoring Program and
 
Fire Protection Program, which are consistent with the GALL Report. Therefore, the staff
 
agrees with the applicant's management of the components under 3.3.1 items 65, 66, and 67.
 
In LRA Table 3.3.1, item 74, the applicant states that for these corresponding AMR result lines
 
in the GALL Report, loss of material due to wear was not identified as an aging effect requiring
 
management for steel cranes - rails exposed to indoor uncontrolled air. The staff reviewed the
 
documentation supporting the applicant's AMR evaluation and noted that steel cranes rails were
 
evaluated in the following tables: Table 3.5.2-2, 3.5.2-4, 3.5.2-6, 3.5.2-7, 3.5.2-8, and 3.5.2-10. 
 
In addition, the staff noted that though the applicant did not identified loss of material due to
 
wear as an aging effect, the applicant did manage the components with Crane Inspection
 
Program, which are consistent with the GALL Report. Therefore, the staff agrees with the
 
applicant's management of the components under 3.3.1 item 74.
 
3.3.2.1.2  Cracking due to Stress Corrosion Cracking (SCC), Intergranular Stress Corrosion
 
Cracking (IGSCC) 
 
LRA Tables 3.3.2-3, 3.3.2-24, 3.3.2-25, 3.3.2-27, and 3.3.2-34 include AMR results for stainless
 
steel components in an environment of treated water with temperature greater than 60&#xba;C
 
(>140&#xba;F) and with an aging effect of cracking due to SCC or IGSCC. There are four AMR result
 
lines in LRA Table 3.3.2-3 where the components are accumulators, filters, piping and valve
 
bodies in the control rod drive hydraulic syst em; three lines in LRA Table 3.3.2-24 where the components are piping, tubing and valve bodies in the reactor non-nuclear instrumentation
 
system; three lines in LRA Table 3.3.2-25 wher e the components are orifices, tubing, and piping and piping components in the reactor water cleanup system; one line in LRA Table 3.3.2-27
 
where the components are piping and piping components in the sampling system; and one line
 
in LRA Table 3.3.2-34 where the components are piping and piping components in the reactor
 
vessel and auxiliaries system (NSAS portions). For these AMR results, the applicant credited
 
use of the BWR Water Chemistry Program, alone, with managing the aging effect. The applicant
 
cited generic Note E, indicating that the result is consistent with the corresponding GALL Report
 
item for material, environment and aging effect, but a different AMP is credited.
 
The staff noted that for the corresponding line in SRP-LR Table 3.2-1 and in GALL Report, Volume 1, Table 2, the recommended AMP is GALL AMP XI.M25, Closed-Cycle Cooling Water 3-317 System, which includes both preventive measures, such as control of water chemistry, to minimize the potential for SCC and IGSCC, and inspection to monitor the effectiveness of the
 
water chemistry program to control cracking due to SCC or IGSCC. Because the applicant
 
recommended the BWR Water Chemistry Program, alone, and no inspection activity credited to
 
monitor effectiveness of the chemistry program, the staff issued RAI 3.3-3 in a letter dated
 
July 15, 2008, asking the applicant to justify why an inspection is not needed to verify the
 
effectiveness of the water chemistry program and confirm that cracking is not occurring in these
 
components.
 
In a letter dated August 15, 2008, the applicant responded to RAI 3.3-3 by providing the
 
following response:
 
For the AMR results identified in LRA Section 3.3 (Tables 3.3.2-3, 3.3.2-24, 3.3.2-25, 3.3.2-27, and 3.3.2-34) that refer to the GALL Report item VII.E3-16, verification of the
 
effectiveness of the BWR Water Chemistry Program is needed to confirm that cracking
 
is not occurring in these components.
 
The affected LRA Tables are revised to explicitly credit the Chemistry Program
 
Effectiveness Inspection in combination with the BWR Water Chemistry Program.
 
The staff reviewed the applicant's response and all of the associated LRA changes. The staff
 
noted that for all of the AMR results being questioned by the staff, the applicant revised the
 
AMPs to be the BWR Water Chemistry Program in combination with the Chemistry Program
 
Effectiveness Inspection, rather than the BWR Chemistry Program, alone. The revised AMR
 
result lines continued to cite generic Note E, indicating that the material, environment and aging
 
effect are consistent with the GALL Report, but a different aging management program is
 
credited.
 
The staff reviewed the applicant's BWR Water Chemistry Program. The staff's evaluation of this
 
program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water Chemistry
 
Program provides mitigation for the aging effect of cracking due to SCC or IGSCC. The staff
 
reviewed the applicant's Chemistry Program Effe ctiveness Inspection. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the Chemistry
 
Program Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "O ne-Time Inspection." The Chemistry Program Effectiveness Inspection includes provisions for inspecting selected components in areas of low
 
or stagnant flow and implements inspection methods that are capable of detecting cracking due
 
to SCC or IGSCC, if it should occur in the selected components. Because the BWR Water
 
Chemistry Program provides mitigation and t he Chemistry Program Effectiveness Inspection provides detection of the aging effect if it should occur, the staff finds the applicant's proposed
 
AMPs for managing the potential aging effect of cracking due to SCC or IGSCC for stainless
 
steel piping, piping components, and piping elements exposed to treated water >60&#xba;C (>140&#xba;F)
 
in the control rod drive hydraulics system, the reactor non-nuclear instrumentation system, the reactor water cleanup system, the sampling system, and the reactor vessel and auxiliaries
 
system (NSAS portions) to be acceptable. The staff also finds that the applicant's response to
 
RAI 3.3-3, together with the associated LRA changes, resolves the issues raised in that RAI.
 
Based on the programs identified and the LRA changes made in response to RAI 3.3-3, the staff
 
concludes that the applicant's AMR results are acceptable because the AMPs provide both
 
detection and mitigation for the aging effect of cracking due to SCC and IGSCC in the subject
 
components. For those items that apply to LRA Table 3.3.1, item 3.3.1-37, the staff determines 3-318 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).
 
3.3.2.1.3  Cracking Due to Stress Corrosion Cracking
 
In LRA Table 3.3.1, Item 3.3.1-46, addresses cracking due to stress corrosion cracking for
 
stainless steel piping, piping components and heat exchanger components with the internal
 
surfaces exposed to treated water greater than 140 o F in the Reactor Building Closed Cooling Water System and Sampling System. The GALL Report recommends GALL AMP XI.M21, "Closed-Cycle Cooling Water System" to manage this aging effect. The staff noted that based
 
on the applicant's response to RAI B.2.14-2 in letter dated August 12, 2008 the applicant
 
amended the LRA so that the AMR line items in LRA Table 2 that reference this line item in
 
GALL Report Table 1 also credit AMP B.2.22 "Chem istry Program Effectiveness Inspection" and cite Generic Note E, indicating that the AMR line items are consistent with GALL Report
 
material, environment, and aging effect, but a different aging management program is credited. 
 
The staff reviewed the AMR results lines that reference note E and determines that the material, environment, and aging effect are consistent with the GALL Report.
 
The staff reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and
 
AMP B.2.22 "Chemistry Program Effectiveness In spection" and its evaluations are documented in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging
 
management program includes activities that are consistent with the recommendations in the GALL AMP XI.M21 to maintain high water purity, which is effective for managing loss of material
 
due to general, pitting and crevice corrosion for steel components exposed to a treated water
 
environment. The staff further noted the Closed Cooling Water Chemistry Program is an
 
existing SSES program that properly monitors components and controls corrosion inhibitor concentrations for components, within the scope of license renewal, consistent with relevant
 
EPRI water chemistry guidelines. The staff confir med that the Chemistry Program Effectiveness Inspection will be used to verify the effectiveness of the applicant's Closed Cooling Water
 
Chemistry Program to manage cracking and that a combination of appropriate volumetric and
 
visual examination techniques (such as VT-1 or VT-3) will be performed by qualified personnel
 
on a sample population of most susceptible subject components. On this basis, the staff finds
 
that AMR results addressed by this line item that credit these programs are acceptable.
 
3.3.2.1.4  Loss of Material Due to General, Pitting and Crevice Corrosion
 
In LRA Table 3.3.1, Item 3.3.1-47, addresses loss of material due to general, pitting, and
 
crevice corrosion for steel chiller and piping components, tanks, pump casings, valve bodies
 
and unit coolers with the internal surfaces exposed to treated water in the Process and Area
 
Radiation Monitoring System, Reactor Building Chilled Water, HVAC and Closed Cooling Water
 
Systems, and Control Structure Chilled Water and HVAC System. The GALL Report recommends GALL AMP XI.M21, "Closed-Cycle Cooling Water System" to manage this aging effect. The staff noted that based on the applicant's response to RAI B.2.14-2 in letter dated
 
August 12, 2008 the applicant amended the LRA so that the AMR line items in LRA Table 2 that
 
reference this line item in GALL Report Table 1 also credit AMP B.2.22 "Chemistry Program Effectiveness Inspection" and cite Generic Note E, indicating that the AMR line items are
 
consistent with GALL Report material, environment, and aging effect, but a different aging
 
management program is credited. The staff reviewed the AMR results lines that reference note
 
E and determines that the material, environment, and aging effect are consistent with the GALL 3-319 Report. By letter dated December 11, 2008 the applicant supplemented its response to RAI B.2.14-2 in which the applicant stated that the aging effect of loss of material for steel
 
components exposed to a treated water environment in the Diesel Jacket Cooling Water System is managed only by the Closed Cooling Water Chemistry Program because corrosion probes
 
have been installed. Further discussion is provided in SER Section 3.0.3.2.7 in which the
 
applicant responded to RAI B.2.14-3. The applicant's supplemental response provided
 
clarification as to why the Chemistry Program Effectiveness Inspection was not credited for
 
these steel components in the Diesel Jacket C ooling Water System, and these AMR line items are consistent with the GALL Report under GALL AMR Item VII.H2-23.
 
The staff reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and
 
AMP B.2.22 "Chemistry Program Effectiveness In spection" and its evaluations are documented in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging
 
management program includes activities that are consistent with the recommendations in the GALL AMP XI.M21 to maintain high water purity, which is effective for managing loss of material
 
due to general, pitting and crevice corrosion for steel components exposed to a treated water
 
environment. The staff further noted the Closed Cooling Water Chemistry Program is an
 
existing SSES program that properly monitors components and controls corrosion inhibitor concentrations for components, within the scope of license renewal, consistent with relevant
 
EPRI water chemistry guidelines. The staff confir med that the Chemistry Program Effectiveness Inspection will be used to verify the effectiveness of the applicant's Closed Cooling Water
 
Chemistry Program to manage loss of material and that a combination of appropriate volumetric
 
and visual examination techniques (such as VT-1 or VT-3) will be performed by qualified
 
personnel on a sample population of most susceptible subject components. On this basis, the
 
staff finds that AMR results addressed by this line item that credit these programs are
 
acceptable.
3.3.2.1.5  Loss of Material Due to General, Pitting, Crevice and Galvanic Corrosion
 
In LRA Table 3.3.1, Item 3.3.1-48, addresses loss of material due to general, pitting, crevice
 
and galvanic corrosion for steel chiller and heat exchanger components with the internal
 
surfaces exposed to treated water in the Fuel P ool Cooling System, Containment Instrument Gas System, Reactor Building Chilled Water and Closed Cooling Water Systems, Reactor
 
Water Cleanup System, Sampling System, Turbine Building Closed Cooling Water System and Control Structure Chilled Water System. The GALL Report recommends GALL AMP XI.M21, "Closed-Cycle Cooling Water System" to manage this aging effect. The staff noted that based
 
on the applicant's response to RAI B.2.14-2 in letter dated August 12, 2008 the applicant
 
amended the LRA so that the AMR line items in LRA Table 2 that reference this line item in
 
GALL Report Table 1 also credit AMP B.2.22 "Chem istry Program Effectiveness Inspection" and cite Generic Note E, indicating that the AMR line items are consistent with GALL Report
 
material, environment, and aging effect, but a different aging management program is credited. 
 
The staff reviewed the AMR results lines that reference note E and determines that the material, environment, and aging effect are consistent with the GALL Report.
 
The staff reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and
 
AMP B.2.22 "Chemistry Program Effectiveness In spection" and its evaluations are documented in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging
 
management program includes activities that are consistent with the recommendations in the GALL AMP XI.M21 to maintain high water purity, which is effective for managing loss of material
 
due to general, pitting, crevice, and galvanic corrosion for steel components exposed to a
 
treated water environment. The staff further noted the Closed Cooling Water Chemistry 3-320 Program is an existing SSES program that properly monitors components and controls corrosion inhibitor concentrations for components, within the scope of license renewal, consistent with relevant EPRI water chemistry guidelines. The staff confirmed that the
 
Chemistry Program Effectiveness Inspection will be used to verify the effectiveness of the applicant's Closed Cooling Water Chemistry Program to manage loss of material and that a
 
combination of appropriate volumetric and visual examination techniques (such as VT-1 or VT-
: 3) will be performed by qualified personnel on a sample population of most susceptible subject
 
components. On this basis, the staff finds that AMR results addressed by this line item that
 
credit these programs are acceptable.
3.3.2.1.6  Loss of Material Due to Pitting and Crevice Corrosion
 
In LRA Table 3.3.1, Item 3.3.1-50, addresses loss of material due to pitting and crevice
 
corrosion for stainless steel unit cooler, heat exchanger and chiller components, piping
 
components, orifices, pump casings, tubing and valve bodies with the internal surfaces exposed
 
to treated water in the Reactor Building Chilled Water, HVAC and Closed Cooling Water
 
Systems, Sampling System, Diesel Generat or Systems (Intake/Exhaust, Jacket Water, Lubricating Oil and NSAS Components) and Control Structure Chilled Water System. The GALL Report recommends GALL AMP XI.M21, "C losed-Cycle Cooling Water System" to manage this aging effect. The staff noted that based on the applicant's response to RAI B.2.14-
 
2 in letter dated August 12, 2008 and supplemental response to RAI B.2.14-2 by letter dated
 
December 11, 2008 the applicant amended the LRA so that the AMR line items in LRA Table 2
 
that reference this line item in GALL Report Table 1 also credit AMP B.2.22 "Chemistry Program Effectiveness Inspection" and cite Generic Note E, indicating that the AMR line items are
 
consistent with GALL Report material, environment, and aging effect, but a different aging
 
management program is credited. The staff reviewed the AMR results lines that reference note
 
E and determines that the material, environment, and aging effect are consistent with the GALL
 
Report.
 
The staff reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and
 
AMP B.2.22 "Chemistry Program Effectiveness In spection" and its evaluations are documented in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging
 
management program includes activities that are consistent with the recommendations in the GALL AMP XI.M21 to maintain high water purity, which is effective for managing loss of material
 
due pitting and crevice corrosion for stainless steel components exposed to a treated water
 
environment. The staff further noted the Closed Cooling Water Chemistry Program is an
 
existing SSES program that properly monitors components and controls corrosion inhibitor concentrations for components, within the scope of license renewal, consistent with relevant
 
EPRI water chemistry guidelines. The staff confir med that the Chemistry Program Effectiveness Inspection will be used to verify the effectiveness of the applicant's Closed Cooling Water
 
Chemistry Program to manage loss of material and that a combination of appropriate volumetric
 
and visual examination techniques (such as VT-1 or VT-3) will be performed by qualified
 
personnel on a sample population of most susceptible subject components. On this basis, the
 
staff finds that AMR results addressed by this line item that credit these programs are
 
acceptable.
 
3.3.2.1.7 Loss of Material Due to Pitting, Crevice and Galvanic Corrosion
 
In LRA Table 3.3.1, Item 3.3.1-51, addresses loss of material due to pitting, crevice and
 
galvanic corrosion for copper and copper alloy chiller and heat exchanger components, piping
 
and piping components and elements with the internal surfaces exposed to treated water in the 3-321 Process and Area Radiation Monitoring System, C ontainment Instrument Gas System, Reactor Building Chilled Water, HVAC and Closed Cooling Water Systems, Sampling System and
 
Control Structure Chilled Water, Diesel Generator Systems (Intake/Exhaust, Jacket Water, Lubricating Oil and NSAS Components) and HVAC System  The GALL Report recommends GALL AMP XI.M21, "Closed-Cycle Cooling Wate r System" to manage this aging effect. The staff noted that based on the applicant's response to RAI B.2.14-2 in letter dated August 12, 2008 and supplemental response to RAI B.2.14-2 by letter dated December 11, 2008 the
 
applicant amended the LRA so that the AMR line items in LRA Table 2 that reference this line
 
item in GALL Report Table 1 also credit AM P B.2.22 "Chemistry Program Effectiveness Inspection" and cite Generic Note E, indicating that the AMR line items are consistent with
 
GALL Report material, environment, and aging effect, but a different aging management
 
program is credited. The staff reviewed the AMR results lines that reference note E and
 
determines that the material, environment, and aging effect are consistent with the GALL
 
Report.
 
The staff reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and
 
AMP B.2.22 "Chemistry Program Effectiveness In spection" and its evaluations are documented in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging
 
management program includes activities that are consistent with the recommendations in the GALL AMP XI.M21 to maintain high water purity, which is effective for managing loss of material
 
due to pitting, crevice, and galvanic corrosion for copper and copper alloy components exposed
 
to a treated water environment. The staff further noted the Closed Cooling Water Chemistry
 
Program is an existing SSES program that properly monitors components and controls corrosion inhibitor concentrations for components, within the scope of license renewal, consistent with relevant EPRI water chemistry guidelines. The staff confirmed that the
 
Chemistry Program Effectiveness Inspection will be used to verify the effectiveness of the applicant's Closed Cooling Water Chemistry Program to manage loss of material and that a
 
combination of appropriate volumetric and visual examination techniques (such as VT-1 or VT-
: 3) will be performed by qualified personnel on a sample population of most susceptible subject
 
components. On this basis, the staff finds that AMR results addressed by this line item that
 
credit these programs are acceptable.
 
3.3.2.1.8  Loss of Material Due to General, Pitting, Crevice and Microbiologically-Influenced
 
Corrosion
 
In LRA Table 3.3.1, Item 3.3.1-72, addresses loss of material due to general, pitting, crevice
 
and microbiologically influenced corrosion for steel HVAC ducting and components internal
 
surfaces exposed to condensation (internal) in the Primary Containment Atmosphere Circulation System. The GALL Report recommends GALL AMP XI.M 38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" to manage this aging effect. The AMR line
 
items in LRA Table 2 that reference this line item in GALL Report Table 1 cite Generic Note E, indicating that the AMR line items are consistent with GALL Report material, environment, and
 
aging effect, but a different aging management program is credited. The staff reviewed the
 
AMR results lines that reference note E and determines that the material, environment, and
 
aging effect are consistent with the GALL Report.
 
The staff reviewed the applicant's AMP B.2.32 "System Walkdown Program" and its evaluation
 
is documented in SER Sections 3.0.3.2.15. The staff determined that this aging management
 
program which include surveillance activities and observations that are adequate to manage
 
loss of material due to general corrosion for steel components exposed to ventilation (internal)
 
addressed by this AMR are consistent with those activities recommend by GALL AMP XI.M38, 3-322 "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components". However the applicant is crediting the AMP B.2.32, which performs visual inspections of the external
 
surfaces only, for the internal surfaces of fan and unit cooler housings. The staff felt that
 
additional information was needed and therefore, by letter dated July 23. 2008 the staff issued
 
RAI 3.x.2.1-1 requesting the applicant to justify the basis for crediting AMP B.2.32, which
 
performs visual inspections of external surfaces only, for the internal surfaces of ducting and
 
components internal surfaces exposed to condensation (internal) environments only. The
 
applicant responded to RAI 3.x.2.1-1, in a letter dated August 22, 2008. The applicant stated
 
that the internal ventilation environment of t hat these components are exposed to is the same as the environment the external surfaces are ex posed to because the function of this system is to circulate the air within containment. The staff noted that if condensation were to occur, that it
 
is expected to form on the external surfaces of the components. The applicant further stated
 
that visual inspections of the external surface for loss of material will be conservatively
 
representative of the condition internal surface, because the external surface may be subjected
 
to condensation. The staff noted that this is consistent with the recommendations given in the
 
program element, "scope of program", of GALL AMP XI.M36 "External Surfaces Monitoring", in which a visual inspection of the external surfaces may be representative of the internal surfaces
 
if the environment is the same for the external and internal surfaces. The staff noted that for the
 
unit cooler housings the AMP B.2.23 "Cooling Units Inspection" will supplement the AMP B.2.32
 
"System Walkdown Program" because this component may be subjected to condensation on
 
the internal surface and the staff confirmed that the AMP B.2.23 will provide verification if
 
degradation has occurred on the internal surfaces of this component and the effectiveness of
 
the AMP B.2.32 "System Walkdown Program" for managing loss of material. On the basis of its
 
review, the staff finds the applicable portion of the applicant's response that references GALL
 
Item VII.F3-3 to be acceptable because (1) the environments of the external surface and
 
internal surface is the same and consistent with the recommendations provided in GALL that an
 
visual inspection of the external surface can be credited for managing aging of the internal
 
surfaces if the environments are the same and (2) the applicant has credited a one-time
 
inspection to verify if degradation has occurred  and the effectiveness of the Systems Walkdown
 
Program when condensation may form on the internal surface. On this basis, the staff finds this
 
AMR results for this line item acceptable.
 
3.3.2.1.9  Loss of Material
 
LRA Table 3.3.1, line items 3.3.1-53 and 3.3.1-54 address the results of an AMR for steel and
 
stainless steel compressed air piping, piping components, and piping elements exposed internal
 
condensation, respectively. The applicant states that the aging effect requiring management is
 
loss of material and proposes to use the Area-Based NSAS Inspection to manage the effects of
 
aging. 
 
The applicant has indicated generic note E for this line item which is consistent with the GALL
 
report for material, environment, and aging effec t, but a different aging management program. The staff noted that the GALL Report recommends GALL AMP XI.M24, "Compressed Air
 
Monitoring."  The applicant cited a plant-specific note which states that internal condensation is
 
collected in strainers, drain traps, tanks and associated piping and this moisture has
 
conservatively been considered a raw water environment, but there is no resulting condensation
 
on the external surface of the components. The staff noted that the applicant referenced the
 
GALL AMR Items VII.D-2 and VII.D-4, which are applicable to compressed air systems, because the component/material/aging effect and environment combination corresponded to
 
those that were applicable to the applicant, noting that the applicant conservatively considered
 
internal condensation as raw water. The staff further noted that the piping and piping 3-323 components applicable to this AMR that is being addressed here, in the Containment Instrument Gas and Service Air System, is not compressed air.
 
The staff's evaluation of the Area-Based NSAS Inspection is documented in SER Section
 
3.0.3.3.1. The staff noted that this program is a plant-specific program that performs an
 
appropriate combination of established volumetric and visual inspection techniques (nondestructive examination techniques) that will be performed by a qualified personnel on a
 
sample population of those components in scope of this program. The staff further noted that
 
the applicant will perform the inspections of the components with in the scope of this program at
 
least 10 years prior to entering the period of extended operation such degradation that
 
progresses slowly and have long incubation time s will have time to become apparent. The staff determined the inspection techniques will be capable of detecting loss of material and the
 
applicant will initiate corrective actions if an unacceptable loss of material or wall thinning has
 
occurred that may have a spatial interaction with safety-related components, as determined by
 
engineering evaluation. On the basis that the applicant will be performing an appropriate
 
combination of a visual inspection and volumetric testing for these components, the staff finds
 
the AMR results for this line item acceptable.
 
3.3.2.1.10 Reduction of Heat Transfer due to Fouling
 
In its letter dated June 30, 2008, in response to RAI B.2.17-2, the applicant amended Table
 
3.3.2-13, Fire Protection System, to credit the Heat Exchanger Inspection Program to manage the aging effect of reduction of heat transfer due to fouling for copper alloy heat exchanger and
 
oil cooler tubes in raw water internal environment. The applicant applied footnote "E" and
 
referenced GALL Report item VII.C1-6. The staff reviewed the AMR results lines that reference
 
note E and determines that the component type, material, environment, and aging effect are
 
consistent with the GALL Report. However, the staff noted that where the GALL Report recommends AMP XI.M20, "Open-Cycle Cooling Water System," the applicant proposed using the Heat Exchanger Inspection Program. The staff noted that these heat exchangers are not
 
included in the GL 89-13 program and will not therefore be in the scope of the Open-Cycle
 
Cooling Water Program. The applicant instead uses the Fire Water System Program to manage loss of material due to corrosion, MIC or biofouling and includes actions to ensure no significant
 
corrosion, MIC, or biofouling has occurred. However, in addition, the applicant has credited the
 
one-time Heat Exchanger Inspection Program to pr ovide direct evidence as to whether, and to what extent, reduction in heat transfer due to fouling has occurred or is likely to occur that could
 
result in a loss of intended function.
 
On the basis that the applicant is crediting the Fire Water Inspection Program to ensure no
 
significant fouling is occurring and crediting the Heat Exchanger inspection Program to obtain
 
direct evidence of fouling, the staff finds that implementation of the Heat Exchanger Inspection
 
will ensure that the heat transfer capabilities of the subject heat exchangers, and the pressure
 
boundary integrity of the subject tubes, are maintained consistent with the current licensing
 
basis during the period of extended operation.
 
In LRA Table 3.3.2-4, the applicant stated that reduction of heat transfer of control structure
 
chilled water chiller evaporator copper and copper alloy tubes in an internal environment of
 
treated water is managed by the Heat Exchanger Inspection Program.
 
The staff noted that the applicant applied note E to this item. The applicant referenced LRA
 
Table 3.3-1, item 3.3.1-52 and GALL Report Volume 2, item VII.C2-2. The staff reviewed the
 
AMR results lines that reference note E and determines that the component type, material, 3-324 environment, and aging effect are consistent with the GALL Report. However, the staff noted that where the GALL Report recommends AMP XI.M 21, "Closed-Cycle Cooling Water System," the applicant proposed using the Heat Exchanger Inspection Program. 
 
The GALL recommended AMP XI.M21, Closed-Cycl e Cooling Water System, recommends preventive measures to minimize corrosion and testing and inspection to monitor the effects of
 
corrosion, whereas the applicant is proposing only a one-time inspection activity. The staff
 
noted that the heat exchangers in question are the chiller evaporators 0S118A/B and chiller oil
 
cooler 0S119A/B. The applicant has credited the Closed-Cycle Cooling Water System program to manage loss of material for these two components and credited the Heat Exchanger
 
Inspection Program to manage reduction of heat transfer. The staff noted that water chemistry is
 
maintained by the Closed-Cycle Cooling Water System Program in accordance with the EPRI guidelines to minimize an aggressive environment. However, the applicant's Closed-Cycle
 
Cooling Water System does not perform inspections for reduction of heat transfer due to fouling.
 
The heat exchanger inspection will provide direct evidence as to whether, and to what extent, reduction in heat transfer due to fouling has occurred or is likely to occur that could result in a
 
loss of intended function. On this basis, the staff finds that the implementation of the Heat
 
Exchanger Inspection will ensure that the heat transfer capabilities of the subject heat
 
exchangers are maintained consistent with the current licensing basis during the period of
 
extended operation.
 
SER Section 3.3.2.1
 
== 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 OE 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 evaluates of aging management, as recommended
 
by the GALL Report, for the auxiliary systems components and provides information concerning how it will manage the following aging effects:
* cumulative fatigue damage
* reduction of heat transfer due to fouling
* cracking due to SCC
* cracking due to SCC and cyclic loading
* hardening and loss of strength due to elastomer degradation
* reduction of neutron-absorbing capacity and loss of material due to general corrosion
* loss of material due to general, pitting, and crevice corrosion
* loss of material due to general, pitting, crevice, and MIC
* loss of material due to general, pitting, crevice, MIC and fouling
* loss of material due to pitting and crevice corrosion
 
3-325
* loss of material due to pitting, crevice, and galvanic corrosion
* loss of material due to pitting, crevice, and MIC
* 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 
 
LRA Section 3.3.2.2.1 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.
 
3.3.2.2.2  Reduction of Heat Transfer Due to Fouling 
 
The staff reviewed LRA Section 3.3.2.2.2 against the criteria in SRP-LR Section 3.3.2.2.2.
 
LRA Section 3.3.2.2.2 addresses reduction of heat transfer due to fouling. The applicant stated
 
that there are no SSES components compared to LRA item number 3.3.1-03. For Auxiliary Systems, stainless steel heat exchanger tubes in treated water are evaluated under LRA item number 3.3.1-52. Fouling of stainless steel heat exchanger tubes in treated water is managed
 
by the Closed Cooling Water Chemistry Pr ogram. The Closed Cooling Water Chemistry Program manages aging effects through periodic monitoring and control of contaminants. Based
 
on review of plant-specific OE, the Closed Cooling Water Chemistry Program is effective in
 
managing fouling through control of microorganisms and corrosion products.
 
SRP-LR Section 3.3.2.2.2 states that reduction of heat transfer due to fouling may occur in
 
stainless steel heat exchanger tubes exposed to treated water. The existing program controls
 
water chemistry to manage reduction of heat transfer due to fouling. However, control of water
 
chemistry may be inadequate; therefore, the GALL Report recommends that the effectiveness
 
of water chemistry control programs should be verified to ensure that reduction of heat transfer
 
due to fouling does not occur. A one-time inspection is an acceptable method to ensure that
 
reduction of heat transfer does not occur and that component intended functions will be
 
maintained during the period of extended operation.
 
The staff noted that LRA Table 3.3.1, item 3.3.1-52 includes the same components, material
 
and aging effect as LRA Table 3.3.1, item 3.3.1-3, and that the closed cycle cooling water
 
environment is also a treated water environm ent. The staff reviewed the components evaluated under LRA Table 3.3.2, item 3.3.1-52 and noted that the only stainless steel heat exchanger
 
components are for the diesel generator jacket water heat exchangers, which does not include
 
primary water on either side of the heat exchanger tubes. Because the component, material and
 
aging effects are identical and both environments are non-primary treated water, the staff finds it
 
acceptable for the applicant to include the evaluations for LRA Table 3.3.1, item 3.3.1-3, with
 
the evaluations for LRA Table 3.3.1, item 3.3.1-52. On this basis, the staff finds it acceptable to 3-326 designate LRA Table 3.3.1, item 3.3.1-3 as not applicable.
 
Based on the above, the staff concludes SRP-LR Section 3.3.2.2.2 criteria is not applicable.
 
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 the BWR Standby Liquid Control System. The applicant stated that this aging effect is not applicable because the normal operating temperature is below 140 F during normal plant operation.
SRP-LR Section 3.3.2.2.3 states that cracking due to SCC may occur in the stainless
 
steel piping, piping components, and piping elements of the BWR SLC system that are exposed to sodium pentaborate solution greater than 60 C (140 F). The existing AMP monitors and controls water chemistry to manage the aging effects of cracking due
 
to SCC. However, high concentrations of impurities in crevices and with stagnant flow
 
conditions may cause SCC; therefore, the GALL Report recommends that the
 
effectiveness of water chemistry control programs should be verified to ensure that SCC
 
does not occur. A one-time inspection of selected components at susceptible locations is
 
an acceptable method to ensure that SCC does not occur and that component intended
 
functions will be maintained during the period of extended operation.
 
The staff reviewed the boundary drawing for the standby liquid control system and
 
confirmed that all components of the sy stem exposed to sodium pentaborate during normal operation are outside the drywell in an area of the reactor building that does not
 
exceed 100&#xba;F during normal operation. The staff also noted that both the GALL Report
 
and the SRP-LR state that the threshold for initiation of cracking due to SCC is a
 
temperature greater than 60&#xba;C (>140&#xba;F). Because ambient temperature of the standby
 
liquid control system components exposed to sodium pentaborate is below 60&#xba;C
(<140&#xba;F) during normal plant operation, the staff finds that the aging effect of cracking
 
due to SCC is not applicable for these components. On this basis, the staff finds it
 
acceptable for the applicant to designate LRA Table 3.3.1, item 3.3.1-4 as not
 
applicable.
 
(2) LRA Section 3.3.2.2.3 addresses cracking due to SCC in heat exchanger components.
The applicant stated that this aging effect is not applicable because the heat exchanger
 
components are carbon steel.
 
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 C (140 F). 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 GALL Report identifies cracking due to SSC as an aging effect
 
applicable for stainless steel, but not for carbon steel components. On the basis that the
 
applicant has no stainless steel or stainless steel clad heat exchanger components
 
exposed to treated water at temperatures greater than 60&#xba;C (>140&#xba;F), and that cracking
 
due to SSC is not an expected aging effect applicable for carbon steel heat exchanger 3-327 components, the staff finds it acceptable for the applicant to designate LRA Table 3.3.1, item 3.3.1-5, as not applicable.
 
(3) LRA Section 3.3.2.2.3 addresses cracking due to SCC in diesel engine exhaust piping, piping components, and piping elements. The applicant stated that this aging effect is
 
not applicable because these components are exposed internally to ambient air, and
 
remain dry during normal plant operation.
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.
 
In a teleconference dated December 5, 2008, the staff had further discussion with the
 
applicant on why cracking due to SCC was not considered to be an AERM for the
 
stainless steel emergency diesel generator exhaust piping surfaces that are exposed
 
internally to diesel exhaust. The applicant clarified that the aging management review
 
methodology identified that the emergency diesel generators are operating only
 
periodically and that the exhaust environment that results from operations of the generators is not a source of contaminants and is dry.
 
In AMR item AP-33 in Table II.A of NUREG-1833, "Technical Bases for Revision to the
 
License Renewal Guidance Documents," the staff provides the following basis on why it
 
is important to identify cracking due to SCC as an AERM for the internal surfaces of
 
stainless steel emergency diesel generator exhaust piping that are exposed to diesel
 
exhaust (i.e. combusted diesel fuel). 
 
"The Staff has accepted the position that the possible stress corrosion cracking
 
of stainless steel diesel engine exhaust piping, piping components, and piping
 
elements is managed by a plant-specif ic aging management program. The FCS SER section 3.3.2.4.3 identifies stainless steel as a material in diesel exhaust
 
gas environment with loss of material and cracking as viable aging effects. GALL
 
Rev. 0 Chapter VIIH.2.4-a only identifies carbon steel and loss of material due to
 
general, pitting, and crevice corrosion of steel diesel engine combustion air
 
exhaust subsystem components that are exposed to hot diesel engine exhaust
 
gases containing moisture and particulates. Similar components constructed of
 
stainless steel were observed to be susceptible to cracking in hot diesel exhaust
 
gas. A plant-specific aging management pr ogram will be evaluated to provide reasonable assurance that the component's intended functions will be
 
maintained within the CLB for the period of extended operation."
 
The diesel exhaust that results from operations of emergency diesel generators is made
 
up mostly of carbon dioxide (CO2) and water (H2O) in the vapor state. However, there
 
may be some amount of liquid state water (moisture) in the exhaust. Diesel exhaust may
 
also contain some contaminants because the oil fractions that make up the diesel fuel
 
prior to combustion may contain small percentages of nitrogen, sulfur or halogen atomic
 
elements impurities. Thus, the staff noted that its basis in NUREG-1833 differed from the
 
applicant's basis because NUREG supports that staff's basis that diesel exhaust could contain enough moisture and particulate containments and that these contaminants lead
 
to cracking in the internal stainless steel emergency diesel generator exhaust piping
 
surfaces that are exposed to the diesel exhaust environment. Thus, based on a 3-328 comparison of the applicant's position against the relative information in NUREG-1833, the staff took the position that the applicant had not taken a conservative position
 
relative to aging management of cracking due to SCC in the internal surfaces of
 
stainless steel emergency diesel generator exhaust piping that are exposed to diesel
 
exhaust. In a teleconference dated January 5, 2009, the staff discussed the applicant's
 
basis for managing cracking in the stainless steel diesel generator exhaust piping, piping
 
components, and piping elements that are exposed to a diesel exhaust environment.
During this teleconference, the applicant stated that it would amend the LRA to identify
 
cracking as an applicable aging effect for the internal stainless steel stainless steel
 
diesel generator exhaust piping, piping component, and piping element surfaces that are
 
exposed to the diesel exhaust environment and that AMP B.2.28, Supplemental Piping and Tanks Inspection Program, will be credited to manage cracking in the internal
 
component surfaces that are exposed to diesel exhaust. 
 
The staff confirmed that the Supplemental Piping and Tanks Inspection Program
 
includes a number of inspection methods, including volumetric (RT or UT) and visual (VT-1 or VT-3 or equivalent) examination techniques that will be performed by qualified
 
personnel on a sample population of subject components. The staff noted that the Subsection IWA-2000 of the ASME Code Section XI lists volumetric and VT-1 visual
 
examination techniques as valid inspection methods for the detection of cracking in metallic components. The staff also noted that GALL AMP XI.M32, "One-Time
 
Inspection," indicates that one-time inspection programs are valid AMPs for cases
 
where: (1) the components may be susceptible to the gradual accumulation or
 
concentration of agents that, if present, could promote certain aging effects, and (2)
 
where additional verification is necessary in order to confirm that degradation is not
 
occurring in the components or is progressing at a very slow propagation rate, or else to
 
trigger additional corrective actions if unacceptable degradation is detected in the
 
components.
 
The staff verified that, in the applicant's letter of January 12, 2009, the applicant made
 
the appropriate changes to the AMRs for the stainless steel emergency diesel exhaust
 
piping to credit the AMP B.2.28, Supplemental Piping and Tanks Inspection Program, for
 
the management of cracking in the internal stainless steel diesel generator exhaust
 
piping, piping component, and piping element surfaces that are exposed to diesel
 
exhaust. The staff also verified that, in the applicant's letter of January 12, 2009, the
 
applicant amended AMP B.2.28 to add these components to the scope of the AMP.
 
Therefore, based on this assessment, the staff finds that the applicant has provided an
 
acceptable basis for crediting the Supplemental Piping and Tanks Inspection Program
 
for aging management of cracking because: (1) the emergency diesel generators are
 
only periodically operated in accordance with plant technical specifications or transient
 
operating procedures, (2) the applicant's basis is consistent with criteria in GALL AMP XI.M32 on when one-time inspection programs can be credited for aging management, and (3) the applicant's Supplemental Piping and Tanks Inspection Program includes
 
volumetric examination methods and VT-1 or enhanced VT-1 visual inspection methods, which are valid techniques for the detection of cracking in the stainless steel
 
components.
 
Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.3.2.2.3
 
criteria. The staff determines that the LRA is consistent with the GALL Report and that the
 
applicant has demonstrated that the effects of aging will be adequately managed so that the
 
intended function(s) will be maintained consistent with the CLB during the period of extended 3-329 operation, as required by 10 CFR 54.21(a)(3).
 
3.3.2.2.4  Cracking Due to Stress Corrosion Cracking and Cyclic Loading 
 
The staff reviewed LRA Section 3.3.2.2.4 against the following criteria in SRP-LR
 
Section 3.3.2.2.4:
 
(1) LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading in stainless steel PWR nonregenerative heat exchanger components exposed to treated borated water greater than 60 C (140 F) in the chemical and volume control system. The applicant stated that this aging effect is not applicable because SSES is a BWR.
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 C (140 F) in the chemical and volume control system. 
 
The staff confirmed in SRP-LR Table 3.3-1, Item 7, is only applicable to PWR plants.
 
Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.3.2.2.4.1
 
does not apply to SSES.
 
(2) LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading in stainless steel PWR regenerative heat exchanger components exposed to treated borated water greater than 60 C (140 F). The applicant stated that this aging effect is not applicable because SSES is a BWR.
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 C (140 F).
The staff confirmed in SRP-LR Table 3.3-1, Item 8, is only applicable to PWR plants.
 
Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.3.2.2.4.2
 
does not apply to SSES.
 
(3) LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading in stainless steel pump casing for the PWR high-pressure pumps in the chemical and volume control
 
system. The applicant stated that this aging effect is not applicable because SSES is a
 
BWR. SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occur
 
in the stainless steel pump casing for the PWR high-pressure pumps in the chemical and
 
volume control system. The existing AMP moni tors 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 staff confirmed in SRP-LR Table 3.3-1, Item 9, is only applicable to PWR plants.
 
Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.3.2.2.4.3 3-330 does not apply to SSES.
 
Based on the above, the staff concludes SRP-LR Section 3.3.2.2.4 criteria are not applicable.
 
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 in components of heating and ventilation systems. The applicant stated that
 
only the elastomers used in flexible connections in the Reactor Building HVAC and the
 
Primary Containment Atmosphere Circulation System were identified as requiring aging
 
management. Levels of ionizing radiation in the Reactor Building and of ionizing
 
radiation and thermal exposure inside Containment exceeded threshold levels for
 
cracking and changes in material properties. Elastomers in HVAC systems in other
 
buildings do not exceed threshold levels for radiation or temperature. The System
 
Walkdown Program is credited for aging management of elastomers in the Reactor
 
Building HVAC and Primary Containment Atmosphere Circulation systems.
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.
 
SRP-LR Section 3.3.2.2.5.1 invokes AMR Item 11 in Table 3 of the GALL Report, Volume 1, and AMR Items VII.F1-7, VII.F2-7, VII.F3-7 and VII.F4-6 in the GALL Report, Volume 2, as applicable to elastomeric seals and components in control room, auxiliary
 
and radwaste, primary containment, and diesel generator building heating and ventilation
 
systems that are exposed either internally or externally to uncontrolled indoor air.
 
The staff reviewed LRA Section 3.3.2.2.5.1 against the staff's recommended regulatory
 
criteria in SRP-LR Section 3.3.2.2.5.1 and the recommendations for these components in
 
GALL AMR Items VII.F1-7, VII.F2-7, VII.F3-7 and VII.F4-6, as applicable to the
 
elastomeric seals and components in the cont rol room, auxiliary and radwaste, primary containment, and diesel generator building HVAC systems that are exposed either internally or externally to uncontrolled indoor air. 
 
The staff noted that the applicant aligned all of its AMR's for the elastomeric auxiliary
 
system seals and components, as given in LRA Tables 3.3.2-7, "Aging Management Review Results - Diesel Generator Buildings HVAC Systems," 3.3.2-9, "Aging
 
Management Review Results - Diesel Generat ors System," 3.3.2-5, "Aging Management Review Results - Control Structure H VAC Systems," 3.3.2-8, "Aging Management Review Results - Diesel Generator Buildings HVAC Systems," 3.3.2-16, "Aging
 
Management Review Results - Primary Contai nment Atmosphere Circulation System,"
"3.3.2-13, "Aging Management Review Results - Fire Protection System," and 3.3.2-23, "Aging Management Review Results - Reactor Building HVAC System," to AMR Item 11 in Table 3 of the GALL Report, Volume 1, but also noted that the applicant was not
 
always consistent in identifying whether hardening or loss of strength were applicable
 
aging effects requiring management (AERMs).
3-331  Specifically, the staff noted that, in the applicant's AMRs for elastomeric components in
 
the reactor building HVAC system and the pr imary containment air processing system that aligned to GALL AMR VII.F3-7, the applicant identified that cracking and changes in
 
material properties were applicable AERMs only for the neoprene rubber or fiberglass
 
flexible connections (expansion joints) in t he reactor building HVAC system exposed to external uncontrolled indoor air and for neoprene expansion joints in the primary
 
containment air processing system expos ed to internal ventilation and external uncontrolled indoor air. For these components the applicant credited its Systems
 
Walkdown Program to managing cracking and changes in material properties. The staff
 
noted that the applicant did not identify cracking and changes in material properties as
 
applicable AERMs for the internal neoprene rubber and fiberglass expansion joint
 
surfaces in the reactor building HVAC sy stem that are exposed to the ventilation environment and this was not consistent with the applicant's aging management
 
approach taken for the analogous internal neoprene component surfaces in the primary
 
containment air processing system. 
 
The staff also noted that the applicant's ventilation and indoor air environment groupings, as given in LRA Tables 3.0-1 or 3.0-2, cover a range of specific environments and
 
environmental conditions. In the applicant's environmental discussions for these
 
groupings, the staff noted insufficient evidence that the ventilation environment and the
 
uncontrolled indoor air environment are equivalent. The applicant's discussion also did
 
not establish the threshold being used for radiologically-induced aging and the maximum
 
radiological levels the components would be exposed to, or whether the temperatures for
 
the specific environments have the potent ial to exceed a thermally-induced aging threshold of 95&deg;F. 
 
The staff noted that the applicant had aligned the table 2 AMR item for the following
 
supplemental HVAC or non-HVAC components to AMR Item 11 in Table 3 of the GALL
 
Report, Volume 1 and either to GALL AMR VII.F1-7, VII.F2-7, VII.F3-7, or VII.F4-6: 
 
(1) silicone rubber heat exchanger tube plugs in the diesel generator intake
 
exhaust systems under exposure to the ventilation environment, 
 
(2) elastomeric (synthetic rubber) flexible connections (hoses) in the diesel
 
generator system, high pressure coolant injection system, and fire protection
 
system under external exposure to uncontrolled indoor air, 
 
(3) neoprene flexible connections in the diesel generator buildings HVAC system
 
that are exposed internally to the vent ilation environment and externally to the uncontrolled indoor air environment, 
 
(4) neoprene/asbestos flexible connections in the diesel generator buildings
 
HVAC system and the control structure H VAC system that are exposed internally to the ventilation environment and externally to the uncontrolled indoor air
 
environment, and 
 
(5) neoprene/fiberglass flexible connections in the diesel generator buildings
 
HVAC system and the control structure HVAC system that is exposed internally to the ventilation environment and externally to the uncontrolled indoor air
 
environment.
3-332  However, in these AMRs, the staff noted that the applicant did not identify any AERMs
 
for the elastomeric/polymeric component surfaces that are exposed either to a ventilation
 
air environment or an uncontrolled indoor air environment, and that in LRA Section
 
3.3.2.2.5.1, the applicant only justified this by stating the temperatures and radiation
 
levels for the elastomers/polymeric materials in these systems "do not exceed threshold
 
levels for radiation or temperature." 
 
Thus, the staff had the following issues with the applicant's AMRs for the elastomeric
 
and polymeric auxiliary system components that the applicant had aligned to AMR Item 11 in Table 3 of the GALL Report, Volume 1 and either to GALL AMR VII.F1-7, VII.F2-7, VII.F3-7, or VII.F4-6:
 
The applicant did not provide sufficient evidence that the environmental conditions between the ventilation environments were equivalent to an
 
uncontrolled, indoor air environment. Thus, for those elastomeric or polymeric
 
components that the applicant had identified as being subject to the aging effects
 
of "cracking" or "changes in material properties," the applicant did not provide
 
sufficient basis why the external visual examinations performed under the
 
Systems Walkdown Program could be used as the basis for managing
 
cracks/subsurface cracks that only break the internal surface or change in
 
material property exposed to the ventilation environment.
For those elastomeric or polymeric components that the applicant had identified as being subject to the aging effect of "changes in material properties," the
 
applicant did not define the specific material properties that could be impacted by
 
exposure to either the ventilation environment or the uncontrolled indoor air
 
environment.
The applicant did not provide a sufficient basis for concluding that there are not any applicable AERMs for the surfaces of the neoprene and fiberglass flexible
 
connections in the reactor building HVAC that are exposed to internal ventilation
 
when cracking and changes in material properties were identified as applicable
 
AERMs for the neoprene expansion joints in the primary containment air
 
processing system exposed to internal ventilation. Also the applicant did not
 
provide the levels of ionizing radiation in the Reactor Building and of ionizing
 
radiation and thermal exposure inside Containment that may have exceeded
 
threshold levels for cracking and changes in material properties.
For those supplemental HVAC or non-HVAC elastomeric or polymeric components that the applicant had aligned to the GALL item, but had not
 
identified any applicable AERMs under exposure to an indoor air or ventilation
 
environment, the applicant did not establish an acceptable basis for concluding
 
that there are not any AERMS for the components. Specifically, the applicant did
 
not establish how high the temperatures and radiation levels could reach under
 
the specific environmental conditions for the subsystems exposed to these environments. Nor did the applicant identify the radiation level threshold for
 
concluding that radiation-induced cracking or material property changes could
 
occur in the polymetric/elastomeric materials used to fabricate these auxiliary
 
system components.
 
3-333 In RAI 3.3.2.2.5.1-1, Part A, by letter dated July 23, 2008, the staff asked the applicant to specify the polymetric/elastomeric material properties that are within the scope of the
 
applicant's aging effect "change in material properties." In RAI 3.3.2.2.5.1-1, Part B, by
 
the same letter, the staff asked the applicant to justify, using a valid technical basis, why
 
cracking and changes in material properties was not identified as an applicable aging
 
effect requiring management (AERM) for the neoprene or fiberglass flexible connection (expansion joint) surfaces in the reacto r building HVAC system that are exposed internally to the ventilation environment when these aging effects had been identified as
 
AERMs for the neoprene expansion joint surfaces in the primary containment air
 
processing system that are exposed inte rnally to the ventilation system. 
 
In its letter dated August 27, 2008, in response to RAI 3.3.2.2.5.1-1 Part A, the applicant
 
stated that the specific material properties that could be impacted by exposure to either
 
the ventilation or uncontrolled indoor air env ironment are hardening (e.g., embrittlement, decrease in elasticity) and loss of strength (e.g., elongation, loss of tensile strength, and, with exposure to ionizing radiation, swelling or melting). The applicant also stated that
 
both types of material property changes could occur as a result of prolonged exposure to
 
high temperature (95 o F or higher), high radiation levels (equal to or greater than 10E6 rads total integrated dose (TID)), or to ultraviolet radiation or ozone.
 
In response to RAI 3.3.2.2.5.1-1 Part B, the applicant provided rationale for not
 
identifying aging effects requiring management for neoprene or fiberglass flexible
 
connections in the Reactor Building HVAC system. The applicant provided a summary of the stressors in the Reactor Building where these flexible connections are located. The
 
applicant further stated that:
 
There are no sources of ionizing radiation within the ventilation environment of the Reactor Building HVAC system that could cause the radiation levels to
 
exceed the threshold level of 10E6 rads TID,  There are no additional heat sources within the ventilation environment of the Reactor Building HVAC system that could contribute to prolonged thermal
 
exposure to a temperature of 95 o F or higher,  The ventilation environment of the Reacto r Building HVAC system contains no sources of ultraviolet radiation or ozone.
 
Therefore, the applicant concluded that for neoprene components in the Reactor Building
 
HVAC system there are no aging effects requiring management.
 
The staff reviewed the applicant response to RAI 3.3.2.2.5-1, Parts A and B and finds the
 
applicant response acceptable because (1) the applicant adequately defined the specific
 
material properties that could be affected by exposure to ventilation atmosphere, and (2)
 
the applicant identified the location where these flexible connections are located in the
 
Reactor Building and defined the stressors that could cause the aging effects in
 
neoprene flexible connections at those locations. The applicant response is consistent with the GALL Report definitions of neoprene material in Section IX and the threshold limits of the stressors as recommended in the GALL Report Section IX. On the basis of
 
its review, the staff finds that neoprene flexible hoses in the Reactor Building HVAC
 
system will not experience the aging effects of cracking and change in material
 
properties in a ventilation environment.
3-334  In RAI 3.3.2.2.5.1-2, Part A, by letter dated July 23, 2008, the staff asked to applicant to
 
clarify, using a valid technical basis, why the environmental conditions for an internal
 
ventilation environment is considered to be equivalent to the environmental conditions that are applicable to an external uncontrolled indoor air environment. In RAI 3.3.2.2.5.1-
 
2, Part B the staff asked the applicant, for each environment that is within the scope the "ventilation" environmental grouping or "i ndoor air/protected from weather" environmental grouping in the LRA, to identify and justify the basis the radiological-
 
induced (gamma ray) aging threshold and threshold that is used to screen 
 
polymer/elastomer components in thes e environments for age related degradation (including cracking, hardening, loss of strength, or other material property changes), and
 
to identify what the maximum-to-minimum temperature ranges and maximum gamma
 
radiation levels are for these specific environments.
 
In its letter dated August 27, 2008, in response to RAI 3.3.2.2.5.1-2, the applicant stated
 
the following for Part A:
 
As described in LRA Table 3.0-1, internal ambient environments found inside
 
components, such as piping and tanks that are either vented or otherwise open to
 
the ambient conditions in their location, are also included in the "ventilation" environment grouping. It is reasonable to assume that, for such components, the
 
relevant conditions that can lead to aging, such as temperature and moisture, are
 
the same both inside and outside the component. In these cases, the condition of
 
the external surface is expected to be representative of the internal surface
 
condition. 
 
Also included in the "ventilation" environment grouping is ambient air that may be
 
conditioned by filtering, heating, cooling, or dehumidification, or some combination
 
thereof, in order to maintain a suitable environment for equipment operation or
 
personnel occupancy. For components exposed internally to this environment, it is reasonable to assume that the relevant conditions that can lead to aging are
 
generally less aggressive, or at least no more aggressive, than the ambient air to
 
which the same components are exposed externally. In these cases, aging of the
 
external surfaces is expected to progress at a faster rate than aging of the internal
 
surfaces.
 
In both of these cases, the System Walkdown Program, which is consistent with the GALL AMP XI.M36 External Surfaces Monitoring, may be credited with aging
 
management.
 
In response to Part B, the applicant stated that ionizing radiation, temperatures, and
 
exposure to ultraviolet radiation and ozone were all within the threshold limits as
 
recommended in the GALL Report. The applicant provided a table identifying the
 
minimum and maximum normal operating temperature and the maximum total integrated
 
dose for specific buildings/ areas within the plant and within the scope of license
 
renewal. The applicant stated that the maximum temperature in each building represents
 
a hot spot or a design consideration for HVAC, and the temperature is not expected to
 
equal or exceed 95 o F for a prolonged period of time.
 
The staff reviewed the applicant response for RAI 3.3.2.2.5.1-2, Part A and finds that the
 
applicant has provided an adequate technical basis to conclude that the internal 3-335 ventilation environments are considered equivalent to or less aggressive than the external uncontrolled indoor-air environment. Ther efore, the staff finds that the System Walkdown Program, which manages the aging effects of the external surfaces of the
 
piping can also be credited for the internal surfaces on the basis that these two
 
environments are similar. The staff reviewed the applicant response for RAI 3.3.2.2.5.1-
 
2, Part B and finds that the applicant has appropriately identified the temperatures and
 
total integrated dose levels in the various structures that are within the scope of license
 
renewal. The applicant response is consistent with the GALL Report definition of the threshold limits of the stressors as recommended in the GALL Report Section IX. On this
 
basis, the staff finds the applicant response adequate.
 
In RAI B.2.32-4, the staff asked the applicant to justify its basis for crediting the System
 
Walkdown Program to manage cracking and changes in material properties that may
 
occur in the internal surfaces of in-scope components that are fabricated from either an
 
elastomeric or polymeric material. The staff also asked the applicant to clarify how visual
 
examinations alone from the external surfaces of these materials would be capable of
 
detecting the following aging effects: (1) a tightly configured crack that penetrates the
 
external surface of the component, (2) a subsurface crack or a crack that only penetrates
 
the internal surface of the materials, and (3) a change in a material property, such as a
 
potential change in the hardness property or strength property for the elastomer or
 
polymer material used to fabricate the component. RAI B.2.32-4 is relevant to the
 
acceptance of the applicant's AMR basis for neoprene and fiberglass flexible connection (expansion joint) surfaces in the reactor building HVAC system and primary containment air processing system that are exposed inte rnally to the ventilation environment or externally to the uncontrolled indoor air environment. The staff's acceptance of the
 
System Walkdown Program to manage the aging effects of cracking and change of
 
material properties for elastomers and the discussion of RAI B.2.32-4 are documented in
 
SER Section 3.0.3.2.14. Based on this review, the staff concludes that the System
 
Walkdown Program will adequately manage the aging effects of cracking and change in
 
material properties of neoprene flexible hoses during the period of extended operation. 
 
In RAI 3.3.2.2.5.1-3, Part A, and RAI 3.3.2.3-1 by letter dated July 23, 2008, the staff
 
asked the applicant to provide its basis why there are not any applicable AERMs
 
identified for the following component/material/environmental combinations: 
 
(1) silicone rubber heat exchanger tube plugs in the diesel generator intake exhaust systems under exposure to the ventilation environment, 
 
(2) elastomeric (synthetic rubber) flexible connections (hoses) in the diesel generator system and fire protection system under external exposure to uncontrolled indoor air, 
 
(3) neoprene flexible connections in the diesel generator buildings HVAC system that are exposed internally to the vent ilation environment and externally to the uncontrolled indoor air environment, 
 
(4) neoprene/asbestos flexible connections in the diesel generator buildings HVAC system and the control struct ure HVAC system that are exposed internally to the ventilation environm ent and externally to the uncontrolled indoor air environment, and 
 
3-336 (5) neoprene/fiberglass flexible connections in the diesel generator buildings HVAC system and the control struct ure HVAC system that is exposed internally to the ventilation environm ent and externally to the uncontrolled indoor air environment.
 
In RAI 3.3.2.2.5.1-2, Part B, the staff asked the applicant to identify what its thermally-
 
induced and radiologically-induced thresholds are for concluding that thermally-induced
 
and radiologically-induced cracking and changes in material properties could occur for
 
the component/material/environmental combinations discussed in Part A of the questions
 
and what the maximum temperature and radiation levels will be for the specific
 
ventilation and/or indoor air environments that the system components are exposed to. 
 
In its letter dated August 27, 2008, in response to RAI 3.3.2.2.5.1-3, Parts A and B, and
 
RAI 3.3.2.3-1, the applicant provided a listing of the structures in which the above
 
identified component/material/environment combinations is located. In all those
 
locations, the applicant indicated that threshold limits for ionizing radiation, temperature, ultraviolet radiation and ozone levels will not be exceeded.
 
On the basis that the recommended threshold levels of the GALL Report will not be
 
exceeded, the staff concludes that the identified component/material/environment combinations will not have any aging effects requiring management.
 
(2) LRA Section 3.3.2.2.5 addresses hardening and loss of strength due to elastomer degradation in spent fuel cooling and cleanup systems. The applicant stated that this
 
aging effect is not applicable because elastomer linings do not perform an intended
 
function.
SRP-LR Section 3.3.2.2.5 states that hardening and loss of strength due to elastomer
 
degradation may occur in elastomer linings of the filters, valves, and ion exchangers in
 
spent fuel pool cooling and cleanup systems (BWR and PWR) exposed to treated water
 
or treated borated water. The GALL Report recommends that a plant-specific AMP be
 
evaluated to determine and assess the qualified life of the linings in the environment to
 
ensure that these aging effects are adequately managed.
 
For BWR designs, SRP-LR Section 3.3.2.2.5.2 invokes AMR Item 12 in Table 3 of the
 
GALL Report, Volume 1, and AMR Item VII.A4-1 in the GALL Report, Volume 2, as
 
applicable to elastomeric liners in BWR spent fuel cooling and cleanup systems that are
 
exposed internally to the treated water environment of the spent fuel pool coolant
 
The staff verified that the applicant does not credit any elastomeric liners in the SSES
 
fuel pool, fuel pool and cleanup system, or fuel pool auxiliaries for aging management.
 
However, the staff noted that the applicant did align one other auxiliary system AMR for
 
elastomeric components to the staff's AMR recommendations in AMR Item 12 in Table 3
 
of the GALL Report, Volume 1, and GALL AMR Item VII.A4-1. In this AMR, the applicant
 
identified that the silicone rubber heat exchanger tube plugs in diesel generator intake
 
and exhaust systems are exposed internally to a treated water environment and are within the scope of an AMR. In this AMR, the applicant stated that there are not any
 
applicable aging effects requiring management (AERMs) for the internal tube plug
 
surfaces that are exposed to a treated water environment. The staff noted that the
 
applicant did not provide any basis for concluding that there are not any applicable
 
AERMs for the tube plug surfaces that are exposed the treated water environment. The 3-337 staff noted that, in contrast to the applicant's determination, GALL AMR VII.A4-1 identifies that elastomeric materials may degrade (i.e., harden or lose strength) under
 
exposure to treated water. 
 
In RAI 3.3.2.2.5.2-1, by letter dated July 23, 2008, the staff asked the applicant to justify
 
its basis for concluding that the silicone tube plugs in the diesel generator intake/exhaust
 
system heat exchangers would not degrade (i.e., harden or lose strength) for the tube
 
plug surfaces that are exposed to the treated water environment. 
 
In its letter dated August 27, 2008, in response to RAI 3.3.2.2.5.2-1, the applicant stated
 
that change in material properties and cracking of elastomers, such as silicone, may be
 
due to ionizing radiation, thermal exposure, or exposure to ultrasonic radiation or ozone.
 
The applicant further stated that:
 
The silicone tube plugs are located in the Diesel Generator Buildings, where the total integrated dose is well below 10E6rads. Also, during
 
normal plant operation, the silicone tube plugs are exposed to a treated
 
water environment that is not expected to contain or to release any
 
measurable ionizing radiation.
To ensure proper diesel generator operation, Diesel Generator Rooms A, B, C and D are individually ventilated and heated to maintain a
 
temperature in the range of approximately 85&deg;F to 95&deg;F. Also, during
 
normal plant operation, the diesel generators are in a standby mode, so
 
the silicone tube plugs are exposed to a treated water temperature that is
 
expected to be approximately the same as the ambient air temperature.
The tube plugs are fabricated of silicone rather than natural rubber, and silicone has been demonstrated to have excellent resistance to ultraviolet
 
radiation and ozone. The treated water environment associated with the
 
Diesel Generator intake/exhaust system contains no sources of ultraviolet radiation or ozone.
Therefore, the applicant stated that change in material properties and cracking is not an
 
aging effect requiring management because none of these stressors exceed their
 
threshold limits.
 
The staff reviewed the applicant response to RAI 3.3.2.2.5.2-1, and finds the applicant
 
response acceptable because (the applicant identified the location where these silicone
 
tube plugs are located in the Diesel Generator Building and defined the stressors that
 
could cause the aging effects at those locations. Although these silicone plugs are in a
 
treated water environment, the staff noted that the stressors that could cause aging
 
degradation in the diesel generator system and in the diesel generator building are not
 
the same as in the spent fuel pool and cleanup system where a higher radiation level
 
and temperatures could be experienced. The staff finds that the applicant's response
 
provides an acceptable basis for concluding that cracking and changes in material
 
properties are not applicable aging effects for these components because: (1) the
 
environmental conditions are at temperatures less than or equal to 95&deg;F and do not include sources of radiation or ozone, (2) this is consistent with the GALL Table IX.C that
 
cracking and changes in material properties are only applicable aging effect if the 3-338 component operating termperatures are greater than 95&deg;F, or if they are exposed to radiation or ozone.
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 determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.3.2.2.6  Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General
 
Corrosion 
 
The staff reviewed LRA Section 3.3.2.2.6 against the criteria in SRP-LR Section 3.3.2.2.6.
 
LRA Section 3.3.2.2.6 addresses reduction of neutron-absorbing capacity and loss of material
 
due to general corrosion. The applicant stated that these aging effects are not applicable
 
because Boral, the neutron-absorbing medium, does not degrade as a result of long-term
 
exposure to radiation, and Boral is stable, durable, and corrosion resistant.
 
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.
 
During its review the staff noted the referenced GALL Report Item VII.A2-3 lists the aging
 
effects as reduction of neutron absorbing capacity and loss of material due general corrosion. 
 
However the AMR result line item in LRA Table 3.5.2-2 used a footnote E for the MEAP
 
combination of boral, treated water, loss of material and BWR Water Chemistry Program. Also
 
during its review, the staff found industry operating experience of aluminum cations being found
 
in the spent fuel pool water that could potentially be from the aluminum poison cans or from the Boral material made from aluminum-boron carb ide composite. By letter dated June 13, 2008 the staff sent RAI 3.3.2.2.6-1 to ask the applicant whether plant-specific operating experience
 
exists at SSES in which aluminum cations were found in the spent fuel pool water and to explain
 
the source of the aluminum. The staff further asked the applicant to justify the basis for not
 
crediting a one-time inspection to determine the effectiveness of the BWR Water Chemistry
 
Program in managing these aging effects. 
 
By letter dated July 24, 2008, the applicant stated in its response letter that SSES does not
 
have plant-specific operating experience with respect to the presence of aluminum cations in
 
the spent fuel pool. The staff noted that the industry operating experience related to the
 
galvanic corrosion between the stainless steel enclosure and the aluminum clad is applicable to
 
PWR's because of the presence of boric acid in the spent fuel pool water which supports this
 
type of corrosion. SSES is a BWR plant that does not contain boric acid in the spent fuel pool
 
and utilizes Boral plates which are contained in sealed tubes manufactured under an accepted
 
Quality Assurance Program, which would prevent the spent fuel pool water from making contact
 
with the Boral material. The applicant also provided plant-specific results from the Boral sample
 
coupons, in which half of the coupons were non-vented to simulate the expected conditions of
 
the spent fuel pool in which water was not in contact with the Boral and the other half of the
 
coupons were vented in simulate the conditions if the Boral was in contact with the spent fuel 3-339 pool water. The applicant stated the results of the Boral coupons that were non-vented have not shown signs of blistering, pitting corrosion or loss of neutron-absorbing capacity and the
 
results of the vented Boral coupons have shown some blistering on the edges but neutron
 
attenuation testing has shown the Boral has retained its design properties for neutron
 
attenuation. On the basis of its review, the staff finds the applicant's response acceptable
 
because the applicant has not found aluminum cations in the spent fuel pool water and the
 
applicant has test results from Boral sample coupons that are representative of the poison cans
 
in the spent fuel pool which have shown that there has not been a loss of neutron absorbing
 
capacity.
 
The staff noted that the applicant's proposed AMP for managing loss of material due to pitting
 
and crevice corrosion is the BWR Water Chemistry Program, alone, without a confirmatory
 
inspection program. Because the applicant had not provided sufficient justification to explain
 
how the BWR Water Chemistry Program, al one, will provide adequate management for the potential aging effect of loss of material due to pitting or crevice corrosion, the staff issued RAI
 
3.3-1 by letter July 15, 2008. The RAI asks the applicant to justify why an inspection program, such as the Chemistry Program Effectiveness Inspection is not needed to confirm that age
 
related degradation of the components is not occurring.
 
In a letter dated August 15, 2008, the applicant responded to RAI 3.3-1 by providing a response
 
to the RAI, citing both industry and plant-specific data. Excerpts from that response are
 
repeated below:
 
The technical justification of the Boral neutron-absorbing capability aging assessment is
 
based on plant-specific and industry operating experience. Loss of material of aluminum
 
in treated water due to general corrosion is not an aging effect requiring management
 
consistent with the GALL (e.g., VII.A4-5), but loss of material due to crevice and pitting
 
corrosion is an aging effect requiring management and is managed by the BWR Water
 
Chemistry Program-Industry Experience:
 
Potential aging effects resulting from sustained irradiation of Boral have been previously
 
evaluated by the staff in NUREG-1787, Safety Evaluation Report Related to the License
 
Renewal of the Virgil C. Summer Nuclear Station (VCSNS). NUREG-1787 states, "- the
 
applicant asserts that Boral does not degrade as a result of long-term exposure to
 
radiation, and there are no aging effects applicable to Boral neutron-absorbing sheets in
 
the spent fuel storage racks of VCSNS. The potential aging effects resulting from
 
sustained irradiation of Boral were previously evaluated by the staff (BNLNUREG-25582, dated January 1979) and determined to be insignificant. Therefore the staff finds the
 
applicant's AMR conclusions to be acceptable."
A search of industry experience (INPO EPIX database) revealed the same conclusion
 
that no instances of reduction of Boral neutron-absorbing capability have been
 
experienced by other nuclear plants.
SSES Plant-Specific Operating Experience:
 
Half of the SSES Boral sample coupons are non-vented, simulating the expected
 
condition at the racks. These have not shown any blistering, pitting corrosion or loss of
 
neutron-absorbing capability. The other half of the SSES Boral coupons are vented, 3-340 simulating a portion of the fuel rack having a bad weld, allowing water into the area with the Boral plates. These vented samples have shown blistering near the edges of the
 
plate due to the porous nature of the cut edge of the plate, where water interacts with the
 
Boron matrix and radiation to generate gases that blister the plate. This effect has, in
 
some cases, caused the outer metal layer of the Boral plate (sample) to blister out and
 
press flat against the outer tube that contains it. This contact in a demineralized water
 
environment has shown no signs of galvanic or other corrosion. Neutron attenuation
 
testing has shown that these plates still retain the required design properties for neutron
 
attenuation. Weighing of the samples has shown no loss of material, although some
 
minor gains in weight (post drying) may be related to the water intrusion/interaction with
 
decay products.
 
The most recent Boral coupon tests (year 20 coupon test) for Units 1 and 2 were
 
performed by independent testing facilities in 2003 and 2005, respectively. The range of
 
water chemistry conditions to which the Boral coupons were subjected are within the fuel
 
pool chemistry specification limits as delineated in the Susquehanna Chemistry Manual.
 
Boral sample coupons are removed from the fuel pool periodically for testing and are evaluated
 
for corrosion or other degradation of the neutron absorber by comparing various physical
 
characteristics. Additional Boral coupons are scheduled to be removed from the spent fuel
 
storage pool and analyzed at years 30 and 40 under a current licensing commitment per
 
UFSAR Section 9.1.2.3.3. The scheduled Boral sample coupon testing is a verification of
 
effectiveness of the credited BWR Water Chemistry program.
 
Based on SSES plant-specific experience of Boral coupon inspections and testing, the loss of
 
material aging effect has been and will continue to be adequately managed by the BWR Water
 
Chemistry Program.
 
The staff reviewed the applicant's response, including the current licensing commitment for
 
inservice inspection of plant-specific Boral coupons, as described in the applicant's UFSAR.
 
The staff notes that both industry and current plant-specific operating experience show that
 
aging effects do not occur or progress very slowly for Boral neutron-absorbing sheets exposed
 
to treated water in a spent fuel pool; and, in addition, the applicant's current licensing
 
commitment for continued Boral coupon testing at 30 and 40 years provides on-going
 
confirmation of effectiveness of the applicant's BWR Water Chemistry Program in controlling the
 
potential aging effects of loss of material due to pitting or crevice corrosion in Boral neutron
 
absorbing sheets exposed to treated water in the spent fuel pool. 
 
The staff reviewed the BWR Water Chemistry Program which will control the quality of the spent
 
fuel pool water to prevent the loss of material of the aluminum cladding and boron-carbide
 
materials within. The staff evaluated the BWR Water Chemistry Program, and the evaluation is
 
documented in SER Section 3.0.3.1.1. On the basis that the applicant has demonstrated with
 
both industry and plant-specific experience that aging effects do not occur or progress very
 
slowly in a treated water environment and the applicant's current licensing commitment for
 
continued Boral coupon testing provides confirmation of the effectiveness of the BWR Water
 
Chemistry Program, the staff finds crediting of the BWR Water Chemistry Program, alone, for
 
managing the aging effects of Boral neutron-absorbing sheets exposed to treated water in the
 
spent fuel pool to be acceptable.
 
Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.3.2.2.6
 
criteria. The staff determines that the LRA is consistent with the GALL Report and that the 3-341 applicant 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 in the reactor coolant pump oil collection system. The applicant stated that this
 
aging effect is not applicable because the SSES primary containment is inerted during
 
normal operation, which meets the requirements of item III.O in 10 CFR Part 50
 
Appendix R.
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 reacto r coolant pump oil collection system, exposed to lubricating oil (as part of the fire pr otection 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 verified that only piping, piping components and elements that align to GALL
 
AMR VII.F1-19 and VII.H2-20 for the Fire Protection, Reactor Building Chilled Water, Control Structure Chilled Water and Diesel Generator Lubricating Oil and NSAS
 
Component Systems that are fabricated from steel materials are applicable to SSES. 
 
The staff evaluated the Lubricating Oil Analysis Program and the Lubricating Oil
 
Inspection Program, and the evaluations are documented in SER Sections 3.0.3.2.15
 
and 3.0.3.2.13 respectively. The staff reviewed the applicant's Lubricating Oil Analysis
 
Program and determined that this program includes periodic sampling and analysis of
 
lubricating oil to maintain contaminants within acceptable limits. The staff finds that
 
these activities are consistent with the recommendations in the GALL Report and are
 
adequate to manage loss of material due to general, pitting and crevice corrosion for
 
steel piping, piping components and elements exposed to lubricating oil internally or
 
externally. The staff verified that the applicant has credited its Lubricating Oil Inspection
 
Program to verify the effectiveness of t he Lubricating Oil Analysis Program to manage 3-342 this aging effect. The applicant's AMPS are consistent with those recommended for aging management in SRP-LR Section 3.3.2.2.7, Item #1 and in GALL AMR Items
 
VII.F1-19 and VII.H2-20.
 
Based on the program identified above, the staff concludes that the applicant's program
 
meet SRP-LR 3.3.2.2.7 Item #1 criteria and therefore the applicant's AMRs are
 
consistent with those under GALL Report Item VII.F1-19 and VII.H2-20. For those line
 
items that apply to LRA Section 3.3.2.2.7 Item #1, the staff determines that the LRA is
 
consistent with the GALL Report and that the applicant has demonstrated that the
 
effects of aging will be adequately managed so that the intended function(s) will be
 
maintained consistent with the CLB during the period of extended operation, as required
 
by 10 CFR 54.21(a)(3).
 
LRA Section 3.3.2.2.7, item #1 states that item numbers 3.3.1-15 and 3.3.1-16 of LRA
 
Table 3.3.1 are not applicable to SSES, which align to the GALL Report Items VII.G-26
 
and VII.G-27. The staff noted that SSES is of BWR design and contains a primary
 
containment that is inerted during normal operation, thus SSES meets the requirements
 
of 10 CFR Part 50 Appendix R Section III.O, and is not required to have an oil collection
 
system for the reactor coolant pump by the rule. The staff confirmed that since SSES is
 
a BWR with an inert primary containment atmosphere, it has no reactor coolant pump oil
 
collection system. Therefore, aging of the piping, tubing, valves bodies, and tanks in the
 
reactor coolant pump oil collection system are not applicable for SSES. Thus, the staff
 
finds the applicant's conclusion that the aging effect loss of material due to general, pitting and crevice corrosion is not applicable to SSES, acceptable because SSES does
 
not have a reactor coolant pump oil colle ction system and GALL Items VII.G-26 and VII.G-27 do not apply. 
 
(2) LRA Section 3.3.2.2.7 addresses loss of material due to general, pitting, and crevice corrosion in the BWR reactor water cleanup and shutdown cooling systems. The
 
applicant stated that loss of material due to general, pitting, and crevice corrosion for
 
steel piping components exposed to treated water is managed by the BWR Water
 
Chemistry Program. The BWR Water Chemistry Program manages aging effects
 
through periodic monitoring and control of contaminants. The Chemistry Program
 
Effectiveness Inspection will provide a verification of the effectiveness of the BWR Water
 
Chemistry Program to manage loss of material due to general, pitting, and crevice
 
corrosion through examination of steel piping components.
SRP-LR Section 3.3.2.2.7 states that loss of material due to general, pitting, and crevice
 
corrosion may occur in steel piping, piping components, and piping elements in the BWR
 
reactor water cleanup and shutdown cooling systems exposed to treated water. The
 
existing AMP monitors and controls reactor water chemistry to manage the aging effects
 
of loss of material from general, pitting, and crevice corrosion. However, high
 
concentrations of impurities in crevices and with stagnant flow conditions may cause
 
general, pitting, or crevice corrosion; therefore, the effectiveness of the chemistry control
 
program should be verified to ensure that corrosion does not occur. The GALL Report
 
recommends further evaluation of programs to manage loss of material from general, pitting, and crevice corrosion to verify the effectiveness of the water chemistry program.
 
A one-time inspection of 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.
 
3-343 The staff noted that in addition to applying this AMR result for reactor water cleanup system components, the applicant also applied this AMR result for carbon steel piping
 
and valve bodies exposed to treated water in the fuel pool cooling and cleanup system
 
and fuel pools and auxiliaries (LRA Table 3.3.2-14, pages 3.3-253 and 3.3-357), for
 
carbon steel piping components exposed to treated water in the process and area
 
radiation monitoring system (LRA Table 3.3.2-17, page 3.3-269), for carbon steel
 
accumulators, piping, valve bodies, and piping and piping components exposed to
 
treated water in the control rod drive hydr aulics system (LRA Table 3.3.2-3, pages 3.3-102, 3.3-105, 3.3-107, and 3.3-108), and for carbon steel accumulators exposed to
 
treated water in the standby liquid control system (LRA Table 3.3.2 31, page 3.3-339).
 
For all of these AMR result lines, the applicant proposed to manage the aging effect of
 
loss of material for carbon steel components in a treated water environment with a
 
combination of the BWR Water Chemistry Program and the Chemistry Program
 
Effectiveness Inspection.
 
The staff reviewed the applicant's BWR Water Chemistry Program. The staff's
 
evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that the
 
BWR Water Chemistry Program provides mitigation for the aging effect of loss of
 
material due to general, pitting, and crevice corrosion. The staff reviewed the applicant's
 
Chemistry Program Effectiveness Inspection.
The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the Chemistry Program
 
Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "One-Time Inspection." The Chemistry
 
Program Effectiveness Inspection includes provisions for inspecting selected
 
components in areas of low or stagnant flow and is capable of detecting loss of material
 
due to general, pitting and crevice corrosion, if it should occur in the selected
 
components. Because the BWR Water Chemistry Program provides mitigation and the
 
Chemistry Program Effectiveness Inspection prov ides detection of the aging effect if it should occur, the staff finds the applicant's proposed AMPs for managing the aging
 
effect of loss of material due to general, pitting, and crevice corrosion for carbon steel
 
components exposed to treated water in the reactor water cleanup system, the fuel pool
 
cooling and cleanup system and fuel pools and auxiliaries, the process and area
 
radiation monitoring system, the control rod drive hydraulics system, and the standby liquid control system to be acceptable.
 
(3) LRA Section 3.3.2.2.7 addresses loss of material due to general, pitting, and crevice corrosion in diesel exhaust piping, piping components, and piping elements. The
 
applicant stated that loss of material due to general corrosion for steel piping
 
components exposed to diesel exhaust is managed by the System Walkdown Program.
Loss of material due to corrosion was not identified as an applicable aging effect for the
 
stainless steel diesel exhaust piping flexible connections and tubing which are located
 
inside the diesel generator buildings. The dies el exhaust system is normally in standby mode and the inside surfaces of the components are dry and not subject to any type of
 
wetting. 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.
 
3-344 SRP-LR Section 3.3.2.2.7.3 references AMR item 18 in Table 3 of the GALL Report, Volume 1 and AMR item VII.H2-2 in Table VII.H2 of the GALL Report, Volume 2 as the
 
applicable AMRs for evaluating loss of material due to general, pitting, and crevice
 
corrosion in steel and stainless steel diesel generator piping, piping components, and
 
piping elements that are exposed to a diesel exhaust environment. The aging
 
management guidance in these AMRs for diesel generator exhaust piping is consistent
 
with that given SRP-LR Section 3.3.2.2.7.3.
 
The staff noted that the applicant's AMR items on loss of material in emergency diesel
 
generator exhaust piping components are giv en in AMR item 3.1.1-18 of LRA Table 3.3.1 and in the AMR items in LRA Table 3.3.2-9, "Aging Management Review Results -
 
Diesel Generators System," that are hav e reference links LRA AMR item 3.1.1-18 The staff confirmed that LRA Table 3.3.2-9 did include AMRs for the managing loss of
 
material due to general, pitting, and crevice corrosion in internal steel emergency diesel
 
generator piping, piping components, and piping elements surfaces that are exposed to
 
a ventilation environment and that these AMRs were referenced to GALL AMR VII.H2-2.
The staff also confirmed that in these AMRs, the applicant credited AMP B.2.32, Systems Walkdown Program, to manage loss of material in the internal steel diesel
 
generator exhaust piping, piping components, and piping element surfaces that are
 
exposed to a ventilation (in this case diesel exhaust) environment. 
 
The staff noted that its Systems Walkdown Program, the applicant identifies that the
 
AMP is consistent the staff's recommended program elements in GALL AMP XI.M36, "External Surfaces Monitoring Program," which is a program that is credited only for
 
managing loss of material that occurs in external metal component surfaces, or for aging
 
management of their external paint or coating surfaces in the components are painted or
 
coating with plastic coatings. The staff also noted that the "scope of program" program element in GALL AMP XI.M36 states the a program corresponding to the GALL AMP XI.M36 may only be used to internal component surfaces if the "material and
 
environment combinations are the same for internal and external surfaces such that
 
external surface condition is representative of internal surface condition."
 
The staff noted that, in LRA Table 3.0-1 of the application, the applicant equates the
 
emergency diesel generator exhaust environment to be the equivalent of the applicant's
 
"ventilation environment" for the application, which is defined by the applicant as follows:
 
Ventilation air and compressed air and gases. Ventilation air is defined as
 
ambient air that is conditioned to maintain a suitable environment for equipment
 
operation or personnel occupancy. Ventilation air may be conditioned by filtering, heating, cooling, dehumidification or some combination.
 
Internal ambient environments found inside components such as piping and tanks
 
that are either vented or otherwise open to the ambient conditions in their location
 
are also included under this environment, as are exhaust gases, such as from a
 
diesel engine.
 
While ventilation is predominantly an inter nal environment, the external surfaces of mechanical components may be exposed to ventilation (e.g., cooling unit tubes in HVAC systems).
 
Comparable GALL environments: Air - Indoor Uncontrolled, Air - Outdoor, 3-345 Condensation, Diesel Exhaust
 
The diesel exhaust that results from operations of emergency diesel generators is made
 
up mostly of carbon dioxide (CO2) and water (H2O) in the vapor state. However, there
 
may be some amount of liquid state water (moisture) in the exhaust. Diesel exhaust may
 
also contain some contaminants because the oil fractions that make up the diesel fuel
 
prior to its combustion may contain small percentages of nitrogen, sulfur or halogen
 
atomic elements impurities. These type of env ironmental conditions are reflected in the staff's environmental description in GALL Table IX.D for diesel exhaust, which states
 
that diesel exhaust contains "gases, fluids, and particulates." The staff took issue with
 
equating the diesel exhaust environment to t he indoor ventilation environment that would be on the outside of these piping, piping components, and piping elements because the
 
diesel exhaust could contain significant levels of moisture and contaminants that are not
 
normally present in the indoor ventilation air. Thus, the staff was of the opinion that the
 
applicant was not justified in crediting the System Walkdown Program for managing loss
 
of material the internal emergency diesel generator piping, piping component, and piping
 
element surfaces that are exposed to diesel exhaust because the diesel exhaust could
 
contain create more harsh conditions than would the normal ventilated air inside of the
 
diesel generators rooms. 
 
In a teleconference dated January 5, 2009, the staff discussed the applicant's basis for
 
managing loss of material in the steel stainless steel diesel generator exhaust piping, piping components, and piping elements that are exposed to a diesel exhaust
 
environment. During this teleconference, the applicant stated that it will amend the LRA
 
to identify loss of material as an applicable aging effect for the internal steel and
 
stainless steel diesel generator exhaust piping, piping component, and piping element
 
surfaces that are exposed to the diesel exhaust environment and to credit a one-time
 
examination of the internal components surfac es using the examinations techniques of the AMP B.2.28, Supplemental Piping and Tanks Inspection Program for aging
 
management of this aging effect. 
 
The staff confirmed that the applicant's Supplemental Piping and Tanks Inspection
 
Program is a one-time inspection program for miscellaneous plant piping and tank
 
components and that the AMP credits a combination of established volumetric (RT or
 
UT) and visual (VT-1 or VT-3 or equivalent) examination techniques performed by
 
qualified personnel on a sample population of subject components. The staff noted that the Subsection IWA-2000 of the ASME Code Section XI lists volumetric and VT-1 visual
 
examination techniques as valid inspection methods for the detection of cracking in metallic components. The staff also noted that GALL AMP XI.M32, "One-Time
 
Inspection," indicates that one-time inspection programs are valid AMPs for cases
 
where: (1) the components may be susceptible to the gradual accumulation or
 
concentration of agents that, if present, could promote certain aging effects, and (2)
 
where additional verification is necessary in order to confirm that degradation is not
 
occurring in the components or is progressing at a very slow propagation rate, or else to
 
trigger additional corrective actions if unacceptable degradation is detected in the
 
components.
 
The staff verified that, in the applicant's letter of January 12, 2008, the applicant made
 
the appropriate changes to the AMRs for the steel stainless steel emergency diesel
 
exhaust piping, piping components, and piping elements to credit the AMP B.2.28, Supplemental Piping and Tanks Inspection Program, to manage loss of material in the 3-346 internal steel and stainless steel diesel generator exhaust piping, piping component, and piping element surfaces that are exposed to diesel exhaust. The staff also verified that, in the applicant's letter of January 12, 2008, the applicant made amended AMP B.2.28 to
 
add the diesel exhaust piping to the scope of the AMP. Therefore, based on this
 
assessment, the staff finds that the applicant has provided an acceptable basis for
 
crediting the Supplemental Piping and Tanks Inspection Program for aging management
 
of loss of material in these components because: (1) the emergency diesel generators
 
are only periodically operated in accordance with plant technical specifications or
 
transient operating procedures, (2) the applicant's basis is consistent with criteria in GALL AMP XI.M32 on when one-time inspection programs can be credited for aging
 
management, and (3) the applicant's Supplemental Piping and Tanks Inspection
 
Program includes volumetric examination methods and VT-1 or VT-3 visual inspection
 
methods, which are valid techniques for the detection of loss of material in these steel
 
and stainless steel diesel exhaust components.
 
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 determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.3.2.2.8  Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced
 
Corrosion 
 
The staff reviewed LRA Section 3.3.2.2.8 against the criteria in SRP-LR Section 3.3.2.2.8.
 
LRA Section 3.3.2.2.8 addresses loss of material due to general, pitting, crevice, and
 
microbiologically influence corrosion (MIC). The applicant stated that loss of material due to
 
general, pitting, and crevice corrosion and MIC for steel piping components with coatings buried
 
in soil is managed by the Buried Piping and Tanks Inspection Program. Loss of material for
 
buried steel piping components with damaged coatings and buried in soil is managed by the
 
Buried Piping Surveillance Program.
 
SRP-LR Section 3.3.2.2.8 states that loss of material due to general, pitting, and crevice
 
corrosion, and MIC may occur in steel (with or without coating or wrapping) piping, piping
 
components, and piping elements buried in soil. Buried piping and tanks inspection programs
 
rely on industry practice, frequency of pipe excavation, and OE to manage the effects of loss of
 
material from general, pitting, and crevice corrosion and MIC. The effectiveness of the buried
 
piping and tanks inspection program should be verified to evaluate an applicant's inspection
 
frequency and OE with buried components, ensuring that loss of material does not occur.
 
The Buried Piping and Tanks Inspection Program is discussed in SER Section 3.0,3.2.13. The
 
Buried Piping and Tanks Inspection Program relies on examination of buried steel piping and
 
piping components with coatings during routine maintenance or by using focused inspections at
 
least once in the ten years prior to entering the period of extended operation and at least once
 
during the first ten years of entering the period of extended operation. The Buried Piping
 
Surveillance Program is discussed in SER Section 3.0.3.2.10. The Buried Piping Surveillance
 
Program relies on the use of cathodic protection to protect buried steel piping with damaged
 
coatings. Reference electrodes are placed along the buried piping which are used to measure
 
the potential of the buried piping to ensure that it is adequately protected by the cathodic 3-347 protection system. In addition, coating conduction measurements are taken to indicate that the cathodic protection is adequately installed, and current requirements are trended to insure that
 
further damage to the coatings is not occurring. Finally, pipe to soil potential surveys are
 
preformed on an annual basis to further demonstrate adequate protection of the buried steel
 
piping with damaged coatings.
 
Based on the programs identified, the staff concludes that the applicant's AMR results are
 
acceptable because the AMPs provide both detection and mitigation for the aging effect of loss
 
of material due to general, pitting, and crevice corrosion and MIC for steel piping
 
components with coatings buried in soil in the subject components. For those items that apply
 
to LRA Table 3.3.1, item 3.3.1 19 and Table 3.4.1, item 3.4.1-17, the staff determines that the
 
LRA is consistent with the GALL Report and that the applicant has demonstrated that the
 
effects of aging will be adequately managed so that the intended function(s) will be maintained
 
consistent with the CLB during the period of extended operation, as required by 10 CFR
 
54.21(a)(3).
 
Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.8 criteria. For those line items that apply to LRA Section 3.3.2.2.8, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.3.2.2.9  Loss of Material Due to General, Pitting, Crevice, Microbiologically-Influenced
 
Corrosion and Fouling 
 
The staff reviewed LRA Section 3.3.2.2.9 against the following 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, MIC and fouling in piping, piping components, and piping elements exposed to fuel oil. The
 
applicant stated that loss of material due to general, pitting, and crevice corrosion and
 
MIC for steel piping components and tanks exposed to fuel oil is managed by the Fuel
 
Oil Chemistry Program. The Fuel Oil Chemis try Program manages aging effects through periodic monitoring and control of contami nants. The Chemistry Program Effectiveness Inspection will provide a verification of the effectiveness of the Fuel Oil Chemistry
 
Program to manage loss of material due to general, pitting, and crevice corrosion
 
through examination of steel piping components and tanks exposed to fuel oil. Fouling is
 
not identified as an aging effect for fuel oil.
SRP-LR Section 3.3.2.2.9 states that loss of material due to general, pitting, and crevice
 
corrosion, MIC, and fouling may occur in steel piping, piping components, piping
 
elements, and tanks exposed to fuel oil. The existing AMP relies on fuel oil chemistry programs to monitor and control fuel oil contamination to manage loss of material due to
 
corrosion or fouling. Corrosion or fouling may occur at locations where contaminants
 
accumulate. The effectiveness of fuel oil chemistry programs should be verified to
 
ensure that corrosion does not occur. The GALL Report recommends further evaluation
 
of programs to manage loss of material due to general, pitting, and crevice corrosion, MIC, and fouling to verify the effectiveness of fuel oil chemistry programs. A one-time
 
inspection of selected components at susceptible locations is an acceptable method to
 
ensure that corrosion does not occur and that component intended functions will be 3-348 maintained during the period of extended operation.
 
The staff noted the applicant's statement in the LRA that fouling is not identified as an
 
aging effect for fuel oil. However, the staff could find no basis for that statement provided
 
in the LRA. The staff issued RAI 3.3.2.2.9.1-1 by letter dated July 15, 2008, asking the
 
applicant to provide a basis for the statement that fouling is not identified as an aging
 
effect for fuel oil.
 
In a letter dated August 15, 2008, the applicant responded to RAI 3.3.2.2.9.1-1 by
 
providing the following response:
 
The quality of fuel oil is verified upon receipt and before it is delivered to the plant's fuel
 
oil storage tanks, and introduced into the fuel oil system, to ensure that it does not
 
contain contaminants, such as sediment, that could cause fouling. The potential for
 
water contamination in the fuel oil during transfer and storage is, however, assumed.
 
Therefore, the only foulants that would be expected in the fuel oil would be those that
 
result from corrosion of steel piping and components, i.e., corrosion products. By
 
managing loss of material due to general, pitting, crevice, and microbiologically induced
 
corrosion, corrosion products will be controlled, and fouling will not occur. Therefore, fouling is not identified as an aging effect for fuel oil.
 
The staff reviewed the applicant's response and finds its acceptable because it provides
 
a reasonable technical justification, based on fuel oil testing upon receipt, prior to
 
introducing the fuel oil into the fuel oil storage tanks, and on control of potential corrosion
 
products, as to why fouling is not expected to occur for steel components exposed to a
 
fuel oil environment. The issues raised in RAI 3.3.2.2.9.1-1 are resolved by the
 
applicant's response. 
 
The staff reviewed the applicant's Fuel Oil Chemistry Program. The staff's evaluation of
 
this program, which is documented in SER Section 3.0.3.2.11, found that the Fuel Oil
 
Chemistry Program provides aging management for loss of material due to general, pitting, and crevice corrosion and MIC through monitoring and control of fuel oil
 
contamination such as water or microbiological organisms. The staff reviewed the
 
applicant's Chemistry Program Effectiveness In spection. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the Chemistry
 
Program Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "One-Time Inspection." The
 
Chemistry Program Effectiveness Inspection in cludes provisions for inspecting selected components determined to be most susceptible to the aging effect(s) of interest and is
 
capable of detecting loss of material due to general, pitting and crevice corrosion, and
 
MIC, if it should occur in the selected components. Based on the applicant's use of a
 
one-time inspection consistent with the recommendations of the GALL Report, the staff
 
finds the applicant's proposed AMPs for managing the potential aging effect of loss of
 
material due to general, pitting, and crevice corrosion, and MIC for steel piping, piping
 
components, piping elements, and tanks exposed to fuel oil in the diesel fuel oil system and in the fire protection system to be acceptable.
 
(2) LRA Section 3.3.2.2.9 addresses loss of material due to general, pitting, crevice, MIC and fouling in piping, piping components, and piping elements exposed to lubricating oil.
 
The applicant stated that loss of material due to general, pitting, and crevice corrosion
 
and MIC for steel piping components exposed to lubricating oil is managed by the 3-349 Lubricating Oil Analysis Program. The Lubric ating Oil Analysis Program manages aging effects through periodic monitoring and control of contaminants, including water. The
 
Lubricating Oil Inspection will provide a verification of the effectiveness of the Lubricating
 
Oil Analysis Program to manage loss of material due to general, pitting, and crevice
 
corrosion and MIC through examination of steel piping components. The Lubricating Oil
 
Analysis Program will also manage reduction in heat transfer due to fouling of heat
 
exchanger tubes exposed to lubricating oil. For those heat exchangers within the scope
 
of Generic Letter 89-13 for SSES, the Piping Corrosion Program is credited with
 
managing fouling of heat exchanger tubes exposed to lubricating oil.
SRP-LR Section 3.3.2.2.9 states that loss of material due to general, pitting, and crevice
 
corrosion, MIC, and fouling may occur in steel heat exchanger components exposed to
 
lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to
 
maintain contaminants within acceptable 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 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 verified that only heat exchanger components that align to GALL AMR VII.H2-5
 
for the Control Structure Chilled Water system that are fabricated from steel materials
 
are applicable to SSES.
 
The staff evaluated the Lubricating Oil Analysis Program and the Lubricating Oil
 
Inspection Program, and the evaluations are documented in SER Sections 3.0.3.2.15
 
and 3.0.3.2.13 respectively. The staff reviewed the applicant's Lubricating Oil Analysis
 
Program and determined that this program includes periodic sampling and analysis of
 
lubricating oil to maintain contaminants within acceptable limits. The staff finds that
 
these activities are consistent with the recommendations in the GALL Report and are
 
adequate to manage loss of material due to pitting, crevice, and microbiologically-
 
influenced corrosion in steel piping, piping components, and piping elements exposed to
 
lubricating oil. The staff verified that the applicant has credited its Lubricating Oil
 
Inspection Program to verify the effectiveness of the Lubricating Oil Analysis Program to manage this aging effect. The applicant's AMPS are consistent with those recommended
 
for aging management in SRP-LR Section 3.3.2.2.9, Item #2 and in GALL AMR Item
 
VII.H2-5.
 
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 determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.3.2.2.10  Loss of Material Due to Pitting and Crevice Corrosion 
 
The staff reviewed LRA Section 3.3.2.2.10 against the following criteria in SRP-LR 3-350 Section 3.3.2.2.10:
 
(1) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in steel piping with elastomer lining or stainless steel cladding. The applicant stated that
 
this aging effect is not applicable because elastomer linings are not credited for
 
protection of metallic components, and are therefore, not subject to AMR. There are no
 
steel with stainless steel cladding piping components that are exposed to treated water
 
or treated borated water in the Auxiliary Systems for SSES.
SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice
 
corrosion may occur in BWR and PWR steel piping with elastomer lining or stainless
 
steel cladding exposed to treated water and treated borated water if the cladding or
 
lining is degraded. The existing AMP monitors and controls reactor water chemistry to
 
manage the aging effects of loss of material from pitting and crevice corrosion. However, high concentrations of impurities in crevices and with stagnant flow conditions may
 
cause pitting or crevice corrosion; therefore, the effectiveness of water chemistry control
 
programs should be verified to ensure that corrosion does not occur. The GALL Report
 
recommends further evaluation of programs to manage loss of material from pitting and crevice corrosion to verify the effectiveness of water chemistry control programs. A one-
 
time inspection of 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.
 
For applicable steel BWR piping, SRP-LR Section 3.3.2.2.10.1 invokes AMR Item 22 in
 
Table 3 of the GALL Report, Volume 1, and GALL AMR Item VII.A4-12, applicable to the
 
steel piping in the spent fuel pool cooling and cleanup (purification) systems designed
 
with elastomeric linings or stainless steel cladding, where the elastomeric lining or
 
stainless steel cladding has been determined to be degraded and the underlying steel
 
material is exposed to treated water or borated treated water.
 
The staff verified that the LRA does not credit internal elastomeric liners in the
 
components of the fuel pool cooling and cleanup system, or fuel pool auxiliaries for
 
aging management. The staff also verified that the steel piping components in the SSES
 
fuel pool cooling and cleanup systems and fuel pool auxiliaries do not include any
 
internal stainless steel cladding. Based on this review, the staff concludes that the
 
applicant has provided an acceptable basis for concluding that the supplemental
 
evaluation recommendations in SRP-LR Section 3.3.2.2.10.1 and in GALL AMR VII.A4-
 
12 are not applicable to the LRA because the staff has verified that the applicant does
 
not credit any elastomeric liner in the fuel pool cooling and cleanup systems for aging
 
management and because the staff has verified that the fuel pool cooling and cleanup
 
systems do not include any steel components that are lined with internal stainless steel cladding.
 
(2) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in piping, piping components, piping elements, and heat exchanger components. The
 
applicant stated that loss of material due to pitting and crevice corrosion for stainless
 
steel heat exchanger components exposed to treated water is managed by the Closed
 
Cooling Water Chemistry Program. The Closed Cooling Water Chemistry Program
 
manages aging effects through periodic monitoring and control of contaminants.
SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice 3-351 corrosion may occur in stainless steel and aluminum piping, piping components, piping elements, and for stainless steel and steel with stainless steel cladding heat exchanger
 
components exposed to treated water. The existing AMP monitors and controls reactor
 
water chemistry to manage the aging effects of loss of material from pitting and crevice
 
corrosion. However, high concentrations of impurities in crevices and with stagnant flow
 
conditions may cause pitting or crevice corrosion; therefore, the effectiveness of water
 
chemistry control programs should be verified to ensure that corrosion does not occur.
 
The GALL Report recommends further evaluation of programs to manage loss of
 
material from pitting and crevice corrosion to verify the effectiveness of water chemistry
 
control programs. A one-time inspection of 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 3.3.2.2.10.2 and the discussions in LRA Table 3.3.1, items 3.3.1 23 and 3.3.1 24, against the criteria in SRP-LR Section 3.3.2.2.10, item 2, which states that loss of material due to pitting and crevice corrosion may occur in
 
stainless steel and aluminum piping, piping components, piping elements, and for
 
stainless steel and steel with stainless steel cladding heat exchanger components
 
exposed to treated water. The SRP-LR states that the existing AMP monitors and
 
controls reactor water chemistry to manage the aging effects of loss of material from
 
pitting and crevice corrosion. However, high concentrations of impurities in crevices and
 
with stagnant flow conditions may cause pitting or crevice corrosion; therefore, the
 
effectiveness of water chemistry control programs should be verified to ensure that
 
corrosion does not occur. The GALL Report recommends further evaluation of programs
 
to manage loss of material from pitting and crevice corrosion to verify the effectiveness
 
of water chemistry control programs. The SRP-LR states that 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 noted that the only AMR results referring to LRA Table 3.3.1, item 3.3.1 23, are
 
for stainless steel heat exchanger components associated with diesel generator jacket
 
water cooling. By letter dated August 12, 2008 and December 11, 2008 the applicant
 
amended its LRA such that aluminum heat exchanger components associated with diesel generator lubricating oil cooling references LRA Table 3.3.1, item 3.3.1 24, in
 
response to RAI B.2.14-2. For the stainless steel components, which are exposed to
 
treated water in the closed cooling water system, as amended by its supplemental
 
response to RAI B.2.14-2 by letter dated December 11, 2008 the applicant proposed to
 
manage loss of material due to pitting and crevice corrosion using the Closed Cooling
 
Water Chemistry Program and and the Chemis try Program Effectiveness Inspection in lieu of the Water Chemistry and One-Time Inspection programs as recommended in the
 
GALL Report. 
 
The staff reviewed the applicant's Closed Cooling Water Chemistry Program. The staff's
 
evaluation of this program, which is documented in SER Section 3.0.3.2.7, found that the
 
Closed Cooling Water Chemistry Program provides mitigation for the aging effect of loss
 
of material due to corrosion by control of closed cooling water system chemistry
 
consistent with applicable EPRI water chemistry guidelines. In addition, the Closed
 
Cooling Water Chemistry Program includes monitoring for corrosion and is
 
supplemented by a separate one-time inspection of other, representative areas serviced
 
by the closed cooling water system. The one-time inspections are performed as part of 3-352 the Chemistry Program Effectiveness Inspec tion, which the staff evaluates in SER Section 3.0.3.1.10. The staff confirmed that the Chemistry Program Effectiveness
 
Inspection will be used to verify the effectiveness of the applicant's Closed Cooling
 
Water Chemistry Program to manage loss of material and that a combination of
 
appropriate volumetric and visual examination techniques (such as VT-1 or VT-3) will be
 
performed by qualified personnel on a sample population of most susceptible subject
 
components. Because the Closed Cooling Water Chemistry Program provides both
 
mitigation of, and monitoring for pitting and crevice corrosion and the applicant will
 
confirm the effectiveness of its chemistry program with a one-time inspection performed
 
by the Chemistry Program Effectiveness Ins pection the staff finds use of the Closed Cooling Water Chemistry Program and the C hemistry Program Effectiveness Inspection acceptable for managing the aging effect of loss of material due to pitting and crevice
 
corrosion in stainless steel heat exchanger components exposed to treated water in the
 
diesel generator jacket water cooling subsystem.
 
In LRA Table 3.3.1, Item 3.3.1-24, the applicant stated that the BWR Water Chemistry
 
Program and the Chemistry Program Effect iveness Inspection are credited to manage loss of material for stainless steel and aluminum components exposed to treated water.
 
The applicant also stated that the BWR Water Chemistry Program, alone, is credited to
 
manage loss of material for spent fuel storage racks made of aluminum. Furthermore, the applicant stated that the BWR Water Chemistry Program, alone, is credited to
 
manage cracking of aluminum components ex posed to treated water; however, that statement was deleted from the LRA as part of the applicant's response to RAI 3.3-2, discussed both near the end of this subsection and in SER Subsection 3.3.2.3.3.
 
The staff noted that for all stainless steel components where the AMR results are
 
referenced to LRA Table 3.3.1, item 3.3.1-24, the aging effect is loss of material due to
 
pitting and crevice corrosion and the applicant states that this aging effect will be
 
managed by a combination of the BWR Water Chemistry Program and the Chemistry
 
Program Effectiveness Inspection. These results are consistent with AMR results in the
 
GALL Report for the same material, environment and aging effect combination.
 
The staff noted that there are three AMR result lines referenced to LRA Table 3.3.1, item
 
3.3.1 24 where the material is aluminum. One of the lines is for aluminum accumulator (pistons) in the control rod drive hydraulic system exposed to treated water where the aging effect of loss of material is managed with a combination of the BWR Water
 
Chemistry Program and the Chemistry Progr am Effectiveness Inspection; this AMR result is consistent with the GALL Report. One of the lines is for aluminum spent fuel
 
pool storage racks exposed to treated water where the aging effect of loss of material is
 
managed with the BWR Water Chemistry Program, alone; this AMR result is not
 
consistent with the GALL Report, but it is acceptable, as discussed below. One of the
 
lines is for aluminum accumulator (pistons) in the control rod drive hydraulic system exposed to treated water where the applicant proposed to managed the aging effect of
 
cracking with the BWR Water Chemistry Program, alone; however, in response to RAI
 
3.3-2 the applicant revised the this AMR result and the LRA as discussed below and in
 
SER Subsection 3.3.2.2.3.
 
In the LRA the applicant provides plant-specific note 0515 to explain use of the BWR
 
Water Chemistry Program, alone, for managing lo ss of material from the aluminum spent fuel storage racks. In Note 0515 the applicant states that one-time inspection is not
 
applicable for the spent fuel racks because the spent fuel pool does not contain areas of 3-353 low or stagnant flow where pitting or crevice corrosion would likely occur. Note 0515 also refers to the GALL Report, Chapter VII.A2, where the Water Chemistry Program, alone, is credited with managing the aging effect of cracking due to stress corrosion cracking in
 
stainless steel spent fuel storage racks. On the basis that there are no areas of low or
 
stagnant flow in the spent fuel pool where contaminants causing corrosion might collect, and the applicant's proposed AMP is consistent with the AMP recommended in the
 
GALL Report, Chapter VII.A2, item VII.A2-6, for similar stainless steel components in a spent fuel pool environment, the staff finds the applicant's use of the BWR Water
 
Chemistry Program, alone, for managing loss of material from the aluminum spent fuel storage racks in a treated water environment to be acceptable.
 
The staff reviewed the applicant's BWR Water Chemistry Program. The staff's
 
evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that the
 
BWR Water Chemistry Program provides mitigation for the aging effect of loss of
 
material due to general, crevice and pitting corrosion. The staff reviewed the Chemistry
 
Program Effectiveness Inspection. The staff' s evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the applicant's Chemistry Program
 
Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "One-Time Inspection." The Chemistry
 
Program Effectiveness Inspection includes provisions for inspecting selected
 
components in areas of low or stagnant flow and is capable of detecting loss of material
 
due to general, pitting or crevice corrosion, if it should occur in the selected components.
 
Based on the applicant's use of a one-time inspection consistent with the
 
recommendations of the GALL Report, the staff finds the applicant's use of the BWR
 
Water Chemistry Program and the Chemistr y Program Effectiveness Inspection for managing the potential aging effect of loss of material due to pitting and crevice
 
corrosion for stainless steel and aluminum components exposed to treated water to be
 
acceptable.
 
In LRA Table 3.3.2-3 (page 3.3-103), the applicant identified the aging effect of cracking
 
as applicable for the aluminum pistons in the control rod drive accumulators which are
 
exposed to an environment of treated water. The applicant proposed use of the BWR
 
Water Chemistry Program, alone, for managing this aging effect in this component and
 
cited generic Note H, indicating that the aging effect is not in the GALL Report for the
 
component, material and environment combination. The staff issued RAI 3.3-2 by letter
 
dated July 15, 2008, asking that the applicant provide further information to justify that
 
the BWR Water Chemistry Program, alone, without an inspection to confirm program
 
effectiveness, provides adequate aging management for this component. The RAI also
 
asked the applicant to explain why the aging effect of cracking is referenced to LRA
 
Table 3.3.1, item 3.3.1-24, where the aging effect is loss of material due to pitting and
 
crevice corrosion.
 
In a letter dated August 15, 2008, the applicant responded to RAI 3.3-2 by providing the
 
following response:
 
For the AMR results item listed on page 3.3-103 of the LRA for accumulator (pistons)
 
made of aluminum in a treated water environment with an aging effect of cracking, Note
 
H is the appropriate generic note because the aging effect, cracking, is not in the GALL
 
Report for aluminum exposed to treated water. However, because the GALL Report item
 
VIII.E3-7 is for loss of material, the GALL Report Volume 2 item number and the Table 1
 
item number should have been identified as "N/A."
3-354  For this AMR result item, verification of the effectiveness of the BWR Water Chemistry
 
Program is needed to confirm that cracking is not occurring in these components.
 
As part of the RAI response, the applicant revised the AMR result line in LRA Table
 
3.3.2 3, page 3.3-103. The revised AMR result line shows that for accumulators (pistons)
 
made of aluminum in a treated water envir onment the aging effect of cracking will be managed by a combination of the BWR Water Chemistry Program and the Chemistry
 
Program Effectiveness Inspection. Generic Note H continues to apply for this AMR result
 
line, indicating that the aging effect is not in the GALL Report for this component, material and environment combination. The revised AMR result line no longer refers to
 
GALL Volume 2 or LRA Table 1 items, and the staff's evaluation of this AMR result, as
 
revised, is documented in SER Subsection 3.3.2.3.3.
 
The applicant responded to RAI B.2.14-2 by letter dated August 12, 2008 and
 
supplemented its response by letter dated December 11, 2008. It is response and
 
supplemental response the applicant amended its LRA such that the material-
 
environment-aging effect combination of aluminum-treated water (internal)-loss of
 
material referenced LRA Table 3.3.1, item 3.3.1 24. For the aluminum components, which are exposed to treated water in the closed cooling water system, the applicant
 
proposed to manage loss of material due to pitting and crevice corrosion using a
 
combination of the Closed Cooling Water Chemistry Program and the Chemistry
 
Program Effectiveness Inspection in lieu of the Water Chemistry and One-Time
 
Inspection programs as recommended in the GALL Report.
 
The staff reviewed the applicant's Closed Cooling Water Chemistry Program. The staff's
 
evaluation of this program, which is documented in SER Section 3.0.3.2.7, found that the
 
Closed Cooling Water Chemistry Program provides mitigation for the aging effect of loss
 
of material due to corrosion by control of closed cooling water system chemistry
 
consistent with applicable EPRI water chemistry guidelines. In addition, the Closed
 
Cooling Water Chemistry Program includes monitoring for corrosion and is
 
supplemented by a separate one-time inspection of other, representative areas serviced
 
by the closed cooling water system. The one-time inspections are performed as part of
 
the Chemistry Program Effectiveness Inspec tion, which the staff evaluates in SER Section 3.0.3.1.10. The staff confirmed that the Chemistry Program Effectiveness
 
Inspection will be used to verify the effectiveness of the applicant's Closed Cooling
 
Water Chemistry Program to manage loss of material and that a combination of
 
appropriate volumetric and visual examination techniques (such as VT-1 or VT-3) will be
 
performed by qualified personnel on a sample population of most susceptible subject
 
components. Because the Closed Cooling Water Chemistry Program provides both
 
mitigation of, and monitoring for pitting and crevice corrosion and the applicant will
 
confirm the effectiveness of its chemistry program with a one-time inspection performed
 
by the Chemistry Program Effectiveness Ins pection the staff finds use of the Closed Cooling Water Chemistry Program and the C hemistry Program Effectiveness Inspection acceptable for managing the aging effect of loss of material due to pitting and crevice
 
corrosion in aluminum heat exchanger components exposed to treated water in the
 
diesel generator lubricating oil cooling subsystem.
 
(3) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in HVAC piping, piping components, and piping elements. The applicant stated that the
 
Cooling Units Inspection is a one-time inspection that will detect and characterize loss of 3-355 material due to pitting and crevice corrosion for copper alloy HVAC piping components in an external environment with potential for wetting.
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 GALL report, under Items VII.F1-16, VII.F2-14, VII.F3-16 and VII.F4-12
 
recommends that a plant-specific program be credited to manage this aging effect for
 
copper alloy HVAC piping, piping components and piping elements in the Auxiliary Systems.
 
The staff verified that only heat exchanger components, piping and piping components
 
and valve bodies that align to GALL AMRs VII.F1-16, VII.F2-14 and VII.F4-12 for the
 
Domestic Water System, Emergency Service Water System, Fire Protection System, Raw Water Treatment System, Reactor Bu ilding Chilled Water System, RHR Service Water System, Sampling System, Service Water System, Control Structure Chilled Water System and Diesel Generator System that are fabricated from copper alloy materials are applicable to SSES that credit the System Walkdown Program.
 
The staff reviewed the applicant's System Walkdown Program and its evaluation is
 
documented in SER Sections 3.0.3.1.9. The staff determined that the System
 
Walkdown Program which includes periodic vi sual inspections performed during system walkdowns, are adequate to manage loss of material due to pitting and crevice corrosion
 
for copper alloy HVAC piping, piping components, and piping elements exposed to
 
indoor and outdoor air environment with the potential for wetting addressed by this AMR. 
 
The staff finds that the System Walkdown Pr ogram performs periodic visual inspections of external surfaces during periodic system to detect aging effects that could result in a
 
loss of the component's intended function. The staff finds that this program includes
 
activities that are consistent with the recommendations in the GALL Report, and that it is
 
adequate to manage loss of material due to pitting and crevice corrosion for copper alloy
 
HVAC piping, piping components and piping elements exposed condensation on the
 
external surface.
 
The staff reviewed the applicant's Cooling Units Inspection Program, which uses a
 
combination of volumetric and visual examination techniques to identify evidence of loss
 
of material or lack thereof. The staff's evaluation of the Cooling Units Inspection Program
 
is documented in SER Section 3.0.3.1.11. Because the Cooling Units Inspection is
 
performed at selected susceptible locations, and employs a combination of volumetric
 
and visual inspection techniques, the staff finds that the Cooling Units Inspection
 
Program will adequately manage the aging effects of loss of material in this wetted
 
environment.
 
(4) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in piping, piping components, and piping elements exposed to lubricating oil. The applicant
 
stated that loss of material due to pitting and crevice corrosion for copper alloy piping
 
components exposed to lubricating oil is managed by the Lubricating Oil Analysis Program. The Lubricating Oil Analysis Progr am manages aging effects through periodic monitoring and control of contaminants, including water. The Lubricating Oil Inspection 3-356 will provide a verification of the effectiveness of the Lubricating Oil Analysis Program to manage loss of material due to pitting and crevice corrosion through examination of
 
copper alloy piping components 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 verified that only piping, piping components and elements that align to GALL
 
AMR VII.C2-5 and VII.H2-10 for the Fire Protection, Control Structure Chilled Water and
 
Diesel Generator Lubricating Oil and NSAS Co mponent systems that are fabricated from copper alloy materials are applicable to SSES.
 
The staff reviewed the applicant's Lubricating Oil Analysis Program and determined that
 
this program includes periodic sampling and analysis of lubricating oil to maintain
 
contaminants within acceptable limits. The staff finds that these activities are consistent
 
with the recommendations in the GALL Report and are adequate to manage loss of
 
material due to pitting and crevice corrosion for copper alloy piping, piping components, and piping elements exposed to lubricating oil.
 
The staff evaluated the Lubricating Oil Analysis Program and the Lubricating Oil
 
Inspection Program, and the evaluations are documented in SER Sections 3.0.3.2.15
 
and 3.0.3.2.13 respectively. The staff verified that the applicant has credited its
 
Lubricating Oil Inspection Program to verify the effectiveness of the Lubricating Oil Analysis Program to manage this aging effect. The applicant's AMPS are consistent with
 
those recommended for aging management in SRP-LR Section 3.3.2.2.10, Item #4 and
 
in GALL AMR Item VII.C2-5 and VII.H2-10. 
 
Based on the program identified above, the staff concludes that the applicant's program
 
meet SRP-LR Section 3.2.2.2.10 Item (4) criteria and therefore the applicant's AMRs are
 
consistent with those under GALL Report Item VII.C2-5 and VII.H2-10. For those line
 
items that apply to LRA Section 3.2.2.2.10 Item #4, the staff determines that the LRA is
 
consistent with the GALL Report and that the applicant has demonstrated that the
 
effects of aging will be adequately managed so that the intended function(s) will be
 
maintained consistent with the CLB during the period of extended operation, as required
 
by 10 CFR 54.21(a)(3).
 
During its review, the staff noted that the applicant identified in LRA Table 3.3.2-4, Control Structure Chilled Water System, a Type-2 line item that utilized a standard note I
 
and plant specific note 0310, claiming that the aging effect, loss of material due to pitting
 
and crevice corrosion, is not applicable to SSES for this component, material and
 
environment combination. The applicant states that this Type-2 item is not applicable to 3-357 SSES because this tubing that is exposed to lubricating oil internally is made of copper with less than 15% zinc, therefore is not susceptible to this aging effect and environment combination. The staff verified in the GALL Report, Chapter IX.C that components made
 
of copper alloy with less than 15% zinc are resistant to loss of material due to pitting and
 
crevice corrosion. Based on this assessment, the staff concludes that this Type-2 item
 
in LRA Table 3.3.2-4 is not applicable to SSES.
 
(5) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in HVAC piping, piping components, and piping elements and ducting. The applicant stated
 
that the Cooling Units Inspection is a one-time inspection credited with detecting and
 
characterizing the condition of aluminum and stainless steel HVAC components exposed to condensation. The System Walkdown Program is credited for managing loss of
 
material due to pitting and crevice corrosion for the external surfaces of stainless steel
 
HVAC components 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 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 GALL report, under Item VII.F1-1, VII.F2-1, VII.F3-1, VII.F1-14, VII.F2-12, VII.F3-14
 
and VII.F4-10 recommends that a plant-specific program be credited to this aging effect
 
for stainless steel ducting and components and piping elements in the Auxiliary Systems.
The staff verified that only ducting and components that align to GALL AMRs VII.F1-1, VII.F2-1 and VII.F3-1 for the Emergency Servic e Water System, Fire Protection System, Fuel Pool Cooling System, Primary Cont ainment Atmosphere Circulation System, Process and Area Radiation Monitoring System, Reactor Building Chilled Water and
 
HVAC System, RHR Service Water System, Sampling System and Control Structure Chilled Water System that are fabricated from stainless steel and steel materials are
 
applicable to SSES that credit the Systems Walkdown Program.
The staff reviewed the applicant's System Walkdown Program and its evaluation is
 
documented in SER Sections 3.0.3.1.9. The staff determined that the System
 
Walkdown Program which includes periodic vi sual inspections performed during system walkdowns, are adequate to manage loss of material due to pitting and crevice corrosion
 
for stainless steel and steel ducting and components exposed to indoor and outdoor air
 
environment with the potential for wetting addressed by this AMR. The staff finds that
 
the System Walkdown Program performs periodic visual inspections of external surfaces during periodic system to detect aging effects that could result in a loss of the
 
component's intended function. The staff finds that this program includes activities that
 
are consistent with the recommendations in the GALL Report, and that it is adequate to
 
manage loss of material due to pitting and crevice corrosion for stainless steel and steel
 
ducting and components exposed indoor and outdoor air with the potential for wetting on
 
the external surface.
 
Subsection 3.3.2.2.10.5 is referenced in the LRA Table 3.3.1 for line item 3.3.1-27. In the
 
discussion column of Table 3.3.1, item 3.3.1-27, the LRA states that the Cooling Units
 
Inspection will also detect and characterize cracking of aluminum HVAC cooling unit 3-358 fins, for which Note H is used. However, a review of Table 2s did not identify a line item where this is identified. The staff issued RAI 3.3.1-6 by letter dated July 9, 2008 to
 
request the applicant to clarify where in Table 2s the Cooling Units Inspection is credited
 
for managing cracking of aluminum HVAC cooling unit fins.
 
In its letter dated August 8, 2008, the applicant responded to RAI 3.3.1-6 by stating that
 
the Cooling Unit Inspection Program is not credited for managing cracking of aluminum HVAC cooling unit fins. The applicant revised LRA Table 3.3.1, item 3.3.1-27 and the
 
associated LRA Section 3.3.2.2.10.5 to remove the statement crediting the Cooling Unit
 
Inspection Program in conjunction with cracking of aluminum HVAC cooling unit fins.
 
The staff reviewed the applicant's response and the LRA revision. With the removal of
 
the statement crediting the Cooling Unit Inspection Program for cracking of aluminum
 
HVAC cooling fins, Table 3.3.1. item 3.3.1-27 and Section 3.3.2.2.10.5 are consistent
 
with Table 2s, where cracking of aluminum fins is not addressed and there is no
 
discrepancy between Table 1 and Table 2. On this basis, the staff finds the response
 
acceptable.
 
The staff reviewed the Cooling Units Inspection Program, which uses a combination of
 
volumetric and visual examination techniques to identify evidence of loss of material or
 
lack thereof. The staff's evaluation of the Cooling Units Inspection Program is
 
documented in SER Section 3.0.3.1.11. Because the Cooling Units Inspection is
 
performed at selected susceptible locations, and employs a combination of volumetric
 
and visual inspection techniques, the staff finds that the Cooling Units Inspection
 
Program will adequately manage the aging effects of loss of material in this wetted
 
environment.
 
In the discussion column of Table 3.3.1, item 3.3.1-27, the LRA states that the System
 
Walkdown Program, the Cooling Units Inspection, and the Supplemental Piping/Tank
 
Inspection are credited to manage loss of material and references Section 3.3.2.2.10.5
 
for further evaluation. However, Section 3.3.2.2.10.5 does not address the Supplemental
 
Piping/Tank Inspection. The staff issued RAI 3.3.10.2.5-1 by letter dated July 9, 2008 to
 
request the applicant to resolve this discrepancy. 
 
In its letter dated August 8, 2008, the applicant responded to RAI 3.3.10.2.5-1 by
 
amending the LRA to add the following in LRA Section 3.3.2.2.10.5
 
The Supplemental Piping/Tank Inspection is a one-time inspection credited with detecting and characterizing the condition of stainless steel components that are exposed to moist air, particularly the aggressive alternate wet/dry environment that exists at air-water interfaces.
 
On the basis that the applicant amended the LRA to resolve the discrepancy between
 
Table 3.3.1, item 3.3.1-27 discussion column and this Subsection, the staff finds the
 
response acceptable. The Supplementary Piping/Tank Inspection Program is discussed
 
below.
 
In Table 3.3.2-14, Fuel Pool Cooling System, item 3.3.1-27 is referenced on three line
 
items, stainless steel piping (in two environments) and stainless steel skimmer surge
 
tanks. Table 3.3.2-14 also references for these three line items footnote 0303, which
 
states that loss of material is due to crevice and/or pitting corrosion caused by alternate 3-359 wetting and drying, not condensation, at the air-water interface. The applicant has chosen to apply SRP-LR Section 3.3.2.2.10.5 to these three line items, even though the
 
stainless piping is in fuel pool cooling system with an environment similar to ventilation. 
 
The applicant referenced GALL Report Volume 2, items VII.F1-1. The staff noted that
 
where the GALL Report recommends a plant-specific aging management program, the applicant proposed using the Supplementary Piping/Tank Inspection Program. 
 
The staff reviewed the Supplementary Piping/Tank Inspection Program, which uses a
 
combination of volumetric and visual examination techniques to identify evidence of loss
 
of material or lack thereof. The staff's evaluation of the Supplementary Piping/Tank
 
Inspection Program is documented in SER Section 3.0.3.1.16. Because the
 
Supplementary Piping/Tank Inspection is performed at very specific locations of
 
air/water interface, and employs a combination of volumetric and visual inspection
 
techniques, the staff finds that the Supplementary Piping/Tank Inspection Program will
 
adequately manage the aging effects of loss of material in this aggressive environment.
 
(6) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in the fire protection system. The applicant stated that this aging effect is not applicable
 
because the components are open to local ambient air conditions such that
 
condensation will not occur and are not subject to continuous wetting or alternate
 
wetting and drying that would constitute an aggressive 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 GALL Report recommends
 
further evaluation of a plant-specific AMP to ensure that the aging effect is adequately
 
managed.
 
The staff reviewed the GALL Report and noted that for copper alloy components in air-
 
indoor environment, line item V.F-3 identifies no aging effect and no aging management
 
program is required. On the basis that these copper alloy fire protection components are
 
open to the atmosphere and do not see continuous wetting or alternate wetting and
 
drying, the staff finds that consistent with the GALL Report, loss of material due to pitting
 
and crevice corrosion is not an aging effect requiring management.
 
(7) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in stainless steel piping, piping components, and piping elements exposed to soil. The
 
applicant stated that this aging effect is not applicable to auxiliary systems and is
 
evaluated in steam and power conversion systems.
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.
 
LRA table 3.3.1 states that there are no SSES components comparable to LRA item
 
number 3.3.1-29. The staff verified that there are no components that are comparable. 
 
The only stainless steel piping subject to aging management review for SSES that is
 
exposed to soil is located in the Condensate Transfer and Storage System and is
 
evaluated in the Steam and Power Conversi on group for LRA item number 3.4.1-17.
The staff's evaluation of the stainless steel piping exposed to soil in the Condensate 3-360 Transfer and Storage System is documented in SER Section 3.4.2.2.7.2.
 
(8) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in BWR SLC system. The applicant stated that loss of material due to pitting and crevice
 
corrosion for stainless steel piping components exposed to sodium pentaborate solution
 
is managed by the BWR Water Chemistry Program. The BWR Water Chemistry
 
Program manages aging effects through periodic monitoring and control of
 
contaminants. The Chemistry Program E ffectiveness Inspection will provide a verification of the effectiveness of the BWR Water Chemistry Program to manage loss of
 
material due to pitting and crevice corrosion through examination of stainless steel
 
piping components exposed to sodium pentaborate solution. SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice corrosion may occur in stainless steel piping, piping components, and piping elements of
 
the BWR SLC system exposed to sodium pentaborate solution. The existing
 
AMP monitors and controls water chemistry to manage the aging effects of loss of
 
material due to pitting and crevice corrosion. However, high concentrations of impurities
 
in crevices and with stagnant flow conditions may cause loss of material due to pitting
 
and crevice corrosion; therefore, the GALL Report recommends that the effectiveness of
 
water chemistry control programs should be verified to ensure that this aging does not
 
occur. A one-time inspection of selected components at susceptible locations is an
 
acceptable method to ensure that loss of material due to pitting and crevice corrosion
 
does not occur and that component intended functions will be maintained during the
 
period of extended operation.
The staff reviewed the applicant's BWR Water Chemistry Program. The staff's
 
evaluation of this program, which is documented in SER Section 3.0.3.1.1, determined
 
that the BWR Water Chemistry Program provides mitigation for the aging effect of loss of
 
material due to pitting and crevice corrosion. The staff reviewed the applicant's
 
Chemistry Program Effectiveness Inspection.
The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the Chemistry Program
 
Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "One-Time Inspection." The Chemistry
 
Program Effectiveness Inspection includes provisions for inspecting selected
 
components in areas of low or stagnant flow and is capable of detecting loss of material
 
due to pitting or crevice corrosion, if it should occur in the selected components. Based
 
on the applicant's use of a one-time inspection consistent with the recommendations of
 
the GALL Report, the staff finds the applicant's proposed AMPs for managing the
 
potential aging effect of loss of material due to pitting or crevice corrosion in stainless
 
steel piping components exposed to sodium pentaborate solution in the standby liquid
 
control system to be acceptable.
 
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 determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.3.2.2.11  Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion 
 
The staff reviewed LRA Section 3.3.2.2.11 against the criteria in SRP-LR Section 3.3.2.2.11.
3-361  LRA Section 3.3.2.2.11 addresses loss of material due to pitting, crevice, and galvanic
 
corrosion. The applicant stated that loss of material due to pitting, crevice, and galvanic
 
corrosion for copper alloy piping components exposed to treated water is managed by the BWR
 
Water Chemistry Program. The BWR Water Chem istry Program manages aging effects through periodic monitoring and control of contami nants. The Chemistry Program Effectiveness Inspection will provide a verification of the effectiveness of the BWR Water Chemistry Program
 
to manage loss of material due to pitting, crevic e, and galvanic corrosion through examination of copper alloy piping components exposed to treated water.
 
SRP-LR Section 3.3.2.2.11 states that loss of material due to pitting, crevice, and galvanic
 
corrosion may occur in copper alloy piping, piping components, and piping elements exposed to
 
treated water. Therefore, the GALL Report recommends that the effectiveness of water
 
chemistry control programs should be verified to ensure that this aging does not occur. A one-
 
time inspection of selected components at susceptible locations is an acceptable method to
 
ensure that loss of material due to pitting and crevice corrosion does not occur and that
 
component intended functions will be maintained during the period of extended operation.
 
The staff reviewed the applicant's BWR Water Chemistry Program. The staff's evaluation of this
 
program, which is documented in SER Section 3.0.3.1.1, determined that the BWR Water
 
Chemistry Program provides mitigation for the aging effect of loss of material due to pitting, crevice and galvanic corrosion. The staff re viewed the applicant's Chemistry Program Effectiveness Inspection. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the Chemistry Program Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "One-
 
Time Inspection." The Chemistry Program Effe ctiveness Inspection includes provisions for inspecting selected components in areas of low or stagnant flow and is capable of detecting
 
loss of material due to pitting, crevice or galvanic corrosion, if it should occur in the selected
 
components. Based on the applicant's use of a one-time inspection consistent with the
 
recommendations of the GALL Report, the staff finds the applicant's proposed AMPs for
 
managing the potential aging effect of loss of material due to pitting, crevice or galvanic
 
corrosion in copper alloy piping components exposed to treated water in the reactor water
 
cleanup system and in the control rod driv e hydraulic system to be acceptable.
 
Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.11 criteria. For those line items that apply to LRA Section 3.3.2.2.11, the staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.3.2.2.12  Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion 
 
The staff reviewed LRA Section 3.3.2.2.12 against the following 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 MIC in piping, piping components, and piping elements exposed to fuel oil. The applicant stated
 
that there are no aluminum piping components exposed to fuel oil that are subject to
 
aging management review for SSES. Loss of material due to pitting and crevice
 
corrosion and MIC for stainless steel and copper alloy piping components exposed to 3-362 fuel oil is managed by the Fuel Oil Chemis try Program. The Fuel Oil Chemistry Program manages aging effects through periodic monitoring and control of contaminants. The
 
Chemistry Program Effectiveness Inspecti on will provide a verification of the effectiveness of the Fuel Oil Chemistry Progr am to manage loss of material due to pitting and crevice corrosion and MIC through examination of stainless steel and copper alloy
 
piping components exposed to fuel oil. Though not credited, the Fire Protection Program
 
provides indirect confirmation of whether degradation of these components has
 
occurred, and that the component intended function is maintained.
SRP-LR Section 3.3.2.2.12 states that loss of material due to pitting and crevice
 
corrosion, and MIC may occur in stainless steel, aluminum, and copper alloy piping, piping components, and piping elements exposed to fuel oil. The existing AMP relies on
 
the fuel oil chemistry program for monitoring and control of fuel oil contamination to
 
manage loss of material due to corrosion; however, corrosion may occur at locations
 
where contaminants accumulate and the effectiveness of fuel oil chemistry control
 
should be verified to ensure that corrosion does not occur. The GALL Report
 
recommends further evaluation of programs to manage corrosion to verify the
 
effectiveness of the fuel oil chemistry control program. A one-time inspection of 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 applicant's Fuel Oil Chemistry Program. The staff's evaluation of
 
this program, which is documented in SER Section 3.0.3.2.1, found that the Fuel Oil
 
Chemistry Program provides aging management for loss of material due to pitting and
 
crevice corrosion and MIC through monitoring and control of fuel oil contamination such
 
as water or microbiological organisms. The staff reviewed the applicant's Chemistry
 
Program Effectiveness Inspection. The staff' s evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the Chemistry Program Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "One-Ti me Inspection." The Chemistry Program Effectiveness Inspection includes provisions for inspecting selected components
 
determined to be most susceptible to the aging effect(s) of interest and is capable of
 
detecting loss of material due to loss of material due to pitting or crevice corrosion or
 
MIC, if it should occur in the selected components. Based on the applicant's use of a
 
one-time inspection consistent with the recommendations of the GALL Report, the staff
 
finds the applicant's proposed AMPs for managing the potential aging effect of loss of
 
material due to pitting and crevice corrosion and MIC for stainless steel or copper alloy
 
piping components exposed to fuel oil in the diesel fuel oil system and in the fire
 
protection system to be acceptable.
 
(2) LRA Section 3.3.2.2.12 addresses loss of material due to pitting, crevice, and MIC in piping, piping components, and piping elements exposed to lubricating oil. The applicant
 
stated that loss of material due to pitting and crevice corrosion and MIC for stainless
 
steel piping components exposed to lubricat ing oil is managed by the Lubricating Oil Analysis Program. The Lubricating Oil Anal ysis Program manages aging effects through periodic monitoring and control of contaminants, including water. The Lubricating Oil
 
Inspection will provide a verification of the effectiveness of the Lubricating Oil Analysis
 
Program to manage loss of material due to pitting and crevice corrosion and MIC
 
through examination of stainless steel piping components.
 
3-363 SRP-LR Section 3.3.2.2.12 states that loss of material due to pitting, crevice, and MIC may occur in stainless steel piping, piping components, and piping elements exposed to
 
lubricating oil. The existing program periodically samples and analyzes lubricating oil to
 
maintain contaminants within acceptable 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 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 verified that only piping, piping components and elements that align to GALL
 
AMR VII.H2-17 for the Diesel Generator Lubricat ing Oil system that are fabricated from stainless steel materials are applicable to SSES.
 
The staff evaluated the Lubricating Oil Analysis Program and the Lubricating Oil
 
Inspection Program, and the evaluations are documented in SER Sections 3.0.3.2.15
 
and 3.0.3.2.13 respectively. The staff reviewed the applicant's Lubricating Oil Analysis
 
Program and determined that this program includes periodic sampling and analysis of
 
lubricating oil to maintain contaminants within acceptable limits. The staff finds that
 
these activities are consistent with the recommendations in the GALL Report and are
 
adequate to manage loss of material due to pitting, crevice, and microbiologically-
 
influenced corrosion in stainless steel piping, piping components, and piping elements
 
exposed to lubricating oil. The staff verified that the applicant has credited its
 
Lubricating Oil Inspection Program to verify the effectiveness of the Lubricating Oil Analysis Program to manage this aging effect. The applicant's AMPS are consistent with
 
those recommended for aging management in SRP-LR Section 3.3.2.2.12, Item #2 and
 
in GALL AMR Item VII.H2-17. 
 
Based on the program identified above, the staff concludes that the applicant's program
 
meet SRP-LR Section 3.3.2.2.12, Item #2 criteria and therefore the applicant's AMRs
 
are consistent with those under GALL Report Item VII.H2-17. For those line items that
 
apply to LRA Section 3.3.2.2.12, Item #2, the staff determines that the LRA is consistent
 
with the GALL Report and that the applicant has demonstrated that the effects of aging
 
will be adequately managed so that the intended function(s) will be maintained
 
consistent with the CLB during the period of extended operation, as required by 10 CFR
 
54.21(a)(3).
 
Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.12 criteria. For those line items that apply to LRA Section 3.3.2.2.12, the staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.3.2.2.13  Loss of Material Due to Wear 
 
The staff reviewed LRA Section 3.3.2.2.13 against the criteria in SRP-LR Section 3.3.2.2.13.
 
3-364 LRA Section 3.3.2.2.13 addresses loss of material due to wear. The applicant stated that this aging effect is not applicable because wear only occurs during the performance of an active
 
function, as a result of improper design, application or operation, or to a very small degree with
 
insignificant consequences.
 
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.
 
For applicable steel BWR piping, SRP-LR Section 3.3.2.2.13 invokes AMR Item 34 in Table 3 of
 
the GALL Report, Volume 1, and GALL AMR Item VII.F1-5, VII.F1-6, VII.F2-5, VII.F2-6, VII.F3-
 
5, VII.F3-6, VII.F4-4 and VII.F4-5, as applicable to the management of loss of material due to wear in elastomeric seals and components in control room area ventilation, auxiliary and radwaste area ventilation, primary containment heating and ventilation, and diesel generator building ventilation systems under internal and external exposure to uncontrolled
 
indoor air.
 
The staff reviewed the information in LRA Section 3.3.2.2.13 against the staff's recommendations in SRP-LR Section 3.3.2.2.13 and in GALL AMR items Item VII.F1-5, VII.F1-
 
6, VII.F2-5, VII.F2-6, VII.F3-5, VII.F3-6, VII.F4-4 and VII.F4-5, as applicable to the management of loss of material due to wear in elastomeric seals and components in control room area ventilation, auxiliary and radwaste area v entilation, primary containment heating and ventilation, and diesel generator building ventilation systems under internal and external exposure to uncontrolled indoor air.
 
The staff confirmed that the scope of the applicant's application includes the following AMR tables for auxiliary HVAC systems:
 
Table 3.3.2-5, Aging Management Results for Control Structure HVAC Systems  Table 3.3.2-8, Diesel Generator Buildings HVAC Systems  Table 3.3.2-12, ESSW Pumphouse HVAC System  Table 3.3.2-16, Primary Containment Atmosphere Circulation System  Tabl3 3.3.2-23, Reactor Building HVAC System
 
The staff noted that these AMR Tables did not include any AMRs on management of loss of
 
material due to wear in elastomeric HVAC seals and components or that were aligned to AMR
 
Item 34 in Table 3 of the GALL Report, Volume 1, or to GALL AMR Item VII.F1-5, VII.F1-6, VII.F2-5, VII.F2-6, VII.F3-5, VII.F3-6, VII.F4-4 or VII.F4-5. The staff also noted that the
 
applicant's basis for concluding that loss of material due to wear was based on a misplaced
 
conclusion. Specifically, the staff noted that the applicant based its conclusion that loss of
 
material due to wear was not an aging effect requiring management (AERM) on the fact that
 
wear is an active loss of material mechanism and not on the fact that the elastomeric HVAC
 
seals and components for which wear is plausible are active components or components that
 
are replaced on a qualified or specified frequency. The staff noted that the fact that wear is an
 
active loss of material mechanism did not provide any logical basis for concluding that wear was
 
not plausible aging mechanisms for any passive, long-lived elastomeric seals or components in
 
these HVAC systems.
 
In RAI 3.3.2.2.13-1, by letter dated July 23, 2008, the staff informed the applicant that the fact
 
that wear is an active aging mechanism does not provide a valid or acceptable basis for
 
concluding that the passive long-lived elastomeric HVAC seals or components are not subject 3-365 to potential loss of material due to wear. In this RAI, the staff asked the applicant to provide a valid basis why loss of material due to wear is not considered to be an aging effect requiring
 
management (AERM) for the elastomeric seals and components in the control structure HVAC
 
systems, diesel generator building HVAC sy stems, ESSW pumphouse HVAC system, primary containment atmosphere circulation syst em, or reactor building HVAC system.
 
In its letter dated August 27, 2008, in response to RAI 3.3.2.2.13-1, the applicant provided the
 
following bases, that have been documented in industry guidance on the aging of elastomers, upon which it concluded that loss of material due to wear is not an aging effect requiring
 
management for elastomer seals and components:
 
the elastomer seals and components were selected based on their suitability for the service in which they would be applied, i.e., they were properly designed;  the elastomer seals and components were properly applied and installed, i.e., within allowable pre-compression and offset limits, thus preventing significant relative motion
 
between the contacting surfaces; and,  the systems in which the elastomer seals and components are installed are operated in accordance with procedures that have been developed based on standard industry good
 
practices, thus preventing excessive vibration and unintended component movements  flexible connections are used in applications where some movement between the joined piping, ductwork, and components is expected to occur. However, as indicated above, the flexible connections are securely attached to the joined components such that there
 
is no relative movement between the connection of the flexible connection and the
 
component. The flexible connection is designed to accommodate relative movements, however proper design and installation ensures that the flexible connection does not
 
make contact with itself or with other nearby components. 
 
Therefore, the applicant concluded that there is no relative motion expected between contacting
 
surfaces and wear is not an aging effect requiring management.
 
The staff reviewed the applicant response and reviewed the definition of wear in the GALL Report Section IX.F. The GALL Report defines wear as the removal of surface layers due to
 
relative motion between two surfaces or under the influence of hard abrasive powder. The GALL
 
Report further states that wear occurs in parts that experience intermittent relative motion or
 
frequent manipulation. The staff determined that use of flexible connections in systems that
 
experience vibration minimizes relative motion of the piping system, thereby minimizing wear.
 
These systems are designed to account for relative motion and therefore, the staff finds that for elastomeric seals and components in control room area ventilation, auxiliary and radwaste area ventilation, primary containment heating and ventilation, and diesel generator building ventilation systems under internal and external exposure to uncontrolled indoor air do not experience loss of material due to wear. On this basis the staff finds the applicant response
 
acceptable.
 
Therefore, the staff concludes that loss of material due to wear is not an aging effect
 
requiring management for elastomer seals and components exposed to air - indoor uncontrolled (internal or external).
 
Based on the above, the staff concludes SRP-LR Section 3.3.2.2.13 criteria are not applicable.
 
3-366 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. The applicant stated
 
that this aging effect is not applicable because SSES is a BWR.
 
SRP-LR Section 3.3.2.2.14 states that loss of material due to cladding breach may occur in
 
PWR steel charging pump casings with stainless steel cladding exposed to treated borated
 
water.
 
The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed
 
the applicant's claim that SSES has no steel with stainless steel cladding pump casing exposed
 
to treated borated water, an environment only exist in PWR. Therefore, the staff agrees with the
 
applicant's determination that the corresponding AMR result line in the GALL Report is not
 
applicable to SSES.
 
Based on the above, the staff concludes SRP-LR Section 3.3.2.2.14 criteria are not applicable.
 
3.3.2.2.15  Quality Assurance for Aging Management of Nonsafety-Related Components 
 
SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.
 
3.3.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report In LRA Tables 3.3.2-1 through 3.3.2-34, 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 3.3.2-34, the applicant indicated, via notes F through J that the
 
combination of component type, material, environment, and AERM does not correspond to a
 
line item in the GALL Report. The applicant prov ided 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.
3-367  3.3.2.3.1  Aging Management Review Results - Building Drains Nonradioactive System -
 
LRA Table 3.3.2-1 
 
The staff reviewed LRA Table 3.3.2-1, which summarizes the results of AMR evaluations for the
 
building drains nonradioactive system component groups.
 
In LRA Table 3.3.2-1, the applicant proposed to manage loss of material due for cast iron, carbon steel and copper alloy material for piping and piping components exposed to an internal
 
environment of raw water using the AMP B.2.46 "Area-Based NSAS Inspection."
 
The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of
 
material for these components. The AMR line item cites Generic Note G, which indicates that
 
the environment is not addressed in GALL Report for this component and material combination. 
 
The staff's evaluation of the AMP B.2.46 is documented in SER Section 3.0.3.3.1. The staff
 
noted that this program is a plant-specific program that performs an appropriate combination of
 
established volumetric and visual inspecti on techniques (nondestructive examination techniques) that will be performed by a qualified personnel on a sample population of those
 
components in scope of this program. The staff further noted that the applicant will perform the
 
inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such degradation that progresses slowly and have
 
long incubation times will have time to become apparent. The staff determined the inspection
 
techniques will be capable of detecting loss of material and the applicant will initiate corrective
 
actions if an unacceptable loss of material or wall thinning has occurred that may have a spatial
 
interaction with safety-related components, as determined by engineering evaluation. On the
 
basis that the applicant will be performing an appropriate combination of a visual inspection and
 
volumetric testing for these components, the staff finds the AMR results for this line item
 
acceptable.
 
In LRA Table 3.3.2-1, the applicant proposed to manage loss of material due to selective
 
leaching for cast iron and copper alloy material for piping and piping components exposed to an
 
internal environment of raw water using the AMP B.2.29 "Selective Leaching Inspection."
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
G, which indicates that the environment is not addressed in GALL Report for this component
 
and material combination. The staff's evaluation of the AMP B.2.29 is documented in SER
 
Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will perform a
 
combination of visual inspection and hardness testing to determine if loss of material due to
 
selective leaching has occurred. The staff further noted that the applicant will perform the
 
inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and
 
the applicant will initiate corrective actions based on the evaluation of the results of these
 
inspections. The staff noted that the GALL Report recommends the use of the Selective
 
Leaching Program for the same combination of material/environment/aging effect in items
 
VII.C1-10, and VII.C1-11 for different systems. On the basis that the applicant will be
 
performing a combination of a visual inspection and hardness test for these components and
 
these AMR material/environment/aging effect combination is consistent with the GALL AMR 3-368 Item VII.C1-10 and VII.C1-11, for copper alloy and cast iron respectively,  the staff finds the AMR results for this line item acceptable.
 
LRA Table 3.3.2-1 summarizes the results of AMRs for the Building Drains Nonradioactive
 
System piping and piping components constructed out of copper alloy and exposed to indoor air (external). The applicant proposed no aging effect and therefore that no AMP is required. 
 
The applicant has indicated that generic note G is applicable for these items. Generic note G is
 
"Environment not in NUREG-1801 for this component and material." The staff confirmed that
 
this environment is not in GALL for this component and material. The staff also agrees that
 
there will not be any aging mechanism for this material/environment combination and that no
 
AMP is required. This conclusion is based on the fact that comprehensive tests conducted over
 
a 20-year period under ASTM supervision have confirmed the suitability of copper and copper
 
alloys for atmospheric exposure as cited in Metals Handbook, Volume 13, "Corrosion" (American Society for Metals International, 1987).
 
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR
 
results of material, environment, AERM, and AMP combinations not evaluated in the GALL
 
Report. The staff finds that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended function(s) will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.3.2.3.2  Aging Management Review Results - Containment Instrument Gas System -
LRA Table 3.3.2-2 
 
The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations for the
 
containment instrument gas system component groups.
 
In LRA Table 3.3.2-2, the applicant proposed to manage cracking of copper alloy for heat
 
exchanger shells in the Containment Instru ment Gas System exposed to an internal environment of treated water using the AMP B.2.
14 "Closed Cooling Water Chemistry Program."
 
The AMR line item credits the Closed Cooling Water Program to manage cracking for these
 
components. The AMR line item cites Generic Note H, which indicates that the aging effect is
 
not addressed in the GALL Report for this component, material and environment combination.
 
The Closed Cooling Water Chemistry Program is an existing program that properly monitors components and controls corrosion inhibitor concentrations for components, within the scope of
 
license renewal, consistent with relevant EPRI water chemistry guidelines.
 
The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008. The applicant
 
clarified that the one-time inspection performed as part of the AMP B.2.22, "Chemistry Program
 
Effectiveness Inspection" will be used to supplement AMP B.2.14, "Closed Cooling Water
 
Chemistry Program" in all instances where AMP B.2.14 is credited for aging management in LRA Table-2 items, with the exception of the Diesel Jacket Water Cooling System. The staff
 
reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP
 
B.2.22 "Chemistry Program Effectiveness Inspec tion" and its evaluations are documented in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging
 
management program includes activities that are consistent with the recommendations in the GALL AMP XI.M21 to maintain high water purity, which is effective for managing cracking for
 
copper and copper alloy components exposed to a treated water environment. The staff further
 
noted the Closed Cooling Water Chemistry Progr am is an existing program that properly 3-369 monitors components and controls corrosion inhibitor concentrations for components, within the scope of license renewal, consistent with relev ant EPRI water chemistry guidelines. The staff confirmed that the Chemistry Program Effect iveness Inspection will be used to verify the effectiveness of the applicant's Closed Cooli ng Water Chemistry Program to manage cracking and that a combination of appropriate volumetric and visual examination techniques (such as
 
VT-1 or VT-3) will be performed by qualified personnel on a sample population of most
 
susceptible subject components. On this basis, the staff finds that these AMR results will be
 
adequately managed by these programs. 
 
In LRA Table 3.3.2-2, the applicant proposed to manage loss of material due for carbon steel
 
material for piping and piping components exposed to an internal environment of raw water
 
using the AMP B.2.46 "Area-Based NSAS Inspection."
 
The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of
 
material for these components. The AMR line item cites Generic Note G, which indicates that
 
the environment is not addressed in GALL Report for this component and material combination. 
 
The staff's evaluation of the AMP B.2.46 is documented in SER Section 3.0.3.3.1. The staff
 
noted that this program is a plant-specific program that performs an appropriate combination of
 
established volumetric and visual inspecti on techniques (nondestructive examination techniques) that will be performed by a qualified personnel on a sample population of those
 
components in scope of this program. The staff further noted that the applicant will perform the
 
inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such degradation that progresses slowly and have
 
long incubation times will have time to become apparent. The staff determined the inspection
 
techniques will be capable of detecting loss of material and the applicant will initiate corrective
 
actions if an unacceptable loss of material or wall thinning has occurred that may have a spatial
 
interaction with safety-related components, as determined by engineering evaluation. On the
 
basis that the applicant will be performing an appropriate combination of a visual inspection and
 
volumetric testing for these components, the staff finds the AMR results for this line item
 
acceptable.
 
LRA Table 3.3.2-2 summarizes the results of AMRs for the Containment Instrument Gas
 
System copper alloy (brass) heat exchanger shells for compressors exposed to indoor air (external). The applicant proposed no aging effect and therefore that no AMP is required. 
 
The applicant has indicated that generic note G is applicable for these items. Generic note G is
 
"Environment not in NUREG-1801 for this component and material." The staff confirmed that
 
this environment is not in GALL for this component and material. The staff also agrees that
 
there will not be an aging mechanism for this material/environment combination and that no
 
AMP is required because copper alloy in air-indoor internal environment has no aging effect.
 
This conclusion is based on the fact that comprehensive tests conducted over a 20-year period
 
under ASTM supervision have confirmed the suitability of copper and copper alloys for
 
atmospheric exposure which is much more severe than indoor air environment as cited in
 
Metals Handbook, Volume 13, "Corrosion" (American Society for Metals International, 1987).
 
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).
 
3-370 3.3.2.3.3  Aging Management Review Results - Control Rod Drive Hydraulic System -
LRA Table 3.3.2-3 
 
The staff reviewed LRA Table 3.3.2-3, which summarizes the results of AMR evaluations for the
 
CRD hydraulic system component groups.
 
In LRA Tables 3.3.2-3 the applicant proposed to manage cracking in copper alloy piping and
 
piping components, and in aluminum accumulator (pistons), in an environment of treated water
 
by using the BWR Water Chemistry Program. The applicant cited generic note H for these AMR
 
results, indicating that the aging effect is not in the GALL Report for this component, material
 
and environment combination. In a letter dated July 15, 2008, the staff issued RAI 3.2 3, applicable for the copper components and for similar AMR results in LRA Tables 3.2.2-1, 3.2.2-
 
3, 3.3.2-25, and 3.4.2 3. In the same letter, the staff also issued RAI 3.3 2, applicable for the
 
aluminum components. The RAIs asked the applicant to provide a technical justification as to
 
why an inspection program, such as the Chemistry Program Effectiveness Inspection is not
 
needed to confirm that the BWR Water Chemistry Program is effective in preventing the aging
 
effect.
 
In a letter dated August 15, 2008, the applicant responded to RAI 3.2-3 and 3.3-2 by providing
 
the following responses:
 
RAI 3.2-3 Response:
 
For the five AMR results lines listed in LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, 3.3.2-25, and 3.4.2-
 
3, where the material is copper alloy, the environment is treated water (internal), and the aging
 
effect is cracking, verification of the effectiveness of the BWR Water Chemistry Program is
 
needed. The Chemistry Program Effectiveness Ins pection will provide confirmation of the effectiveness of this program in managing the effects of aging, including cracking in susceptible
 
materials. LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, 3.3.2-25, and 3.4.2-3 are revised to reflect these
 
results.
 
RAI 3.3-2 Response:
 
For the AMR results item listed on page 3.3-103 of the LRA for accumulator (pistons) made of
 
aluminum in a treated water environment with an aging effect of cracking, verification of the
 
effectiveness of the BWR Water Chemistr y Program is needed. The Chemistry Program Effectiveness Inspection will provide confirmati on of the effectiveness of this program in managing the effects of aging, including cracking of susceptible materials. The affected LRA
 
Tables are revised. 
 
The staff reviewed the applicant's response and the associated LRA changes. The staff
 
reviewed the applicant's BWR Water Chemistry Pr ogram. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water Chemistry Program
 
provides mitigation for the aging effect of cracking due to stress corrosion cracking. The staff
 
reviewed the applicant's Chemistry Program Effe ctiveness Inspection. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the Chemistry
 
Program Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "O ne-Time Inspection." The Chemistry Program Effectiveness Inspection includes provisions for inspecting selected components in areas of low
 
or stagnant flow and uses examination techniques that are capable of detecting cracking, if it
 
should occur in the selected components. Because the BWR Water Chemistry Program
 
provides mitigation and the Chemistry Program Effectiveness Inspection provides detection of the aging effect if it should occur, the staff finds the applicant's proposed AMPs for managing 3-371 the potential aging effect of cracking in copper alloy piping and piping components and in aluminum accumulator (pistons) exposed to treat ed water in the control rod drive hydraulic system to be acceptable. On this basis, the staff finds that the issues raised in RAIs 3.2 3 and
 
3.3-2 are resolved by the applicant's LRA changes.
 
LRA Table 3.3.2-3 summarizes the results of AM Rs for control rod drive hydraulics system piping and piping components constructed using copper alloy exposed to indoor air (external).
 
The applicant proposed that there is no aging effect for the material environment combination
 
and that no AMR is required.
 
The applicant has indicated that generic note G is applicable for these items. Generic note G is
 
"Environment not in NUREG-1801 for this component and material." The staff confirmed that
 
this environment is not in GALL for the component and material. The staff also agrees that there
 
will not be an aging mechanism for this material/environment combination, and that no AMP is
 
required.
 
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR
 
results of material, environment, AERM, and AMP combinations not evaluated in the GALL
 
Report. The staff finds that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended function(s) will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.3.2.3.4  Aging Management Review Results - Control Structure Chilled Water System -
 
LRA Table 3.3.2-4 
 
The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations for the
 
control structure chilled water system component groups.
 
In LRA Table 3.3.2-4, the applicant proposed to manage cracking of copper alloy for chiller
 
evaporator and oil cooler tubes and plugs in the Control Structure Chilled Water System
 
exposed to an internal and external environment of treated water using the AMP B.2.14 "Closed Cooling Water Chemistry Program."
 
The AMR line item credits the Closed Cooling Water Program to manage cracking for these
 
components. The AMR line item cites Generic Note H, which indicates that the aging effect is
 
not addressed in the GALL Report for this component, material and environment combination.
 
The Closed Cooling Water Chemistry Program is an existing program that properly monitors components and controls corrosion inhibitor concentrations for components, within the scope of
 
license renewal, consistent with relevant EPRI water chemistry guidelines. 
 
The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008. The applicant
 
clarified that the one-time inspection performed as part of the AMP B.2.22, "Chemistry Program
 
Effectiveness Inspection" will be used to supplement AMP B.2.14, "Closed Cooling Water
 
Chemistry Program" in all instances where AMP B.2.14 is credited for aging management in LRA Table-2 items, with the exception of the Diesel Jacket Water Cooling System. The staff
 
reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP
 
B.2.22 "Chemistry Program Effectiveness Inspec tion" and its evaluations are documented in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging
 
management program includes activities that are consistent with the recommendations in the GALL AMP XI.M21 to maintain high water purity, which is effective for managing cracking for
 
copper and copper alloy components exposed to a treated water environment. The staff further 3-372 noted the Closed Cooling Water Chemistry Progr am is an existing program that properly monitors components and controls corrosion inhibitor concentrations for components, within the
 
scope of license renewal, consistent with relev ant EPRI water chemistry guidelines. The staff confirmed that the Chemistry Program Effect iveness Inspection will be used to verify the effectiveness of the applicant's Closed Cooli ng Water Chemistry Program to manage cracking and that a combination of appropriate volumetric and visual examination techniques (such as
 
VT-1 or VT-3) will be performed by qualified personnel on a sample population of most
 
susceptible subject components. On this basis, the staff finds that these AMR results will be
 
adequately managed by these programs. 
 
In LRA Table 3.3.2-4, the applicant proposed to manage reduction of heat transfer for copper
 
alloy greater than 15 percent zinc material for chiller oil cooler tube tubes exposed to an
 
external environment of lubricating oil using the Lubricating Oil Analysis Program, supplemented by the Lubricating Oil Inspection. The AMR line item cites Generic Note H, which indicates that
 
the aging effect is not addressed in the GALL Report for this component, environment and
 
material combination.
 
The staff evaluated the Lubricating Oil Analysis Program and the Lubricating Oil Inspection
 
Program, and the evaluations are documented in SER Sections 3.0.3.2.15 and 3.0.3.2.13, respectively. The Lubricating Oil Analysis Progr am is an existing program, that when enhanced, will include sample locations from the Control Structure Chiller, and will properly monitor
 
relevant conditions, such as particulate and water concentrations, viscosity, neutralization
 
number and flash point, that can lead to start and spread of loss of material or reduction in heat
 
transfer capability. The program's monitoring is based on manufacturer's recommendations, equipment importance and accessibility and American Society for Testing of Materials (ASTM)
 
standards for lubricating oils. The applicant will supplement this program with the Lubricating
 
Oil Inspection, which will provide direct evidence as to whether and to what extent reduction of heat transfer has occurred, thus providing evi dence of the effectiveness of the Lubricating Oil Analysis Program. On the basis of its review, the staff finds that because these the lubricating
 
oil in contact with these components will proper ly monitor relevant conditions, such as particulate and water concentrations, viscosity, neutralization number and flash point and then
 
supplemented by a one-time inspection, "Lubricating Oil Inspection"  to confirm program
 
effectiveness that the aging effect of reduction in heat transfer of copper alloy greater than 15
 
percent zinc exposed to an external envir onment of lube oil will be adequately managed by these programs.
 
In LRA Table 3.3.2-4, the applicant proposed to manage loss of material due to selective
 
leaching for copper alloy material for valve bodi es exposed to an external environment of indoor air using the AMP B.2.29 "Selective Leaching Inspection."
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
H, which indicates that the aging effect is not addressed in the Gall Report for this component, material and environment combination. The staff's evaluation of the AMP B.2.29 is documented
 
in SER Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will
 
perform a combination of visual inspection and hardness testing to determine if loss of material
 
due to selective leaching has occurred. The staff further noted that the applicant will perform
 
the inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective 3-373 leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and the applicant will initiate corrective actions based on the evaluation of the results of these
 
inspections. On the basis that the applicant will be performing a combination of a visual
 
inspection and hardness test, which is consistent with the with the recommendations in GALL AMP XI.M33, for these components,  the staff finds the AMR results for this line item.
 
In Table 3.3.2-4, the LRA states that for glass skid-mounted sight glass components under
 
internal exposure to an air-gas environment, there are no aging effects identified and no aging
 
management program is required. The staff found that the plant specific AMR for the exposure
 
of the glass skid-mounted sight glass components under internal exposure to an air-gas
 
environment (an uncontrolled air environment) was consistent with the AMR in GALL Report item VII.J-08 for exposure of glass components to uncontrolled indoor air environments. Based on this review, the staff finds that the applicant has provided a valid basis for concluding that
 
there are not any AERMs for the glass skid-mounted sight glass components because the
 
applicant's AMR is consistent with GALL Report item VII.J-08.
 
LRA Table 3.3.2-4 summarizes the results of AMRs for the Control Structure Chilled Water
 
System copper tubing (skid mounted) exposed to lubricating oil (internal). The applicant
 
proposed no aging effect and therefore that no AMP is required. 
 
The applicant has indicated that generic note I is applicable for these items. Generic note I is
 
"Aging effect in NUREG-1801 for this component, material, and environment is not applicable."
 
Plant specific note 310 stated that "copper contains less than 15% zinc, and therefore is not
 
susceptible to loss of material in this environment." The staff agrees that there will not be an
 
aging mechanism for this material/environment combination for copper tubing containing less
 
than 15% Zn and that no AMP is required. The GALL Report line items V EP-11-I, VII AP-10-J
 
and VIII SP-7-I have copper alloy exposed to lubricating oil with no aging effect and no aging
 
management program required. The same will be true for the Control Structure Chilled 
 
Water System copper tubing because it has the same material/environment combination as the
 
GALL Report Chapter V and VII material/environment and will have the same aging effect and
 
aging management program.
 
LRA Table 3.3.2-4 summarizes the results of AMRs for the Control Structure Chilled Water
 
System sight gauges (skid mounted) constructed fr om glass and exposed to air-gas (internal).
The applicant proposed no aging effect and therefore that no AMP is required.
 
The applicant has indicated that generic note G is applicable for these items. Generic note G is
 
"Environment not in NUREG-1801 for this component and material." The staff confirmed that
 
this environment is not in GALL for this component and material. The staff also agrees that
 
there will not be an aging mechanism for this material/environment combination and that no
 
AMP is required. This conclusion is based on the fact that there have been no aging effects
 
observed for glass components in this environment. Ref: Handbook of Glass Properties, N. P.
 
Bansal and R. H. Doremua, Academic Press 1986, pg. 646.
 
The staff reviewed LRA Table 3.3.2-4 which summarizes the results of AMRs for the Control
 
Structure Chilled Water System copper alloy (copper-nickel or brass) chiller tube plugs. The
 
applicant proposed that this system meets t he definitions given above and therefore the environment, aging effect requiring management, and AMR should be classified as not
 
applicable. The staff agrees with this proposal because these components do not have an
 
internal surface because they are solid and therefore, there will not be an aging effect requiring
 
an AMP.
3-374  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  Aging Management Review Result s - Control Structure HVAC Systems -
LRA Table 3.3.2-5 
 
The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for the
 
control structure HVAC systems component groups.
 
In LRA Table 3.3.2-5, the applicant proposed to manage cracking of copper alloy for heating
 
and ventilation unit structure channels and cooling unit control and computer room channels in
 
the Control Structure HVAC System exposed to an internal and external environment of treated water using the AMP B.2.14 "Closed Cooling Water Chemistry Program."
 
The AMR line item credits the Closed Cooling Water Program to manage cracking for these
 
components. The AMR line item cites Generic Note H, which indicates that the aging effect is
 
not addressed in the GALL Report for this component, material and environment combination.
 
The Closed Cooling Water Chemistry Program is an existing program that properly monitors components and controls corrosion inhibitor concentrations for components, within the scope of
 
license renewal, consistent with relevant EPRI water chemistry guidelines.
 
The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008. The applicant
 
clarified that the one-time inspection performed as part of the AMP B.2.22, "Chemistry Program
 
Effectiveness Inspection" will be used to supplement AMP B.2.14, "Closed Cooling Water
 
Chemistry Program" in all instances where AMP B.2.14 is credited for aging management in LRA Table-2 items, with the exception of the Diesel Jacket Water Cooling System. The staff
 
reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP
 
B.2.22 "Chemistry Program Effectiveness Inspec tion" and its evaluations are documented in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging
 
management program includes activities that are consistent with the recommendations in the GALL AMP XI.M21 to maintain high water purity, which is effective for managing cracking for
 
copper and copper alloy components exposed to a treated water environment. The staff further
 
noted the Closed Cooling Water Chemistry Progr am is an existing program that properly monitors components and controls corrosion inhibitor concentrations for components, within the
 
scope of license renewal, consistent with relev ant EPRI water chemistry guidelines. The staff confirmed that the Chemistry Program Effect iveness Inspection will be used to verify the effectiveness of the applicant's Closed Cooli ng Water Chemistry Program to manage cracking and that a combination of appropriate volumetric and visual examination techniques (such as
 
VT-1 or VT-3) will be performed by qualified personnel on a sample population of most
 
susceptible subject components. On this basis, the staff finds that these AMR results will be
 
adequately managed by these programs.
 
In LRA Table 3.3.2-5, the applicant proposed to manage loss of material due for carbon steel
 
material for piping and piping components and humidifier housings exposed to an internal
 
environment of raw water using the AMP B.2.46 "Area-Based NSAS Inspection."
 
The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of 3-375 material for these components. The AMR line item cites Generic Note G, which indicates that the environment is not addressed in GALL Report for this component and material combination. 
 
The staff's evaluation of the AMP B.2.46 is documented in SER Section 3.0.3.3.1. The staff
 
noted that this program is a plant-specific program that performs an appropriate combination of
 
established volumetric and visual inspecti on techniques (nondestructive examination techniques) that will be performed by an qualified personnel on a sample population of those
 
components in scope of this program. The staff further noted that the applicant will perform the
 
inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such degradation that progresses slowly and have
 
long incubation times will have time to become apparent. The staff determined the inspection
 
techniques will be capable of detecting loss of material and the applicant will initiate corrective
 
actions if an unacceptable loss of material or wall thinning has occurred that may have a spatial
 
interaction with safety-related components, as determined by engineering evaluation. On the
 
basis that the applicant will be performing an appropriate combination of a visual inspection and
 
volumetric testing for these components, the staff finds the AMR results for this line item
 
acceptable.
 
In LRA Table 3.3.2-5, the applicant proposed to manage loss of material due to selective
 
leaching for copper alloy material for the computer room floor cooling unit, control room floor
 
cooling unit and the control structure heating and ventilation unit exposed to an external
 
environment of indoor air using the AMP B.2.29 "Selective Leaching Inspection."  By letter dated
 
July 25, 2008 the applicant amended its LRA to credit AMP B.2.29 for aging management of
 
these AMR line items.
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
H, which indicates that the aging effect is not addressed in the Gall Report for this component, material and environment combination. The staff's evaluation of the AMP B.2.29 is documented
 
in SER Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will
 
perform a combination of visual inspection and hardness testing to determine if loss of material
 
due to selective leaching has occurred. The staff further noted that the applicant will perform
 
the inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and
 
the applicant will initiate corrective actions based on the evaluation of the results of these
 
inspections. On the basis that the applicant will be performing a combination of a visual
 
inspection and hardness test, which is consistent with the with the recommendations in GALL AMP XI.M33, for these components,  the staff finds the AMR results for this line item 
 
LRA Table 3.3.2-5 summarizes the results of AMRs for the Control Structure HVAC System
 
cooling unit, cooling coils, copper alloy (brass), copper tubing, flow element valve bodies, computer and control room floor cooling co ils, and aluminum flow elements exposed to ventilation (internal and external). The applicant proposed no aging effect and therefore that no
 
AMP is required.
 
The applicant has indicated that generic note G is applicable for these items. Generic note G is
 
"Environment not in NUREG-1801 for this component and material." The staff confirmed that
 
this environment is not in GALL for this component and material. The staff also agrees that
 
there will not be an aging mechanism for this material/environment combination and that no 3-376 AMP is required. The staff noted aluminum has an excellent resistance to corrosion when exposed to a humid air (outdoor environment). In most environments the aluminum oxide film bonds strongly to its surface and if damaged, reforms immediately. 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 corrosion. Therefore, aluminum exposed to an outdoor air environment has no applicable aging effect. (M. G. Fontana, "Corrosion Engineering, Third Edition, McGraw-Hill, 1986.)  Copper alloy in an air-indoor internal environment has no
 
aging effect. This conclusion is based on the fact that comprehensive tests conducted over a
 
20-year period under ASTM supervision have confirmed the suitability of copper and copper
 
alloys for atmospheric exposure as cited in Metals Handbook, Volume 13, "Corrosion" (American Society for Metals International, 1987). 
 
The staff reviewed LRA Table 3.3.2-5 which summarizes the results for the Control Structure
 
HVAC System air strengtheners and fins constr ucted out of aluminum. The applicant proposed that this system meets the definitions giv en above and therefore the environment, aging effect requiring management, and AMR should be classified as not applicable. The staff agrees with
 
this proposal because these components do not have an internal surface because they are solid
 
and therefore, there will not be an aging effect requiring an AMP.
 
In LRA Table 3.3.2-5, the applicant proposed to manage reduction of heat transfer of aluminum
 
cooling unit fins in an external environment of ventilation by using the Cooling Units Inspection Program. The applicant referenced footnote "H" for this line item indicating that aging effect is
 
not in the GALL Report for this component, material and environment combination. 
 
The staff noted the Cooling Unit Inspection Program will detect and characterize the condition of
 
cooling unit components that are exposed to a ventilation environment, and provides direct evidence as to whether and to what extent, reduction of heat transfer has occurred, or is likely
 
to occur that could result in a loss of intended function. In its letter dated July 25, 2008, the
 
applicant responded to RAI B.2.23-2 stating that visual inspection (VT-3 or equivalent)
 
techniques will be used to determine whether reduction in heat transfer is occurring. The
 
applicant also stated that the specific inspection technique will be determined prior to the inspection activities and will be consistent with the recommendations in GALL AMP XI.M32. The
 
staff's evaluation of the Cooling Units Inspection Program is documented in SER Section
 
3.0.3.1.11. Because the Cooling Units Inspection Program performs visual inspection to
 
determine if any fouling has occurred that could cause reduction of heat transfer, and on the
 
basis that the visual inspection technique will be consistent with the recommendation in GALL AMP XI.M32, the staff finds the Cooling Units Inspection Program will adequately manage the
 
aging effect of reduction of heat transfer in cooling unit components exposed to a ventilation
 
environment.
 
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  Aging Management Review Results -
Cooling Tower System - LRA Table 3.3.2-6 
 
The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations for the
 
cooling tower system component groups. The staff determined that all AMR evaluation
 
results in LRA Table 3.3.2-6 are consistent with the GALL Report.
3-377  3.3.2.3.7  Aging Management Review Results - Diesel Fuel Oil System - LRA Table 3.3.2-7 
 
The staff reviewed LRA Table 3.3.2-7, which summarizes the results of AMR evaluations for the
 
diesel fuel oil system component groups.
 
In LRA Table 3.3.2-7 the applicant proposed to manage cracking in copper alloy level gauges, orifices, tubing, and valve bodies in an environment of fuel oil using the Fuel Oil Chemistry Program, alone. The staff noted that the Fuel Oil Chemistry Program does not include a
 
component inspection activity and issued RAI 3.3-5 by letter dated July 15, 2008, asking the
 
applicant to explain how effectiveness of the Fuel Oil Chemistry Program will be confirmed for these components.
 
In a letter dated August 15, 2008, the applicant responded to RAI 3.3-5 by providing the
 
following response:
 
For the seven AMR result lines listed in LRA Table 3.3.2-7, where the aging effect is cracking
 
and the AMP is designated as the Fuel Oil Chemistry Program, verification of the effectiveness
 
of the Fuel Oil Chemistry Program is needed to confirm that cracking is not occurring in these
 
components.
 
The Chemistry Program Effectiveness Inspection will detect and characterize the condition of materials managed by the Fuel Oil Chemistry Program. Implementation of the Chemistry Program Effectiveness Inspection will provide conf irmation of the effectiveness of this program in managing the effects of aging, including cracking of the susceptible materials.
 
The applicant revised the seven (7) affected lines in LRA Table 3.3.2-7 to show that the Fuel Oil
 
Chemistry Program in combination with the C hemistry Program Effectiveness Inspection will be used to manage the aging effect of cracking for copper alloy components exposed to fuel oil in
 
the diesel fuel oil system.
 
The staff reviewed the applicant's Fuel Oil Chemistry Program. The staff's evaluation of this
 
program, which is documented in SER Section 3.0.3.2.1, found that the Fuel Oil Chemistry
 
Program provides aging management for loss of material and is also credited with mitigating the
 
aging effect of cracking in susceptible materials through monitoring and control of fuel oil
 
contamination such as water or microbiological organisms, which might produce ammonia that
 
would cause cracking in copper alloy. The staff reviewed the applicant's Chemistry Program
 
Effectiveness Inspection. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the Chemistry Program Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "One-
 
Time Inspection." The Chemistry Program Effe ctiveness Inspection includes provisions for inspecting selected components determined to be most susceptible to the aging effect(s) of
 
interest and uses examination techniques that are capable of detecting cracking if it should
 
occur in the selected components. Based on the applicant's use of a one-time inspection
 
consistent with the recommendations of the GALL Report, the staff finds the applicant's
 
proposed AMPs provide both mitigation and detection for the potential aging effect of cracking
 
in copper alloy components exposed to fuel oil in the diesel fuel oil system. On this basis, the
 
staff finds that the applicant's proposed AMPs provide adequate aging management and that
 
the issue raised in RAI 3.3-5 is resolved by the applicant's LRA changes.
 
In LRA Table 3.3.2-7, the applicant proposed to manage loss of material due to selective 3-378 leaching for cast iron and copper alloy material for level gauges, orifices, piping/tubing, pump casings and valve bodies exposed to an internal environment of fuel oil using the AMP B.2.29
 
"Selective Leaching Inspection."
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
H, which indicates that the aging effect is not addressed in the Gall Report for this component, material and environment combination. The staff's evaluation of the AMP B.2.29 is documented
 
in SER Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will
 
perform a combination of visual inspection and hardness testing to determine if loss of material
 
due to selective leaching has occurred. The staff further noted that the applicant will perform
 
the inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and
 
the applicant will initiate corrective actions based on the evaluation of the results of these
 
inspections. On the basis that the applicant will be performing a combination of a visual
 
inspection and hardness test, which is consistent with the with the recommendations in GALL AMP XI.M33, for these components,  the staff finds the AMR results for this line item.
 
In LRA Table 3.3.2-7, the applicant proposed to manage loss of material of carbon steel tanks in
 
an external environment of ventilation by us ing the Supplementary Piping/Tank Inspection Program. The applicant referenced footnote "G" for th is line item indicating that environment is not in the GALL Report for this component and material combination. The environment is an
 
aggressive environment of air-water interface.
 
The staff reviewed the Supplementary Piping/Tank Inspection Program, which uses a
 
combination of volumetric and visual examination techniques to identify evidence of loss of
 
material or lack thereof. The staff's evaluation of the Supplementary Piping/Tank Inspection
 
Program is documented in SER Section 3.0.3.1.16. Because the Supplementary Piping/Tank
 
Inspection is performed at very specific locations of air/water interface, and employs a
 
combination of volumetric and visual inspection techniques, the staff finds that the
 
Supplementary Piping/Tank Inspection Program will adequately manage the aging effects of
 
loss of material in this aggressive environment.
 
In Table 3.3.2-7, the LRA states that for synthetic rubber flexible connections in a fuel oil
 
internal environment in the diesel fuel oil system, there are no aging effects requiring
 
management. In RAI 3.3.2.3-1, part A by letter dated July 23, 2008, the staff asked the applicant
 
to justify why it had not identified any aging effects requiring management for these system-
 
material-environment combinations. In RAI 3.3.2.3-1, part B, the staff asked the applicant to
 
identify those material properties that could be impacted by exposure of these materials and
 
other materials such as plastic, synthetic rubber, butyl rubber and Teflon, to either a treated
 
water, raw water, fuel oil, lubricating oil, ventilation air, indoor air, and air-gas (including Freon)
 
environments. Finally, in RAI 3.3.2.3-1, part C, the staff asked the applicant to identify the AMP
 
that will be credited for aging management if PPL does identify that are applicable AERMs for
 
any of these system-materia l-environmental combinations.
 
In its letter dated August 27, 2008, in response to RAI 3.3.2.3-1 part A, the applicant stated that
 
the applicable aging effects for elastomers (including butyl rubber, synthetic rubber, neoprene, and silicone) are change in material properties and cracking, which may be due to ionizing 3-379 radiation, thermal exposure, and exposure to ultraviolet radiation or ozone. The applicant provided the threshold level for ionizing radiation as 10E6 rads, for temperature as greater than
 
95oF, and for ultraviolet radiation and ozone as prolonged exposure. The applicant further
 
stated that, except for certain areas in the Reactor Building, where ionizing radiation could be
 
more than the threshold limit, the other buildings are all in an environment that is within the
 
threshold limits. Therefore, the applicant concluded that there are no aging effects requiring
 
management for synthetic rubber flexible connections in a fuel oil internal environment in the diesel fuel oil system.
 
In response to RAI 3.3.2.3-1, part B, the applicant stated that the specific material properties
 
that could be impacted by exposure to treated water, raw water, fuel oil, lubricating oil, ventilation air, indoor air, and air-gas (including Freon) environments are hardening (e.g.,
embrittlement, decrease in elasticity) and loss of strength (e.g., elongation, loss of tensile
 
strength, and, with exposure to ionizing radiation, swelling or melting). The applicant further
 
stated that hardening and loss of strength could occur as a result of prolonged exposure to high
 
temperature, high radiation levels, or to ultraviolet radiation or ozone. 
 
In response to RAI 3.3.2.3.-1, part C, the applicant stated that there are no aging effects
 
requiring management for the system-material-environment combinations listed in RAI 3.3.2.3-1, except for those that have already been identified in the LRA as noted in the response to Part
 
B.
 
The staff reviewed the applicant response to RAI 3.3.2.3-1, parts A, B and C, and finds the
 
applicant response acceptable because the applicant defined the stressors that could cause the
 
aging effects in various structures. The applicant response is consistent with the GALL Report
 
definitions of the threshold limits of the stressors as recommended in the GALL Report Section IX. On the basis of its review, the staff finds for synthetic rubber flexible connections in a fuel oil
 
internal environment in the diesel fuel oil system, there are no 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. 
 
LRA Table 3.3.2-7, summarizes the results of AMRs for the Diesel Fuel Oil System, orifices
 
constructed using copper alloy (brass), level gauges (day tank) constructed from copper alloy (bronze), heat exchangers channels, covers and shells constructed from copper alloy (copper-
 
nickel), valve bodies and tubing (and fittings) constructed from copper alloy (brass and bronze)
 
exposed to indoor air (external), level gauges (day tank) constructed from copper alloy (brass)
 
exposed to ventilation (internal), and piping and piping components constructed from copper
 
and exposed to lubricating oil (internal). The applicant proposes that for these combinations of
 
components, materials and environment conditions, there is no aging effect requiring
 
management and therefore that no AMR is required. 
 
The applicant has indicated that the GALL note G is applicable for these items. Note G is
 
"Environment not in NUREG-1801 for this component and material." The staff confirmed that
 
this environment is not in the GALL for these components and materials. The staff also agrees
 
that there will not be an aging mechanism for this material/environment combination and that no
 
AMP is required. Copper alloy in an air-indoor internal environment has no aging effect. This
 
conclusion is based on the fact that comprehensive tests conducted over a 20-year period
 
under ASTM supervision have confirmed the suitability of copper and copper alloys for 3-380 atmospheric exposure as cited in Metals Handbook, Volume 13, "Corrosion" (American Society for Metals International, 1987). 
 
LRA Table 3.3.2-7 summarizes the results of an AMR for the Diesel Fuel Oil System piping and
 
piping components constructed from carbon steel and exposed to outdoor air (external). The
 
applicant claims that for these combinations of components, materials and environment there is
 
no aging effect requiring management and therefore no AMR is required. The applicant
 
references plant specific note 0361. Plant specific note 0361 states, Nonsafety-related vent and
 
fill piping and piping components in the Diesel Fuel Oil System are normally empty and are attached to safety-related components (storage tanks or piping) that are anchored in below
 
grade vaults or within Seismic Category I buildings. As such, degradation of the vent and fill
 
piping or piping components will not result in a loss of support for safety-related components to
 
which they are attached. Also, there is no high pressure, other motive force, or medium in the
 
air to cause degradation."  Because these components are normally empty, and because even if
 
for some reason, they would fail, they would not affect the intended function of safety related
 
components, and they are not in scope for license renewal the staff finds this to be acceptable.
 
The applicant also references Table 3.3.1-58 which covers "Steel external surfaces exposed to
 
air-indoor uncontrolled (external), air-outdoor (external), and condensation (external)" and
 
identifies the aging effect as "Loss of material due to general corrosion" and the AMP as
 
External Surfaces Monitoring. The LRA, in t he discussion section states "The System Walkdown Program also manages loss of material due to crevice and/or pitting corrosion due to
 
condensation." The discussion states that this AMR is consistent with GALL while the line item
 
in Table 3.3.2-7 reference note I, which states that the aging effect is not applicable.
 
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  Aging Management Review Results -
Diesel Generator Buildings HVAC Systems -
LRA Table 3.3.2-8 
 
The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for the
 
diesel generator buildings HVAC systems component groups.
 
LRA Table 3.3.2-8 summarizes the results of AMRs for the Diesel Generator Building HVAC
 
System flexible connectors (ductwork) constructed from neoprene/fiberglass and neoprene/asbestos and neoprene exposed to ventilation (internal) and indoor air (external). The
 
applicant proposes that these components, materials, environment combinations have no aging
 
effects requiring management and therefore no AMP is required.
 
The applicant has indicated that generic note I is applicable for these items. Generic note I is
 
"Aging effect in NUREG-1801 for this component, material, and environment is not applicable." 
 
The staff agrees that there will not be an aging mechanism for this material/environment
 
combination.
 
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR
 
results of material, environment, AERM, and AMP combinations not evaluated in the GALL
 
Report. The staff finds that the applicant has demonstrated that the effects of aging will be 3-381 adequately managed so that the intended 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  Aging Management Review Results - Di esel Generators System - LRA Table 3.3.2-9 
 
The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for the
 
diesel generators system component groups.
 
In LRA Table 3.3.2-9, the applicant proposed to manage loss of material of nickel alloy (monel)
 
for heat exchanger heating core tube plugs in t he Diesel Generator Intake/Exhaust System exposed to an internal environment of treated water using the AMP B.2.14 "Closed Cooling
 
Water Chemistry Program."
 
The AMR line item credits the AMP B.2.14 "Clo sed Cooling Water Chemistry Program." to manage loss of material for these components. The AMR line item cites Generic Note G, which
 
indicates that the environment is not addressed in GALL Report for this component and material
 
combination. The Closed Cooling Water Chemistry Program is an existing SSES program that
 
properly monitors components and controls corrosion inhibitor concentrations for components, within the scope of license renewal, consistent with relevant EPRI water chemistry guidelines.
 
The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008 and supplemented
 
its response by letter dated December 11, 2008. The applicant clarified that the one-time
 
inspection performed as part of the AMP B.2.22, "Chemistry Program Effectiveness Inspection" will be used to supplement AMP B.2.14, "Clos ed Cooling Water Chemistry Program" in all instances where AMP B.2.14 is credited for aging management in LRA Table-2 items, with the
 
exception of the Diesel Jacket Water Cooling System. The staff reviewed the applicant's SSES
 
AMP B.2.14 "Closed Cooling Water Chemistr y Program" and AMP B.2.22 "Chemistry Program Effectiveness Inspection" and its evaluations are documented in SER Section 3.0.3.2.7 and
 
3.0.3.1.10, respectively. The staff verified that this aging management program includes activities that are consistent with the recommendations in the GALL AMP XI.M21 to maintain
 
high water purity, which is effective for managing loss of material for nickel alloy components
 
exposed to a treated water environment. The staff further noted the Closed Cooling Water
 
Chemistry Program is an existing program t hat properly monitors components and controls corrosion inhibitor concentrations for components, within the scope of license renewal, consistent with relevant EPRI water chemistry guidelines. The staff confirmed that the
 
Chemistry Program Effectiveness Inspection will be used to verify the effectiveness of the applicant's Closed Cooling Water Chemistry Program to manage loss of material and that a
 
combination of appropriate volumetric and visual examination techniques (such as VT-1 or VT-
: 3) will be performed by qualified personnel on a sample population of most susceptible subject
 
components. On this basis, the staff finds that these AMR results will be adequately managed
 
by these programs. 
 
In LRA Table 3.3.2-9, the applicant proposed to manage cracking of copper alloy for piping, piping components, tubing, fittings, valve bodies, heater immersion sheaths, and heat
 
exchanger components in the Diesel Generator Lubr icating Oil, Jacket Water, Intake/Exhaust and NSAS Component System exposed to an internal or external environment of treated water using the AMP B.2.14 "Closed Cooling Water Chemistry Program."
 
The AMR line item credits the Closed Cooling Water Program to manage cracking for these
 
components. The AMR line item cites Generic Note H, which indicates that the aging effect is
 
not addressed in the GALL Report for this component, material and environment combination.
3-382 The Closed Cooling Water Chemistry Program is an existing program that properly monitors components and controls corrosion inhibitor concentrations for components, within the scope of
 
license renewal, consistent with relevant EPRI water chemistry guidelines.
 
The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008. The applicant
 
clarified that the one-time inspection performed as part of the AMP B.2.22, "Chemistry Program
 
Effectiveness Inspection" will be used to supplement AMP B.2.14, "Closed Cooling Water
 
Chemistry Program" in all instances where AMP B.2.14 is credited for aging management in LRA Table-2 items, with the exception of the Diesel Jacket Water Cooling System. The staff
 
reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP
 
B.2.22 "Chemistry Program Effectiveness Inspec tion" and its evaluations are documented in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging
 
management program includes activities that are consistent with the recommendations in the GALL AMP XI.M21 to maintain high water purity, which is effective for managing cracking for
 
copper and copper alloy components exposed to a treated water environment. The staff further
 
noted the Closed Cooling Water Chemistry Progr am is an existing program that properly monitors components and controls corrosion inhibitor concentrations for components, within the
 
scope of license renewal, consistent with relev ant EPRI water chemistry guidelines. The staff confirmed that the Chemistry Program Effect iveness Inspection will be used to verify the effectiveness of the applicant's Closed Cooli ng Water Chemistry Program to manage cracking and that a combination of appropriate volumetric and visual examination techniques (such as
 
VT-1 or VT-3) will be performed by qualified personnel on a sample population of most
 
susceptible subject components. On this basis, the staff finds that these AMR results will be
 
adequately managed by these programs. 
 
In LRA Table 3.3.2-9, the applicant proposed to manage loss of material for aluminum material
 
for heat exchanger shells exposed to an internal environment of lubricating oil using the
 
Lubricating Oil Analysis Program, supplemented by the Lubricating Oil Inspection. The AMR line item cites Generic Note G, which indicates that the environment is not addressed in GALL
 
Report for this component and material combination.
 
The staff evaluated the Lubricating Oil Analysis Program and the Lubricating Oil Inspection
 
Program, and the evaluations are documented in SER Sections 3.0.3.2.15 and 3.0.3.2.13, respectively. The Lubricating Oil Analysis Pr ogram is an existing SSES program that will properly monitor relevant conditions, such as particulate and water concentrations, viscosity, neutralization number and flash point that can lead to start and spread of loss of material or
 
reduction in heat transfer capability. The program's monitoring is based on manufacturer's
 
recommendations, equipment importance and accessibility and American Society for Testing of
 
Materials (ASTM) standards for lubricating oils. The applicant will supplement this program with
 
the Lubricating Oil Inspection, which will provi de direct evidence as to whether and to what extent reduction of heat transfer has occurred, t hus providing evidence of the effectiveness of the Lubricating Oil Analysis Program. On the basis of its review, the staff finds that because
 
these the lubricating oil in contact with these components will properly monitor relevant conditions, such as particulate and water concentrations, viscosity, neutralization number and
 
flash point and then supplemented by a one-time inspection, "Lubricating Oil Inspection"  to
 
confirm program effectiveness that the aging effect of loss of material of aluminum exposed to an external environment of lube oil w ill be adequately managed by these programs.
 
In LRA Table 3.2.2-9, the applicant proposed to manage reduction of heat transfer in copper
 
alloy heat exchanger tubes in an external environm ent of lubricating oil by using the Piping Corrosion Program. The applicant referenced footnote H for this line item indicating that aging 3-383 effect is not in the GALL Report for this component, material and environment combination.
However, the staff noted that GALL Report item V.D2-9 has the same aging effect for this
 
component, material and environment. The GALL Report recommends GALL AMP XI.M39, Lubricating Oil Analysis, and  GALL AMP XI.M32, One-Time Inspection. Since the internal
 
environment of these tubes is raw water, these heat exchangers are included in the GL 89-13
 
program. Therefore, the applicant is proposing to use the Piping Corrosion Program, which is consistent with GALL AMP XI.M20, Open-Cycle Cooling Water System.
 
The staff reviewed the Piping Corrosion Program, which is a combination of condition
 
monitoring program (consisting of inspections, su rveillances, and testing to detect the presence of, and to assess the extent of, fouling and loss of material) and a mitigation program (consisting of chemical treatments and cleaning activities to minimize fouling and loss of
 
material). The staff's evaluation of the Piping Corrosion program is documented in SER Section
 
3.0.3.2.6. Because the Piping Corrosion Program includes both the chemistry treatment and
 
cleaning for mitigation and inspection for verification, the staff finds that the Piping Corrosion
 
Program will adequately manage the aging effects of reduction of heat transfer in copper alloy
 
heat exchanger tubes in an external environment of lubricating oil through the period of
 
extended operation.
 
In Table 3.3.2-9, the LRA states that for synthetic rubber flexible connections in a lubricating oil
 
internal environment in the diesel generator system, there are no aging effects requiring management. In RAI 3.3.2.3-1, part A by letter dated July 23, 2008, the staff asked the applicant
 
to justify why it had not identified any aging effects requiring management for these system-
 
material-environment combinations. In RAI 3.3.2.3-1, part B, the staff asked the applicant to
 
identify those material properties that could be impacted by exposure of these materials and
 
other materials such as plastic, synthetic rubber, butyl rubber and Teflon, to either a treated
 
water, raw water, fuel oil, lubricating oil, ventilation air, indoor air, and air-gas (including Freon)
 
environments. Finally, in RAI 3.3.2.3-1, part C, the staff asked the applicant to Identify the AMP
 
or AMPs that will be credited for aging management if PPL does identify that are applicable
 
AERMs for any of these system-mat erial-environmental combinations.
 
In its letter dated August 27, 2008, in response to RAI 3.3.2.3-1 part A, the applicant stated that
 
the applicable aging effects for elastomers (including butyl rubber, synthetic rubber, neoprene, and silicone) are change in material properties and cracking, which may be due to ionizing
 
radiation, thermal exposure, or exposure to ultraviolet radiation or ozone. The applicant
 
provided the threshold level for ionizing radiation as 10E6 rads, for temperature as greater than
 
95oF, and for ultraviolet radiation and ozone as prolonged exposure. The applicant further
 
stated that, except for certain areas in the Reactor Building, where ionizing radiation could be
 
more than the threshold limit, the other buildings are all in an environment that is within the
 
threshold limits. Therefore, the applicant concluded that there are no aging effects requiring
 
management for synthetic rubber flexible connections in a lubricating oil internal environment in the diesel generator system.
 
In response to RAI 3.3.2.3-1, part B, the applicant stated that the specific material properties
 
that could be impacted by exposure to treated water, raw water, fuel oil, lubricating oil, ventilation air, indoor air, and air-gas (including Freon) environments are hardening (e.g.,
embrittlement, decrease in elasticity) and loss of strength (e.g., elongation, loss of tensile
 
strength, and, with exposure to ionizing radiation, swelling or melting). The applicant further
 
stated that hardening and loss of strength could occur as a result of prolonged exposure to high
 
temperature, high radiation levels, or to ultraviolet radiation or ozone. 
 
3-384 In response to RAI 3.3.2.3.-1, part C, the applicant stated that there are no aging effects requiring management for the system-material-environment combinations listed in RAI 3.3.2.3-1, except for those that have already been identified in the LRA as noted in the response to part
 
B.
 
The staff reviewed the applicant response to RAI 3.3.2.3-1, parts A, B and C, and finds the
 
applicant response acceptable because the applicant defined the stressors that could cause the
 
aging effects in various structures. The applicant response is consistent with the GALL Report
 
definitions of the threshold limits of the stressors as recommended in the GALL Report Section IX. On the basis of its review, the staff finds for synthetic rubber flexible connections in a
 
lubricating oil internal environment in the di esel generator system, there are no aging effects requiring management.
 
In Table 3.3.2-9, the LRA states that for plastic (Lucite) level gauges in internal ventilation, lubricating oil and external indoor air environments, and plastic (poly-carbonate) filters in air/gas internal and indoor air external environments in the diesel generator system, there are no aging effects requiring management. In RAI 3.3.2.3-1, by letter dated July 23, 2008, the staff asked
 
the applicant to justify why it had not identified any aging effects requiring management for
 
these system-material-environment combinations. 
 
In its letter dated August 27, 2008, in response to RAI 3.3.2.3-1, the applicant stated that 
 
Degradation of plastic materials is considered a design issue. Plastic is either completely
 
resistant to the environment to which it is exposed, or it deteriorates. Acceptability for the use of
 
plastics in any particular environment is a des ign-driven criterion, and once the appropriate material is chosen, the component will have no aging effects that require management. That is, the occurrence of any aging effects is considered a design deficiency that will be detected and
 
corrected within the current license period.
 
Therefore, based on a review of industry operating experience and the expectation of proper
 
design and application of the material, aging of plastics is not considered to require further
 
evaluation for license renewal.
 
The staff reviewed the applicant response and concurs that the selection of plastic material is a
 
design consideration for the system and envir onment; and once selected for the environment of ventilation, lubricating oil or indoor air, aging of plastic material is not expected. The staff
 
acknowledges that plastic, like glass, is an impervious material and as identified in the GALL
 
Report item VII.J-8, glass has no aging effects requiring management in an indoor air
 
environment. The staff has not observed any age rela ted industry experience for plastic material in internal ventilation or air/gas and external indoor air environments, and therefore, finds that for plastic (Lucite) level gauges in internal ventilation, lubricating oil and external indoor air
 
environments, and plastic (poly-carbonate) filters in air/gas internal and indoor air external
 
environments in the diesel generator system will not experience any 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.
 
LRA Table 3.3.2-9 summarizes the results of AMRs for the Diesel Generators Lubrication Oil
 
System heat exchangers end bells and shells c onstructed from aluminum and exposed to indoor air (external). The applicant proposed that there is no aging effect for the material 3-385 environment combination and that no AMR is required.
 
LRA Table 3.3.2-9 summarizes the results of AMRs for Diesel Generators System starting air
 
and intake/exhaust valve bodies constructed from nickel alloys (nickel-iron), valve bodies and
 
orifices constructed from copper alloy (bronze), and filter bodies and heat exchanger fins
 
constructed from aluminum exposed to indoor air (external) and ventilation (external). The applicant proposed that there is no aging effect for the material environment combination and
 
that no AMR is required.
 
The staff finds that this conclusion is acceptable for nickel iron alloys because nickel iron alloys
 
show very low corrosion rates in atmospheric exposure as discussed in F. L. LaQue and H. R.
 
Copson, "Corrosion Resistance of Metals and Alloys," Second Edition, Reinhold Publishing
 
Corporation, New York, 1963. The staff finds that this conclusion is acceptable for copper
 
alloys because copper alloys in air-indoor internal environment has no aging effect. This
 
conclusion is based on the fact that comprehensive tests conducted over a 20-year period
 
under ASTM supervision have confirmed the suitability of copper and copper alloys for
 
atmospheric exposure (which is more severe than indoor air or ventilation) as cited in Metals
 
Handbook, Volume 13, "Corrosion" (American Society for Metals International, 1987). The staff
 
finds that his is acceptable for aluminum becaus e aluminum exposed internally to an indoor air environment and externally to ventilation has no applicable aging effect as discussed in M. G.
Fontana, "Corrosion Engineering, Third Edition, McGraw-Hill, 1986. 
 
LRA  Table 3.3.2-9 summarizes the results of AMRs for the Diesel Generators System
 
intake/exhaust heat exchanger cooling core and heating core tube plugs constructed from nickel
 
alloys (model), heat exchanger cooling core and heating core tube sheets constructed from
 
copper alloy (copper-nickel), heat exchanger cooling core and heating core tubes constructed
 
from copper alloy (copper-nickel) exposed to v entilation (external), heat exchanger water boxes constructed from copper alloy (copper-nickel), and valve bodies constructed from copper alloy (bronze) and exposed to indoor air (exterior), and filter housings constructed from galvanized
 
steel exposed to outdoor air (exterior). For these components, materials and environment
 
combinations, the applicant proposed no aging effect requiring management and no
 
requirement for an AMP. 
 
The applicant has indicated that generic note G is applicable for these items. Generic note G is
 
"Environment not in NUREG-1801 for this component and material." The staff confirmed that
 
this environment is not in the GALL Report for these components and materials. The staff
 
agrees that there will be no aging effect for the tube plugs because they are not exposed to an
 
external environment. The staff agrees with this position because these components do not
 
have an external surface in contact with an env ironment because their external surface is in contact with the inside of the heat exchanger tubes.
 
The staff also agrees that there will not be an aging mechanism for the remaining
 
material/environment combinations and that no AMP is required. The staff noted items include
 
the external surface of components (e.g., heat exchanger shells, piping and piping components, and tanks) that do not contain chilled water, raw water, domestic water or cooling unit drainage
 
and, therefore, do not experience condensation. For copper alloys, items match GALL items
 
V.F-3 and VIII.I-2 for closed water systems, but no such item exists in GALL (Chapter VII) for closed cooling water auxiliary systems.
 
LRA Table 3.3.2-9 summarizes the results of AMRs for diesel generators NSAS components, process system piping and piping components constructed using copper alloy exposed to 3-386 indoor air (external). The applicant proposed that there is no aging effect for the material environment combination and that no AMR is required.
 
The applicant has indicated that generic note G is applicable for these items. Generic note G is
 
"Environment not in NUREG-1801 for this component and material." The staff confirmed that
 
this environment is not in GALL for the component and material. The staff also agrees that there
 
will not be an aging mechanism for this material/environment combination, and that no AMP is
 
required.
 
LRA Table 3.3.2-9 summarizes the results of AMRs for the Diesel Generator intake/exhaust
 
heat exchanger fins constructed from aluminum , diesel generators jacket water heat exchanger tube plugs constructed from copper alloy (copper-nickel) and stainless steel. The applicant
 
proposed that this system meets the definit ions given above and therefore the environment, aging effect requiring management, and AMR should be classified as not applicable. The staff
 
agrees with this proposal because these components do not have an internal surface.
 
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  Aging Management Review Results - Domestic Water System - LRA Table 3.3.2-10 
 
The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations for
 
the domestic water system component groups.
 
In LRA Table 3.3.2-10, the applicant proposed to manage loss of material due for copper alloy
 
material for piping and piping components exposed to an internal environment of raw water
 
using the AMP B.2.46 "Area-Based NSAS Inspection."
 
The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of
 
material for these components. The AMR line item cites Generic Note G, which indicates that
 
the environment is not addressed in GALL Report for this component and material combination. 
 
The staff's evaluation of the AMP B.2.46 is documented in SER Section 3.0.3.3.1. The staff
 
noted that this program is a plant-specific program that performs an appropriate combination of
 
established volumetric and visual inspecti on techniques (nondestructive examination techniques) that will be performed by qualified personnel on a sample population of those
 
components in scope of this program. The staff further noted that the applicant will perform the
 
inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such degradation that progresses slowly and have
 
long incubation times will have time to become apparent. The staff determined the inspection
 
techniques will be capable of detecting loss of material and the applicant will initiate corrective
 
actions if an unacceptable loss of material or wall thinning has occurred that may have a spatial
 
interaction with safety-related components, as determined by engineering evaluation. On the
 
basis that the applicant will be performing an appropriate combination of a visual inspection and
 
volumetric testing for these components, the staff finds the AMR results for this line item
 
acceptable.
 
In LRA Table 3.3.2-10, the applicant proposed to manage cracking for copper alloy material for
 
piping and piping components exposed to an internal environment of raw water using the AMP 3-387 B.2.46 "Area-Based NSAS Inspection."
 
The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage cracking
 
for these components. The AMR line item cites Generic Note G, which indicates that the
 
environment is not addressed in GALL Report for this component and material combination. 
 
The staff's evaluation of the AMP B.2.46 is documented in SER Section 3.0.3.3.1. The staff
 
noted that this program is a plant-specific program that performs an appropriate combination of
 
established volumetric and visual inspecti on techniques (nondestructive examination techniques) that will be performed by a qualified personnel on a sample population of those
 
components in scope of this program. The staff further noted that the applicant will perform the
 
inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such degradation that progresses slowly and have
 
long incubation times will have time to become apparent. The staff determined the inspection
 
techniques will be capable of detecting cracking and the applicant will initiate corrective actions
 
if an unacceptable loss of material or wall thinning has occurred that may have a spatial
 
interaction (e.g., leakage) with safety-related components, as determined by engineering
 
evaluation. On the basis that the applicant will be performing an appropriate combination of a
 
visual inspection and volumetric testing for these components, the staff finds the AMR results
 
for this line item acceptable.
 
In LRA Table 3.3.2-10, the applicant proposed to manage loss of material due to selective
 
leaching for copper alloy material for piping and piping components exposed to an internal
 
environment of raw water and external envir onment of indoor air using the AMP B.2.29 "Selective Leaching Inspection."
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
G, which indicates that the environment is not addressed in GALL Report for this component
 
and material combination. The staff's evaluation of the AMP B.2.29 is documented in SER
 
Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will perform a
 
combination of visual inspection and hardness testing to determine if loss of material due to
 
selective leaching has occurred. The staff further noted that the applicant will perform the
 
inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and
 
the applicant will initiate corrective actions based on the evaluation of the results of these
 
inspections. On the basis that the applicant will be performing a combination of a visual
 
inspection and hardness test, which is consistent with the with the recommendations in GALL AMP XI.M33, for these components,  the staff finds the AMR results for this line item. 
 
In Table 3.3.2-10, the LRA states that for glass liner in the domestic water tank under internal
 
exposure to a raw water environment, there are no aging effects identified and no aging
 
management program is required. In RAI 3.3.2.3-1, Part A by letter dated July 23, 2008, the staff asked the applicant to justify why it had not identified any aging effects requiring
 
management for these system-mater ial-environment combinations.
 
In its letter dated August 27, 2008, in response to RAI 3.3.2.3-1 Part A, the applicant stated that:
 
The relevant conditions that could result in aging degradation of glass are high 3-388 temperature water, and/or the presence of hydrofluoric acid or caustic alkalis.
Hydrofluoric acid and caustic alkalis are not expected to exist in the in the raw water
 
environment of the domestic water system.
When hot water attacks glass, it is not dissolved in the usual sense but is hydrolytically decomposed. Resistance to water
 
varies from excellent to poor depending on the composition of the glass. Furthermore, glass-lined steel combines the corrosion resistance of glass with the strength of steel, making it useful for equipment operating at elevated temperature and pressure. Glass-
 
lined steel has excellent resistance to corrosion over a wide range of pH and
 
environments. As such, it is expected that the glass lining for the water heater tank is
 
properly designed and selected for the service in which it is used. Therefore, there are
 
no aging effects requiring management for the subject glass components in the domestic water system.
 
The staff found that the plant specific AMR for the exposure of the glass liner in the domestic
 
water tank under internal exposure to a raw water environment was consistent with the AMR in
 
GALL AMR item VII.J-11 for exposure of gla ss components to raw water environments. Based on this review, the staff finds that the applicant has provided a valid basis for concluding that
 
there are not any AERMs for the glass lining in the domestic water system tank because the
 
applicant's AMR is consistent with GALL AMP VII.J-11.
 
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. 
 
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  Aging Management Review Resu lts - Emergency Service Water System -
LRA Table 3.3.2-11 
 
The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations for
 
the emergency service water system component groups.
 
In LRA Table 3.3.2-11, the applicant proposed to manage loss of material for stainless steel
 
material for piping and piping components exposed to an external environment of outdoor air using the AMP B.2.32 "System Walkdown Program."
 
The AMR line item credits the AMP B.2.32 "System Walkdown Program" to manage loss of
 
material for these components. The AMR line item cites Generic Note G, which indicates that
 
the environment is not addressed in GALL Report for this component and material combination. 
 
The staff's evaluation of the AMP B.2.32 "System Walkdown Program" is documented in SER
 
Section 3.0.3.2.15. The staff determined that this program is a condition monitoring program
 
that will detect the aging effect of loss of material for metals, including stainless steel, by
 
periodic surveillance activities and observations of components' external surfaces to detect
 
aging degradation that are with in the scope of license renewal. The staff also determined that
 
these activities are adequate to manage loss of material for stainless steel piping and piping
 
components exposed to air-outdoor. On this basis, the staff finds the AMR results for this line
 
item acceptable.
3-389  In LRA Table 3.3.2-11, the applicant proposed to manage loss of material due to selective
 
leaching for copper alloy material for piping and piping components exposed to an internal
 
environment of raw water using the AMP B.2.46 "Area-Based NSAS Inspection."
 
The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of
 
material for these components. The AMR line item cites Generic Note H, which indicates that
 
the aging effect is not addressed in the Gall Report for this component, material and
 
environment combination. The staff's evaluation of the AMP B.2.46 is documented in SER
 
Section 3.0.3.3.1. The staff noted that this program is a plant-specific program that performs an
 
appropriate combination of established volumetric and visual inspection techniques (nondestructive examination techniques) that will be performed by a qualified personnel on a
 
sample population of those components in scope of this program. The staff further noted that
 
the applicant will perform the inspections of the components with in the scope of this program at
 
least 10 years prior to entering the period of extended operation such degradation that
 
progresses slowly and have long incubation time s will have time to become apparent. The staff determined the inspection techniques will be capable of detecting cracking and the applicant will
 
initiate corrective actions if an unacceptable loss of material or wall thinning has occurred that
 
may have a spatial interaction with safety-related components, as determined by engineering
 
evaluation. On the basis that the applicant will be performing an appropriate combination of a
 
visual inspection and volumetric testing for these components, the staff finds the AMR results
 
for this line item acceptable.
 
In LRA Table 3.3.2-11, the applicant proposed to manage loss of material due to selective
 
leaching for copper alloy material for piping and piping components exposed to an external
 
environment of indoor air using the AMP B.2.29 "Selective Leaching Inspection."
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
H, which indicates that the aging effect is not addressed in the Gall Report for this component, material and environment combination. The staff's evaluation of the AMP B.2.29 is documented
 
in SER Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will
 
perform a combination of visual inspection and hardness testing to determine if loss of material
 
due to selective leaching has occurred. The staff further noted that the applicant will perform
 
the inspections of the components within the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and
 
the applicant will initiate corrective actions based on the evaluation of the results of these
 
inspections. On the basis that the applicant will be performing a combination of a visual
 
inspection and hardness test, which is consistent with the with the recommendations in GALL AMP XI.M33, for these components,  the staff finds the AMR results for this line item. 
 
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).
3-390  3.3.2.3.12  Aging Management Review Re sults - ESSW Pumphouse HVAC System -
LRA Table 3.3.2-12 
 
The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations for
 
the ESSW Pumphouse HVAC system component groups. The staff determined that all AMR evaluation results in LRA Table 3.3.2-12 are consistent with the GALL Report.
 
3.3.2.3.13  Aging Management Review Results - Fire Protection System - LRA Table 3.3.2-13 
 
The staff reviewed LRA Table 3.3.2-13, which summarizes the results of AMR evaluations for
 
the fire protection system component groups.
 
In LRA Table 3.3.2-13, the applicant proposed to manage loss of material due to selective
 
leaching for cast iron, gray cast iron and copper alloy material for heat exchanger components, piping, piping components and elements, strainers and sprinkler heads exposed to an external
 
environment of indoor air using the AMP B.2.29 "Selective Leaching Inspection."
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
H, which indicates that the aging effect is not addressed in the Gall Report for this component, material and environment combination. The staff's evaluation of the AMP B.2.29 is documented
 
in SER Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will
 
perform a combination of visual inspection and hardness testing to determine if loss of material
 
due to selective leaching has occurred. The staff further noted that the applicant will perform
 
the inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and
 
the applicant will initiate corrective actions based on the evaluation of the results of these
 
inspections. On the basis that the applicant will be performing a combination of a visual
 
inspection and hardness test, which is consistent with the with the recommendations in GALL AMP XI.M33, for these components,  the staff finds the AMR results for this line item 
 
In LRA Table 3.3.2-13, the applicant proposed to manage loss of material due to selective
 
leaching for cast iron pump casings exposed to an internal environment of fuel oil using the
 
AMP B.2.29 "Selective Leaching Inspection."
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
H, which indicates that the aging effect is not addressed in the Gall Report for this component, material and environment combination. The staff's evaluation of the AMP B.2.29 is documented
 
in SER Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will
 
perform a combination of visual inspection and hardness testing to determine if loss of material
 
due to selective leaching has occurred. The staff further noted that the applicant will perform
 
the inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and 3-391 the applicant will initiate corrective actions based on the evaluation of the results of these inspections. On the basis that the applicant will be performing a combination of a visual
 
inspection and hardness test, which is consistent with the with the recommendations in GALL AMP XI.M33, for these components,  the staff finds the AMR results for this line item. 
 
In LRA Table 3.3.2-13, the applicant proposed to manage loss of material due to selective
 
leaching for cast iron pump casings and copper alloy tubing exposed to an internal environment
 
of lubricating oil using the AMP B.2.29 "Selective Leaching Inspection."
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
H, which indicates that the aging effect is not addressed in the Gall Report for this component, material and environment combination. The staff's evaluation of the AMP B.2.29 is documented
 
in SER Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will
 
perform a combination of visual inspection and hardness testing to determine if loss of material
 
due to selective leaching has occurred. The staff further noted that the applicant will perform
 
the inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and
 
the applicant will initiate corrective actions based on the evaluation of the results of these
 
inspections. On the basis that the applicant will be performing a combination of a visual
 
inspection and hardness test, which is consistent with the with the recommendations in GALL AMP XI.M33, for these components,  the staff finds the AMR results for this line item
 
acceptable.
 
In LRA Table 3.3.2-13, the LRA states that for copper alloy sprinkler heads in indoor air, outdoor
 
air and ventilation environments there are no aging effects. The applicant has referenced
 
footnotes "G" and "0322". Footnote "0322" states that the Fire Water System Program is
 
credited with aging management for all sprinkler heads, regardless of whether aging effects
 
requiring management have been identified. 
 
The staff has determined that copper alloy in an indoor, uncontrolled air environment exhibits no
 
aging effect and that the component or structure will therefore remain capable of performing its
 
intended functions consistent with the CLB for the period of extended operation. This conclusion
 
is based on the fact that comprehensive tests conducted over a 20-year period under the
 
supervision of ASTM have confirmed the suitability of copper and copper alloy for atmospheric
 
exposure as cited in Metals Handbook, Volume 13, Corrosion, American Society for Metals, 1987. Based on this review, the staff finds that because the copper alloy sprinkler heads are
 
exposed to an internal environment that is open to local ambient air conditions such that
 
condensation will not occur, loss of material due to pitting and crevice corrosion is not an aging
 
effect requiring management.
 
However, the applicant has committed (Commitment No. 46) to enhance the Fire Water System
 
Program prior to entering the period of extended operation to require testing or replacement of
 
sprinkler heads in service for 50 years. On the basis that sprinkler heads are normally open to
 
the atmosphere and that the applicant is committing to testing or replacement of sprinkler heads
 
in service for 50 years, the staff finds these AMR line items to be acceptable.
 
In Table 3.3.2-13, the LRA states that for synthetic rubber flexible connections in internal 3-392 environments of fuel oil, raw water and lubricating oil, and for teflon flexible connections in internal raw water environment, there are no aging effects identified and no aging management
 
program is required. The staff issued RAI 3.3.2.3.13-1 by letter dated July 23, 2008 to request
 
the applicant to provide a justification why no aging effects are identified.
 
In its letter dated August 22, 2008, the applicant responded to RAI 3.3.2.3-13 by stating that
 
change in material properties and cracking of elastomers, such as synthetic rubber may be due
 
to ionizing radiation, thermal exposure, or exposure to ultraviolet radiation, or ozone. The
 
applicant also stated that for polymers, such as Teflon, change in material properties may result
 
from exposure to gamma radiation, but cracking is not a potential aging effect, and change in
 
material properties is not influenced by thermal ex posure or exposure to ultraviolet radiation or ozone.
 
The applicant stated that:
: 1) The lubricating oil, fuel oil, and raw water environments of the fire protection system contain no sources of ionizing radiation. Therefore, change in
 
material properties and cracking due to ionizing radiation are not aging
 
effects requiring management for synthetic rubber or Teflon components that
 
are exposed to lubricating oil, fuel oil, or raw water.
: 2) Thermal exposure is an applicable aging mechanism for synthetic rubber components only if they are exposed for prolonged periods to a temperature
 
greater than 95 o F. Since there are no significant sources of heat within the diesel driven fire pump room, the applicant assumed that the ambient
 
temperature will not exceed 95 o F over a prolonged period. Additionally, the fire protection system is in the standby mode during normal plant operation, so there is normally no flow through the system, and the lubricating oil, fuel
 
oil, and raw water temperatures are approximately the same as the ambient
 
temperature. Therefore, change in material properties and cracking due to
 
thermal exposure are not aging effects requiring management for synthetic
 
rubber flexible connections that are exposed to lubricating oil, fuel oil, or raw
 
water. 3) Ultraviolet radiation and ozone are applicable aging mechanisms only for
 
natural rubber components that are exposed to sources of ultraviolet
 
radiation and ozone. Synthetic rubbers have demonstrated excellent
 
resistance to ultraviolet radiation and ozone. The lubricating oil, fuel oil, and
 
raw water environments contain no sources of ultraviolet radiation and ozone.
 
Therefore, change in material properties and cracking due to ultraviolet
 
radiation and ozone are not aging effects requiring management for synthetic
 
rubber flexible connections that are exposed to lubricating oil, fuel oil, or raw
 
water.
Based on its review, the staff finds the applicant's response has satisfactorily identified stressors
 
and thresholds for which hardening and loss of strength are aging effects for elastomer
 
components and applied aging management for these cases. Where the stressors and
 
thresholds for which hardening and loss of strength are not exceeded, aging management is not required. This is also confirmed by the GALL Report, Section IX.C, which defines elastomer
 
materials and states that hardening and loss of strength of elastomers can be induced by
 
elevated temperatures (over 95 o F), and additional aging factors such as exposure to ozone, 3-393 oxidation, and radiation. Therefore, the staff finds the applicant response to be acceptable.
 
In Table 3.3.2-13, the LRA states that for copper and copper alloy tubing and valve bodies in an
 
air-indoor external environment, there are no aging effects identified and no aging management program is required. The applicant has referenced footnote "G", environment not in the GALL
 
Report for this component and material. However, the staff noted GALL Report item V.F-3
 
identifies copper alloy in an air-indoor uncontrolled external environment with no aging effects
 
and no aging management program. On the basis that the GALL Report recommends no aging
 
effects for copper alloy piping components in an air-indoor external environment, the staff finds
 
these line items acceptable. 
 
In its letter dated June 30, 2008, in response to RAI B.2.17-2, the applicant amended Table
 
3.3.2-13, Fire Protection System, to credit the Heat Exchanger Inspection Program to manage the aging effect of reduction of heat transfer due to fouling for copper alloy oil cooler tubes in a
 
lubricating oil external environment. The applicant applied footnote "H". The staff noted that the
 
internal environment of these tubes is raw water and the internal surfaces are managed by the
 
Fire Water System Program for loss of material, which includes actions to ensure no significant
 
corrosion, MIC, or biofouling has occurred, and the Heat Exchanger Inspection Program for
 
reduction of heat transfer. The staff reviewed the Heat Exchanger Inspection Program, which
 
will be inspecting the inner and the external surface of the tubes to detect for fouling. The staff's
 
evaluation of the Heat Exchanger Inspection Program is documented in Section 3.0.3.1.12.
 
On the basis that the applicant is crediting the Fire Water Inspection Program to ensure no
 
significant fouling is occurring and crediting the Heat Exchanger inspection Program to obtain
 
direct evidence of fouling for the internal surfaces of the tubes, the staff finds that
 
implementation of the Heat Exchanger Inspection for the external surfaces of the tubes in a
 
lubricating oil environment will ensure that the heat transfer capabilities of the subject heat
 
exchangers, and the pressure boundary integrity of the subject tubes, are maintained consistent
 
with the current licensing basis during the period of extended operation.
 
In Table 3.3.2-13, the LRA states that for synthetic rubber flexible connections in fuel oil and
 
raw water internal environments in the fire protection system, there are no aging effects
 
requiring management. In RAI 3.3.2.3-1, Part A by letter dated July 23, 2008, the staff asked the
 
applicant to justify why it had not identified any aging effects requiring management for these
 
system-material-environment combinations.
 
In its letter dated August 27, 2008, in response to RAI 3.3.2.3-1 Part A, the applicant stated that
 
the applicable aging effects for elastomers (including butyl rubber, synthetic rubber, neoprene, and silicone) are change in material properties and cracking, which may be due to ionizing
 
radiation, thermal exposure, or exposure to ultraviolet radiation or ozone. The applicant
 
provided the threshold level for ionizing radiation as 10E6 rads, for temperature as greater than
 
95 o F, and for ultraviolet radiation and ozone as prolonged exposure. The applicant further stated that, except for certain areas in the Reactor Building, where ionizing radiation could be
 
more than the threshold limit, the other buildings are all in an environment that is within the
 
threshold limits. Therefore, the applicant concluded that there are no aging effects requiring
 
management for synthetic rubber flexible connections in fuel oil and raw water internal
 
environments in the fire protection system.
 
The staff reviewed the applicant response to RAI 3.3.2.3-1, Part A, and finds the applicant
 
response acceptable because the applicant defined the stressors that could cause the aging
 
effects in various structures. The applicant response is consistent with the GALL Report 3-394 definitions of the threshold limits of the stressors as recommended in the GALL Report Section IX. On the basis of its review, the staff finds for synthetic rubber flexible connections in a fuel oil
 
internal environment in the diesel fuel oil system, there are no aging effects requiring
 
management.
 
In Table 3.3.2-13, the LRA states that for Teflon flexible connections in raw water internal and
 
indoor air external environments in the fire protection system, there are no aging effects requiring management. In RAI 3.3.2.3-1, Part A by letter dated July 23, 2008, the staff asked the
 
applicant to justify why it had not identified any aging effects requiring management for these
 
system-material-environment combinations.
 
In its letter dated August 27, 2008, in response to RAI 3.3.2.3-1, Part A, the applicant stated
 
that:
The only applicable aging effect for Teflon is change in material properties. Change in
 
material properties of Teflon may be due to exposure to gamma radiation. Thermal
 
exposure and exposure to ultraviolet radiation or ozone are not applicable aging
 
mechanisms for Teflon.
 
Gamma radiation is an applicable aging mechanism for Teflon components only if the
 
total integrated dose (TID) is equal to or greater than 10E4 rads. The Teflon components
 
in the Fire Protection System are located in the Circulating Water Pumphouse, an area
 
of the plant where ionizing radiation levels are such that the TID over a 60-year period, which includes the period of extended operation, will not equal or exceed 10E3 rads.
 
Also, there are no sources of gamma radiation expected to exist in the raw water of the
 
Fire Protection System or the treated wa ter environment of the Sampling System.
Therefore, change in material properties and cracking due to ionizing radiation are not
 
aging effects requiring management for these components.
 
The staff reviewed the applicant response and noted that these flexible connections are located
 
in an area where the ionizing radiation is less than the threshold value of 10E6 rads. On this
 
basis, the staff finds the applicant response acceptable and concludes that for Teflon flexible
 
connections in raw water internal and indoor air external environments in the fire protection
 
system, there are no 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. 
 
In Table 3.3.2-13, the LRA states that for galvanized steel piping in an outdoor external
 
environment, there are no aging effects i dentified and no aging management program is required. The applicant has referenced footnote "G", environment not in the GALL Report for
 
this component and material. 
 
The staff finds that as discussed in M. G. Fontana, "Corrosion Engineering, Third Edition, McGraw-Hill, 1986, this is acceptable for galvanized steel in an outdoor environment because
 
the corrosion protection of the zinc coating is enhanced by the build-up of corrosion products
 
deposited out of solution. The staff finds galvanized steel in an outdoor environment has no
 
aging effects that require aging management because galvanized steel in an outdoor
 
environment  has no applicable aging effect as discussed in M. G. Fontana, "Corrosion
 
Engineering, Third Edition, McGraw-Hill, 1986.
3-395  In Table 3.3.2-13, the LRA states that for copper alloy halon spray nozzles in an environment of
 
ventilation, there are no aging effects identif ied and no aging management program is required.
The applicant has referenced footnote "G", environment not in the GALL Report for this
 
component and material. 
 
The staff noted that these spray nozzles are in the halon system, which is normally a dry air
 
environment. The staff also noted that these spray nozzles are open to atmosphere. In LRA
 
Table 3.0-1, Internal Environments, the applicant stated that internal ambient environment
 
inside components that are open to the ambient conditions in their location are also included
 
under ventilation environment. Since the spray nozzles are open to atmosphere and would
 
normally be exposed to internal air environment, the staff finds that this material/ environment is similar to GALL Report item VII.I-2, for copper alloy components in an air-indoor uncontrolled
 
environment, with no aging effects and no aging m anagement program required. Based on this review, the staff finds that for copper alloy halon spray nozzles in an environment of ventilation, there are no aging effects identified and no aging management program is required.
 
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  Aging Management Review Results - Fuel Pool Cooling and Cleanup System and
 
Fuel Pool and Auxiliaries - LRA Table 3.3.2-14 
 
The staff reviewed LRA Table 3.3.2-14, which summarizes the results of AMR evaluations for
 
the fuel pool cooling and cleanup system and fuel pool and auxiliaries component groups.
 
The staff reviewed LRA Table 3.3.2-14 which summarizes the results of AMRs for fuel pool
 
cooling screens for skimmer surge tanks which are constructed from stainless steel. The
 
applicant proposed that this system meets t he definitions given above and therefore the environment, aging effect requiring management, and AMR should be classified as not
 
applicable. The staff agrees with this proposal because these components do not have an
 
internal surface.
 
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  Aging Management Review Results -
Neutron Monitoring System - LRA Table 3.3.2-15 
 
The staff reviewed LRA Table 3.3.2-15, which summarizes the results of AMR evaluations for
 
the neutron monitoring system component groups.
The staff determined that all AMR evaluation results in LRA Table 3.3.2-15 are consistent with the GALL Report.
3-396  3.3.2.3.16  Aging Management Review Results - Primary Containment Atmosphere Circulation
 
System - LRA Table 3.3.2-16 
 
The staff reviewed LRA Table 3.3.2-16, which summarizes the results of AMR evaluations for
 
the primary containment atmosphere circulation system component groups. The staff
 
determined that all AMR evaluation results in LRA Table 3.3.2-16 are consistent with the GALL
 
Report.
 
3.3.2.3.17  Aging Management Review Results - Process and Area Radiation Monitoring
 
System - LRA Table 3.3.2-17 
 
The staff reviewed LRA Table 3.3.2-17, which summarizes the results of AMR evaluations for
 
the process and area radiation monitoring system component groups.
 
In LRA Table 3.3.2-17, the applicant proposed to manage cracking of copper alloy for piping
 
and piping components in the Process and Area R adiation Monitoring System exposed to an internal environment of treated water using t he AMP B.2.14 "Closed Cooling Water Chemistry Program."
 
The AMR line item credits the Closed Cooling Water Program to manage cracking for these
 
components. The AMR line item cites Generic Note H, which indicates that the aging effect is
 
not addressed in the GALL Report for this component, material and environment combination.
 
The Closed Cooling Water Chemistry Program is an existing SSES program that properly monitors components and controls corrosion inhibitor concentrations for components, within the
 
scope of license renewal, consistent with relevant EPRI water chemistry guidelines.
 
The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008. The applicant
 
clarified that the one-time inspection performed as part of the AMP B.2.22, "Chemistry Program
 
Effectiveness Inspection" will be used to supplement AMP B.2.14, "Closed Cooling Water
 
Chemistry Program" in all instances where AMP B.2.14 is credited for aging management in LRA Table-2 items, with the exception of the Diesel Jacket Water Cooling System. The staff
 
reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP
 
B.2.22 "Chemistry Program Effectiveness Inspec tion" and its evaluations are documented in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging
 
management program includes activities that are consistent with the recommendations in the GALL AMP XI.M21 to maintain high water purity, which is effective for managing cracking for
 
copper and copper alloy components exposed to a treated water environment. The staff further
 
noted the Closed Cooling Water Chemistry Progr am is an existing program that properly monitors components and controls corrosion inhibitor concentrations for components, within the
 
scope of license renewal, consistent with relev ant EPRI water chemistry guidelines. The staff confirmed that the Chemistry Program Effect iveness Inspection will be used to verify the effectiveness of the applicant's Closed Cooli ng Water Chemistry Program to manage cracking and that a combination of appropriate volumetric and visual examination techniques (such as
 
VT-1 or VT-3) will be performed by qualified personnel on a sample population of most
 
susceptible subject components. On this basis, the staff finds that these AMR results will be
 
adequately managed by these programs. 
 
LRA Table 3.3.2-17 summarizes the results of AMRs for process and area radiation monitoring
 
system piping and piping components constructed using copper alloy exposed to indoor air (external). The applicant proposed that there is no aging effect for the material environment 3-397 combination and that no AMR is required.
 
The applicant has indicated that generic note G is applicable for these items. Generic note G is
 
"Environment not in NUREG-1801 for this component and material." The staff confirmed that
 
this environment is not in GALL for the component and material. The staff also agrees that there
 
will not be an aging mechanism for this material/environment combination, and that no AMP is
 
required.
 
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  Aging Management Review Results -
Radwaste Liquid System - LRA Table 3.3.2-18 
 
The staff reviewed LRA Table 3.3.2-18, which summarizes the results of AMR evaluations for
 
the radwaste liquid system component groups.
 
In LRA Table 3.3.2-18, the applicant proposed to manage loss of material due to selective
 
leaching for cast iron for piping and piping components exposed to an internal environment of
 
raw water using the AMP B.2.29 "Selective Leaching Inspection."
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
G, which indicates that the environment is not addressed in GALL Report for this component
 
and material combination. The staff's evaluation of the AMP B.2.29 is documented in SER
 
Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will perform a
 
combination of visual inspection and hardness testing to determine if loss of material due to
 
selective leaching has occurred. The staff further noted that the applicant will perform the
 
inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and
 
the applicant will initiate corrective actions based on the evaluation of the results of these
 
inspections. The staff noted that the GALL Report recommends the use of the Selective
 
Leaching Program for the same combination of material/environment/aging effect in items
 
VII.C1-11 for a different system. On the basis that the applicant will be performing a
 
combination of a visual inspection and hardness test for these components and these AMR
 
material/environment/aging effect combination is consistent with the GALL AMR Item VII.C1-11
 
for cast iron,  the staff finds the AMR results for this line item acceptable.
 
In LRA Table 3.3.2-18, the applicant proposed to manage loss of material  in piping and piping
 
components, and cleanouts and pump casings in an internal environment of raw water by using
 
the Monitoring and Collection System Inspection Program. The applicant referenced footnote G
 
for this line item indicating that environment is not in the GALL Report for this component and
 
material combination. The applicant also referenced footnote 0356, which indicates that
 
uncontrolled drainage in the radwaste liquids system is considered to be a raw water
 
environment.
 
3-398 The staff noted that these components are in scope for a structural integrity function only to ensure that its failure does not impact other safety-related system and components. The staff reviewed the Monitoring and Collection System Inspection Program, which uses a combination
 
of volumetric and visual examination techniques to identify evidence of loss of material or lack
 
thereof. The staff's evaluation of the Monitori ng and Collection System Inspection Program is documented in SER Section 3.0.3.1.15. Because the Monitoring and Collection System
 
Inspection is performed at susceptible locations, and employs a combination of volumetric and
 
visual inspection techniques, the staff finds that the Monitoring and Collection System
 
Inspection Program will adequately manage the aging effects of loss of material in this
 
aggressive environment. 
 
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  Aging Management Review Result s - Radwaste Solids Handling System -
LRA Table 3.3.2-19 
 
The staff reviewed LRA Table 3.3.2-19, which summarizes the results of AMR evaluations for
 
the radwaste solids handling system component groups.
 
In LRA Table 3.3.2-19, the applicant proposed to manage loss of material due for carbon steel, stianless steel and copper alloy material for piping and piping components and tanks exposed
 
to an internal environment of raw water using the AMP B.2.46 "Area-Based NSAS Inspection."
 
The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of
 
material for these components. The AMR line item cites Generic Note G, which indicates that
 
the environment is not addressed in GALL Report for this component and material combination. 
 
The staff's evaluation of the AMP B.2.46 is documented in SER Section 3.0.3.3.1. The staff
 
noted that this program is a plant-specific program that performs an appropriate combination of
 
established volumetric and visual inspecti on techniques (nondestructive examination techniques) that will be performed by qualified personnel on a sample population of those
 
components in scope of this program. The staff further noted that the applicant will perform the
 
inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such degradation that progresses slowly and have
 
long incubation times will have time to become apparent. The staff determined the inspection
 
techniques will be capable of detecting loss of material and the applicant will initiate corrective
 
actions if an unacceptable loss of material or wall thinning has occurred that may have a spatial
 
interaction with safety-related components, as determined by engineering evaluation. On the
 
basis that the applicant will be performing an appropriate combination of a visual inspection and
 
volumetric testing for these components, the staff finds the AMR results for this line item
 
acceptable.
 
In LRA Table 3.3.2-19, the applicant proposed to manage loss of material due to selective
 
leaching for copper alloy material for piping and piping components exposed to an internal
 
environment of raw water using the AMP B.2.46 "Area-Based NSAS Inspection."
 
The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of
 
material for these components. The AMR line item cites Generic Note G, which indicates that 3-399 the environment is not addressed in GALL Report for this component and material combination.
The staff's evaluation of the AMP B.2.46 is documented in SER Section 3.0.3.3.1. The staff
 
noted that this program is a plant-specific program that performs an appropriate combination of
 
established volumetric and visual inspecti on techniques (nondestructive examination techniques) that will be performed by a qualified personnel on a sample population of those
 
components in scope of this program. The staff further noted that the applicant will perform the
 
inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such degradation that progresses slowly and have
 
long incubation times will have time to become apparent. The staff determined the inspection
 
techniques will be capable of detecting cracking and the applicant will initiate corrective actions
 
if an unacceptable loss of material or wall thinning has occurred that may have a spatial
 
interaction (e.g., leakage) with safety-related components, as determined by engineering
 
evaluation. On the basis that the applicant will be performing an appropriate combination of a
 
visual inspection and volumetric testing for these components, the staff finds the AMR results
 
for this line item acceptable.
 
In LRA Table 3.3.2-19, the applicant proposed to manage loss of material due to selective
 
leaching for copper alloy for piping and piping components exposed to an internal environment
 
of raw water using the AMP B.2.29 "Selective Leaching Inspection."
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
G, which indicates that the environment is not addressed in GALL Report for this component
 
and material combination. The staff's evaluation of the AMP B.2.29 is documented in SER
 
Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will perform a
 
combination of visual inspection and hardness testing to determine if loss of material due to
 
selective leaching has occurred. The staff further noted that the applicant will perform the
 
inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and
 
the applicant will initiate corrective actions based on the evaluation of the results of these
 
inspections. The staff noted that the GALL Report recommends the use of the Selective
 
Leaching Program for the same combination of material/environment/aging effect in items
 
VII.C1-10 for a different system. On the basis that the applicant will be performing a
 
combination of a visual inspection and hardness test for these components and these AMR
 
material/environment/aging effect combination is consistent with the GALL AMR Item VII.C1-10
 
for copper alloy,  the staff finds the AMR results for this line item acceptable.
 
LRA Table 3.3.2-19 summarizes the results of AMRs for the Radwaste Solids Handling System
 
piping and piping components constructed from copper alloy and exposed to indoor air (external) and the applicant proposed that this material-environment combination has no aging
 
effects requiring management and no AMR is required.
 
The applicant has indicated that generic note G is applicable for these items. Generic note G is
 
"Environment not in NUREG-1801 for this component and material." The staff confirmed that
 
this environment is not in the GALL Report for this component and material. The staff also
 
agrees that there will not be an aging mechanism for this material/environment combination and
 
that no AMP is required. Copper alloys in an air-indoor internal environment have no aging
 
effect. This conclusion is based on the fact that comprehensive tests conducted over a 20-year 3-400 period under ASTM supervision have confirmed the suitability of copper and copper alloys for atmospheric exposure (which is more severe than indoor air) as cited in Metals Handbook, Volume 13, "Corrosion" (American Society for Metals International, 1987).
 
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  Aging Management Review Results - Raw Water Treatment System -
 
LRA Table 3.3.2-20 
 
The staff reviewed LRA Table 3.3.2-20, which summarizes the results of AMR evaluations for
 
the raw water treatment system component groups.
 
In LRA Table 3.3.2-20, the applicant proposed to manage loss of material due to selective
 
leaching for cast iron and copper alloy material for valve bodies exposed to an external
 
environment of outdoor air using the AMP B.2.29 "Selective Leaching Inspection."
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
H, which indicates that the aging effect is not addressed in the Gall Report for this component, material and environment combination. The staff's evaluation of the AMP B.2.29 is documented
 
in SER Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will
 
perform a combination of visual inspection and hardness testing to determine if loss of material
 
due to selective leaching has occurred. The staff further noted that the applicant will perform
 
the inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and
 
the applicant will initiate corrective actions based on the evaluation of the results of these
 
inspections. On the basis that the applicant will be performing a combination of a visual
 
inspection and hardness test, which is consistent with the with the recommendations in GALL AMP XI.M33, for these components,  the staff finds the AMR results for this line item 
 
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR
 
results of material, environment, AERM, and AMP combinations not evaluated in the GALL
 
Report. The staff finds that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended function(s) will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3.3.2.3.21  Aging Management Review Results - Reactor Building Chilled Water System -
 
LRA Table 3.3.2-21 
 
The staff reviewed LRA Table 3.3.2-21, which summarizes the results of AMR evaluations for
 
the reactor building chilled water system component groups.
 
In LRA Table 3.3.2-21, the applicant proposed to manage cracking of copper alloy for piping
 
and piping components in the Reactor Building Chilled Water System exposed to an internal 3-401 environment of treated water using the AMP B.2.
14 "Closed Cooling Water Chemistry Program."
 
The AMR line item credits the Closed Cooling Water Program to manage cracking for these
 
components. The AMR line item cites Generic Note H, which indicates that the aging effect is
 
not addressed in the GALL Report for this component, material and environment combination.
 
The Closed Cooling Water Chemistry Program is an existing SSES program that properly monitors components and controls corrosion inhibitor concentrations for components, within the
 
scope of license renewal, consistent with re levant EPRI water chemistry guidelines. 
 
The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008. The applicant
 
clarified that the one-time inspection performed as part of the AMP B.2.22, "Chemistry Program
 
Effectiveness Inspection" will be used to supplement AMP B.2.14, "Closed Cooling Water
 
Chemistry Program" in all instances where AMP B.2.14 is credited for aging management in LRA Table-2 items, with the exception of the Diesel Jacket Water Cooling System. The staff
 
reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP
 
B.2.22 "Chemistry Program Effectiveness Inspec tion" and its evaluations are documented in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging
 
management program includes activities that are consistent with the recommendations in the GALL AMP XI.M21 to maintain high water purity, which is effective for managing cracking for
 
copper and copper alloy components exposed to a treated water environment. The staff further
 
noted the Closed Cooling Water Chemistry Progr am is an existing SSES program that properly monitors components and controls corrosion inhibitor concentrations for components, within the
 
scope of license renewal, consistent with relev ant EPRI water chemistry guidelines. The staff confirmed that the Chemistry Program Effect iveness Inspection will be used to verify the effectiveness of the applicant's Closed Cooli ng Water Chemistry Program to manage cracking and that a combination of appropriate volumetric and visual examination techniques (such as
 
VT-1 or VT-3) will be performed by qualified personnel on a sample population of most
 
susceptible subject components. On this basis, the staff finds that these AMR results will be
 
adequately managed by these programs.
 
In LRA Table 3.3.2-21, the applicant proposed to manage loss of material due to selective
 
leaching for copper alloy material for piping and piping components exposed to an internal
 
environment of raw water using the AMP B.2.46 "Area-Based NSAS Inspection."
 
The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of
 
material for these components. The AMR line item cites Generic Note H, which indicates that
 
the aging effect is not addressed in the Gall Report for this component, material and
 
environment combination. The staff's evaluation of the AMP B.2.46 is documented in SER
 
Section 3.0.3.3.1. The staff noted that this program is a plant-specific program that performs an
 
appropriate combination of established volumetric and visual inspection techniques (nondestructive examination techniques) that will be performed by an qualified personnel on a
 
sample population of those components in scope of this program. The staff further noted that
 
the applicant will perform the inspections of the components with in the scope of this program at
 
least 10 years prior to entering the period of extended operation such degradation that
 
progresses slowly and have long incubation time s will have time to become apparent. The staff determined the inspection techniques will be capable of detecting cracking and the applicant will
 
initiate corrective actions if an unacceptable loss of material or wall thinning has occurred that
 
may have a spatial interaction with safety-related components, as determined by engineering
 
evaluation. On the basis that the applicant will be performing an appropriate combination of a
 
visual inspection and volumetric testing for these components, the staff finds the AMR results
 
for this line item acceptable.
3-402  In LRA Table 3.3.2-21, the applicant proposed to manage loss of material due to selective
 
leaching for cast iron and copper alloy material for chillers, piping and piping components and
 
elements exposed to an external environment of indoor air using the AMP B.2.29 "Selective Leaching Inspection."
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
H, which indicates that the aging effect is not addressed in the Gall Report for this component, material and environment combination. The staff's evaluation of the AMP B.2.29 is documented
 
in SER Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will
 
perform a combination of visual inspection and hardness testing to determine if loss of material
 
due to selective leaching has occurred. The staff further noted that the applicant will perform
 
the inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and
 
the applicant will initiate corrective actions based on the evaluation of the results of these
 
inspections. On the basis that the applicant will be performing a combination of a visual
 
inspection and hardness test, which is consistent with the with the recommendations in GALL AMP XI.M33, for these components,  the staff finds the AMR results for this line item 
 
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  Aging Management Review Results - Reactor Building Closed Cooling Water
 
System - LRA Table 3.3.2-22 
 
The staff reviewed LRA Table 3.3.2-22, which summarizes the results of AMR evaluations for
 
the reactor building closed cooling water system component groups.
 
In LRA Table 3.3.2-22, the applicant proposed to manage cracking of copper alloy for piping
 
and piping components in the Reactor Building Closed Cooling Water System exposed to an
 
internal environment of treated water using t he AMP B.2.14 "Closed Cooling Water Chemistry Program."
 
The AMR line item credits the Closed Cooling Water Program to manage cracking for these
 
components. The AMR line item cites Generic Note H, which indicates that the aging effect is
 
not addressed in the GALL Report for this component, material and environment combination. 
 
The staff noted that on LRA page 3.3-289 in LRA Table 3.3.2-22, the applicant referenced a
 
NUREG-1801 Volume 2 item and then cited a note H, which indicates that this aging effect is
 
not in NUREG-1801 for this component, material and environment combination. It was unclear
 
to the staff why the applicant referenced a GALL line item and cited a note H, therefore by letter
 
dated July 23, 2008 the staff issued RAI 3.3.2-4, requesting the applicant to clarify the
 
applicability of this GALL item to the LRA Table 2 item. By letter dated August 22, 2008 the
 
applicant responded to RAI 3.3.2-4, in which the applicant stated this was an error in the LRA 3-403 and that based upon their review, this was the only instance in which copper alloy subject to cracking in a treated water environment referenced a GALL item. The staff confirmed the
 
applicant amended the LRA to remove the reference to the GALL line item and replaced it with
 
"N/A". On the basis of its review, the staff finds the applicant's response acceptable because
 
the LRA was amended and the error was corrected.
 
During its review, it was unclear to the staff whether SSES would be supplementing the Closed
 
Cooling Water Chemistry Program with a one-time inspection, either the Chemistry
 
Effectiveness Program or Heat Exchanger In spection Program. Therefore by letter dated August 12, 2008 the staff issued RAI B.2.14-2 requesting the applicant to clarify whether an
 
appropriate one-time inspection will supplement the Closed Cooling Water Chemistry Program
 
whenever credited and to identify which one-time inspection would be used. 
 
The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008. The applicant
 
clarified that the one-time inspection performed as part of the AMP B.2.22, "Chemistry Program
 
Effectiveness Inspection" will be used to supplem ent B.2.14, "Closed Cooling Water Chemistry Program" in all instances where AMP B.2.14 is credited for aging management in LRA Table-2
 
items, with the exception of the Diesel Jacket Water Cooling System. The staff reviewed the
 
applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP B.2.22
 
"Chemistry Program Effectiveness Inspection" and its evaluations are documented in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging management
 
program includes activities that are consistent with the recommendations in the GALL AMP XI.M21 to maintain high water purity, which is effective for managing cracking for copper and
 
copper alloy components exposed to a treated water environment. The staff further noted the
 
Closed Cooling Water Chemistry Program is an existing SSES program that properly monitors components and controls corrosion inhibitor concentrations for components, within the scope of
 
license renewal, consistent with relevant EPRI water chemistry guidelines. The staff confirmed that the Chemistry Program Effectiveness Inspec tion will be used to verify the effectiveness of the applicant's Closed Cooling Water Chemistry Program to manage cracking and that a
 
combination of appropriate volumetric and visual examination techniques (such as VT-1 or VT-
: 3) will be performed by qualified personnel on a sample population of most susceptible subject
 
components. On this basis, the staff finds that these AMR results will be adequately managed
 
by these programs.
 
LRA Table 3.3.2-22 summarizes the results of AMRs for reactor building closed cooling water, system piping and piping components constructed using copper alloy exposed to indoor air (external). The applicant proposed that there is no aging effect for the material environment
 
combination and that no AMR is required.
 
The applicant has indicated that generic note G is applicable for these items. Generic note G is
 
"Environment not in NUREG-1801 for this component and material." The staff confirmed that
 
this environment is not in GALL for the component and material. The staff also agrees that there
 
will not be an aging mechanism for this material/environment combination, and that no AMP is
 
required.
 
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).
 
3-404 3.3.2.3.23  Aging Management Review Results - Reactor Building HVAC System -
LRA Table 3.3.2-23 
 
The staff reviewed LRA Table 3.3.2-23, which summarizes the results of AMR evaluations for
 
the reactor building HVAC system component groups.
 
In Table 3.3.2-23, the LRA states that for glass sight gauges in the reactor building HVAC
 
system exposed to Freon environment, there are no aging effects identified and no aging management program is required. The staff was concerned, however, that the Freon environment for the glass sight gauges in the reactor building HVAC system might create sufficiently cold environments for the glass material that could, at a minimum impact the fracture
 
toughness of the material. Hence, the staff was concerned that the Freon environment might
 
impact the tolerance of the glass material to withstand an existing crack in the glass material
 
used to fabricate the components (i.e., reduce the flaw tolerance of the material). In RAI 3.3.2.3-
 
2 by letter dated July 23, 2008, the staff asked the applicant to justify why reduction of fracture
 
toughness and cracking would not be applicable aging effects requiring management for the
 
surfaces of glass sight gauges in the reactor building HVAC system under internal exposure to
 
an air - gas (Freon) environment.
 
In its letter dated August 27, 2008, in response to RAI 3.3.2.3-2, the applicant stated:
 
The only relevant conditions that could result in aging degradation (such as cracking) of
 
glass, as identified by industry operating experience, and by research conducted by the
 
Electric Power Research Institute, are exposure to high-temperature water, and/or
 
exposure to hydrofluoric acid or caustic al kalis. High-temperature water, hydrofluoric acid, and caustic alkalis are not expected to exist in the air-gas (Freon) environment of
 
the Reactor Building HVAC System.
 
Exposure to low temperature has not been identified as a relevant condition that could
 
result in aging degradation of glass. Also, reduction in fracture toughness has not been
 
identified as an applicable aging effect for glass, which is by definition a brittle material
 
when subject to impact.
 
Additionally, the coldest part of the refrigerati on cycle, expansion, is typically in the range of approximately 30'F to 40'F, which is not exceptionally cold. The subject glass sight
 
gauges, however, are located between the components of compression and expansion
 
cycles, where the temperature is typically in the range of approximately 95&deg;F to 110&deg;F.
 
The staff reviewed the applicant response and noted that the coldest temperature the glass
 
material would experience during normal operation is between 30 o F to 40 o F, which are not very cold temperatures and at those temperatures the glass material will be resistant to cracking.
 
Based on the operating conditions, and also the location of the sight glasses between
 
components of compression and expansion cycles, the staff finds that the glass material in a
 
Freon environment will not experience any 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. 
 
LRA Table 3.3.2-23 summarizes the AMR results for the emergency switchgear (SWGR) and
 
load center rooms cooling coils constructed from copper exposed to ventilation (internal) and 3-405 the applicant proposed that this material-environment combination has no aging effects requiring management and no AMR is required.
 
The applicant has indicated that generic note I is applicable for these items. Generic note I is
 
"Aging effect in NUREG-1801 for this component, material, and environment is not applicable." 
 
The staff agrees that there will not be an aging mechanism for this material/environment
 
combination. This conclusion is based on the fact that comprehensive tests conducted over a
 
20-year period under ASTM supervision have confirmed the suitability of copper and copper
 
alloys for atmospheric exposure (which is more severe or ventilation) as cited in Metals
 
Handbook, Volume 13, "Corrosion" (American Society for Metals International, 1987).
 
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).
 
LRA Table 3.3.2-23 summarizes the AMR results for reactor building HVAC system valve
 
bodies made from copper alloy (bronze and br ass) and tubing made from copper and exposed to indoor air (external), sight gauges made from glass exposed to air-gas (Freon) (internal),
piping and cooling units, emergency SWGR and load center room DX type cooling coils made
 
from copper and exposed to indoor air (external), and cooling units, emergency SWGR and load
 
center rooms cooling coils made from copper alloy (copper-nickel) exposed to ventilation (external). The applicant proposed that this material-environment combination has no aging
 
effects requiring management and no AMR is required.
 
The applicant has indicated that generic note G is applicable for these items. Generic note G is
 
"Environment not in NUREG-1801 for this component and material." The staff confirmed that
 
this environment is not in GALL for this component and material. The staff also agrees that
 
there will not be an aging mechanism for this material/environment combination and that no
 
AMP is required. Copper alloy in air-indoor internal environment has no aging effect. This
 
conclusion is based on the fact that comprehensive tests conducted over a 20-year period
 
under ASTM supervision have confirmed the suitability of copper and copper alloys for
 
atmospheric exposure (which is more severe than indoor air) as cited in Metals Handbook, Volume 13, "Corrosion" (American Society for Metals International, 1987). This conclusion is
 
also based on the fact that there have been no aging effects observed for glass components in
 
this air environment. Ref: Handbook of Glass Properties, N. P. Bansal and R. H. Doremua, Academic Press 1986, pg. 646.
 
The staff reviewed LRA Table 3.3.2-23 which summarizes the results of AMRs for the Reactor
 
Building HVAC System, unit coolers, CSP pump room RHR pump room, RCIC pump room, and HPCI pump room tube plugs constructed from stainless steel, and unit coolers, CSP pump room, RHR pump room, RCIC pump room, and HPCI pump room fins constructed from copper, and condenser water cooled tube plugs constructed from copper alloy (copper-nickel). The
 
applicant proposed that this system meets t he definitions given above and therefore the environment, aging effect requiring management, and AMR should be classified as not
 
applicable. The staff agrees with this proposal because these components do not have an
 
internal surface because they are solid and therefore, there will not be an aging effect requiring
 
an AMP.
 
In LRA Table 3.3.2-23, the applicant proposed to manage reduction of heat transfer of copper 3-406 cooling unit fins in an external environment of ventilation by using the Cooling Units Inspection Program. The applicant referenced footnote "H" for this line item indicating that aging effect is
 
not in the GALL Report for this component, material and environment combination. 
 
The staff noted the Cooling Unit Inspection Program will detect and charaterize the condition of
 
cooling unit components that are exposed to a ventilation environment, and provides direct evidence as to whether, and to what extent, reduction of heat transfer has occurred, or is likely
 
to occur that could result in a loss of intended function. In its letter dated July 25, 2008, the
 
applicant responded to RAI B.2.23-2 stating that visual inspection (VT-3 or equivalent)
 
techniques will be used to determine whether reduction in heat transfer is occurring. The
 
applicant also stated that the specific inspection technique will be determined prior to the inspection activities and will be consistent with the recommendations in GALL AMP XI.M32. The
 
staff's evaluation of the Cooling Units Inspection Program is documented in SER Section
 
3.0.3.1.11. Because the Cooling Units Inspection Program performs visual inspection to
 
determine if any fouling has occurred that could cause reduction of heat transfer, and on the
 
basis that the visual inspection technique will be consistent with the recommendation in GALL AMP XI.M32, the staff finds the Cooling Units Inspection Program will adequately manage the
 
aging effect of reduction of heat transfer in cooling unit components exposed to a ventilation
 
environment.
 
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  Aging Management Review Results -
Reactor Nonnuclear Instrumentation System -
LRA Table 3.3.2-24 
 
The staff reviewed LRA Table 3.3.2-24, which summarizes the results of AMR evaluations for
 
the reactor nonnuclear instrumentation system component groups. The staff determined that all
 
AMR evaluation results in LRA Table 3.3.2-24 are consistent with the GALL Report.
 
3.3.2.3.25  Aging Management Review Results - Reactor Water Cleanup System -
 
LRA Table 3.3.2-25 
 
The staff reviewed LRA Table 3.3.2-25, which summarizes the results of AMR evaluations for
 
the reactor water cleanup system component groups.
 
In LRA Tables 3.2.2-25 the applicant proposed to manage cracking in copper alloy piping and
 
piping components in an environment of treated water by using the BWR Water Chemistry
 
Program, alone. The applicant cited generic note H for these AMR results, indicating that the
 
aging effect is not in the GALL Report for this component, material and environment
 
combination. In a letter dated July 15, 2008, the staff issued RAI 3.2-3, applicable for these
 
AMR results and for similar AMR results in LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, and 3.4.2 3.
 
The RAI asked the applicant to provide a technical justification as to why an inspection program, such as the Chemistry Program Effectiveness Inspection is not needed to confirm that the BWR
 
Water Chemistry Program is effective in preventing the aging effect.
 
In a letter dated August 15, 2008, the applicant responded to RAI 3.3-3 by providing the
 
following response:
3-407  For the five AMR results lines listed in LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, 3.3.2-25, and 3.4.2-
 
3, where the material is copper alloy, the environment is treated water (internal), and the aging
 
effect is cracking, verification of the effectiveness of the BWR Water Chemistry Program is
 
needed. The Chemistry Program Effectiveness Ins pection will provide confirmation of the effectiveness of this program in managing the effects of aging, including cracking in susceptible materials.
 
LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, 3.3.2-25, and 3.4.2-3 are revised to reflect these results.
 
The staff reviewed the applicant's response and the associated LRA changes. The staff
 
reviewed the applicant's BWR Water Chemistry Pr ogram. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water Chemistry Program
 
provides mitigation for the aging effect of cracking due to stress corrosion cracking. The staff
 
reviewed the applicant's Chemistry Program Effe ctiveness Inspection. The staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the Chemistry
 
Program Effectiveness Inspection is a one-time inspection that is consistent with the GALL Report's recommendations for AMP XI.M32, "O ne-Time Inspection." The Chemistry Program Effectiveness Inspection includes provisions for inspecting selected components in areas of low
 
or stagnant flow and uses examination techniques that are capable of detecting cracking, if it
 
should occur in the selected components. Because the BWR Water Chemistry Program
 
provides mitigation and the Chemistry Program Effectiveness Inspection provides detection of the aging effect if it should occur, the staff finds the applicant's proposed AMPs for managing
 
the potential aging effect of cracking due to stress corrosion cracking in copper alloy piping and
 
piping components exposed to treated water in the reactor water cleanup system to be
 
acceptable. On this basis, the staff finds that the issue in RAI 3.2 3 is resolved by the applicant's
 
LRA changes.
 
In LRA Table 3.3.2-25, the applicant applied note "H" for carbon steel piping and valve bodies
 
exposed to an internal environment of treated water in the reactor water cleanup system. The
 
applicant proposed to manage loss of material due to flow-accelerated corrosion by using the
 
Flow-Accelerated Corrosion Program. The definition of footnote "H" implies that these line items
 
are not consistent with GALL Report. However, the applicant has identified GALL Report item
 
VII.E3-18, which is for loss of material due to general, pitting and crevice corrosion.
 
Furthermore, footnote "H" states that aging effect is not in the GALL Report for this component, material and environment combination. Yet in the same table, the LRA has another line item for
 
the same component, material and environment combination with an aging effect of loss of
 
material due to flow-accelerated corrosion where the LRA has referenced footnote "A" and
 
correctly identified GALL Report item VIII.D2-8. 
 
Since the GALL Report addresses the aging effect of loss of material due to flow-accelerated
 
corrosion for this component, material and environment combination, the staff issued RAI
 
3.3.2.3.25-1 by letter dated July 9, 2008 requesting the applicant to justify why footnote "H" was
 
identified in these two line items and footnote "A" in other line item in the same system. The staff also asked the applicant to justify why a GALL Report item number was referenced with
 
footnote "H". 
 
In its letter dated August 8, 2008, the applicant responded to RAI 3.3.2.3.25-1 by stating that
 
there is no line item in GALL Chapter VII, Section E3, Reactor Water Cleanup System, for loss
 
of material due to flow-accelerated corrosion and therefore, comparison to Chapter VII should
 
not have been made. The applicant further stated that similar to other line items in Table 3.3.2-3-408 25 for which the FAC program was credited, comparison should have been made to GALL item VIII.D2-8. The applicant revised the subject line item to refer to GALL item VIII.D2-8 and Table
 
3.4.1, item 3.4.1-29, which is applicable to FAC. The applicant changed footnote H to footnote A
 
and the line item is consistent with the GALL Report.
 
The staff reviewed the changes and compared them with GALL item VIII.D2-8, and noted that
 
the material, environment, aging effect and recommended AMP are the same as in the GALL
 
Report. On this basis, the staff finds the applicant response acceptable. 
 
LRA Table 3.3.2-25 summarizes the results of AMRs for reactor water cleanup system piping
 
and piping components constructed using copper alloy exposed to indoor air (external). The
 
applicant proposed that there is no aging effect for the material environment combination and
 
that no AMR is required.
 
The applicant has indicated that generic note G is applicable for these items. Generic note G is
 
"Environment not in NUREG-1801 for this component and material." The staff confirmed that
 
this environment is not in GALL for the component and material. The staff also agrees that there
 
will not be an aging mechanism for this material/environment combination, and that no AMP is
 
required.
 
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  Aging Management Review Results - RHR Service Water System -
 
LRA Table 3.3.2-26 
 
The staff reviewed LRA Table 3.3.2-26, which summarizes the results of AMR evaluations for
 
the RHR service water system component groups.
 
In LRA Table 3.3.2-26, the applicant proposed to manage loss of material for stainless steel
 
material for piping and piping components exposed to an external environment of outdoor air using the AMP B.2.32 "System Walkdown Program."
 
The AMR line item credits the AMP B.2.32 "System Walkdown Program" to manage loss of
 
material for these components. The AMR line item cites Generic Note G, which indicates that
 
the environment is not addressed in GALL Report for this component and material combination. 
 
The staff's evaluation of the AMP B.2.32 "System Walkdown Program" is documented in SER
 
Section 3.0.3.2.15. The staff determined that this program is a condition monitoring program
 
that will detect the aging effect of loss of material for metals, including stainless steel, by
 
periodic surveillance activities and observations of components' external surfaces to detect
 
aging degradation that are with in the scope of license renewal. The staff also determined that
 
these activities are adequate to manage loss of material for stainless steel piping and piping
 
components exposed to air-outdoor. On the basis that the applicant will be performing periodic
 
visual inspections of these components, the staff finds the AMR results for this line item
 
acceptable.
 
In LRA Table 3.3.2-26, the applicant proposed to manage loss of material due to selective
 
leaching for copper alloy material for piping and piping components exposed to an internal 3-409 environment of raw water using the AMP B.2.46 "Area-Based NSAS Inspection."
 
The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of
 
material for these components. The AMR line item cites Generic Note H, which indicates that
 
the aging effect is not addressed in the Gall Report for this component, material and
 
environment combination. The staff's evaluation of the AMP B.2.46 is documented in SER
 
Section 3.0.3.3.1. The staff noted that this program is a plant-specific program that performs an
 
appropriate combination of established volumetric and visual inspection techniques (nondestructive examination techniques) that will be performed by a qualified personnel on a
 
sample population of those components in scope of this program. The staff further noted that
 
the applicant will perform the inspections of the components with in the scope of this program at
 
least 10 years prior to entering the period of extended operation such degradation that
 
progresses slowly and have long incubation time s will have time to become apparent. The staff determined the inspection techniques will be capable of detecting cracking and the applicant will
 
initiate corrective actions if an unacceptable loss of material or wall thinning has occurred that
 
may have a spatial interaction with safety-related components, as determined by engineering
 
evaluation. On the basis that the applicant will be performing an appropriate combination of a
 
visual inspection and volumetric testing for these components, the staff finds the AMR results
 
for this line item acceptable.
 
In LRA Table 3.3.2-26, the applicant proposed to manage loss of material due to selective
 
leaching for copper alloy material for piping and piping components and elements exposed to
 
an external environment of indoor air using the AMP B.2.29 "Selective Leaching Inspection."
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
H, which indicates that the aging effect is not addressed in the Gall Report for this component, material and environment combination. The staff's evaluation of the AMP B.2.29 is documented
 
in SER Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will
 
perform a combination of visual inspection and hardness testing to determine if loss of material
 
due to selective leaching has occurred. The staff further noted that the applicant will perform the
 
inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and
 
the applicant will initiate corrective actions based on the evaluation of the results of these
 
inspections. On the basis that the applicant will be performing a combination of a visual
 
inspection and hardness test, which is consistent with the with the recommendations in GALL AMP XI.M33, for these components,  the staff finds the AMR results for this line item 
 
In LRA Table 3.3.2-26, the applicant proposed to manage loss of material of carbon steel piping
 
in an internal environment of ventilation by using the Supplementary Piping/Tank Inspection Program. The applicant referenced footnote "G" for th is line item indicating that environment is not in the GALL Report for this component and material combination. The environment is an
 
aggressive environment of air-water interface.
 
The staff reviewed the Supplementary Piping/Tank Inspection Program, which uses a
 
combination of volumetric and visual examination techniques to identify evidence of loss of
 
material or lack thereof. The staff's evaluation of the Supplementary Piping/Tank Inspection
 
Program is documented in SER Section 3.0.3.1.16. Because the Supplementary Piping/Tank 3-410 Inspection is performed at very specific locations of air/water interface, and employs a combination of volumetric and visual inspection techniques, the staff finds that the
 
Supplementary Piping/Tank Inspection Program will adequately manage the aging effects of
 
loss of material in this aggressive environment.
 
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  Aging Management Review Results - Sampling System - 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 system component groups.
 
In LRA Table 3.3.2-27, the applicant proposed to manage cracking of copper alloy for piping
 
and piping components and chiller components (condenser channel header, evaporator shell
 
and integral piping/tubing) in the Sampling System exposed to an internal environment of
 
treated water using the AMP B.2.14 "Closed Cooling Water Chemistry Program."
 
The AMR line item credits the Closed Cooling Water Program to manage cracking for these
 
components. The AMR line item cites Generic Note H, which indicates that the aging effect is
 
not addressed in the GALL Report for this component, material and environment combination.
 
The Closed Cooling Water Chemistry Program is an existing SSES program that properly monitors components and controls corrosion inhibitor concentrations for components, within the
 
scope of license renewal, consistent with relevant EPRI water chemistry guidelines.
 
The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008. The applicant
 
clarified that the one-time inspection performed as part of the AMP B.2.22, "Chemistry Program
 
Effectiveness Inspection" will be used to supplement AMP B.2.14, "Closed Cooling Water
 
Chemistry Program" in all instances where AMP B.2.14 is credited for aging management in LRA Table-2 items, with the exception of the Diesel Jacket Water Cooling System. The staff
 
reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP
 
B.2.22 "Chemistry Program Effectiveness Inspec tion" and its evaluations are documented in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging
 
management program includes activities that are consistent with the recommendations in the GALL AMP XI.M21 to maintain high water purity, which is effective for managing cracking for
 
copper and copper alloy components exposed to a treated water environment. The staff further
 
noted the Closed Cooling Water Chemistry Progr am is an existing SSES program that properly monitors components and controls corrosion inhibitor concentrations for components, within the
 
scope of license renewal, consistent with relev ant EPRI water chemistry guidelines. The staff confirmed that the Chemistry Program Effect iveness Inspection will be used to verify the effectiveness of the applicant's Closed Cooli ng Water Chemistry Program to manage cracking and that a combination of appropriate volumetric and visual examination techniques (such as
 
VT-1 or VT-3) will be performed by qualified personnel on a sample population of most
 
susceptible subject components. On this basis, the staff finds that these AMR results will be
 
adequately managed by these programs.
 
In LRA Table 3.3.2-27, the applicant proposed to manage loss of material due to selective
 
leaching for copper alloy material for chiller components (channel/header, integral piping/tubing 3-411 and evaporator shell) exposed to an external env ironment of indoor air using the AMP B.2.29 "Selective Leaching Inspection."
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
H, which indicates that the aging effect is not addressed in the Gall Report for this component, material and environment combination. The staff's evaluation of the AMP B.2.29 is documented
 
in SER Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will
 
perform a combination of visual inspection and hardness testing to determine if loss of material
 
due to selective leaching has occurred. The staff further noted that the applicant will perform
 
the inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and
 
the applicant will initiate corrective actions based on the evaluation of the results of these
 
inspections. On the basis that the applicant will be performing a combination of a visual
 
inspection and hardness test, which is consistent with the with the recommendations in GALL AMP XI.M33, for these components,  the staff finds the AMR results for this line item 
 
In Table 3.3.2-27, the LRA states that for Teflon piping and piping components in treated water
 
internal environment in the sampling system , there are no aging effects requiring management.
In RAI 3.3.2.3-1, part A by letter dated July 23, 2008, the staff asked the applicant to justify why
 
it had not identified any aging effects requi ring management for these system-material-environment combinations.
 
In its letter dated August 27, 2008, in response to RAI 3.3.2.3-1, Part A, the applicant stated
 
that:
The only applicable aging effect for Teflon is change in material properties. Change in
 
material properties of Teflon may be due to exposure to gamma radiation. Thermal
 
exposure and exposure to ultraviolet radiation or ozone are not applicable aging
 
mechanisms for Teflon.
 
Gamma radiation is an applicable aging mechanism for Teflon components only if the
 
total integrated dose (TID) is equal to or greater than 10E4 rads. The Teflon components
 
in the Fire Protection System are located in the Circulating Water Pumphouse, an area
 
of the plant where ionizing radiation levels are such that the TID over a 60-year period, which includes the period of extended operation, will not equal or exceed 10E3 rads.
 
Also, there are no sources of gamma radiation expected to exist in the raw water of the
 
Fire Protection System or the treated wa ter environment of the Sampling System.
Therefore, change to the material properties and cracking due to ionizing radiation are
 
not aging effects requiring management for these components.
 
The staff reviewed the applicant response and noted that these piping and piping components
 
are located in an area where the ionizing radiation is less than the threshold value of 10E6 rads.
 
On this basis, the staff finds the applicant response acceptable and concludes that for Teflon
 
piping and piping components in treated water inte rnal environment in the sampling system, there are no aging effects requiring management.
 
3-412 In Table 3.3.2-27, the applicant stated that Teflon piping and piping components in an indoor air external environment has an aging effect of change in material properties and has credited the
 
System Walkdown Program to manage this aging effect. In its letter dated August 27, 2008, in
 
response to RAI 3.3.2.3-1, the applicant stated that these Teflon piping and piping components
 
are located in areas of the Reactor Building where these components could be exposed to
 
ionizing radiation greater than 10E6 rads and to temperatures greater than 95 o F. Therefore, the applicant has identified the aging effect of change in material properties.
 
In RAI B.2.32-4, the staff asked the applicant to justify its basis for crediting the System
 
Walkdown Program to manage cracking and changes in material properties that may occur in
 
the internal surfaces of in-scope components that are fabricated from non-metallic material. In
 
its letter dated August 12, 2008, in response to RAI B.2.32-4, the applicant revised the LRA to
 
include additional enhancements to address the management of changes in material properties
 
of elastomer and polymer materials. The staff's acceptance of the System Walkdown Program
 
to manage this aging effect and its discussion of RAI B.2.32-4 are documented in SER Section
 
3.0.3.2.14. The staff determined the applicant will supplement a visual inspection performed
 
during periodic system walkdowns with a suppl emental physical manipulation and/or prodding to inspect elastomer and polymer components. The staff noted that the physical manipulation will
 
aid the visual inspection in detecting age-related degradation because changes in material
 
properties and cracking can be detected during manipulation of elastomeric and polymeric
 
components by the relative inflexibility of the co mponent, or by the failure of the component to return to its previous shape or configuration.
Based on this review, the staff concludes that the System Walkdown Program will adequately manage the aging effect of change in material
 
properties of Teflon piping and piping components during the period of extended operation.
 
LRA Table 3.3.2-27 summarizes the results of AMRs for sampling system piping and piping
 
components constructed using copper alloy exposed to indoor air (external). The applicant
 
proposed that there is no aging effect for the material environment combination and that no
 
AMR is required.
 
The applicant has indicated that generic note G is applicable for these items. Generic note G is
 
"Environment not in NUREG-1801 for this component and material." The staff confirmed that
 
this environment is not in GALL for the component and material. The staff also agrees that there
 
will not be an aging mechanism for this material/environment combination, and that no AMP is
 
required.
 
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  Aging Management Review Results - Sanitary Drainage System - LRA Table 3.3.2-28 
 
The staff reviewed LRA Table 3.3.2-28, which summarizes the results of AMR evaluations for
 
the sanitary drainage system component groups.
 
In LRA Table 3.3.2-28, the applicant proposed to manage loss of material due for cast iron and
 
carbon steel material for piping and piping components exposed to an internal environment of
 
raw water using the AMP B.2.46 "Area-Based NSAS Inspection."
3-413  The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of
 
material for these components. The AMR line item cites Generic Note G, which indicates that
 
the environment is not addressed in GALL Report for this component and material combination. 
 
The staff's evaluation of the AMP B.2.46 is documented in SER Section 3.0.3.3.1. The staff
 
noted that this program is a plant-specific program that performs an appropriate combination of
 
established volumetric and visual inspecti on techniques (nondestructive examination techniques) that will be performed by a qualified personnel on a sample population of those
 
components in scope of this program. The staff further noted that the applicant will perform the
 
inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such degradation that progresses slowly and have
 
long incubation times will have time to become apparent. The staff determined the inspection
 
techniques will be capable of detecting loss of material and the applicant will initiate corrective
 
actions if an unacceptable loss of material or wall thinning has occurred that may have a spatial
 
interaction with safety-related components, as determined by engineering evaluation. On the
 
basis that the applicant will be performing an appropriate combination of a visual inspection and
 
volumetric testing for these components, the staff finds the AMR results for this line item
 
acceptable.
 
In LRA Table 3.3.2-28, the applicant proposed to manage loss of material due to selective
 
leaching for cast iron for piping and piping components exposed to an internal environment of
 
raw water using the AMP B.2.29 "Selective Leaching Inspection."
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
G, which indicates that the environment is not addressed in GALL Report for this component
 
and material combination. The staff's evaluation of the AMP B.2.29 is documented in SER
 
Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will perform a
 
combination of visual inspection and hardness testing to determine if loss of material due to
 
selective leaching has occurred. The staff further noted that the applicant will perform the
 
inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and
 
the applicant will initiate corrective actions based on the evaluation of the results of these
 
inspections. The staff noted that the GALL Report recommends the use of the Selective
 
Leaching Program for the same combination of material/environment/aging effect in items
 
VII.C1-11 for a different system. On the basis that the applicant will be performing a
 
combination of a visual inspection and hardness test for these components and these AMR
 
material/environment/aging effect combination is consistent with the GALL AMR Item VII.C1-11
 
for cast iron,  the staff finds the AMR results for this line item acceptable.
 
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR
 
results of material, environment, AERM, and AMP combinations not evaluated in the GALL
 
Report. The staff finds that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended function(s) will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-414  3.3.2.3.29  Aging Management Review Results - Service Air System - LRA Table 3.3.2-29 
 
The staff reviewed LRA Table 3.3.2-29, which summarizes the results of AMR evaluations for
 
the service air system component groups. The sta ff determined that all AMR evaluation results in LRA Table 3.3.2-29 are consistent with the GALL Report.
 
3.3.2.3.30  Aging Management Review Results -
Service Water System - LRA Table 3.3.2-30 
 
The staff reviewed LRA Table 3.3.2-30, which summarizes the results of AMR evaluations for
 
the service water system component groups.
 
In LRA Table 3.3.2-30, the applicant proposed to manage cracking for copper alloy material for
 
piping and piping components exposed to an internal environment of raw water using the AMP
 
B.2.46 "Area-Based NSAS Inspection."
 
The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of
 
material for these components. The AMR line item cites Generic Note H, which indicates that
 
the aging effect is not addressed in the Gall Report for this component, material and
 
environment combination. The staff's evaluation of the AMP B.2.46 is documented in SER
 
Section 3.0.3.3.1. The staff noted that this program is a plant-specific program that performs an
 
appropriate combination of established volumetric and visual inspection techniques (nondestructive examination techniques) that will be performed by a qualified personnel on a
 
sample population of those components in scope of this program. The staff further noted that
 
the applicant will perform the inspections of the components with in the scope of this program at
 
least 10 years prior to entering the period of extended operation such degradation that
 
progresses slowly and have long incubation time s will have time to become apparent. The staff determined the inspection techniques will be capable of detecting cracking and the applicant will
 
initiate corrective actions if an unacceptable loss of material or wall thinning has occurred that
 
may have a spatial interaction with safety-related components, as determined by engineering
 
evaluation. On the basis that the applicant will be performing an appropriate combination of a
 
visual inspection and volumetric testing for these components, the staff finds the AMR results
 
for this line item acceptable.
 
In LRA Table 3.3.2-30, the applicant proposed to manage loss of material due to selective
 
leaching for copper alloy material for piping and piping components exposed to an external
 
environment of indoor air using the AMP B.2.29 "Selective Leaching Inspection."
 
The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of
 
material due to selective leaching for these components. The AMR line item cites Generic Note
 
H, which indicates that the aging effect is not addressed in the Gall Report for this component, material and environment combination. The staff's evaluation of the AMP B.2.29 is documented
 
in SER Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will
 
perform a combination of visual inspection and hardness testing to determine if loss of material
 
due to selective leaching has occurred. The staff further noted that the applicant will perform
 
the inspections of the components with in the scope of this program at least 10 years prior to
 
entering the period of extended operation such that the condition of the material is more
 
representative of the conditions during the period of extended operation. The staff determined
 
the applicants proposed inspection techniques to detect loss of material due to selective leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and
 
the applicant will initiate corrective actions based on the evaluation of the results of these 3-415 inspections. On the basis that the applicant will be performing a combination of a visual inspection and hardness test, which is consistent with the with the recommendations in GALL AMP XI.M33, for these components,  the staff finds the AMR results for this line item 
 
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  Aging Management Review Results - Standby Liquid Control System -
 
LRA Table 3.3.2-31 
 
The staff reviewed LRA Table 3.3.2-31, which summarizes the results of AMR evaluations for
 
the SLC system component groups.
 
In LRA Table 3.3.2-31, the applicant proposed to manage loss of material of stainless steel
 
tanks in an internal environment of ventila tion by using the Supplementary Piping/Tank Inspection Program. The applicant referenced footnote "J" for this line item indicating that
 
neither the component nor the material and environment combination is evaluated in the GALL
 
Report. The applicant also references footnote 0338, indicating loss of material is due to crevice
 
and/or pitting corrosion at the air/water interface within the SLC Storage Tank.
 
The staff reviewed the Supplementary Piping/Tank Inspection Program, which uses a
 
combination of volumetric and visual examination techniques to identify evidence of loss of
 
material or lack thereof. The staff's evaluation of the Supplementary Piping/Tank Inspection
 
Program is documented in SER Section 3.0.3.1.16. Because the Supplementary Piping/Tank
 
Inspection is performed at very specific locations of air/water interface, and employs a
 
combination of volumetric and visual inspection techniques, the staff finds that the
 
Supplementary Piping/Tank Inspection Program will adequately manage the aging effects of
 
loss of material in this aggressive environment.
 
In Table 3.3.2-31, the LRA states that for butyl rubber accumulators that are exposed internally
 
to a nitrogen air gas environment and externally to treated water, there are no aging effects
 
requiring management. In RAI 3.3.2.3-1, Part A by letter dated July 23, 2008, the staff asked the
 
applicant to justify why it had not identified any aging effects requiring management for these
 
system-material-environment combinations.
 
In its letter dated August 27, 2008, in response to RAI 3.3.2.3-1 part A, the applicant stated that
 
the applicable aging effects for elastomers (including butyl rubber, synthetic rubber, neoprene, and silicone) are change in material properties and cracking, which may be due to ionizing
 
radiation, thermal exposure, or exposure to ultraviolet radiation or ozone. The applicant
 
provided the threshold level for ionizing radiation as 10E6 rads, for temperature as greater than
 
95 o F, and for ultraviolet radiation and ozone as prolonged exposure. The applicant further stated that, except for certain areas in the Reactor Building, where ionizing radiation could be
 
more than the threshold limit, the other buildings are all in an environment that is within the
 
threshold limits. Therefore, the applicant concluded that there are no aging effects requiring
 
management for butyl rubber accumulators that are exposed internally to a nitrogen air gas
 
environment and externally to treated wate r in the standby liquid control system.
 
The staff reviewed the applicant response to RAI 3.3.2.3-1, part A, and finds the applicant 3-416 response acceptable because the applicant defined the stressors that could cause the aging effects in various structures. The applicant response is consistent with the GALL Report
 
definitions of the threshold limits of the stressors as recommended in the GALL Report Section IX. On the basis of its review, the staff finds for butyl rubber accumulators that are exposed
 
internally to a nitrogen air gas environment and ex ternally to treated water in the standby liquid control system, there are no 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).
 
3.3.2.3.32  Aging Management Review Results - Turbine Building Closed Cooling Water
 
System - LRA Table 3.3.2-32 
 
The staff reviewed LRA Table 3.3.2-32, which summarizes the results of AMR evaluations for
 
the turbine building closed cooling water system component groups.
 
The staff reviewed LRA Table 3.3.2-32, which summarizes the results of AMR evaluations for
 
the turbine building closed cooling water system component groups. The staff determined that
 
all AMR evaluation results in LRA Table 3.3.2-32 are consistent with the GALL Report.
 
3.3.2.3.33  Aging Management Review Results - Reactor Recirculation System (NSAS Portions)
 
- LRA Table 3.3.2-33 
 
The staff reviewed LRA Table 3.3.2-33, which summarizes the results of AMR evaluations for
 
the reactor recirculation system (NSAS) component groups. The staff determined that all AMR
 
evaluation results in LRA Table 3.3.2-33 are consistent with the GALL Report.
 
3.3.2.3.34  Aging Management Review Results - Reactor Vessel and Auxiliaries System (NSAS Portions) - LRA Table 3.3.2-34 
 
The staff reviewed LRA Table 3.3.2-34, which summarizes the results of AMR evaluations for
 
the RV and auxiliaries system (NSAS portions) component groups. The staff determined that all
 
AMR evaluation results in LRA Table 3.3.2-33 are consistent with the GALL Report.
 
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:
* Auxiliary Boiler System 3-417
* Bypass Steam System
* Condensate Transfer and Storage System
* Condenser and Air Removal System
* Feedwater System
* Main Steam System
* Main Turbine System
* Makeup Demineralizer System
* Makeup Transfer and Storage System
* Refueling Water Transfer and Storage 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
 
Programs for Steam and Power Conversion Syst ems Evaluated in Chapter VIII of the GALL Report," is a summary comparison of the applicant's AMRs with those evaluated in the GALL
 
Report for the steam and power conversi on systems components and component groups.
 
The applicant's AMRs evaluated and incorporated applicable plant-specific and industry OE 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 OE included a review of the GALL Report and OE 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 onsite 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 3.4.2.1.
 
In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which
 
further evaluation is recommended. The staff confirmed that the 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, 3-418 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 Steel piping, piping components, and
 
piping elements
 
exposed to steam or treated water
 
(3.4.1-1)
Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes TLAA Consistent with GALL Report, which
 
recommends further
 
evaluation (See SER
 
Section 3.4.2.2.1)
Steel piping, piping
 
components, and
 
piping elements
 
exposed to steam
 
(3.4.1-2)
Loss of material due to general, pitting and
 
crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable. The applicant addresses
 
these components
 
under GALL Report
 
item number 3.4.1-4. (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 Not applicable Not applicable to BWRs (See SER
 
Section 3.4.2.2.2.1)
Steel piping, piping
 
components, and
 
piping elements
 
exposed to treated water (3.4.1-4)
Loss of material due to general, pitting and
 
crevice corrosion Water Chemistry and One-Time Inspection Yes BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report (See SER Section 3.4.2.2.2.1)
Steel heat exchanger
 
components exposed to treated water
 
(3.4.1-5)
Loss of material due to general, pitting, crevice, and galvanic
 
corrosion Water Chemistry and One-Time InspectionYes Not applicable Not Applicable. There are no steel heat
 
exchanger
 
components in-scope for license renewal in the steam and power conversion system. (See SER Section 3.4.2.2.9) 3-419 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 tanks exposed to treated water
 
(3.4.1-6)
Loss of material due to general (steel only)
 
pitting and
 
crevice corrosion Water Chemistry and One-Time Inspection Yes BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report  (See SER Section 3.4.
2.2.2.1, and SER Section 3.4.2.2.7.1)
Steel piping, piping
 
components, and
 
piping elements
 
exposed to
 
lubricating oil
 
(3.4.1-7)
Loss of material due to general, pitting and
 
crevice corrosion Lubricating Oil Analysis and One-Time InspectionYes Not applicable Not applicable (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 (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 Not applicable Not Applicable (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 Not applicable Not applicable  (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 No 
 
Yes Not applicable Not applicable  (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 (See SER Section 3.4.2.2.5.2) 3-420 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 Inspection Yes BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report  (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 C (> 140 F) (3.4.1-14)
Cracking due to stress corrosion
 
cracking Water Chemistry and One-Time InspectionYes Not applicable Not applicable. The applicant addresses
 
these components
 
under GALL Report
 
item number
 
3.4.1-13. (See SER Section 3.4.2.2.6)
Aluminum and copper alloy piping, piping components, and piping elements
 
exposed to treated water (3.4.1-15)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time Inspection Yes BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with the GALL Report (See SER Section 3.4.2.2.7.1)
Stainless steel
 
piping, piping
 
components, and
 
piping elements;
 
tanks, and heat
 
exchanger
 
components exposed to treated water
 
(3.4.1-16)
Loss of material due to pitting
 
and crevice
 
corrosion Water Chemistry and One-Time Inspection Yes BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection (B.2.22) Consistent with GALL Report (See SER Section 3.4.2.2.7.1)
Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to soil
 
(3.4.1-17)
Loss of material due to pitting
 
and crevice
 
corrosion Plant-specific Yes Buried Piping and Tanks
 
Inspection
 
Program 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 (See SER Section 3.4.2.2.7.3) 3-421 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 Not applicable Not applicable (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 System Walkdown Program (B.2.32) and
 
Condensate and Refueling Water Storage Tank
 
Inspection (B.2.19) Consistent with GALL Report 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 Bolting Integrity Program (B.2.12) Consistent with GALL Report  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.2.12) Consistent with GALL Report  Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to closed-cycle cooling water > 60 C (> 140 F) (3.4.1-23)
Cracking due to stress corrosion
 
cracking Closed-Cycle Cooling Water System No BWR Water Chemistry
 
Program (B.2.2) and Chemistry
 
Program Effectiveness
 
Inspection
 
Program (B.2.22) Evaluated in line item 3.4.1-13  (See SER
 
Section 3.4.2.1.1)
Steel heat exchanger
 
components exposed to closed cycle cooling water
 
(3.4.1-24)
Loss of material due to general, pitting, crevice, and galvanic
 
corrosion Closed-Cycle Cooling Water System No Not applicable Not applicable to SSES (See SER
 
Section 3.4.2.1.1) 3-422 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 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 SSES (See SER
 
Section 3.4.2.1.1) 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 SSES (See SER
 
Section 3.4.2.1.1)
Steel, stainless steel, and copper alloy heat
 
exchanger tubes
 
exposed to closed cycle cooling water
 
(3.4.1-27)
Reduction of heat transfer due
 
to fouling Closed-Cycle Cooling Water System No Not applicable Not applicable to SSES (See SER
 
Section 3.4.2.1.1)
Steel external
 
surfaces exposed to
 
air - indoor
 
uncontrolled (external),
condensation (external), or air
 
outdoor (external)
 
(3.4.1-28)
Loss of material due to general
 
corrosion External Surfaces Monitoring No System Walkdown Program (B.2.32), and Supplementary Piping/Tank
 
Inspection (B.2.28) Consistent with GALL Report (See SER Section 3.4.2.1.2)
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 (B.2.11), and
 
Preventive
 
Maintenance
 
Activities - Main Turbine (B.2.49) Consistentwith GALL Report (See SER Section 3.4.2.1.3)
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 Supplemental Piping and Tanks Inspection
 
Program (B.2.28) Consistent with GALL Report (See SER
 
Section 3.4.2.1.4) 3-423 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel heat exchanger components exposed to 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 Not applicable Not applicable (See SER Section
 
3.4.2.1.1)
Stainless steel and copper alloy piping, piping components, and piping elements exposed to raw water
 
(3.4.1-32)
Loss of material due to pitting, crevice, and
 
microbiologically
-influenced
 
corrosion Open-Cycle Cooling Water System No Not applicable Not applicable to SSES (See SER
 
Section 3.4.2.1.1)
Stainless steel heat
 
exchanger
 
components exposed to raw water
 
(3.4.1-33)
Loss of material due to pitting, crevice, and
 
microbiologically
-influenced
 
corrosion, and
 
fouling Open-Cycle Cooling Water System No Not applicable Not applicable to SSES (See SER
 
Section 3.4.2.1.1)
Steel, stainless steel, and copper alloy heat
 
exchanger tubes exposed to raw water
 
(3.4.1-34)
Reduction of heat transfer due
 
to fouling Open-Cycle Cooling Water System No Not applicable Not applicable to SSES (See SER
 
Section 3.4.2.1.1) Copper alloy
> 15% Zn piping, piping components, and piping elements
 
exposed to closed cycle cooling water, raw water, or treated water (3.4.1-35)
Loss of material due to selective
 
leaching Selective Leaching of Materials No Selective Leaching Inspection
 
Program (B.2.29) Consistent with GALL Report Gray cast iron piping, piping components, and piping elements
 
exposed to soil, treated water, or raw water (3.4.1-36)
Loss of material due to selective
 
leaching Selective Leaching of Materials No Not applicable Not applicable to SSES (See SER
 
Section 3.4.2.1.1)
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 BWR Water Chemistry
 
Program (B.2.2) Consistent with GALL Report (See SER Section 3.4.2.1) 3-424 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel bolting and external surfaces exposed to air with borated water
 
leakage (3.4.1-38)
Loss of material due to boric acid
 
corrosion Boric Acid Corrosion No Not applicable Not applicable to BWRs Stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to steam
 
(3.4.1-39)
Cracking due to stress corrosion
 
cracking Water Chemistry No Not applicable Not applicable to BWRs 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 SSES (See SER
 
Section 3.4.2.1.1)
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 SSES (See SER
 
Section 3.4.2.1.1)
Steel and stainless
 
steel piping, piping
 
components, and
 
piping elements in
 
concrete (3.4.1-43) None None No Not applicable Not applicable to SSES (See SER
 
Section 3.4.2.1.1)
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 c onversion 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 3-425 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 documented 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 programs
 
that manage aging effects for the steam and power conversion systems components:
BWR Water Chemistry Program  Flow-Accelerated Corrosion (FAC) Program  Bolting Integrity Program Condensate and Refueling Water Storage Tanks Inspection Chemistry Program Effectiveness Inspection  Supplemental Piping/Tank Inspection  Selective Leaching Inspection  Buried Piping and Tanks Inspection Program System Walkdown Program LRA Tables 3.4.2-1 through 3.4.2-10 summarizes 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 GA LL Report; however, the applicant identified in 3-426 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. 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 reviewed the LRA to confirm that the applicant: (a) provided a brief description of the
 
system, components, materials, and environments; (b) stated that the applicable aging effects were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the
 
engineered safety features ESF components that are subject to an AMR. On the basis of its
 
audit and review, the staff determines that, for AMRs not requiring further evaluation, as
 
identified in LRA Table 3.2.1, the applicant's references to the GALL Report are acceptable and
 
no further staff review is required, with the exception of the following AMRs that the applicant
 
had identified were consistent with the AMRs of the GALL Report and for which the staff felt
 
were in need of additional clarification and assessment. The staff's evaluations of these AMRs
 
are providing in the subsections that follows. 
 
3.4.2.1.1 AMR Results Identified as Not Applicable 
 
In LRA Table 3.4.1, item 23, the applicant states for this line item cracking of stainless steel
 
piping, piping components, and piping elements is addressed under the treated water
 
environment in table item 3.4.1-23. The staff reviewed the documentation supporting the
 
applicant's AMR evaluation and confirmed that the components under the this commodity group: stainless steel piping, piping components, and piping elements, are evaluated as
 
exposed to uncontrolled air under line item 3.4.1-23. On the basis that this commodity group
 
has been evaluated, the staff agreed with the applicant's treatment of this line item.
 
In LRA Table 3.4.1, items 24 and 25, the applicant states that there are no steel heat exchanger
 
components and stainless steel components that are subject to AMR and exposed to treated (closed cycle cooling) water in the steam and power conversion system for SSES. The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed that no 3-427 components under this commodity group exist in the Steam and Power Conversion System.
Therefore, the staff agrees with the applicant's determination that the corresponding AMR result
 
lines in the GALL Report is not applicable to SSES.
 
In LRA Table 3.4.1, items 27 and 28, the applicant states that there are no cooper alloy
 
components and heat exchanger tubes exposed to cl osed cycle cooling water in the steam and power system for SSES that are subject to AMR. The staff reviewed the documentation
 
supporting the applicant's AMR evaluation and confirmed that no components under this
 
commodity group exist in the Steam and Power C onversion System. Therefore, the staff agrees with the applicant's determination that the corresponding AMR result lines in the GALL Report is
 
not applicable to SSES.
 
In LRA Table 3.4.1, items 31, 32, 33, and 34, the applicant states that the corresponding AMR
 
result line in the GALL Report is not applicable because only the main condenser in the steam
 
and power conversion system contains steel components that are subject to AMR and exposed to raw water. The applicant further stated that no aging effects were identified that could affect
 
the intended function of Isolated Condenser Treatment Method (ICTM) volume for these
 
components. The staff reviewed the system intended function provided in LRA Section 2.3.4.4
 
and noted that the intended function is to support the MSIV leakage ICTM by providing hold-up
 
and plate-out of fission products. 
 
The staff found that, to maintain the intended function of plateout and holdup during post-
 
accident conditions, the main condenser and main condenser complex components must
 
remain intact. The staff noted that normal plant operations monitor condenser vacuum
 
continuously to verify its integrity, and that the acceptable performance of the main condenser
 
during normal plant operation is adequate assurance that it will perform the plateout and holdup
 
post-accident function. Therefore, the staff agrees with the applicant's conclusion that no AMP
 
is required to assure the post-accident intended function and that this aging effect is not
 
applicable, and the staff finds that the corresponding AMR result line in the GALL Report is not
 
applicable to SSES.
 
In LRA Table 3.4.1, item 36, the applicant states for this line item there are no gray cast iron
 
piping, piping, components or piping elements that are subject to AMR and exposed to soil, treated water or raw water in the steam and power conversion system for SSES. The staff
 
reviewed the documentation supporting the applicant's AMR evaluation and confirmed that no
 
components under this commodity group exist in the Steam and Power Conversion System.
Therefore, the staff agrees with the applicant's determination that the corresponding AMR result
 
lines in the GALL Report is not applicable to SSES. 
 
In LRA Table 3.4.1, item 40, the applicant states for this line item, there are no glass piping
 
elements in the steam and power conversion system for SSES. The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed that no components
 
under this commodity group exist in the Steam and Power Conversion System. Therefore, the staff agrees with the applicant's determination that the corresponding AMR result lines in the
 
GALL Report is not applicable to SSES.
In LRA Table 3.4.1, item 42, the applicant states for this line item, indoor environments are
 
considered to be uncontrolled. The staff reviewed the documentation supporting the applicant's
 
AMR evaluation and confirmed that the com ponents under the this commodity group: steel piping, piping components, and piping elements, are evaluated as exposed to uncontrolled air
 
under line item 3.4.1-28. On the basis that this commodity group has been evaluated, the staff 3-428 agreed with the applicant's statement that this line item is not applicable.
In LRA Table 3.4.1, item 43, the applicant states for this line item, there are no components in the steam and power conversion system for SSES embedded in concrete. The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed that no
 
components under this commodity group exist in the Steam and Power Conversion System.
Therefore, the staff agrees with the applicant's determination that the corresponding AMR result
 
lines in the GALL Report is not applicable to SSES. 
 
3.4.2.1.2  Loss of material due to general corrosion
 
In Table 3.4.2-6, the LRA states that loss of material of main steam system steel piping in an
 
external environment of indoor air is managed by the Supplementary Piping/Tank Inspection Program.
 
During the audit, the staff noted that the applicant applied note E to this item and referenced
 
LRA Table 3.4-1, item 3.4.1-28 and GALL Report Volume 2, item VII.H-7. The staff reviewed the
 
AMR results lines that reference note E and determines that the component type, material, environment, and aging effect are consistent with the GALL Report. However, the staff noted that where the GALL Report recommends AMP XI.M36, "External Surface Monitoring", the
 
applicant proposed using the Supplementary Piping/Tank Inspection Program. The LRA also
 
references footnote 0401, which states that the environment is an aggressive air/water interface
 
in the suppression pool. The staff determined that in this environment, loss of material is due to
 
crevice and pitting corrosion on the inside surface of SRV discharge piping at air/water interface
 
in the suppression pool, and also, on the outside surface of SRV discharge piping at air/water
 
interface in the suppression pool. 
 
However, the discussion column of Table 3.4.1, line item 3.4.1-28 only credits the System
 
Walkdown Program, and does not address the Supplementary Piping/Tank Inspection Program.
 
The staff issued RAI 3.4.2.1-1 by letter dated July 23, 2008 to request the applicant to clarify
 
this discrepancy. 
 
Furthermore, for the same air/water interface environment, in some cases the LRA tables
 
reference footnote "G" or "H" and in some cases, they reference footnote "E." RAI 3.4.2-1 also
 
requested to clarify this discrepancy.
 
In its letter dated August 22, 2008, the applicant responded to RAI 3.4.2.1-1 by amending the
 
LRA to include the following paragraph in the discussion column of Table 3.4.1, item 3.4.1-28:
 
This item also includes loss of material due to pitting and crevice corrosion at air/water
 
interfaces for carbon steel piping components in an indoor air environment. The
 
Supplemental Piping/Tank Inspection is credited to detect and characterize loss of
 
material for these components. A Note E is used.
 
On the basis that the applicant amended the LRA to resolve the discrepancy between
 
Table 3.4.1, item 3.4.1-28 discussion column and Table 3.4.2-6, the staff finds the response
 
acceptable.
 
Furthermore, the applicant stated that the footnote H was used incorrectly and that note E
 
should have been used as per the response provided in RAI 3.2.2.3.1-1 and documented in
 
SER Section 3.2.2.3.1.
3-429  The staff reviewed the Supplementary Piping/Tank Inspection Program, which uses a
 
combination of volumetric and visual examination techniques to identify evidence of loss of
 
material or lack thereof. The staff's evaluation of the Supplementary Piping/Tank Inspection
 
Program is documented in SER Section 3.0.3.1.16. Because the Supplementary Piping/Tank
 
Inspection is performed at very specific locations of air/water interface, and employs more
 
conservative inspection techniques than the visual inspection of External Surfaces Monitoring Program, the staff finds that the Supplementary Piping/Tank Inspection Program will adequately
 
manage the aging effects of loss of material in this aggressive environment.
 
3.4.2.1.3  Wall Thinning due to Flow-Accelerated Corrosion
 
In its letter dated June 30, 2008, in response to RAI B2.11-1, the applicant stated that wall
 
thinning due to flow-accelerated corrosion of steel main turbine casings in a treated water
 
environment is managed by the Preventive Ma intenance Activities - Main Turbine.
The staff noted that the applicant applied note E to this item and referenced Table 3.4-1, item 3.4.1-29 and GALL Report Volume 2, item VIII.B2-4. The staff reviewed the AMR results lines
 
that reference note E and determines that the component type, material, environment, and
 
aging effect are consistent with the GALL Report. However, the staff noted that where the GALL Report recommends AMP XI.M17, "Flow-Accelerated Corrosion", the applicant proposed using
 
the Preventive Maintenance Activities - Main Turbine Program. 
 
The staff reviewed the Preventive Maintenance Activities - Main Turbine Program, which is an
 
existing plant-specific program that will be enhanced to include the inspection of the high
 
pressure turbine shell using visual inspection (VT-3 or equivalent) techniques and an ultrasonic
 
examination for wall thickness. The staff evaluated the Preventive Maintenance Activities - Main
 
Turbine Program and its evaluation is documented in SER Section 3.0.3.3.4. The staff finds the
 
Preventive Maintenance Activities - Main Turbine acceptable to manage the aging effects of
 
loss of material due to flow-accelerated corrosion because the turbine shell will be visually and
 
volumetrically inspected in the presence of the turbine manufacturer representative, and the
 
operating experience review did not indicate any wear on the turbine outer casing during
 
significant modification work performed on these turbines over the last 5 years. On this basis, the staff finds that the Preventive Maintenance Activities - Main Turbine will adequately manage
 
loss of material of steel turbine casing in a treated water environment during the period of
 
extended operation.
 
3.4.2.1.4  Loss of material due to general, pitting and crevice corrosion
 
In Table 3.4.2-3, the LRA states that loss of material of condensate transfer and storage system
 
steel valve bodies in an internal environment of ventilation is managed by the Supplementary Piping/Tank Inspection Program.
 
During the audit, the staff noted that the applicant applied note E to this item and referenced
 
LRA Table 3.4-1, item 3.4.1-30 and GALL Report Volume 2, item VIII.B1-6. The staff reviewed
 
the AMR results lines that reference note E and determines that the component type, material, environment, and aging effect are consistent with the GALL Report. However, the staff noted that where the GALL Report recommends AMP AMP XI.M38, "Inspection of Internal Surfaces in
 
Miscellaneous Piping and Ducting Components", the applicant proposed using the
 
Supplementary Piping/Tank Inspection Program. 
 
3-430 The staff reviewed the Supplementary Piping/Tank Inspection Program, which uses a combination of volumetric and visual examination techniques to identify evidence of loss of
 
material or lack thereof. The staff's evaluation of the Supplementary Piping/Tank Inspection
 
Program is documented in SER Section 3.0.3.1.16. Because the Supplementary Piping/Tank
 
Inspection employs more conservative inspecti on techniques than only the visual inspection of Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, the
 
staff finds that the Supplementary Piping/Tank Inspection Program will adequately manage the
 
aging effects of loss of material in an internal environment of ventilation.
 
SER Section 3.4.2.1 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).
3.4.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is
 
Recommended In LRA Section 3.4.2.2, the applicant further evaluates of aging management, as recommended
 
by the GALL Report, for the steam and power conversion systems co mponents and provides information concerning how it will manage the following aging effects:
* cumulative fatigue damage
* loss of material due to general, pitting, and crevice corrosion
* loss of material due to general, pitting, crevice, and microbiologically-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 
 
3-431 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). SER Section 4.3 documents the staff's
 
review of the applicant's evaluation of this TLAA.
 
3.4.2.2.2  Loss of Material Due to General, Pitting, and Crevice Corrosion 
 
The staff reviewed LRA Section 3.4.2.2.2 against the following 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 piping, piping components, piping elements, tanks, and heat exchangers.
 
The applicant stated that loss of material due to general, pitting, and crevice corrosion
 
for steel piping components and tanks exposed to treated water in the Steam and Power
 
Conversion System is managed by the BWR Water Chemistry Program. The BWR Water Chemistry Program manages aging effects through periodic monitoring and
 
control of contaminants. The Chemistry Progr am Effectiveness Inspection will provide a verification of the effectiveness of the BWR Water Chemistry Program to manage loss of
 
material due to general, pitting, and crevice corrosion through examination of steel
 
piping components and tanks exposed to treated water.
SRP-LR Section 3.4.2.2.2 states that loss of material due to general, pitting, and crevice
 
corrosion may occur in steel piping, piping components, piping elements, tanks, and
 
heat exchanger components exposed to treated water and for steel piping, piping
 
components, and piping elements exposed to steam. The existing AMP monitors and controls water chemistry to manage the effects of loss of material due to general, pitting, and crevice corrosion. However, control of water chemistry does not preclude loss of
 
material due to general, pitting, and crevice corrosion at locations with stagnant flow
 
conditions; therefore, the effectiveness of water chemistry control programs should be
 
verified to ensure that corrosion does not occur. The GALL Report recommends further
 
evaluation of programs to verify the effectiv eness 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.
 
The staff noted that the applicant combined components from LRA Table 3.4.1, item 2
 
with components in LRA Table 3.4.1, item 4 for the purpose of aging management
 
review. The staff finds this acceptable because the material, environment and aging
 
effect for item 3.4.1-2 is the same as for it em 3.4.2 4 except that the environment in item 3.4.1-2 is steam and in item 3.4.1-4 is liquid, and with regard to loss of material due to
 
corrosion, the aging effects in a liquid and in a steam environment are identical for steel
 
components. On this basis, the staff finds the application treatment of LRA Table item
 
3.4.1-2 as acceptable
 
The staff reviewed the applicant's BWR Water Chemistry Program. The staff's
 
evaluation of this program, which is documented in SER Section 3.0.3.1.1, determined
 
that the BWR Water Chemistry Program is consistent with the GALL Report's recommendations for AMP XI.M2, "Water Chemistry," and provides mitigation for the
 
aging effect of loss of material due to general, pitting, crevice, and galvanic corrosion.
 
The staff reviewed the applicant's Chemistry Program Effectiveness Inspection. The
 
staff's evaluation of this program, which is documented in SER Section 3.0.3.1.10, found
 
that the Chemistry Program Effectiveness Inspection is a one-time inspection that is 3-432 consistent with the GALL Report's recommendations for AMP XI.M32, "One-Time Inspection." The Chemistry Program Effectiv eness Inspection includes provisions for inspecting selected components in areas of low or stagnant flow and is capable of
 
detecting loss of material due to general, pitting crevice, and galvanic corrosion, if it
 
should occur in the selected components. Based on the applicant's use of a water
 
chemistry program that provides mitigation of the aging effect and use of a one-time
 
inspection to confirm effectiveness of the water chemistry program consistent with the
 
recommendations of the GALL Report, the staff finds the applicant's proposed AMPs for
 
managing the potential aging effect of loss of material due to general, pitting, crevice, and galvanic corrosion, in steel piping, piping components, piping elements, and tanks
 
exposed to treated water or to steam in the feedwater system, the condensate storage
 
and transfer system, the makeup demineralizer system, the makeup transfer and
 
storage system, and the refueling water transfer and storage system to be acceptable.
 
(2) LRA Section 3.4.2.2.2 addresses loss of material due to general, pitting, and crevice corrosion in piping, piping components, and piping elements exposed to lubricating oil.
 
The applicant stated that this aging effect is not applicable because there are no steel
 
components that are exposed to lubricati ng oil in the steam and power conversion system. 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 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
 
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.
 
The staff reviewed LRA Section 2.3.4 and verified that SSES does not have support
 
systems with-in the scope of license renewal that contain the piping, piping components
 
and piping elements fabricated from steel exposed to lubricating oil.
Based on the staff's review as described above and of LRA Section 3.4 and found that
 
there were no steel piping, piping components and piping elements exposed to
 
lubricating oil internally or externally. On the basis of this review, the staff finds that SRP-
 
LR Section 3.4.2.2.2 Item #2 is not applicable to SSES.
 
Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.4.2.2.2 criteria. For those line items that apply to LRA Section 3.4.2.2.2, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
3-433 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 (MIC), and fouling. The applicant stated that this aging
 
effect is not applicable because the only steam and power conversion components exposed to
 
raw water are the stainless steel tubes inside the main condenser.
 
SRP-LR Section 3.4.2.2.3 states that loss of material due to general, pitting, and crevice
 
corrosion, and MIC and fouling may occur in steel piping, piping components, and piping
 
elements exposed to raw water. The GALL Report recommends further evaluation of a plant-
 
specific AMP to ensure that the aging effect is adequately managed.
The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed
 
the applicant's claim that SSES has no steel piping, piping components, and piping elements
 
exposed to raw water. Therefore, the staff agrees with the applicant's determination that the
 
corresponding AMR result line in the GALL Report is not applicable to SSES.
 
Based}}

Latest revision as of 12:59, 14 January 2025

Safety Evaluation Report with Open Items Related to Susquehanna Steam Electric Station, Units 1 and 2
ML090630309
Person / Time
Site: Susquehanna  Talen Energy icon.png
Issue date: 03/13/2009
From:
Office of Nuclear Reactor Regulation
To:
Gettys Evelyn, NRR/DLR/RLRA 415-4029
Shared Package
ml090630304 List:
References
TAC MD3019, TAC MD3020
Download: ML090630309 (804)
v • d • e


Text

Retrieved from "https://kanterella.com/w/index.php?title=ML090630309&oldid=5319524"