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| number = ML092530506
| number = ML092530506
| issue date = 08/12/2009
| issue date = 08/12/2009
| title = 2009/08/12 Indian Point Lr Hearing - IP Final SER
| title = Lr Hearing - IP Final SER
| author name =  
| author name =  
| author affiliation = NRC/NRR
| author affiliation = NRC/NRR
Line 15: Line 15:


=Text=
=Text=
{{#Wiki_filter:1 IPRenewal NPEmails From: Green, Kimberly Sent: Wednesday, August 12, 2009 12:19 PM To: Santos, Cayetano Cc: Wen, Peter
{{#Wiki_filter:}}
 
==Subject:==
IP Final SER Attachments:
IP Final Safety Evaluation Report.pdf Tanny, Attached is the IP Final SER which is scheduled to be discussed at the Full Committee ACRS Meeting on September 10th.
 
I will bring over 15 cds and 3 printed copies as requested.
 
Please let me know if you have any questions.
 
KimberlyGreenSafetyPM(301)4151627kimberly.green@nrc.gov Hearing Identifier:  IndianPointUnits2and3NonPublic_EX Email Number:  1631  Mail Envelope Properties  (Kimberly.Green@nrc.gov20090812121800) 
 
==Subject:==
IP Final SER  Sent Date:  8/12/2009 12:18:48 PM  Received Date:  8/12/2009 12:18:00 PM From:    Green, Kimberly Created By:  Kimberly.Green@nrc.gov Recipients:    "Wen, Peter" <Peter.Wen@nrc.gov>
Tracking Status: None  "Santos, Cayetano" <Cayetano.Santos@nrc.gov>  Tracking Status: None Post Office:      Files    Size      Date & Time MESSAGE    382      8/12/2009 12:18:00 PM  IP Final Safety Evaluation Report.pdf    2174879 Options  Priority:    Standard  Return Notification:    No  Reply Requested:    No  Sensitivity:    Normal  Expiration Date:      Recipients Received:
Safety Evaluation Report Related to the License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3 Docket Nos. 50-247 and 50-286Entergy Nuclear Operations, Inc.
United States Nuclear Regulatory Commission Office of Nuclear Reactor Regulation August 2009 ii THIS PAGE INTENTIONALLY LEFT BLANK.
iii ABSTRACT This safety evaluation report (SER) documents the technical review of the Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3), license renewal application (LRA) by the U.S.
 
Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated April 23, 2007, and as
 
supplemented by letters dated May 3 and June 21, 2007, Entergy Nuclear Operations, Inc.,
(Entergy 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. Entergy requests renewal of the IP2 and IP3 operating licenses (Facility Operating
 
License Numbers DPR-26 and DPR-64, respectively) for a period of 20 years beyond the
 
current expirations at midnight on September 28, 2013, for IP2, and at midnight on
 
December 12, 2015, for IP3.
Indian Point is located approximately 24 miles north of the New York City boundary line. The NRC issued the construction permits on October 14, 1966 for IP2, and on August 13, 1969, for
 
IP3. The NRC issued the operating licenses on September 28, 1973 for IP2, and on
 
December 12, 1975, for IP3. IP2 and IP3 employ a pressurized water reactor design with a dry
 
ambient containment. Westinghouse Electric Corporation supplied the nuclear steam supply
 
system and Westinghouse Development Corporation originally designed and constructed the
 
balance of the plant with the assistance of its agent, United Engineers and Constructors. The
 
licensed power output of each unit is 3216 megawatts thermal (MWt) with a gross electrical
 
output of approximately 1080 megawatts electric (MWe).
On January 15, 2009, the staff issued an SER with Open Items Related to the License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3, in which the staff identified 20 open items
 
necessitating further review. This SER presents the status of the staffs review of information
 
submitted through August 6, 2009, the cutoff date for consideration in this SER. The 20 open
 
items that had been identified in the previous SER were resolved before the staff made a final determination on the LRA. SER Section1.5 summarizesthese items and their resolution.
Section 6.0 provides the staffs final conclusion on its review of the IP2 and IP3 LRA.
iv THIS PAGE INTENTIONALLY LEFT BLANK.
v TABLE OF CONTENTSABSTRACT...................................................................................................................................................iii TABLE OF CONTENTS................................................................................................................................vABBREVIATIONS........................................................................................................................................xiiINTRODUCTION AND GENERAL DISCUSSION.....................................................................................1-1 1.1  Introduction............................................................................................................................1-11.2  License Renewal Background...............................................................................................1
-3 1.2.1  Safety Review........................................................................................................1-4
 
====1.2.2 Environmental====
Review...........................................................................................1-5
 
===1.3 Principal===
ReviewMatters.......................................................................................................1-51.4  Interim Staff Guidance...........................................................................................................1-7
 
===1.5 Summary===
of Open Items........................................................................................................1-8 1.6  Summary of Proposed License Conditions..........................................................................1-21 STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW........................2-1
 
===2.1 Scoping===
and Scr eening Methodology....................................................................................2-1 2.1.1  In troduction
............................................................................................................
2-1 2.1.2  Summary of Technical Info rmation in the Application...........................................2-1
 
====2.1.3 Scoping====
and Screening Program Review..............................................................2-2 2.1.3.1  Implementating Procedures and Documentation Sources for Scoping and Screening.....................................................................................2-32.1.3.2  Quality Controls Applied to LRA Development......................................2-52.1.3.3  Training..................................................................................................2-5
 
2.1.3.4  Conclusion of Scoping and Screening Program Review.......................2-62.1.4  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)....................2-15 2.1.4.4  Plant-Level Scoping of Systems and Structures.................................2-18 2.1.4.5  Mechanical Scoping.............................................................................2-20 2.1.4.6  Structural Scoping................................................................................2-22 2.1.4.7  Electrical Scoping................................................................................2-232.1.4.8  Conclusion for Scoping Methodology..................................................2-24
 
====2.1.5 Screening====
 
Methodology.......................................................................................2-242.1.5.1  General Screening Methodology.........................................................2-24 2.1.5.2  Mechanical Component Screening......................................................2-25 2.1.5.3  Structural Component Screening.........................................................2-26 2.1.5.4  Electrical Component Screening.........................................................2-28 2.1.5.5  Conclusion for Screening Methodology...............................................2-29
 
====2.1.6 Summary====
of Ev aluation Findings.........................................................................2-29 2.2  Plant-Level Scoping Results................................................................................................2-29 2.2A  IP2 Plant-Level Scoping Results.......................................................................................2-2 9 2.2A.1  Intr oduction........................................................................................................2-2 9 2.2A.2  Summary of Technical Info rmation in the Application.......................................2-302.2A.3  Staff Evaluation.................................................................................................2-30 2.2A.4  Conclusion.........................................................................................................2-31 2.2B  IP3 Plant-Level Scoping Results.......................................................................................2-3 2 2.2B.1  Intr oduction........................................................................................................2-3 2 2.2B.2  Summary of Technical Info rmation in the Application.......................................2-322.2B.3  Staff Evaluation.................................................................................................2-32 2.2B.4  Conclusion.........................................................................................................2-33
 
===2.3 Scoping===
and Screening Result s: Mechanical Systems.......................................................2-34 2.3A  IP2 Scoping and Screening Results: Mechanical Systems..............................................2-36 2.3A.1  Reactor Coolant System....................................................................................2-36 vi2.3A.1.1  Reactor Vessel..................................................................................2-38 2.3A.1.2  Reactor Vesse l Internals...................................................................2-39 2.3A.1.3  Reactor Coolant Pressure Boundary................................................2-41 2.3A.1.4  Steam Generators.............................................................................2-442.3A.2  Engineered Safety Features..............................................................................2-45 2.3A.2.1  IP2 Residual Heat Removal..............................................................2-45 2.3A.2.2  IP2 Containment Spray System........................................................2-46 2.3A.2.3  IP2 Containment Isolation Support Systems.....................................2-48 2.3A.2.4  IP2 Safety Injection System..............................................................2-50 2.3A.2.5  IP2 Containment Penetrations..........................................................2-52 2.3A.3  IP2 Auxiliary Systems........................................................................................2-54 2.3A.3.1  IP2 Spent Fuel Pit Cooling System...................................................2-55 2.3A.3.2  IP2 Service Water System................................................................2-562.3A.3.3  IP2 Component C ooling Water System............................................2-58 2.3A.3.4  IP2 Compressed Air Systems...........................................................2-60 2.3A.3.5  IP2 Nitrogen Systems........................................................................2-61 2.3A.3.6  IP2 Chemical and Volume Control System.......................................2-63 2.3A.3.7  IP2 Primary Water System................................................................2-642.3A.3.8  IP2 Heating, Ventilation and Air Conditioning Systems....................2-65 2.3A.3.9  IP2 Containment Cooling and Filtration System...............................2-692.3A.3.10  IP2 Control Room Heating, Ventilation and Cooling System..........2-70 2.3A.3.11  IP2 Fire Protection - Water..............................................................2-71 2.3A.3.12  IP2 Fire ProtectionCarbon Dioxide, Halon, and RCP Oil Collection Systems............................................................................................2-86 2.3A.3.13  IP2 Fuel Oil Systems.......................................................................2-90 2.3A.3.14  IP2 Emergency Diesel Generator System......................................2-91 2.3A.3.15  IP2 Security Generator System.......................................................2-94 2.3A.3.16  IP2 Appendix R Diesel Generator System......................................2-95 2.3A.3.17  IP2 City Water.................................................................................2-96 2.3A.3.18  IP2 Plant Drains.............................................................................2-1012.3A.3.19  IP2 Miscellaneous Systems in Scope for 10 CFR 54.4(a)(2)........2-102 2.3A.4  Steam and Power Conversion Systems..........................................................2-1072.3A.4.1  IP2 Main Steam System..................................................................2-107
 
2.3A.4.2  IP2 Main Feedwater System...........................................................2-109 2.3A.4.3  IP2 Auxiliary Feedwater System.....................................................2-112 2.3A.4.4  IP2 Steam Gener ator Blowdown System........................................2-1142.3A.4.5  IP2 Auxiliary Feedwater Pump Room Fire Event............................2-115
 
2.3A.4.6  IP2 Condensate System..................................................................2-120 2.3B  IP3 Scoping and Screening Results: Mechanical Systems............................................2-122 2.3B.1  Reactor Coolant System..................................................................................2-1222.3B.2  Engineered Safety Features............................................................................2-125 2.3B.2.1  IP3 Residual Heat Removal............................................................2-126 2.3B.2.2  IP3 Containment Spray System......................................................2-127 2.3B.2.3  IP3 Containment Is olation Support Systems...................................2-128 2.3B.2.4  IP3 Safety Injection System............................................................2-130 2.3B.2.5  IP3 Containment Penetrations........................................................2-132 2.3B.3  Auxiliary Systems............................................................................................2-134 2.3B.3.1  IP3 Spent Fuel Pit Cooling System.................................................2-136 2.3B.3.2  IP3 Service Water System..............................................................2-1382.3B.3.3  IP3 Component C ooling Water System..........................................2-139 2.3B.3.4  IP3 Compressed Air Systems.........................................................2-141 2.3B.3.5  IP3 Nitrogen System........................................................................2-142 2.3B.3.6  IP3 Chemical and Volume Control System.....................................2-143 2.3B.3.7  IP3 Primary Water System..............................................................2-1452.3B.3.8  IP3 Heating, Ventilation and Air Conditioning Systems..................2-146 vii2.3B.3.9  IP3 Vapor Containment Building Ventilation System......................2-1492.3B.3.10  IP3 Control Room Heating, Ventilation and Cooling System........2-150 2.3B.3.11  IP3 Fire Protection - Water............................................................2-151 2.3B.3.12  IP3 Fire ProtectionCarbon Dioxide, Halon, and RCP Oil Collection Systems..........................................................................................2-162 2.3B.3.13  IP3 Fuel Oil Subsystems...............................................................2-165 2.3B.3.14  IP3 Emergency Diesel Generator System....................................2-166 2.3B.3.15  IP3 Security Generator System.....................................................2-168 2.3B.3.16  IP3 Appendix R Diesel Generator System....................................2-169 2.3B.3.17  IP3 City Water System..................................................................2-170 2.3B.3.18  IP3 Plant Drains.............................................................................2-1742.3B.3.19  IP3 Miscellaneous Systems in Scope for 10 CFR 54.4(a)(2)........2-175 2.3B.4  Steam and Power Conversion Systems..........................................................2-1812.3B.4.1  IP3 Main Steam System..................................................................2-181
 
2.3B.4.2  IP3 Main Feedwater System...........................................................2-184 2.3B.4.3  IP3 Auxiliary Feedwater System.....................................................2-1872.3B.4.4  IP3 Steam Generator Blowdown System.........................................2188 2.3B.4.5  IP2 Auxiliary Feedwater Pump Room Fire Event (Not Applicable to IP3.....................................................................................2-189 2.3B.4.6  IP3 Condensate System..................................................................2-190
 
===2.4 Scoping===
and Screening Re sults: Structures......................................................................2-192
 
====2.4.1 Containment====
 
Buildings.......................................................................................2-194 2.4.1.1  Summary of Technical Info rmation in the Application.......................2-194 2.4.1.2  Staff Evaluation..................................................................................2-1952.4.1.3  Conclusion.........................................................................................2-203
 
====2.4.2 Water====
Control Structures...................................................................................2-203 2.4.2.1  Summary of Technical Info rmation in the Application.......................2-203 2.4.2.2  Staff Evaluation..................................................................................2-2042.4.2.3  Conclusion.........................................................................................2-2062.4.3  Turbine Buildings, Auxiliary Buildings, and Other Structures............................2-207 2.4.3.1  Summary of Technical Info rmation in the Application.......................2-207 2.4.3.2  Staff Evaluation..................................................................................2-2122.4.3.3  Conclusion.........................................................................................2-216 2.4.4  Bulk Commodities..............................................................................................2-217 2.4.4.1  Summary of Technical Info rmation in the Application.......................2-217 2.4.4.2  Staff Evaluation..................................................................................2-2172.4.4.3  Conclusion.........................................................................................2-2202.5  Scoping and Screening Results: Electrical and Instrumentation and
 
Control Systems........................................................................................................................2-220
 
====2.5.1 Electrical====
and Instrumentation and Control Systems.........................................2-221 2.5.1.1  Summary of Technical Info rmation in the Application.......................2-221 2.5.1.2  Staff Evaluation..................................................................................2-2222.5.1.3  Conclusion.........................................................................................2-2252.6  Conclusion for Scoping and Screening..............................................................................2-225 AGING MANAGEMENT REVIEW RESULTS............................................................................................3-13.0  Applicants Use of the Generic Aging Lessons Learned Report...........................................3-1
 
====3.0.1 Format====
of the Licens e Renewal Application..........................................................3-2 3.0.1.1  Overview of Table 1s............................................................................3-3 3.0.1.2  Overview of Table 2s............................................................................3-3
 
====3.0.2 Staffs====
Review Process..........................................................................................3-4 3.0.2.1  Review of Programs...............................................................................3-5 3.0.2.2  Review of AMR Results.........................................................................3-6 3.0.2.3  UFSAR Supplement...............................................................................3-6 3.0.2.4  Documentation and Documents Reviewed...........................................3-6
 
====3.0.3 Aging====
Management Programs...............................................................................3-6 viii 3.0.3.1  Programs Consistent with the GALL Report........................................3-103.0.3.2  Programs Consistent with the GALL Report with Exceptions or Enhancements..................................................................................3-59 3.0.3.3  Programs Not Consistent with or Not Addressed in
 
the GALL Report.............................................................................................3-1453.0.4  QA Program Attributes Integral to Aging Management Programs....................3-214 3.0.4.1  Summary of Technical Info rmation in the Application.......................3-214 3.0.4.2  Staff Evaluation..................................................................................3-2153.0.4.3  Conclusion.........................................................................................3-2163.1  Aging Management of Reactor Vessel, Internals and Reactor Coolant System...............3-216
 
====3.1.1 Summary====
of Technical Info rmation in the Application.......................................3-2163.1.2  Staff Evaluation..................................................................................................3-216 3.1.2.1  AMR Results Consistent with the GALL Report................................3-236 3.1.2.2  AMR Results Consistent with the GALL Report for Which
 
Further Evaluation is Recommended.............................................................3-257 3.1.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report...................................................................................................3-2833.1.3  Conclusion.........................................................................................................3-286
 
===3.2 Aging===
Management of Engineered Safety Features Systems...........................................3-286
 
====3.2.1 Summary====
of Technical Info rmation in the Application.......................................3-2863.2.2  Staff Evaluation..................................................................................................3-286 3.2.2.1  AMR Results Consistent with the GALL Report................................3-296 3.2.2.2  AMR Results Consistent with the GALL Report for Which
 
Further Evaluation is Recommended.............................................................3-302 3.2A.2.3  IP2 AMR Results Not Consistent with or Not Addressed in the GALL Report.............................................................................................3-313 3.2B.2.3  IP3 AMR Results Not Consistent with or Not Addressed in the GALL Report.............................................................................................3-3173.2.3  Conclusion.........................................................................................................3-322
 
===3.3 Aging===
Management of Auxiliary Systems..........................................................................3-322
 
====3.3.1 Summary====
of Technical Info rmation in the Application.......................................3-3223.3.2  Staff Evaluation..................................................................................................3-323 3.3.2.1  AMR Results Consistent with the GALL Report................................3-340 3.3.2.2  AMR Results Consistent with the GALL Report for Which
 
Further Evaluation is Recommended.............................................................3-352 3.3A.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report...................................................................................................3-372 3.3B.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report...................................................................................................3-4013.3.3  Conclusion.........................................................................................................3-427
 
===3.4 Aging===
Management of Steam and Power Conversion Systems........................................3-428
 
====3.4.1 Summary====
of Technical Info rmation in the Application.......................................3-4283.4.2  Staff Evaluation..................................................................................................3-429 3.4.2.1  AMR Results Consistent with the GALL Report................................3-437 3.4.2.2  AMR Results Consistent with the GALL Report for Which
 
Further Evaluation is Recommended.............................................................3-446 3.4A.2.3  IP2 AMR Results Not Consistent with or Not Addressed in the GALL Report.............................................................................................3-463 3.4B.2.3  IP3 AMR Results Not Consistent with or Not Addressed in the GALL Report.............................................................................................3-4743.4.3  Conclusion.........................................................................................................3-479
 
===3.5 Aging===
Management of Containments, Structures, and Component Supports..................3-479
 
====3.5.1 Summary====
of Technical Info rmation in the Application.......................................3-4793.5.2  Staff Evaluation..................................................................................................3-480 3.5.2.1  AMR Results Consistent with the GALL Report................................3-493 ix 3.5.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended.............................................................3-499 3.5.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report...................................................................................................3-5273.5.3  Conclusion.........................................................................................................3-530
 
===3.6 Aging===
Management of Electrical and Instrumentation and Controls System....................3-531
 
====3.6.1 Summary====
of Technical Info rmation in the Application.......................................3-5313.6.2  Staff Evaluation..................................................................................................3-531 3.6.2.1  AMR Results Consistent with the GALL Report................................3-535 3.6.2.2  AMR Results Consistent with the GALL Report for Which
 
Further Evaluation Is Recommended.............................................................3-537 3.6.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report...................................................................................................3-5413.6.3  Conclusion.........................................................................................................3-546
 
===3.7 Conclusion===
for Aging Management Review Results..........................................................3-546TIME-LIMITEDAGING ANALYSES..........................................................................................................4-1 4.1  Identification of Time-Limited Aging Analyses.......................................................................4-1
 
====4.1.1 Summary====
of Technical Info rmation in the Application...........................................4-1
 
====4.1.2 Staff====
Evaluation......................................................................................................4-24.1.3  Conclusion.............................................................................................................4
-2 4.2  Reactor Vessel Neutron Embrittlement.................................................................................4-2
 
====4.2.1 Reactor====
Vessel Fluence.........................................................................................4-3 4.2.1.1  Summary of Technical Information in the Application...........................4-34.2.1.2  Staff Evaluation......................................................................................4-4
 
4.2.1.3  UFSAR Supplement...............................................................................4-64.2.1.4  Conclusion.............................................................................................4-64.2.2  Charpy Upper-Shelf Energy...................................................................................4-7 4.2.2.1  Summary of Technical Information in the Application...........................4-74.2.2.2  Staff Evaluation......................................................................................4-8
 
4.2.2.3  UFSAR Supplement.............................................................................4-124.2.2.4  Conclusion...........................................................................................4-12 4.2.3  Pressure-Tem perature Limits..............................................................................4-12 4.2.3.1  Summary of Technical Info rmation in the Application.........................4-12 4.2.3.2  Staff Evaluation....................................................................................4-12 4.2.3.3  UFSAR Supplement.............................................................................4-124.2.3.4  Conclusion...........................................................................................4-134.2.4  Low Temperature Overpressure Protection PORV Setpoints.............................4-13 4.2.4.1  Summary of Technical Info rmation in the Application.........................4-13 4.2.4.2  Staff Evaluation....................................................................................4-13 4.2.4.3  UFSAR Supplement.............................................................................4-134.2.4.4  Conclusion...........................................................................................4-13
 
====4.2.5 Pressurized====
 
Thermal Shock.................................................................................4-14 4.2.5.1  Summary of Technical Info rmation in the Application.........................4-14 4.2.5.2  Staff Evaluation....................................................................................4-14 4.2.5.3  UFSAR Supplement.............................................................................4-174.2.5.4  Conclusion...........................................................................................4-18
 
===4.3 Metal===
Fatigue.......................................................................................................................4-18
 
====4.3.1 Class====
1 Fatigue....................................................................................................4-19 4.3.1.1  Reactor Vessel.....................................................................................4-21 4.3.1.2  Reactor Vesse l Internals......................................................................4-23 4.3.1.3  Pressurizer...........................................................................................4-25 4.3.1.4  Steam Generators................................................................................4-29 4.3.1.5  Reactor Coolant Pump Fatigue Analysis.............................................4-30 4.3.1.6  Control Rod Drive Mechanisms...........................................................4-32 4.3.1.7  Class-1 Heat Exchangers....................................................................4-33 x 4.3.1.8  Class 1 Piping and Components.........................................................4-35 4.3.2  Non-Class 1 Fatigue............................................................................................4-39 4.3.2.1  Summary of Technical Info rmation in the Application.........................4-39 4.3.2.2  Staff Evaluation....................................................................................4-39 4.3.2.3  UFSAR Supplement.............................................................................4-404.3.2.4  Conclusion...........................................................................................4-40
 
====4.3.3 Effects====
of Reactor Water Environment on Fatigue Life.......................................4-40 4.3.3.1  Summary of Technical Info rmation in the Application.........................4-40 4.3.3.2  Staff Evaluation....................................................................................4-41 4.3.3.3  UFSAR Supplement.............................................................................4-454.3.3.4  Conclusion...........................................................................................4-46
 
===4.4 Environmental===
Qualification of Electric Equipment..............................................................4-46
 
====4.4.1 Summary====
of Technical Info rmation in the Application.........................................4-464.4.2  Staff Evaluation....................................................................................................4-47
 
====4.4.3 UFSAR====
 
Supplement.............................................................................................4-474.4.4  Conclusion...........................................................................................................4-4 74.5  Concrete Containment Tendon Prestress Analyses............................................................4-48
 
====4.5.1 Summary====
of Technical Info rmation in the Application.........................................4-484.5.2  Staff Evaluation....................................................................................................4-48
 
====4.5.3 UFSAR====
 
Supplement.............................................................................................4-484.5.4  Conclusion...........................................................................................................4-4 8 4.6  Containment Liner Plate and Penetration Fatigue Analyses...............................................4-48
 
====4.6.1 Summary====
of Technical Info rmation in the Application.........................................4-484.6.2  Staff Evaluation....................................................................................................4-49
 
====4.6.3 UFSAR====
 
Supplement.............................................................................................4-504.6.4  Conclusion...........................................................................................................4-5 0 4.7  Other Plant-Specific TLAAs.................................................................................................4-504.7.1  Reactor Coolant Pump Flywheel Analysis...........................................................4-50 4.7.1.1  Summary of Technical Info rmation in the Application.........................4-50 4.7.1.2  Staff Evaluation....................................................................................4-51 4.7.1.3  UFSAR Supplement.............................................................................4-534.7.1.4  Conclusion...........................................................................................4-53 4.7.2  Leak Before Break...............................................................................................4-54 4.7.2.1  Summary of Technical Info rmation in the Application.........................4-54 4.7.2.2  Staff Evaluation....................................................................................4-55 4.7.2.3  UFSAR Supplement.............................................................................4-604.7.2.4  Conclusion...........................................................................................4-614.7.3  Steam Generator Flow Induced Vibration and Tube Wear.................................4-61 4.7.3.1  Summary of Technical Info rmation in the Application.........................4-61 4.7.3.2  Staff Evaluation....................................................................................4-61 4.7.3.3  UFSAR Supplement.............................................................................4-624.7.3.4  Conclusion...........................................................................................4-62
 
===4.8 Conclusi===
on for TLAAs..........................................................................................................4-62REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS.........................................5-1 CONCLUSION
...........................................................................................................................................6-1 xi AppendicesAPPENDIX A:  Indian Point Nuclear Generating Unit Nos. 2 and 3 License Renewal Commitments.....A-1APPENDIX B:Chronology.......................................................................................................................B-1 APPENDIX C:  Princi pal Contributors.......................................................................................................C-1APPENDIX D:References.......................................................................................................................D-1 List of Tables Table 1.4-1  Current and Proposed Interim Staff Guidance......................................................................1
-7 Table 3.0.3-1  IP2 and IP3 Ag ing Management Programs........................................................................3-7 Table 3.1-1  Staff Evaluation for Reactor Vessel, Reactor Vessel Internals and Reactor Coolant System Components in the GALL Report...............................................................3-217 Table 3.2-1  Staff Evaluation for Engineered Safety Features System Components
 
in the GALL Report.............................................................................................................................3-287 Table 3.3-1  Staff Evaluation for Auxiliary System Components in the GALL Report...........................3-323 Table 3.4-1  Staff Evaluation for Steam and Power Conversion System Components
 
in the GALL Report.............................................................................................................................3-430 Table 3.5-1  Staff Evaluation for Structures, and Component Supports
 
in the GALL Report.............................................................................................................................3-481 Table 3.6-1  Staff Evaluation for Electrical and Instrumentation and Controls
 
in the GALL Report.............................................................................................................................3-532 xii ABBREVIATIONSAC  alternating current ACAR  aluminum conductor aluminum-reinforced ACI  American Concrete Institute ACRS  Advisory Committee on Reactor Safeguards ACSR  aluminum core steel-reinforced ADAMS Agencywide Document Access and Management System ADV  atmospheric dump valve AEIC  Association of Edison Illuminating Companies AERM  aging effect requiring management AFW  auxiliary feedwater AISC  American Institute of Steel Construction AMP  aging management program AMR  aging management review AMSAC ATWS Mitigating System Actuation Circuitry ANSI  American National Standards Institute APCSB Auxiliary and Power Conversion Systems Branch ART  adjusted reference temperature ASME  American Society of Mechanical Engineers ASTM  American Society for Testing and Materials ATWS  anticipated transient without scram B&PV  Boiler and Pressure Vessel BADGER boron-10 areal density gauge for evaluating racks BIL  basic impulse level BMI  bottom mounted instrumentation BOP  balance of plant BTP  branch technical position BVS  building vent sampling BWR  boiling water reactor C  Celsius CASS  cast austenitic stainless steel CB  core barrel CCW  component cooling water CEA  control element assembly
 
CETNA TM core exit thermocouple nozzle assembly CFR Code of Federal RegulationsCII  containment inservice inspection CL  chlorination system CLB  current licensing basis
 
CO 2  carbon dioxide xiiiCR  condition report CRD  control rod drive CRDM  control rod drive mechanism Cr-Mo  chromium-molybdenum CS  containment spray CST  condensate storage tank Cu  copper CUF  cumulative usage factor CVCS  chemical and volume control
 
C VUSE  Charpy upper-shelf energy CW  circulating water CWM  IP3 city water system code CYW  IP2 city water system code DBA  design basis accident DBD  design basis document DBE  design basis event DC  direct current ECCS  emergency core cooling system ECT  eddy current testing EDG  emergency diesel generator EFPY  effective full-power year EMA  equivalent margin analysis EN  shelter or protection EPRI  Electric Power Research Institute EQ  environmental qualification, environmentally qualified EQAP  Entergy Quality Assurance Program ER  Environmental Report (Applicants Environmental Report Operating License Renewal Stage) ESF  engineered safety features F  Fahrenheit FAC  flow accelerated corrosion
 
F en  environmental fatigue life correction factor FERC  Federal Energy Regulatory Commission FLB  flood barrier FLT  filtration FMP  Fatigue Monitoring Program
 
FR  Federal RegisterFRV  feedwater regulating valve FSAR  final safety analysis report ft-lb  foot-pound FW  feedwater FWST  fire water storage tank GALL  Generic Aging Lessons Learned Report GDC  general design criteria or general design criterion GEIS  Generic Environmental Impact Statement GL  generic letter xivGSI  generic safety issue GT  gas turbine H 2  hydrogen HELB  high-energy line break HEPA  high efficiency particulate air HPSI  high pressure safety injection HVAC  heating, ventilation, and air conditioning HX  heat exchanger I&C  instrumentation and controls IA  instrument air IASCC  irradiation assisted stress corrosion cracking IEEE  Institute of Electrical and Electronics Engineers IGA  intergranular attack IGSCC  inter-granular stress corrosion cracking ILRT  integrated leak rate testing IN  information notice INPO  Institute of Nuclear Power Operations IP1  Indian Point Nuclear Generating Unit 1 IP2  Indian Point Nuclear Generating Unit 2 IP3  Indian Point Nuclear Generating Unit 3 IP  Indian Point (site)
IPA  integrated plant assessment IPEC  Indian Point Energy Center ISG  interim staff guidance ISI  inservice inspection ISO  International Standards Organization ksi  kip per square inch KV or kV kilo-volt lb  pound LBB  leak before break LO  lube oil LOCA  loss of coolant accident LRA  license renewal application mhos/cm micromhos per centimeter MB  missile barrier MC  ASME Class for metal containment components MEB  metal-enclosed bus MFW  main feedwater MIC  microbiologically influenced corrosion MOV  motor-operated valve MPa  megapascal MRP  Materials Reliability Program MS  main steam MSIV  main steam isolation valve MWe  megawatts-electric xvMWt  megawatts-thermal n/cm 2  neutrons per square centimeter NaOH  sodium hydroxide NDE  nondestructive examination NEI  Nuclear Energy Institute NESC  National Electric Safety Code NFPA  National Fire Protection Association Ni  nickel NPS  nominal pipe size NRC  US Nuclear Regulatory Commission NSAC  Nuclear Safety Analysis Center NSAS  nonsafety system affecting safety system NSSS  nuclear steam supply system NYPA  New York Power Authority O 2  oxygen ODSCC outside-diameter stress corrosion cracking OI  open item P&ID  piping and instrumentation diagram PAB  primary auxiliary building PB  pressure boundary PBD  program basis document pH  potential of hydrogen PM  preventive maintenance PORV  power-operated relief valve ppb  parts per billion ppm  parts per million psi  pound per square inch psig  pound-force per square inch gauge PSPM  periodic surveillance and preventive maintenance P-T  pressure-temperature PTS  pressurized thermal shock PVC  polyvinyl chloride PW  primary water makeup PWR  pressurized water reactor PWSCC primary water stress corrosion cracking QA  quality assurance RAI  request for additional information RCCA  rod cluster control assembly RCIC  reactor core isolation cooling RCP  reactor coolant pump RCPB  reactor coolant pressure boundary RCS  reactor coolant system RG  regulatory guide RHR  residual heat removal RI-ISI  risk-informed inservice inspection xviRO  refueling outage RPV  reactor pressure vessel
 
RT NDT  reference temperature nil ductility transition RT PTS  reference temperature for pressurized thermal shock RTD  resistance temperature detector RVCH  reactor vessel closure head RVI  reactor vessel internals RVID  Reactor Vessel Integrity Database RVLIS  reactor vessel level indication system RW  river water RWST  refueling water storage tank S&PC  steam and power conversion S A  stress allowables SAR  safety analysis report SBO  station blackout SC  structure and component SCC  stress-corrosion cracking SER  safety evaluation report SFP  spent fuel pool SFPC  spent fuel pit/pool cooling SG  steam generator SGBD  steam generator blowdown SI  safety injection SMP  structures monitoring program
 
SO 2  sulfur dioxide SOC  statement of consideration SOV  solenoid-operated valve SPU  stretch power uprate SR  surveillance requirement SRP-LR Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants SS  stainless steel SSC  system, structure, and component SSE  safe-shutdown earthquake SSFS  safety system function sheets SW  service water TLAA  time-limited aging analysis TS  technical specification(s)
TSC  technical support center UFSAR Updated Final Safety Analysis Report USE  upper-shelf energy UT  ultrasonic testing UV  ultraviolet V  volt VCT  volume control tank xviiWCAP  Westinghouse Commercial Atomic Power WOG  Westinghouse Owners Group XLPE  cross-linked polyethylene yr  year Zn  zinc 1/4 T  one-fourth of the way through the vessel wall measured from the internal surface of the vessel xviii THIS PAGE INTENTIONALLY LEFT BLANK.
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 Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3), as filed by Entergy Nuclear
 
Operations, Inc. (Entergy or the applicant). By letter dated April 23, 2007, and as supplemented
 
by letters dated May 3 and June 21, 2007, Entergy submitted its application to the U.S. Nuclear
 
Regulatory Commission (NRC) for renewal of the Indian Point (IP) operating licenses for an
 
additional 20 years. The NRC staff (the staff) prepared this report to summarize the results of its
 
safety review of the LRA for compliance with Title 10, Part 54, Requirements for Renewal of
 
Operating Licenses for Nuclear Power Plants, of the Code of Federal Regulations (10 CFR Part 54). The NRC project manager for the license renewal review is Kim Green.
 
Ms. Green may be contacted by telephone at 301-415-1627 or by electronic mail at
 
Kimberly.Green@nrc.gov. Alternatively, written correspondence may be sent to the following
 
address: Division of License Renewal US Nuclear Regulatory Commission
 
Washington, D.C. 20555-0001
 
Attention: Kim Green, Mail Stop O11-F1 In its April 23, 2007, submission letter, the applicant requested renewal of the operating licenses issued under Section 104b (Operating License Nos. DPR-26 and DPR-64) of the Atomic Energy
 
Act of 1954, as amended, for IP2 and IP3 for a period of 20 years beyond the current
 
expirations at midnight on September 28, 2013, for IP2, and at midnight on December 12, 2015, for IP3. Indian Point is located approximately 24 miles north of the New York City boundary line.
 
The NRC issued the construction permits on October 14, 1966, for IP2, and on August 13, 1969, for IP3. The NRC issued the operating licenses on September 28, 1973, for IP2, and on
 
December 12, 1975, for IP3. IP2 and IP3 employ a pressurized water reactor design with a dry
 
ambient containment. Westinghouse Electric Corporation supplied the nuclear steam supply
 
system and Westinghouse Development Corporation originally designed and constructed the
 
balance of the plant with the assistance of its agent, United Engineers and Constructors. The
 
licensed power output of each unit is 3216 megawatt thermal (MWt) with a gross electrical output of approximately 1080 megawatt electric (MWe). The updated final safety analysis
 
reports (UFSARs) contain details of the plants and the site.
During its docketing sufficiency review, the staff identified two areas which required clarification from the applicant. The first issue was related to the name by which the applicant referred to the
 
plant and the operating units. As noted in the LRA, the applicant refers to the operating units as
 
Indian Point Energy Center Unit 2 and Unit 3. By letter dated May 3, 2007, the applicant clarified
 
that the name "Indian Point Energy Center Units 2 and 3" is synonymous with the name "Indian
 
Point Nuclear Generating Unit Nos. 2 and 3." The second issue was related to the proposed
 
installation of the IP2 station blackout (SBO)/Appendix R diesel generator. By letter dated June
 
18, 2007, the staff notified Entergy that the staff believed that the current licensing basis for IP2
 
was not fully represented in accordance with Section 54.4(a)(3) of Title 10 of the Code of 1-2 Federal Regulations (10 CFR 54.4(a)(3)). The staff determined that the applicant had not included within the scope of license renewal those systems, structures, and components relied
 
on in the safety analyses or plant evaluations to perform a function that demonstrates
 
compliance with the requirements for station blackout (SBO) per 10 CFR 50.63, and safe
 
shutdown per 10 CFR 50.48. In this regard, the LRA did not include information on the gas
 
turbines, which at the time of submittal, were credited as an alternate power supply for the
 
Appendix R and SBO events. Therefore, the staff requested that Entergy inform the staff of its
 
plans to resolve this issue. By letter dated June 21, 2007, Entergy supplemented the LRA, and
 
committed that the IP2 SBO/Appendix R diesel generator would be installed and operational by
 
April 30, 2008. The applicant determined that the committed change to the facility met the
 
requirements of 10 CFR 50.59(c)(1) and, therefore, a license amendment pursuant to 10 CFR
 
50.90 was not required. By letter dated July 25, 2007, the staff notified Entergy that it had
 
completed its sufficiency review and that the application was acceptable for docketing.
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 IP license renewal is based on the applicants LRA, amendments to the LRA, and on its
 
responses to the staffs requests for additional information. On January 15, 2009, the staff
 
issued an SER with Open Items Related to the License Renewal of Indian Point Nuclear
 
Generating Unit Nos. 2 and 3, in which the staff identified 20 open items necessitating further
 
review. Thereafter, the applicant supplemented the LRA and provided clarifications through its
 
responses to the staffs RAIs and docketed correspondence. Unless otherwise noted, the staff
 
reviewed and considered information submitted through August 6, 2009. The staff reviewed
 
certain information received after that date as necessary and appropriate. The public may view
 
the LRA and all pertinent information and materials, including the UFSARs, at the NRC Public
 
Document Room, located on the first floor of One White Flint North, 11555 Rockville Pike, Rockville, MD 20852-2738 (301-415-4737 / 800-397-4209). Copies of the LRA are also
 
available at White Plains Public Library, 100 Martine Avenue, White Plains, NY 10601, at Field
 
Library, 4 Nelson Avenue, Peekskill, NY 10566, and at Hendrick Hudson Free Library, 185
 
Kings Ferry Rd., Montrose, NY 10548. In addition, the public may find the LRA, as well as
 
materials related to the license renewal review, on the NRC Web site at http://www.nrc.gov.
This SER summarizes the results of the staffs safety review of the LRA and describes the technical details considered in evaluating the safety aspects of the units proposed operation for
 
an additional 20 years beyond the term of the current operating 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 staffs evaluation of license renewal issues considered during the review of the application. SER Section 5 is reserved for the report provided of the
 
Advisory Committee on Reactor Safeguards (ACRS), which is expected to be issued
 
subsequent to the publication of this SER. The conclusions of this SER are in Section 6.
SER Appendix A is a table showing the applicants 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 safety 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 1-3 staffs review.
In accordance with 10 CFR Part 51, the staff issued the draft, plant-specific Supplement 38 to NUREG-1437, Generic Environmental Impact Statement for License Renewal of Nuclear
 
Plants Regarding Indian Point Nuclear Generating Unit Nos. 2 and 3 Draft Report for
 
Comment, Volumes 1 and 2, on December 22, 2008. The supplement discusses the
 
environmental considerations related to license renewal for IP2 and IP3. The draft Supplement
 
is available on the NRC website (http://www.nrc.gov/reactors/operating/licensing/renewal.html). 1.2  License Renewal Background Pursuant to the Atomic Energy Act of 1954, as amended, and NRC regulations, operating
 
licenses for commercial power reactors are issued for 40 years and can be renewed for up to
 
20 additional years. The original 40-year license term was selected based on economic and
 
antitrust considerations rather than on technical limitations; however, some individual plant and
 
equipment designs may have been engineered for an expected 40-year service life.
In 1982, the staff anticipated interest in license renewal and held a workshop on nuclear power plant aging. This workshop led the NRC to establish a comprehensive program plan for nuclear
 
plant aging research. From the results of that research, a technical review group concluded that many aging phenomena are readily manageable and pose no technical issues precluding life
 
extension for nuclear power plants. In 1986, the staff published a request for comment on a
 
policy statement that would address major policy, technical, and procedural issues related to
 
license renewal for nuclear power plants.
In 1991, the staff published 10 CFR Part 54, the License Renewal Rule (Volume 56, page 64943, of the Federal Register (56 FR 64943), dated December 13, 1991). The staff participated in an industry-sponsored demonstration program to apply 10 CFR Part 54 to a pilot
 
plant and to gain the experience necessary to develop implementation guidance. To establish a
 
scope of review for license renewal, 10 CFR Part 54 defined age-related degradation unique to
 
license renewal; however, during the demonstration program, the staff found that adverse aging
 
effects on plant systems and components are managed during the period of initial license and
 
that the scope of the review did not allow sufficient credit for management programs, 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 systems, structures, and components (SSCs) will
 
continue to perform their intended functions during the period of extended operation. In addition, the amended 10 CFR Part 54 clarifies and simplifies the integrated plant assessment process to
 
be consistent with the revised focus on passive, long-lived structures and components (SCs).
Concurrent with these initiatives, the staff pursued a separate rulemaking effort (61 FR 28467, June 5, 1996) and amended 10 CFR Part 51 to focus the scope of the review of environmental
 
impacts of license renewal in order to fulfill NRC responsibilities under the National
 
Environmental Policy Act of 1969.
1-41.2.1  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 NRCs
 
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.
Pursuant to 10 CFR 54.21(d), the LRA is required to include a UFSAR supplement with a summary description of the applicants programs and activities for managing aging effects and
 
an evaluation of time-limited aging analyses (TLAAs) for the period of extended operation.
License renewal also requires TLAA identification. During the plant design phase, certain assumptions about the length of time the plant may 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 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.
1-5 In the LRA, the applicant 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, improving the efficiency and effectiveness of the license
 
renewal review process. The GALL Report summarizes the aging management evaluations, programs, and activities credited for managing aging for most of the SCs used by nuclear power
 
plants. The report is also a quick reference for both applicants and staff reviewers with respect
 
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 pertaining to environmental protection. In December 1996, the staff revised the environmental protection regulations to facilitate the
 
environmental review for license renewal. The staff prepared the GEIS to document its
 
evaluation of possible environmental impacts associated with nuclear power plant license
 
renewals. For certain types of environmental impacts, the GEIS contains generic findings that
 
apply to all nuclear power plants and are codified in Appendix B, Environmental Effect of
 
Renewing the Operating License of a Nuclear Power Plant, to Subpart A of 10 CFR Part 51, as
 
Category 1 issues. Pursuant to 10 CFR 51.53(c)(3)(i), a license renewal applicant may
 
incorporate these generic findings in its environmental report. In accordance with
 
10 CFR 51.53(c)(3)(ii), an environmental report also must include analyses of environmental
 
impacts that must be evaluated on a plant-specific basis (i.e., Category 2 issues).
In accordance with the National Environmental Policy Act of 1969 and 10 CFR Part 51, the staff reviewed the plant-specific environmental impacts of license renewal, including any new and
 
significant information not considered in the GEIS. As part of its scoping process, the staff held
 
a public meeting on September 19, 2007 at the Colonial Terrace in Cortlandt Manor, New York, to identify plant-specific environmental issues. The draft, plant-specific Supplement 38 to the
 
GEIS documents the results of the environmental review and makes a preliminary
 
recommendation as to the license renewal action, based on environmental considerations. The
 
staff held additional public meetings on February 12, 2009, in Cortlandt Manor, New York, to
 
receive comments on the draft, plant-specific GEIS Supplement 38. The staff received
 
numerous comments concerning the draft supplement. The staff plans to issue the final
 
supplement in February 2010. 1.3  Principal Review Matters Part 54 of 10 CFR describes the requirements for renewal of operating licenses for nuclear
 
power plants. The staffs technical review of the LRA was performed in accordance with
 
10 CFR Part 54 requirements and NRC guidance. 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 staffs safety review of the Indian Point LRA.
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.
1-6 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 agreement shall terminate at the time of expiration of the license specified in Item 3 of the Attachment to the agreement, which is the last to expire. Item 3 of
 
the Attachment to the indemnity agreement, as revised by Amendment No. 25, lists IPEC operating license numbers DPR-26 and DPR-64. The applicants
 
request that conforming changes be made to Article VII of the indemnity
 
agreement, and Item 3 of the Attachment to that agreement, specifying the
 
extension of agreement until the expiration date of the renewed IPNG facility
 
operating license sought in this application. In addition, should the license
 
number be changed upon issuance of the renewal license, the applicants request
 
that conforming changes be made to Item 3 of the Attachment, and other
 
sections of the indemnity agreement as appropriate.
The staff intends to maintain the original license 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 NRCs 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) 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 NRCs review, the applicant
 
submit an LRA amendment identifying any CLB changes to the facility that materially affect the
 
contents of the LRA, including the FSAR supplement. By letter dated June 11, 2008, the
 
applicant submitted an LRA update which summarizes the CLB changes that have occurred
 
during the staffs review of the LRA.
Pursuant to 10 CFR 54.22, Contents of Application - Technical Specifications, the NRC requires that the LRA include changes or additions to the technical specifications (TS) that are
 
necessary to manage aging effects during the period of extended operation. In LRA
 
Appendix D, the applicant stated that it had not identified any TS changes necessary for
 
issuance of the renewed IP 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 regulatory guidance. SER Sections 2, 3, and 4 document
 
the staffs evaluation of the LRA technical information.
As required by 10 CFR 54.25, Report of the Advisory Committee on Reactor Safeguards, the SER will be referred to the ACRS, and the ACRS will issue a report documenting its evaluation
 
of the staffs 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.
1-7 1.4  Interim Staff Guidance The staff, industry, and other interested stakeholders gain experience and develop lessons learned with each renewed license. The lessons learned address the staffs performance goals
 
of maintaining safety, improving effectiveness and efficiency, reducing regulatory burden, and
 
increasing public confidence. Interim staff guidance (ISG) is documented for use by the staff, industry, and other interested stakeholders until incorporated into such license renewal
 
guidance documents as the SRP-LR and GALL Report.
Table 1.4-1 shows the current set of ISGs and proposed ISGs, as well as the SER sections in which they are addressed.
Table 1.4-1  Current and Proposed Interim Staff Guidance ISG Issue (Approved ISG Number)
Purpose SER Section Nickel-alloy components in the reactor coolant pressure boundary (LR-ISG-19B)To address the cracking of nickel-alloy components in the reactor pressure boundary. This ISG is currently 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.
SER Section 3.0.3.3.5 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 issued the proposed ISG for public comment. A final ISG has not yet been issued.
SER Section 3.0.3.3.6 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 issued the proposed ISG for public comments. On July 7, 2009, the staff withdrew LR-ISG-2008-01. See 74 FR 33478, dated July 13, 2009.
Not applicable 1-81.5  Summary of Open Items On January 15, 2009, at the time the SER with Open Items was issued, the staff identified the following open items (OIs). An item was considered open if, in the staffs judgment, it has not
 
been shown to meet all applicable regulatory requirements at the time of the issuance of the
 
SER. The staff assigned a unique identifying number to each OI. By letters dated January 29, May 1, and June 12, 2009, the applicant provided additional information which enabled the staff
 
to close out the open items.
OI 2.3A.3.11-1: (SER Section 2.3A.3.11 - IP2 Fire Protection - Water)
In LRA Section 2.3.3.11, the applicant lists the component types that require aging management review. However, some components were not included in the list that are either referenced in
 
the applicants current licensing basis documents or are shown on the license renewal
 
drawings. Therefore, in RAI 2.3A.3.11-2, the staff asked the applicant to determine whether the
 
components listed in the RAI should be included as component types subject to an AMR, and if
 
not, to justify the exclusion. By letter dated November 16, 2007, the applicant stated that yard
 
hose houses and chamber housings are not subject to an aging management review (AMR)
 
because failure of these components will not result in a failure of the fire suppression function of
 
the associated fire hydrant and the sprinkler system, respectively. The yard hose houses and
 
chamber housings are passive, long-lived components that were identified as within the scope
 
of license renewal. Therefore, the staff considers that these components are subject to an AMR
 
in accordance with 10 CFR 54.21(a)(1). The staff indicated that the applicant should justify why
 
the yard hose houses and chamber housings are not subject to an AMR.
By letter dated January 27, 2009, the applicant stated that yard hose houses and chamber housings provide no function that supports 10 CFR 50.48 requirements; therefore, they are not
 
within the scope of license renewal. The closure of this item is documented in SER Section
 
2.3A.3.11.2.OI 2.3.4.2-1: (SER Sections 2.3A.4.2 and 2.3B.4.2 - Main Feedwater System)
IP2 (SER Section 2.3A.4.2 - IP2 Main Feedwater System):
UFSAR Section 14.2.5.6, Containment Peak Pressure for a Postulated Steam Line Break, indicates that for IP2 the applicant takes credit for the main feedwater stop valves, BFD-5s, to
 
close within 120 seconds, in the event of the failure of the main feedwater control valve.
In its revised response to RAI 2.3A.4.2-1 regarding feedwater isolation valves, dated March 24, 2008, the applicant stated that the feedwater valves credited for feedwater isolation
 
are safety-related and, although not highlighted on the license renewal drawing, these valves
 
and the remainder of the feedwater system components on the associated license renewal
 
drawing are within scope of license renewal and are subject to an AMR based upon meeting the
 
requirements of 10 CFR 54.4(a)(2) because of their potential for spatial interaction with
 
safety-related equipment. Based upon the staffs understanding of the applicants UFSAR, the
 
main feedwater stop valves (BFD-5s), have an intended function that meets the criteria of 10
 
CFR 54.4(a)(1); however, these valves are neither included within the system intended function
 
boundary, nor are they highlighted on the license renewal drawings for having an intended
 
function in accordance with 10 CFR 54.4(a)(1).
1-9 By letter dated December 30, 2008, the staff requested the applicant to justify the exclusion of the main feedwater stop valves (BFD-5s), from the scope of license renewal in accordance with
 
10 CFR 54.4(a)(1).
By letter dated January 27, 2009, the applicant explained that the BFD-5 isolation valves are nonsafety-related components, and consistent with the requirements in 10 CFR 54.4(a)(2), the
 
valves are included in the scope for license renewal. The closure of this item is documented in
 
SER Section 2.3A.4.2.2. IP3 (SER Section 2.3B.4.2 - IP3 Main Feedwater System):
UFSAR Section 14.2.5, Rupture of a Steam Pipe, states in the event of a main steam line break incident, the motor-operated valves (MOVs) associated with each of the feedwater regulating
 
valves (FRVs) also will close. The mechanical stroke time of 120 seconds to close these
 
associated MOVs has been analyzed and is acceptable. License renewal drawing 9321-20193
 
shows a HIGH STEAM FLOW SI LOGIC signal goes to these MOVs (BFD-90s). UFSAR
 
Section 14.2.5.1 states that redundant isolation of the main feedwater lines is necessary, because sustained high feedwater flow would cause additional cooldown. Therefore, in addition
 
to the normal control action which will close the main feedwater valves, any safety injection
 
signal will rapidly close all feedwater control valves (including the motor-operated block valves
 
and low-flow bypass valves), trip the main feedwater pumps, and close the feedwater pump
 
discharge valves.
The motor-operated block valves shown on license renewal drawings are BFD-5s and BFD-90s for the main FRVs, and the low flow bypass regulating valves, respectively. The feedwater
 
isolation valves, BFD-5s and BFD-90s, are not included within the system intended function
 
boundary, nor are they highlighted on the license renewal drawings for having an intended
 
function in accordance with 10 CFR 54.4(a)(1).
By letter dated December 30, 2008, the staff requested the applicant to justify the exclusion of the isolation valves, BFD-5s and BFD-90s, from the scope of license renewal in accordance
 
with 10 CFR 54.4(a)(1).
By letter dated January 27, 2009, the applicant explained that the BFD-5 and BFD-90 isolation valves are nonsafety-related components, and consistent with the requirements in
 
10 CFR 54.4(a)(2), the valves are included in the scope for license renewal. The closure of this
 
item is documented in SER Section 2.3B.4.2.2. OI 2.3A.4.5-1: (SER Section 2.3A.4.5 - IP2 Auxiliary Feedwater Pump Room Fire Event)
In LRA Section 2.3.4.5 the applicant describes systems not described elsewhere in the application credited for mitigating the consequences of a Unit 2 fire event in the auxiliary
 
feedwater (AFW) pump room. Each system listed has an intended function of support safe
 
shutdown in the event of a fire in the auxiliary feed pump room (10 CFR 50.48) in accordance
 
with 10 CFR 54.4(a)(3). However, the applicant did not highlight the components or flowpaths
 
needed to support this event on the license renewal drawings. In addition, the applicant did not
 
identify and list the structures and components that are subject to an AMR in accordance with
 
10 CFR 54.21(a)(1). Therefore, based upon the information provided in the LRA, the staff was
 
not able to verify which components needed to perform the stated function are included within 1-10 the scope of license renewal and are subject to an AMR.
By letter dated December 30, 2008, the staff requested the applicant to a) identify the system support function for the AFW pump room fire event, b) clearly identify the portions of the
 
systems flowpaths that support these functions that are subject to an AMR, and c) identify the
 
portions of these flowpaths that are not already in scope for 10 CFR 54.4(a)(1) or (a)(2).
By letter dated January 27, 2009, the applicant explained that it has included the components required to support the safety function in the event of a fire in the AFW pump room within the
 
scope of license renewal in accordance with 10 CFR 54.4(a)(3), and identified the passive long-
 
lived components requiring an AMR in accordance with 10 CFR 54.21(a)(1). The closure of this
 
item is documented in SER Section 2.3A.4.5.2. OI 2.5-1: (SER Section 2.5.1 - Electrical and Instrumentation and Control Systems)
By letter dated November 16, 2007, the applicant responded to RAI 2.5-1 and revised LRA Figures 2.5-2 and 2.5-3, the Offsite Power Scoping Diagram(s) for IP2 and IP3, to address
 
staff concerns regarding the IP2 and IP3 primary and secondary offsite power paths. By letter
 
dated March 24, 2008, the applicant revised its response to RAI 2.5-1. In a subsequent letter
 
dated August 14, 2008, the applicant further clarified its response to RAI 2.5-1.
At the time of issuance of the SER with Open Items, the staff was completing its review of the applicants information on the SBO scoping boundary. As a result of its review, the staff
 
identified a need for additional information, and by letter dated May 20, 2009, the staff
 
requested the applicant to explain why certain components associated with the delayed access
 
circuit were not included within the scope of license renewal. By letter dated June 12, 2009, the
 
applicant provided additional information. The closure of this item is documented in SER
 
Section 2.5.1.2.
OI 3.0.3.2.7-1: (SER Section 3.0.3.2.7 - Fire Protection Program)
During an audit, the staff reviewed program basis documents (for IP3) associated with the fire protection AMP. One of the basis documents states that 15 percent of the fire seals located in
 
fire barriers are demonstrated to be operable by visual inspection on a frequency of 24 months.
 
However, for those penetration seals that are inaccessible, the frequency of inspection is given
 
as not required. By letter dated April 29, 2008, the staff requested that the applicant justify the
 
lack of visual inspections of inaccessible penetration seals.
In its response, dated May 28, 2008, the applicant stated that penetration seals are inspected at least once every seven operating cycles. However, IP3 site surveillance procedure provides
 
provisions for cases where a penetration seal may become inaccessible for periodic inspection
 
as result of plant configuration changes (i.e., installation of new plant equipment, walls, barriers, or other obstacles). In such cases, the IP3 site procedure includes guidance for the cessation of
 
periodic surveillance of such penetration seals, subject to preparation of a formal fire protection
 
engineering evaluation justifying the discontinuance of periodic visual surveillance.
As stated in the IP3 basis document, the visual inspection of inaccessible penetration seals is not required if justified by a supporting fire protection engineering evaluation, developed in
 
accordance with the guidance of GL 86-10. On a case-by-case basis, the inaccessibility of any
 
such penetration seal must be justified, and the fire protection adequacy of the configuration 1-11 must be demonstrated. The evaluation, as stated in the basis document, must include assessment of proximate combustible loading, mitigating features, and the consequences of
 
potential failure of the affected seal.
The staff reviewed the applicant's response and found that it did not address the fact that GL 86-10 evaluations exist for all inaccessible fire barrier penetration seals; the response only
 
indicated that it is a part of the fire protection program to perform such analyses. The staff
 
requested the applicant to confirm that these analyses do exist and are periodically reviewed
 
and updated to ensure their continued applicability.
By letter January 27, 2009, the applicant stated that there are no IP3 fire barrier penetration seals excluded from periodic inspection due to inaccessibility. Therefore, there are no
 
corresponding engineering evaluations. The closure of this item is documented in SER Section
 
3.0.3.2.7.
OI 3.0.3.2.15-1: (SER Section 3.0.3.2.15 - Structures Monitoring Program)
In response to Audit Item 359 regarding IP2 reactor cavity leakage into the containment, Entergy described the degraded conditions, summarized corrective actions taken, and identified
 
the current status of the degradation. The reactor cavity at IP2 has a history of leakage at the
 
upper elevations of the stainless steel cavity liner when flooded during refueling outages.
 
Attempts have been made over the last several outages to mitigate this condition, with limited
 
success. An action plan is being developed for a permanent fix to this issue. However, Entergy
 
made no commitment for augmented inspection during the extended period of operation. In a
 
follow-up discussion, the staff expressed its concern with regard to the potential for degradation
 
of the underlying concrete and reinforcement rebar due to the leakage of borated water through
 
the cavity liner and potential impact of the leakage on other adjacent structures. The staff
 
requested Entergy to provide the technical basis as to why augmented inspection during the
 
period of extended operation is not necessary, if the recurring leak condition is not permanently
 
fixed.In an August 14, 2008, supplemental response to the staffs request, the applicant provided further information regarding the matter and committed to perform a one-time inspection and
 
evaluation of a sample of potentially affected refueling cavity concrete, including embedded
 
reinforcing steel, prior to the period of extended operation, in order to provide additional
 
assurance that the concrete walls have not degraded (Commitment 36).
The staff has concluded that Entergys commitment to perform a one-time inspection and evaluation of a sample of potentially affected refueling cavity concrete, including embedded
 
reinforcing steel, prior to the period of extended operation, is appropriate in order to assess the
 
current state of the concrete and rebar. However, because the applicant does not plan to
 
perform periodic inspections of the refueling cavity and affected area, the staff determined that
 
for this structure/environment/aging effect combination, the LRA is not consistent with the GALL Report AMP. Additionally, the applicants program did not address concrete exposed to borated
 
water.By letter dated November 6, 2008, the applicant submitted a supplemental response to Audit Question 359, describing its plan for implementing a permanent fix over the next three (3)
 
scheduled IP2 refueling outages (2010, 2012, and 2014). At the time of the issuance of the SER
 
with Open Items, the staff was reviewing the applicant's response, pertinent to the effects of the 1-12 refueling cavity leakage on the affected structures during the period of extended operation. As a result of the review, the staff identified the need for additional information, and by letters dated
 
April 3, 2009 and May 20, 2009, the staff requested the applicant to provide additional
 
information on the leakage path from the refueling cavity to the collection point lower in
 
containment, and to explain how the structures monitoring program will adequately manage
 
potential aging effects in this region during the period of extended operation. By letters dated
 
May 1,2009, and June 12,2009, the applicant responded to the staffs request for additional information. The closure of this item is documented in the Operating Experience section of
 
SER Section 3.0.3.2.15.
OI 3.0.3.2.15-2: (SER Section 3.0.3.2.15 - Structures Monitoring Program)
In response to Audit Item 360 regarding IP2 spent fuel pool (SFP) crack/leak paths, Entergy described the degraded conditions in greater detail, summarized corrective actions taken, and
 
identified the current status of the degradation. The leakage was first discovered during
 
excavation for the IP2 Fuel Storage Building in 2005. Entergy stated its belief that the conditions
 
leading to this leakage have been corrected.
Entergy made no commitment for augmented inspection during the period of extended operation. Due to the lack of a leak-chase channel system at IP2 to monitor, detect and quantify
 
potential leakage through the SFP liner, the staff was concerned that there has been insufficient
 
time following the corrective actions to be certain that the leakage problems have been
 
permanently corrected. In a follow-up discussion, the staff requested Entergy to provide the
 
technical basis as to why augmented inspection during the extended period of operation is not
 
necessary.
In an August 14, 2008, supplemental response to the staffs request, the applicant committed to test the groundwater outside the IP2 spent fuel pool for the presence of tritium from samples
 
taken from adjacent monitoring wells, every 3 months (Commitment 25). The presence of tritium
 
in the groundwater could be indicative of a continuing leak from the spent fuel pool.
Although Entergy has taken corrective action and has committed to quarterly monitoring for tritium in the groundwater, the staff was concerned that hidden degradation of concrete and
 
rebar may have resulted from prior leakage, and may be continuing if there is still an active
 
leakage mechanism. The staff requested the applicant to submit additional relevant information
 
on the condition of concrete and rebar in areas where leakage was detected, and the design
 
margins in these areas.
By letter dated November 6, 2008, the applicant submitted the requested information, which provides a detailed description of (1) the design margins for the spent fuel pool concrete walls;
 
and (2) the results of prior concrete core sample testing and rebar corrosion testing. At the time
 
of the issuance of the SER with Open Items, the staff was reviewing the applicant's response.
 
As a result of its review, the staff identified the need for additional information. By letter dated
 
April 3, 2009, the staff requested the applicant to explain how the Structures Monitoring
 
Program will adequately manage potential aging effects in the inaccessible concrete of the IP2
 
spent fuel pool due to borated water leakage during the period of extended operation. By letter
 
dated May 1, 2009, the applicant responded to the staffs request for additional information. The
 
closure of this item is documented in the Operating Experience section of SER Section
 
3.0.3.2.15.
1-13 OI 3.0.3.3.2-1: (SER Section 3.0.3.3.2 Containment Inservice Inspection Program)
In response to Audit Item 361 regarding areas of spalling of the exterior concrete containment, Entergy provided information about the areas and reasons for the spalling. The applicant stated
 
that the spalls occur at locations where Cadweld sleeves have insufficient concrete cover, attributed to an original installation deficiency. Rusting is not active and spalls are in an area
 
where the rebar stresses are low. Entergy indicated that Raytheon has evaluated the structural
 
margins for the IP containments, and at the locations of the exposed rebar, there is sufficient
 
margin to accommodate additional loss of material due to corrosion. The condition is being
 
monitored under the containment inservice inspection program (CII-IWL). Entergy stated that
 
remedial action will be taken if the spalls further degrade and affect structural integrity.
In an August 14, 2008 supplemental response to the staffs request, the applicant committed to enhance the CII-IWL inspections during the period of extended operation
 
through enhanced characterization of the degradation (i.e., quantifying the dimensions of
 
noted indications through the use of optical aids), and that this quantification will allow
 
for more effective trending of degradation following future inspections (Commitment 37).
 
However, since the degraded areas will remain exposed to the environment during the
 
period of extended operation, the staff needed additional clarification of how Entergy
 
plans to implement aging management during the period of extended operation.
The staff requested additional relevant information for the IP2 and IP3 containments on the design margins at the locations of observed degradation, identifying the specific locations and
 
dimensions of the damage.
By letter dated November 6, 2008, the applicant submitted the requested information, describing the design margins for the IP containment structures at the locations of existing concrete
 
degradation. At the time of the issuance of the SER with Open Items, the staff was reviewing
 
the applicant's response. As a result of its review, the staff identified the need for additional
 
information. By letter dated April 3, 2009, the staff requested the applicant to explain how the
 
existing degradation and design margin will be considered in performing periodic inspections to
 
monitor degradation that would ensure that there is no loss of containment intended function
 
during the period of extended operation. By letter dated May 1, 2009, the applicant responded
 
to the staffs request for additional information. The closure of this item is documented in the
 
Operating Experience section of SER Section 3.0.3.3.2.
OI 3.0.3.3.3-1: (3.0.3.3.3 Heat Exchanger Monitoring Program)
LRA Section B.1.17 states that the minimum acceptable tube wall thickness for each heat exchanger inspected is based upon a component-specific engineering evaluation. Wall
 
thickness is acceptable if greater than the minimum wall thickness for the component.
The applicant stated that the existing program will be enhanced to include the minimum wall thickness for the new heat exchangers added to the scope of the program, and to specify that if
 
visual examination is performed, the acceptance criterion is no unacceptable signs of
 
degradation. The acceptance criteria for the eddy current tests based on minimum wall
 
thicknesses are acceptable. However, the acceptance criteria for visual examination were not
 
clear and appeared to be subjective. By letter dated December 30, 2008, the staff requested
 
that Entergy define the visual inspection acceptance criteria.
1-14 By letter dated January 27, 2009, the applicant stated that visual inspections are performed on heat exchangers that cannot be inspected by quantitative non-destructive examination due to
 
design limitations. The applicant further stated that visual inspection of external portions of heat
 
exchanger tubes focuses on detecting the extent of tube erosion, vibration wear, corrosion, pitting, fouling, and scaling. Any unacceptable signs of degradation will be evaluated through
 
the corrective action process. The closure of this item is documented in the Acceptance
 
Criteria section of SER Section 3.0.3.3.3.
OI 3.0.3.3.4-1: (SER Section 3.0.3.3.4 Inservice Inspection Program)
The staff noted that the applicant indicated it plans to enhance the Inservice Inspection Program to provide for periodic visual inspections of lubrite sliding supports used in the SG supports and reactor coolant pump (RCP) supports in order to confirm the absence of aging effects. By letter
 
dated December 30, 2008, the staff requested the applicant to establish and justify its selection
 
of the inspection methods, inspections frequencies, sample sizes, and acceptance criteria that
 
are applicable to the lubrite components, and the corrective actions that would be implemented
 
if these acceptance criteria are exceeded.
By letter dated January 27, 2009, the applicant stated that the Inservice Inspection Program will be enhanced prior to the period of extended operation to include explicit provisions for periodic
 
inspections of the lubrite sliding supports. The closure of this item is documented in the
 
Detection of Aging Effects section of SER Section 3.0.3.3.4.
OI 3.0.3.3.4-2: (SER Section 3.0.3.3.4 Inservice Inspection Program)
The staff noted that the corrective actions program element for AMP B.1.18, Inservice Inspection Program, credits only the corrective actions in the ASME Code, Section XI, Articles
 
IWA-4000 and IWA-7000 as the corrective action criteria for the program. The ASME Code, Section XI editions of record for IP are the 2001 Edition of the ASME Code, Section XI inclusive of the 2003 Addenda for IP2 and the 1989 Edition of the ASME Code, Section XI, with no
 
addenda for IP3. The staff noted that Entergy did not credit component-specific corrective action criteria in ASME Section XI, Article IWB-4000/7000 for Class 1 components, Article IWC-
 
4000/7000 for Class 2 components, Article IWD-4000/7000 Class 3 components, or Article IWF-
 
4000/7000 for ASME Code Class component supports as being within the scope of the
 
corrective action program element for this AMP. By letter dated December 30, 2008, the staff
 
asked the applicant to clarify whether the content of the corrective actions program element
 
was intended to mean that Entergy will implement the corrective action provisions in the ASME Code, Section XI, Subsections IWA, IWB, IWC, IWD, and IWF that are applicable to the component Code Class in the applicable ASME Code, Section XI code of record.
By letter dated January 27, 2009, the applicant stated that it will implement the corrective action provisions in the ASME Code, Section XI, Subsections IWA, IWB, IWC, IWD, and IWF that are applicable to the component Code Class in the applicable ASME Code, Section XI edition of
 
record. The closure of this item is documented in the Corrective Actions section of SER
 
Section 3.0.3.3.4.
OI 3.0.3.3.7-1: (SER Section 3.0.3.3.7 - Periodic Surveillance and Preventive Maintenance)
In LRA Appendix B, Section B.1.29, the applicant describes the existing Periodic Surveillance and Preventive Maintenance Program as an existing, plant-specific program. The staff reviewed 1-15 the applicants program using the review criteria and guidance in the SRP-LR, Appendix. During its review, the staff determined that additional information regarding certain program elements
 
was needed. By letter dated December 30, 2008, the staff issued an RAI to obtain information in
 
the following areas: 1. The scope of program program element for the Periodic Surveillance and Preventive Maintenance Program did not specify which components were within the scope of the
 
program.2. The applicant appeared to be crediting visual examinations, in part, to manage cracking but did not identify the visual techniques to be used. 3. The monitoring and trending program element discussion only mentioned that the activities within the scope of the AMP provided for adequate monitoring and trending;
 
there was no discussion on how the data from the inspections performed under the
 
detection of aging effects program element would be collected, quantified, or evaluated
 
against applicable acceptance criteria, and used to make predictions related to
 
degradation growth or to schedule re-inspections of the components. 4. For the majority of the elastomeric or polymeric components within the scope of the AMP, the applicant credited both visual examinations and manual flexing of the
 
components to manage changes in material properties of these elastomeric or polymeric
 
components. However, material properties are intrinsic thermodynamic properties that
 
cannot be monitored by direct visual or NDE inspection methods, and changes in
 
material properties (such as loss of fracture toughness, hardening, or increases or
 
reductions in strength) are more appropriately managed through appropriate material
 
property analyses (including destructive analyses) or though performance of physical
 
tests (such as flexing, etc.) that could provide some indication of whether the material
 
properties for the components were changing.5. Certain statements regarding operating experience were ambiguous in that the applicant did not indicate clearly whether aging had been detected but that the amount
 
of aging was determined to be acceptable when compared to the acceptance criteria for
 
the aging effect, or whether the inspections did not identify the presence of aging effects
 
in the components being inspected.
By letter dated January 27, 2009, the applicant responded to the staffs request for additional information. The closure of this item is documented in SER Section 3.0.3.3.7. OI 3.1.2-1: (SER 3.1.2.1.3  Cracking Due to Cycling Loading, Stress Corrosion Cracking, and Primary Water Stress Corrosion Cracking)
During its review of the nickel alloy components and the Nickel Alloy Program, the staff determined that for some component types, the applicant: (1) did not indicate which base metal
 
is used at IP (i.e., Alloy 600); (2) did not include any AMR entries for reactor vessel bottom head
 
drains; and (3) did not credit the Inservice Inspection Program to manage cracking in steam
 
generator primary nozzle closure rings. By letter dated December 30, 2008, the staff requested
 
the applicant to:
1-16 Part A - Clarify whether the following components at IP2 or IP3 are fabricated from Alloy 600 base metal materials or welded with Alloy 182 or Alloy 82 filler metal materials: (1) control rod
 
drive (CRD) housing-CRD nozzle welds, (2) upper reactor vessel closure head (RVCH) head
 
vent nozzle-to-RVCH welds, and (3) CRD housing penetration core exit thermocouple nozzle
 
assembly (CETNA TM) components.
Part B - The staff notes that in the applicants response to Audit Item 208, dated December 18, 2007, the applicant stated that the LRA Tables 3.1.2-1-IP2 through 3.1.2-4-IP2
 
and LRA Tables 3.1.2-1-IP3 through 3.1.2-4-IP3 include numerous AMR items for nickel-alloy
 
components. The applicant stated that these AMR items are compared to GALL Report Items
 
IV.A2-18 and IV.A2-19, which correspond to LRA table entries 3.1.1-31 and 3.1.1-65. The
 
applicant stated that the AMR in LRA AMR 3.1.1-69 is only for management of cracking in the
 
RV inlet and outlet nozzle safe-ends and the RV bottom head drain safe-ends. With respect to
 
the AMRs on cracking of nickel alloy bottom mounted instrumentation (BMI) nozzle
 
components, the staff notes that the response to Audit Item 208 stated that the RV bottom head
 
safe-ends at IP2 and IP3 are those for the RV bottom head drains, but LRA Tables 3.1.2-1-IP2
 
and 3.1.2-1-IP3 do not include any AMR entries for RV bottom head drains. The staff requested
 
the applicant to provide its basis on whether LRA Tables 3.1.2-1-IP2 and 3.1.2-1-IP3 need to be
 
amended to include new AMRs for RV bottom head drains and their associated drain-to-bottom
 
head welds, and if so to clarify whether the bottom head drains are fabricated from Alloy 600
 
base metal materials or are welded to the bottom RV heads using Alloy 82 or 182 nickel alloy
 
filler metal materials.
Part C - AMRs of LRA Tables 3.1.2-4-IP2 and 3.1.2-4-IP3, which pertain to the management of cracking in the steam generator (SG) primary nozzle closure rings, credit only the Water
 
Chemistry Control Program to manage cracking of the components. GALL Report Table IV.D1, Line Item D1-1 for these components recommends, in part, that the Inservice Inspection
 
Program be credited for aging management of this effect in addition to Water Chemistry Control
 
Program - Primary and Secondary. Given the information requested in Part A above, the staff
 
requested the applicant to provide a basis for why the AMRs on cracking of the nickel alloy SG
 
primary nozzle closure rings were aligned to GALL AMR Table VI.D1, Line Item D1-6, and why
 
the Inservice Inspection Program is not also credited.
By letter dated January 27, 2009, the applicant responded to the staffs request for additional information. The closure of this item is documented in SER Sections 3.0.3.3.5, 3.1.2.1.3, 3.1.2.2.13, and 3.1.2.2.16.
OI 3.1.2.2.7-1: (SER Section 3.1.2.2.7 - Cracking Due to Stress Corrosion Cracking)
The Inservice Inspection Program is a plant-specific condition monitoring program for the management of cracking in ASME Code Class 1 components, including ASME Code Class 1
 
cast austenitic stainless steel (CASS) components. However, the staff noted that the
 
inspections credited under this program might be either ultrasonic test (UT) examinations or
 
enhanced VT-1 visual examinations. The staff also noted that the applicants program includes
 
a flaw evaluation methodology for CASS components that are susceptible to thermal aging
 
embrittlement.
By letter dated December 30, 2008, the staff asked the applicant to (a) clarify how current state of the art UT methods, as implemented through the Inservice Inspection Program or other 1-17 programs, would be adequate to detect cracks in CASS materials, and (b) justify its basis for crediting the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program to
 
manage and detect for cracking in the CASS pressurizer spray heads at IP2 and IP3.
By letter dated January 27, 2009, the applicant stated that because current volumetric examination methods are not adequate for reliable detection and evaluation of cracking in
 
CASS components, ultrasonic testing examinations are not credited for use in aging
 
management of reduction of fracture toughness in CASS components at Indian Point. Entergy
 
also stated that listing the Thermal Aging Embrittlement of CASS Program on the line item for
 
cracking may be unnecessary, but was included to demonstrate consistency with NUREG-1801
 
Item IV.C-3, which recommends a plant-specific program to address thermal aging
 
embrittlement. The closure of this item is documented in SER Section 3.1.2.2.7. OI 3.3-1: (SER Section 3.3A.2.3.1 - Service Water System - Summary of Aging Management Review - LRA Table 3.3.2-2-IP2)
The staff reviewed LRA Table 3.3.2-2-IP2, which summarizes the results of AMR evaluations for the service water system component groups. The LRA table referenced Note F for titanium heat
 
exchanger shell externally exposed to condensation with no aging effect and no AMP. The staff
 
noted that in LRA Table 3.3.2-9-IP2, the applicant used Note F for the same
 
material/environment combination, but cited an aging effect of loss of material and stated that it
 
will be managed by the Periodic Surveillance and Preventive Maintenance Program. This
 
appears to be a discrepancy.
Similarly, the staff reviewed LRA Table 3.3.2-14-IP2, which summarizes the results of AMR evaluations for the emergency diesel generator system component groups. The LRA table
 
referenced Note F for titanium heat exchanger tubes exposed to raw water (internal) having
 
aging effects of fouling and loss of material which will be managed using the Service Water
 
Integrity Program. The staff noted that in LRA Table 3.3.2-2-IP2, the applicant used Note F for
 
the same material/environment combination but cites cracking as an additional aging effect.
 
This appears to be a discrepancy.
The staff indicated that further information was required regarding the apparent discrepancies, before this item may be closed.
By letter dated January 27, 2009, the applicant stated that LRA Table 3.3.2-2-IP2 contains correct AMR results for the titanium heat exchanger shell externally exposed to condensation
 
with no aging effect and no AMP, and that LRA Table 3.3.2-9-IP2 has been corrected. In
 
addition, the applicant stated that the reason for the difference between cited aging effects in
 
LRA Tables 3.3.2-14-IP2 and Table 3.3.2-2-IP2 is the difference between the grades of titanium
 
used. In LRA Table 3.3.2-2-IP2, the grade of titanium installed in the service water system is
 
unknown so it was conservatively assumed that the material was not grades 1, 2, 7, 11 or 12
 
and therefore, cracking was identified as an aging effect requiring management. The closure of
 
this item is documented in SER Sections 3.3A.2.3.1 and 3.3A.2.3.11.OI 3.4-1: (SER Section 3.4.2.1.9 - Auxiliary Feedwater Pump Room Fire Event)
In LRA Section 3.4.2, the applicant states that:
The components in the systems required to supply feedwater to the steam 1-18 generators during the short duration of the fire event are in service at the time the event occurs or their availability is checked daily. Therefore, integrity of the
 
systems and components required to perform post-fire intended functions for at
 
least one hour is continuously confirmed by normal plant operation. During the
 
event these systems and components must continue to perform their intended
 
functions to supply feedwater to the steam generators for a minimum of one
 
hour. Significant degradation that could threaten the performance of the intended
 
functions will be apparent in the period immediately preceding the event and
 
corrective action will be required to sustain continued operation. For the minimal
 
one hour period that these systems would be required to provide make up to the
 
steam generators, further aging degradation that would not have been apparent
 
prior to the event is negligible. Therefore, no aging effects are identified, and no
 
Summary of Aging Management Review table is provided.
Because these systems contain passive, long-lived components, the applicant must demonstrate 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. Based on the
 
information contained in the LRA, Entergy did not appear to have demonstrated that the effects
 
of aging for passive, long-lived components within the systems credited for providing flow to the
 
steam generators during the fire event will be adequately managed.
By letter dated December 30, 2008, the staff issued an RAI to request that the applicant provide a list of passive, long-lived component types, material, environment, and aging effect
 
combinations, and the programs that will be used to manage the aging effects for these SCs.
By letter dated January 27, 2009, the applicant responded to the staffs RAI and provided AMR results for the passive, long-lived components within the systems credited for providing flow to
 
the steam generators during the fire event. For all component types, the applicant listed the
 
aging effects and AMP as none. The staff reviewed the response and determined that the
 
systems contain passive, long-lived components made of materials that when exposed to the
 
stated environments may experience aging effects, which must be managed during the period
 
of extended operation in accordance with 10 CFR 54.21(a)(3).
By letter dated May 1, 2009, Entergy submitted a clarification response to RAI 3.4.2-1 as well as a new commitment to install a fixed automatic fire suppression system for IP2 in the AFW pump
 
room prior to entering the period of extended operation. Entergy stated that this commitment will
 
delete the requirement for IP2 to place reliance on certain portions of the secondary plant
 
systems for alternate secondary heat sink measures to cope with potential AFW Pump Room
 
fire scenarios.
The staff determined that because the planned installation is not yet part of the current licensing basis, it cannot make a finding consistent with the requirement in 10 CFR 54.29(a). Therefore, by letter dated May 20, 2009, the staff requested that the applicant provide information to
 
demonstrate that the effects of aging will be adequately managed so that the intended
 
function(s) will maintained consistent with the current licensing basis for the period of extended
 
operation as required by 10 CFR 54.21(a)(3).
By letter dated June 12, 2009, the applicant responded to the staffs request and provided revised tables which include aging effects and AMPs to manage the aging effects for the
 
component types that support the AFW pump room fire event that were not already included in 1-19 scope and subject to aging management review for 10 CFR 54.4(a)(1) or (a)(2). The closure of this item is documented in SER Section 3.4A.2.9 OI 3.5-1: (SER Section 3.5.2.2.1 - Containment Structures)
In LRA Sections 3.5.2.2.1.1 and 3.5.2.2.2.1, the applicant referenced an inconsistent combination of air entrainment and water-cement ratios. Per American Concrete Institute (ACI) 318-63, the water-cement ratio may be as high as 0.576 if there is no air entrainment.
 
With air entrainment of four to six percent, the maximum water-cement should be 0.465. The
 
staff asked the applicant to clarify if the correct value should be 0.465, and also to substantiate
 
how it meets the code of record (i.e., ACI 318-63).
By letter dated November 6, 2008, the applicant stated that ACI 318-63 provides two methods for determination of concrete properties which will result in the required concrete strength. The
 
applicant further stated that the concrete mixture at IP was established based on tests of
 
concrete mixtures and actual tests for containment concrete showed compressive strengths
 
above the required 20.7 MPa (3000 psi). In the SER with Open Items, the staff stated that it was
 
reviewing the applicants response, and that its evaluation of this matter would be included in
 
the final SER.
The staff also noted that the applicant states in the LRA that the concrete also meets the requirements of a later ACI guide, ACI 201.2R-77. The staff asked the applicant to clarify the
 
use of the later ACI 201.2R-77, since the editions of the ASTM standards may have changed
 
between 1963 and 1977. In its letter dated November 6, 2008, the applicant stated that IP
 
structures designed in accordance with ACI 318-63 align with many of the recommendations in
 
ACI 201.2R-77. At the time of the issuance of the SER with Open Items, the staff was reviewing
 
the applicant's response. As a result of the review, the staff identified the need for additional
 
information. By letter dated April 3, 2009, the staff asked the applicant to describe the
 
methodology used to establish the required concrete compressive strength of 3000 psi for the
 
containment and other safety-related concrete structures, in accordance with ACI 318- 63, Method 2. By letter dated May 1, 2009, the applicant responded to the staffs request for
 
additional information. The closure of this item is documented in SER Section 3.5.2.2.1.
OI 3.5-2: (SER Section 3.5.2.2.1, Subsection entitled "Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature")
In LRA Section 3.5.2.2.1.3, the applicant stated that ACI 349 specifies long-term temperature limits of 66&deg;C (150
&deg;F) for general areas and 93&deg;C (200
&deg;F) for local areas. The effects of aging due to elevated temperature exposure are not significant below these temperatures.
The applicant also stated that the IP2 containment areas during normal operation are below 54&deg;C (130 &deg;F) bulk average temperature. Penetrations through the containment cylinder wall for
 
pipes carrying hot fluid are cooled by air-to-air heat exchangers and the pipes are insulated to
 
maintain the temperature in the adjoining concrete below 121&deg;C (250 &deg;F). The GALL Report
 
provides for local area concrete temperatures higher than 93&deg;C (200 &deg;F) if tests or calculations
 
evaluate the reduction in strength. The applicant also states that an evaluation of IP2 hot piping
 
penetration concrete has found temperatures up to 121&deg;C (250 &deg;F) acceptable.
The applicant further stated that the IP3 containment areas normally operate below a bulk average temperature of 54&deg;C (130 &deg;F). Penetrations through the containment cylinder wall for 1-20 pipes carrying hot fluid are cooled by air-to-air heat exchangers and the pipes are insulated to maintain the temperature in the adjoining concrete below 93&deg;C (200 &deg;F).
The applicant concluded that these are not aging effects requiring management for IP.
 
In SRP-LR Section 3.5.3.2.1.3, it is stated that the GALL Report recommends further evaluation of programs to manage reduction of strength and modulus of concrete structures due to
 
elevated temperature for PWR and BWR concrete and steel containments. The GALL Report notes that the implementation of ASME Section XI, Subsection IWL examinations and 10 CFR
 
50.55a would not be able to detect the reduction of concrete strength and modulus due to
 
elevated temperature and also notes that no mandated aging management exists for managing
 
this aging effect. The GALL Report recommends that a plant-specific evaluation be performed if
 
any portion of the concrete containment components exceeds specified temperature limits, i.e.,
general temperature greater than 66&deg;C (150 &deg;F) and local area temperature greater than 93&deg;C
 
(200 &deg;F).
The staffs review of operating experience did not identify any occurrences of concrete degradation at the IP2 hot penetrations. However, because concrete degradation at elevated
 
temperatures is a slow process, there is a need to confirm that an additional 20 years of
 
operation will not lead to significant degradation. The staff asked the applicant what the effects
 
on the concrete will be during the period of extended operation for areas where the local
 
temperature exceeds 93&deg;C (200 &deg;F). By letter dated November 6, 2008, the applicant stated that
 
an engineering evaluation of the effect of 121&deg;C (250 &deg;F) temperatures on the hot piping
 
penetration concrete was performed. The evaluation determined that a reduction in strength of
 
15 percent could be expected from the elevated temperatures. The applicant further stated that
 
this reduction in strength was acceptable since the original concrete compressive strength tests
 
showed an actual strength more than 15 percent greater than the design strength of 20.7 MPa
 
(3000 psi).
At the time of the issuance of the SER with Open Items, the staff was reviewing the applicant's response. As a result of its review, the staff identified the need for additional information. By
 
letter dated April 3, 2009, the staff requested the applicant to clearly explain the role of the air-
 
to-air heat exchangers in cooling the concrete around the hot piping penetrations. In addition
 
the staff asked the applicant to describe the methodology used to arrive at the conclusion that
 
the actual concrete strength is more than 15 percent greater than 20.7 MPa (3000 psi), i.e.,
greater than 23.8 MPa (3450 psi), to provide a summary of the results, and to explain how
 
consideration was given to the reduction in modulus of elasticity in the high temperature
 
concrete evaluation. By letter dated May 1, 2009, the applicant responded to the staffs request
 
for additional information. The closure of this item is documented in SER Section 3.5.2.2.1. OI 3.5-3: (SER Section 3.5.2.2.2 - Safety-Related and Other Structures and Component Supports)Item 3.5.1-40 of LRA Table 3.5.1 addresses building concrete at locations of expansion and grouted anchors for the aging effect of reduction in concrete anchor capacity due to local
 
concrete degradation/service-induced cracking or other concrete aging mechanisms. The GALL
 
Report recommends the Structures Monitoring Program (SMP) for monitoring this concrete
 
component for the stated aging effect. In the SER with Open Items, the staff found that the
 
applicant had appropriately credited the SMP for Groups B2 through B5 component supports
 
and surrounding concrete consistent with the GALL Report. However, for the Group B1 (ASME 1-21 Class 1, 2, 3 & MC) supports, the applicants reference to IP concrete anchors and surrounding concrete implies that the applicant is crediting the ISI-IWF AMP for both the supports and
 
surrounding concrete. The staff found that, while ISI-IWF is appropriate for the Group B1
 
component supports themselves, ISI-IWF is not specifically applicable for concrete surrounding
 
the anchors for these supports, because the code support boundary definition which extends to
 
the surface of the building but does not include the building structure. Therefore, the staff
 
indicated that the applicant should indicate which AMP it will use to manage the effects of aging
 
for the concrete surrounding the B1 supports.
By letter dated January 27, 2009, the applicant stated that the applicable aging management program for concrete surrounding concrete anchors is the Structures Monitoring Program. The
 
applicant also clarified the statement in LRA Section 3.5.2.2.2.6(1). The closure of this item is
 
documented in SER Section 3.5.2.2.2.
OI 4.3-1: (SER Section 4.3.1 - Class 1 Fatigue)
In its review, the staff noted that the applicant used data from 1973 to 1995 to project the number of plant heatups and cooldowns from 1995 to March 31, 2006 (current cycles), rather
 
than use actual data. As stated above, the applicant will track the number of transients under
 
the Fatigue Monitoring Program. However, without the actual number of heatups and cooldowns
 
from 1995 to March 31, 2006, the applicant may not be able to accurately predict when the
 
number of analyzed cycles might be exceeded. The staff notes that changes in operating
 
practices such as refueling (12-month refueling cycle vs. 24-month refueling cycle) would
 
decrease the number of heatups and cooldowns experienced post 1995, which should yield a
 
more conservative projection. Nonetheless, the applicant should have the actual data for the
 
plant startups and shutdowns during this period of time. Therefore, the staff believes that the
 
use of actual plant operating experience in lieu of a projection for the current number of cycles
 
is appropriate.
By letter dated January 27, 2009, the applicant provided the actual number of cycles for IP3 plant heatups and cooldowns through March 31, 2006. This information was also provided in
 
response to Audit Item 14. The closure of this item is documented in the Staff Evaluation
 
section of SER Section 4.3.1. 1.6  Summary of Proposed License Conditions Following the staffs 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 first UFSAR 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 1-22 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 of the Code of Federal Regulations (10 CFR) 54.21, Contents of Application Technical Information, requires for each license renewal application (LRA) an integrated plant
 
assessment (IPA) listing those structures and components (SCs) subject to an aging
 
management review (AMR) for all of the systems, structures, and components (SSCs) within the
 
scope of license renewal.
LRA Section 2.1, Scoping and Screening Methodology, describes the methodology for identifying those SSCs at the Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3)
 
that are within the scope of license renewal and those SCs that are subject to an AMR. The
 
staff reviewed the scoping and screening methodology of Entergy Nuclear Operations, Inc.
(Entergy or the applicant), to determine whether it meets the scoping requirements of
 
10 CFR 54.4(a) and the screening requirements of 10 CFR 54.21.
In developing the scoping and screening methodology for the LRA, the applicant considered the requirements of 10 CFR Part 54, Requirements for Renewal of Operating Licenses for Nuclear
 
Power Plants (the Rule), Statements of Consideration for the Rule, and the guidance of
 
Nuclear Energy Institute (NEI) 95-10, Revision 6, Industry Guideline for Implementing the
 
Requirements of 10 CFR Part 54The License Renewal Rule, issued June 2005. The
 
applicant also considered the correspondence between the U.S. Nuclear Regulatory
 
Commission (NRC) staff, other applicants, and NEI. 2.1.2  Summary of Technical Information in the Application LRA Sections 2 and 3 detail the technical information required by 10 CFR 54.4, Scope, and 10 CFR 54.21(a). This safety evaluation report (SER) with open items contains sections entitled
 
Summary of Information from the Application, which provide information taken directly from the
 
LRA.In LRA Section 2.1, the applicant described the process to identify the SSCs that meet the license renewal scoping criteria of 10 CFR 54.4(a) and the process used to identify the SCs that
 
are subject to an AMR, as required by 10 CFR 54.21(a)(1). Additionally, LRA Section 2.2, Plant
 
Level Scoping Results, Section 2.3, Scoping and Screening Results: Mechanical Systems,
 
Section 2.4, Scoping and Screening Results: Structures, and Section 2.5, Scoping and
 
Screening Results: Electrical and Instrumentation and Control Systems, provide the results of
 
the process used to identify the SCs that are subject to an AMR. LRA Section 3.0, Aging
 
Management Review Results, presents information regarding the IP2 and IP3 AMR process in
 
Section 3.1, Reactor Vessel, Internals and Reactor Coolant System, Section 3.2, Engineered
 
Safety Features Systems, Section 3.3, Auxiliary Systems, Section 3.4, Steam and Power
 
Conversion Systems, Section 3.5, Structures and Component Supports, and Section 3.6, 2-2Electrical and Instrumentation and Controls. Section 4.0 of the LRA, Time-Limited Aging Analyses, contains the applicants identification and evaluation of time-limited aging analyses (TLAAs).2.1.3  Scoping and Screening Program Review The staff evaluated the LRA scoping and screening methodology in accordance with the guidance contained in NUREG-1800, Revision 1, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants (hereafter referred to as the SRP-LR), Section 2.1, Scoping and Screening Methodology. The following regulations form the basis for
 
the acceptance criteria for the scoping and screening methodology review:  10 CFR 54.4(a), as it relates to the identification of plant SSCs within the scope of the Rule 10 CFR 54.4(b), as it relates to the identification of the intended functions of SSCs within the scope of the Rule  10 CFR 54.21(a)(1) and 10 CFR 54.21(a)(2), as they relate to the methods used by the
 
applicant to identify plant SCs subject to an AMR As part of the review of the applicants scoping and screening methodology, the staff reviewed the activities described in the following sections of the LRA using the guidance contained in the
 
SRP-LR: Section 2.1 to ensure that the applicant described a process for identifying SSCs that are within the scope of license renewal in accordance with the requirements of
 
10 CFR 54.4(a)  Section 2.2 to ensure that the applicant described a process for determining SCs that
 
are subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1) and
 
10 CFR 54.21(a)(2)
In addition, the staff conducted a scoping and screening methodology audit at IP2 and IP3, located outside Buchanan, NY, during the week of October 8
-12, 2007. The audit focused on ensuring that the applicant had developed and implemented adequate guidance to conduct the scoping and screening of SSCs in accordance with the methodologies described in the LRA and
 
the requirements of the Rule. The staff reviewed implementation of the project-level guidelines
 
and topical reports describing the applicants scoping and screening methodology. The staff
 
conducted detailed discussions with the applicant on the implementation and control of the
 
license renewal program and reviewed the administrative control documentation used by the
 
applicant during the scoping and screening process, the quality practices used by the applicant
 
to develop the LRA, and the training and qualification of the LRA development team. The staff
 
evaluated the quality attributes of the applicants Aging Management Program activities
 
described in Appendix A, Updated Final Safety Analysis Report Supplement, and Appendix B, Aging Management Programs and Activities, to the LRA. On a sampling basis, the staff
 
performed a system review of the service water (SW) system and the turbine building, including
 
a review of the scoping and screening results reports and the supporting design documentation
 
used to develop the reports, to ensure that the applicant had appropriately implemented the
 
methodology outlined in the administrative controls and to verify that the results are consistent
 
with the current licensing basis (CLB) documentation.
2-3 2.1.3.1  Implementing Procedures and Documentation Sources for Scoping and Screening The staff reviewed the applicants scoping and screening implementing procedures as documented in the Scoping and Screening Methodology Audit Trip Report (Agencywide
 
Documents Access and Management System [ADAMS] Accession No. ML083540648) to verify
 
that the process for identifying SCs subject to an AMR was consistent with the SRP-LR.
 
Additionally, the staff reviewed the scope of CLB documentation sources and the process used
 
by the applicant to ensure that the applicants commitments, as documented in the CLB and
 
relative to the requirements of 10 CFR 54.4 and 10 CFR 54.21, were appropriately considered
 
and that the applicant adequately implemented its procedural guidance during the scoping and
 
screening process.
2.1.3.1.1  Summary of Technical Information in the Application
 
In LRA Section 2.1, the applicant addressed the following information sources for the license renewal scoping and screening process:  updated final safety analysis reports (UFSARs)  technical specifications and bases  technical requirements manual  design-basis documents (DBDs)  licensing commitment database  Maintenance Rule bases documents  fire hazards analysis  Appendix R safe-shutdown analysis  station blackout (SBO) analysis  SERs docketed correspondence  plant drawings The applicant stated that it used this information to identify the functions performed by plant systems and structures. It then compared these functions to the scoping criteria in 10 CFR 54(a)(1)
-(3) to determine whether the associated plant system or structure performed a license renewal intended function. It also used these sources to develop the list of SCs subject to an AMR.
2.1.3.1.2  Staff Evaluation Scoping and Screening Implementation Procedures. The staff reviewed the applicants scoping and screening methodology implementation procedures, including license renewal guidelines, documents, reports, and AMR reports, as documented in the audit report, to ensure that the
 
guidance is consistent with the requirements of the Rule, the SRP-LR, and NEI 95-10. The staff
 
finds that the overall process used to implement the 10 CFR Part 54 requirements described in
 
the implementing documents and AMRs is consistent with the Rule, the SRP-LR, and industry
 
guidance. The applicants implementing documents contain guidance for determining plant
 
SSCs within the scope of the Rule and for determining which SCs within the scope of license
 
renewal are subject to an AMR (see ADAMS Accession No. ML080730399). 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 2-4 documented in the SRP-LR, and the information in responses, dated February 13, 2008, to the staffs requests for additional information (RAIs).
After reviewing the LRA and supporting documentation, the staff determined that the scoping and screening methodology instructions are consistent with the methodology description
 
provided in LRA Section 2.1. The applicant described its methodology in 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 applicants CLB review to verify that the methodology is sufficiently comprehensive to identify
 
SSCs within the scope of license renewal, as well as SCs requiring an AMR. As defined in
 
10 CFR 54.3(a), the CLB is the set of NRC requirements applicable to a specific plant and a
 
licensees written commitments for ensuring compliance with, and operation within, applicable
 
requirements of the NRC and the plant-specific design bases that are docketed and in effect.
 
The CLB includes applicable NRC regulations, orders, license conditions, exemptions, technical
 
specifications, and design-basis information (documented in the most recent final safety
 
analysis report). The CLB also includes licensee commitments remaining in effect that were
 
made in docketed licensing correspondence, such as licensee responses to NRC bulletins, generic letters, and enforcement actions, and licensee commitments documented in NRC safety
 
evaluations or licensee event reports.
During the audit, the staff reviewed pertinent information sources used by the applicant including the UFSARs, license renewal boundary diagrams, and Maintenance Rule information.
 
In addition, the applicants license renewal process identified additional potential sources of
 
plant information pertinent to the scoping and screening process, including the equipment
 
database, system safety function sheets, safety classification documents, design-basis
 
references, piping and instrumentation diagrams (P&IDs), electrical drawings, docketed
 
correspondence, technical specifications and bases, the fire hazards analysis, and safety
 
evaluations. The staff confirmed that the applicants detailed license renewal program
 
guidelines specify the use of the CLB source information in developing scoping evaluations.
The IP2 and IP3 equipment database and the system safety function sheets are the applicants primary repository for component safety classification information. During the audit, the staff
 
reviewed the applicants administrative controls for the IP2 and IP3 equipment database, the
 
system safety function sheets, and safety classification data. Plant administrative procedures
 
describe these controls and govern their implementation. Based on a review of the
 
administrative controls and a sample of the safety classification information contained in the IP2
 
and IP3 equipment database and system safety function sheets, the staff concludes that the
 
applicant established adequate measures to control the integrity and reliability of IP2 and IP3
 
safety classification data and, therefore, the IP2 and IP3 equipment database and system safety
 
function sheets provide a sufficiently controlled source of system and component data to
 
support scoping and screening evaluations.
During the staffs review of the applicants CLB evaluation process, the applicant explained the incorporation of updates to the CLB and the process used to ensure that those updates are
 
adequately incorporated into the license renewal process. The staff determined that LRA
 
Section 2.1 describes the CLB and related documents used during the scoping and screening
 
process consistently with the guidance contained in the SRP-LR.
2-5 In addition, the staff reviewed the implementing procedures and results reports used to support identification of SSCs relied on to demonstrate compliance with the safety-related criteria, nonsafety-related criteria, and the regulated events criteria detailed in 10 CFR 54.4(a). The applicants license renewal program guidelines provide a comprehensive listing of documents
 
used to support scoping and screening evaluations. The staff finds these design documentation
 
sources useful for ensuring that the initial scope of SSCs identified by the applicant is consistent
 
with the plants CLB.
2.1.3.1.3  Conclusion
 
Based on its review of LRA Section 2.1, the detailed scoping and screening implementation procedures, and the results from the scoping and screening audit, the staff concludes that the
 
applicants scoping and screening methodology considers CLB information consistently with the
 
Rule, the SRP-LR and NEI 95-10 guidance and, therefore, is acceptable.
2.1.3.2  Quality Controls Applied to the Development of the License Renewal Application 2.1.3.2.1  Staff Evaluation The staff reviewed the quality controls used by the applicant to ensure that scoping and screening methodologies used in the LRA were adequately implemented. The applicant applied
 
the following quality assurance processes during the LRA development:  The applicant developed written plans and procedures to direct implementation of the scoping and screening methodology, control LRA development, and describe training
 
requirements and documentation. The applicant developed written requirements for developing, revising, and approving the guidelines and procedures. The applicant considered pertinent issues in previous LRAs and corresponding RAIs to determine their relevance to the IP2 and IP3 application. Industry peers and the site review committee examined the LRA before its submittal to
 
the staff.
2.1.3.2.2  Conclusion
 
On the basis of its review of pertinent LRA development guidance, discussion with the applicants license renewal staff, and a review of the applicants documentation of the activities
 
performed to assess the quality of the LRA, the staff concludes that the applicants quality
 
assurance activities meet current regulatory requirements and provide assurance that LRA
 
development activities were performed in accordance with the applicants license renewal
 
program requirements.
2.1.3.3  Training 2.1.3.3.1  Staff Evaluation The staff reviewed the applicants training process for consistent and appropriate guidelines and methodology for the scoping and screening activities. As outlined in the implementing
 
documents, the applicant requires training and documentation for all personnel participating in 2-6 the LRA development. Personnel are required to complete the training before preparing and approving implementing procedures. Training materials include the applicants project
 
guidelines; pertinent industry documents; 10 CFR Part 54 and its Statements of Consideration;
 
NEI 95-10, Revision 6; Regulatory Guide 1.188, Revision 1, Standard Format and Content for
 
Applications to Renew Nuclear Power Plant Operating Licenses, issued September 2005;
 
SRP-LR; NUREG-1801, Revision 1, Generic Aging Lessons Learned (GALL) Report (hereafter
 
referred to as the GALL Report); and attendance at a license renewal orientation session.
The applicants procedures specify two levels of training(1) training for the corporate project team personnel and (2) training for site personnel. Generally, the project team personnel review
 
all training documents in order to identify those documents directly related to their specific
 
scoping and screening responsibilities. The intent of the training for site personnel is to ensure
 
that personnel understand the license renewal process and the materials specifically related to
 
each individuals license renewal responsibilities. Completion of the training allows site
 
personnel to evaluate and approve the license renewal documents for technical accuracy.
 
Qualification and training records and a checklist serve as documentation for each individuals
 
completed license renewal training. The staff reviewed completed qualification and training
 
records and the completed checklists for several of the applicants license renewal personnel.
 
Additionally, after discussions with the applicants license renewal personnel during the audit, the staff verified that the applicants personnel are knowledgeable about the license renewal
 
process requirements and specific technical issues within their areas of responsibility.
2.1.3.3.2  Conclusion
 
On the basis of discussions with the applicants license renewal project personnel responsible for the scoping and screening process and its review of selected documentation in support of
 
the process, the staff concludes that the applicants personnel are adequately trained to implement the scoping and screening methodology as described in the applicants implementing
 
documents and the LRA.
2.1.3.4  Conclusion of Scoping and Screening Program Review On the basis of a review of information provided in LRA Section 2.1, a review of the applicants detailed scoping and screening implementing procedures, discussions with the applicants
 
license renewal personnel, and the results from the scoping and screening audit, the staff
 
concludes that the applicants scoping and screening program is consistent with the SRP-LR
 
and the requirements of 10 CFR Part 54 and, therefore, is acceptable.2.1.4  Scoping Methodology for Plant Systems, Structures, and Components In LRA Section 2.1, the applicant described the methodology used to scope SSCs under 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 detailed in 10 CFR 54.4(a). The applicant
 
developed the list of systems using the equipment database; the list of plant structures was
 
developed from a review of plant layout drawings, Maintenance Rule documentation, DBDs, and
 
the UFSARs. Mechanical system functions were identified from the IP2 and IP3 safety system
 
function sheets (SSFSs). The applicant obtained additional information on mechanical system
 
functions from the UFSARs, the Maintenance Rule documents, piping flow diagrams, and 2-7 DBDs. Structural functions were identified using the UFSARs, the Maintenance Rule basis documents for structures, the fire hazards analyses, DBDs, and structural drawings. According
 
to the LRA, all electrical and instrumentation and control (I&C) systems, and electrical and I&C
 
components in mechanical systems, are within the scope of license renewal.
2.1.4.1  Application of the Scoping Criteria in 10 CFR 54.4(a)(1) 2.1.4.1.1  Summary of Technical Information in the Application LRA Section 2.1.1.1, A Application of Safety-Related Scoping Criteria,@ describes the scoping methodology as it relates to the safety-related criterion in accordance with 10 CFR 54.4(a)(1).
With respect to the safety-related criterion, the applicant stated that safety-related system and
 
structure functions are initially identified through a review of the SSFSs and then confirmed by a
 
review of the UFSARs, Maintenance Rule documents, piping flow diagrams, and DBDs, as
 
applicable. Systems and structures whose intended functions meet one or more of the criteria in
 
10 CFR 54.4(a)(1) were included within the scope of license renewal. The applicant confirmed
 
that it considered all plant conditions, including conditions of normal operation, design-basis
 
accidents (DBAs), external events, and natural phenomena for which the plant must be
 
designed, for license renewal scoping under the 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 on to remain functional during and following a design-basis event (DBE) to ensure the performance of
 
certain functions. These functions are (1) the integrity of the reactor coolant pressure boundary (RCPB), (2) the ability to shut down the reactor and maintain it in a safe-shutdown condition, or
 
(3) the capability to prevent or mitigate the consequences of accidents that could result in
 
potential offsite exposures comparable to those described in 10 CFR 50.34(a)(1),
10 CFR 50.67(b)(2), or 10 CFR 100.11, Determination of Exclusion Area, Low Population
 
Zone, and Population Center Distance.
With regard to identification of DBEs, SRP-LR, Section 2.1.3, Review Procedures, states the following:
The set of DBEs as defined in the Rule is not limited to Chapter 15 (or equivalent) of the UFSAR. Examples of DBEs that may not be described in this chapter
 
include external events, such as floods, storms, earthquakes, tornadoes, or
 
hurricanes, and internal events, such as a high energy line break. Information
 
regarding DBEs as defined in 10 CFR 50.49(b)(1) may be found in any chapter of
 
the facility UFSAR, the Commissions regulations, NRC orders, exemptions, or
 
license conditions within the CLB. These sources should also be reviewed to
 
identify SSCs relied upon to remain functional during and following DBEs (as
 
defined in 10 CFR 50.49(b)(1)) to ensure the functions described in
 
10 CFR 54.4(a)(1).
During the audit, the applicant stated that it evaluated the types of events listed in NEI 95-10 (i.e., anticipated operational occurrences, DBAs, external events, and natural phenomena) that
 
were applicable to IP2 and IP3. The applicant identified the documents (the UFSARs and the
 
fire hazards analysis) that described the events. The applicant also reviewed licensing
 
correspondence and DBDs. The staff determined that the applicant
=s evaluation of DBEs is 2-8 consistent with the SRP-LR.
The applicant performed scoping of SSCs for the 10 CFR 54.4(a)(1) criterion in accordance with the license renewal implementing documents, which provide guidance for the preparation, review, verification, and approval of the scoping evaluations to ensure the adequacy of the
 
results of the scoping process. The staff reviewed the implementing documents governing the
 
applicants evaluation of safety-related SSCs and sampled the applicants reports of the scoping
 
results to ensure that the applicant applied the methodology in accordance with those written
 
instructions. In addition, the staff discussed the methodology and results with the applicants
 
personnel who were responsible for these evaluations.
The staff reviewed the applicants evaluation of the Rule and CLB definitions pertaining to 10 CFR 54.4(a)(1). The IP2 and IP3 CLB definition of safety-related meets the definition in
 
10 CFR 54.4(a)(1). LRA Section 2.1.1.1 documents the applicants definition of safety-related
 
and exceptions to the definition in 10 CFR 54.4(a)(1). Based on its review, the staff confirmed
 
that the applicant correctly identified the applicable dose criteria for IP2 and IP3 as set forth in
 
10 CFR 54.4(a)(1)(iii). The dose criteria are set forth in 10 CFR 50.67(b)(2) and 10 CFR 100.11
 
for IP2, as reflected in the LRA. Although the IP3 CLB definition of safety-related did not
 
explicitly include reference to 10 CFR 50.67(b)(2), the requirements of 10 CFR 50.67(b)(2),
which concern the use of an alternate source term in the dose analysis, are also applicable to
 
IP3, which has been approved for the use of an alternate source term. The staff confirmed that
 
the applicant reviewed the IP3 systems and components credited in the plants dose analyses
 
to ensure that the applicable systems and components were included in the scope of the license
 
renewal. The applicant did not identify any additional SSC functional requirements, beyond
 
those established to meet the requirements of 10 CFR Part 100, Reactor Site Criteria, credited
 
for the application of the alternate source term, and no additional SSCs for IP3 were required for
 
inclusion in the scope of license renewal under 10 CFR 50.67(b)(2).
The staff reviewed a sample of the license renewal scoping results for the SW system and the turbine building to provide additional assurance that the applicant adequately implemented its
 
scoping methodology in accordance with 10 CFR 54.4(a)(1). The staff verified that the applicant
 
developed the scoping results for each of the sampled systems consistently with the
 
methodology, identified the SSCs credited for performing intended functions, and adequately
 
described the basis for the results, as well as the intended functions.
In order to verify that the applicant identified and used pertinent engineering and licensing information to identify the SSCs required by 10 CFR 54.4(a)(1) to be within the scope of license
 
renewal, the staff determined that it would require additional information to complete its review
 
of the applicants scoping methodology.
In RAI 2.1-1(c), dated January 14, 2008, the staff stated that during the audit, it reviewed the applicants technical evaluation and onsite documentation for nonsafety-related SSCs affecting
 
safety-related SSCs, which indicate that certain similar SSCs were included within the scope of
 
license renewal under 10 CFR 54.4(a)(1) for one unit, but under 10 CFR 54.4(a)(2) for the other
 
unit. The staff requested that the applicant provide the rationale and basis for including similar
 
SSCs within the scope of license renewal under 10 CFR 54.4(a)(1) for one unit, but under
 
10 CFR 54.4(a)(2) for the other unit, and describe how it performed the corresponding review of
 
the adjacent or attached nonsafety-related SSCs (for inclusion within the scope of license
 
renewal) for similar systems in the two units. In its February 13, 2008, response to RAI 2.1-1(c),
the applicant stated the following:
2-9 Because IP2 and IP3 were operated independently for an extended period of time, there are differences between IP2 and IP3 in terms of the number of
 
systems, as well as system boundaries and intended functions for similarly
 
named systems. The site component database along with system flow diagrams
 
were used to define system boundaries and identify system intended functions.
 
Consequently, certain similarly named SSCs were included within the scope of
 
license renewal in accordance with the requirements of 10 CFR 54.4(a)(1) only
 
for one unit and 10 CFR 54.4(a)(2) only for the other unit because the system
 
boundaries were different.
The IP2 city water system (CYW) is in-scope for 10 CFR 54.4(a)(1) and 10 CFR 54.4(a)(2) while the IP3 city water system (CWM) is in-scope only for
 
10 CFR 54.4(a)(2). IP2 piping assigned to the city water system provides
 
containment isolation, a 10 CFR 54.4(a)(1) intended function, for supply to fire
 
water hose reels inside the containment building. The IP3 city water system does
 
not provide a similar intended function or any other (a)(1) functions and therefore
 
is not in-scope for 10 CFR 54.4(a)(1). Since the city water systems are fluid-filled, all components not included for 54.4(a)(1) or (a)(3) in structures containing
 
components with safety functions were reviewed for potential spatial impact.
 
Appropriate LRA drawings were also reviewed to verify that no components
 
required for structural support of components with safety functions were
 
excluded. This review was performed for both systems regardless of system
 
functions to ensure all in-scope components were identified.
The IP2 instrument air closed cooling water system is in-scope only for 10 CFR 54.4(a)(2) while the IP3 instrument air closed-cooling system is in-scope
 
for 10 CFR 54.4(a)(1) and 10 CFR 54.4(a)(2). IP3 instrument air closed-cooling heat exchangers SWN CLC 31 HTX, SWN CLC 32 HTX perform an intended
 
function of providing service water system pressure boundary and are in-scope
 
for 10 CFR 54.4(a)(1). The corresponding IP2 instrument air closed-cooling heat exchangers 21 CWHX, 22CWHX are assigned to the SW system and not
 
instrument air closed-cooling, so the IP2 instrument air closed-cooling system
 
has no components with a 10 CFR 54.4(a)(1) intended function. Since the
 
instrument air closed-cooling systems are fluid-filled, all components in structures
 
containing components with safety functions were reviewed for potential spatial
 
impact. Appropriate LRA drawings were also reviewed to verify that no
 
components required for structural support of components with safety functions
 
were excluded. This review was performed for both systems regardless of
 
system functions to ensure all in-scope components were identified.
The IP2 river water service system (RW) is in-scope for 10 CFR 54.4(a)(1) to support the service water system pressure boundary. Both IP2 and IP3 RW
 
systems are in-scope for 10 CFR 54.4(a)(2). The IP3 RW system has no
 
components within its boundary that support the service water system pressure
 
boundary or any other (a)(1) functions. Since the RW systems are fluid-filled, all
 
system components in structures containing components with safety functions
 
were included for potential spatial impact. Appropriate LRA drawings were also
 
reviewed to verify that no components required for structural support of
 
components with safety functions were excluded. This review was performed for 2-10 both systems regardless of system functions to ensure all in-scope components were included.
The staff reviewed the applicants response to RAI 2.1-1(c) and determined that the applicants description of the process used to ensure that SSCs have been appropriately included within
 
the scope of license renewal is in accordance with 10 CFR 54.4(a)(1) or (a)(2), as applicable, based on the intended function of the SSC for the unit that the system serves. The staffs
 
concern described in RAI 2.1-1(c) is resolved.
2.1.4.1.3  Conclusion
 
On the basis of its review of systems (on a sampling basis), discussions with the applicant, review of the applicants scoping process, and the applicants response to RAI 2.1-1(c), the staff
 
concludes that the applicants methodology for identifying systems and structures is consistent
 
with the SRP-LR and the requirements of 10 CFR 54.4(a)(1) and, therefore, is acceptable.
2.1.4.2  Application of the Scoping Criteria in 10 CFR 54.4(a)(2) 2.1.4.2.1  Summary of Technical Information in the Application In LRA Section 2.1.1.2, Application of Criterion for Nonsafety-Related SSCs Whose Failure Could Prevent the Accomplishment of Safety Functions, the applicant described the scoping
 
methodology as it relates to the nonsafety-related criteria in 10 CFR 54.4(a)(2). The applicant
 
based its 10 CFR 54.4(a)(2) scoping methodology on guidance provided in Appendix F of
 
NEI 95-10, Revision 6. By considering functional failures and physical failures, the applicant
 
evaluated the impacts of nonsafety-related SSCs that meet the 10 CFR 54.4(a)(2) criteria.
Functional Failure of Nonsafety-Related SSCs. LRA Section 2.1.1.2.1, Functional Failures of Nonsafety-Related SSC, states that SSCs required to perform a function in support of
 
safety-related components are generally classified as safety related and are included within the
 
scope of license renewal in accordance with 10 CFR 54.4(a)(1). For the few exceptions where
 
nonsafety-related components are required to remain functional to support a safety function, the
 
applicant identified this intended system function and included the components within the scope
 
of license renewal in accordance with the requirements of 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, Physical Failures of Nonsafety-Related SSCs, states that
 
nonsafety-related systems and nonsafety-related portions of safety-related systems are
 
identified as in scope under 10 CFR 54.4(a)(2) if there is a potential for spatial interactions with
 
safety-related equipment. Spatial failures are defined as failures of nonsafety-related SSCs that
 
are connected to or located in the vicinity of safety-related SSCs, creating the potential for
 
interaction between the SSCs from physical impact, pipe whip, jet impingement, a harsh environment resulting from a piping rupture,or damage from leakage or spray that could impede
 
or prevent the accomplishment of the safety-related functions of a safety-related SSC. In
 
addition, the applicant included overhead handling systems and mitigative features, such as
 
missile barriers, flood barriers, and spray shields, within the scope of license renewal in
 
accordance with 10 CFR 54.4(a)(2).
The applicant used the preventive option described in NEI 95-10, Appendix F, to determine the scope of license renewal with respect to the protection of safety-related SSCs from spatial 2-11 interactions that the CLB does not address. This scoping process, referred to as the spaces approach, involves an evaluation based on the location of nonsafety-related equipment and its
 
proximity to safety-related SSCs, including the identification of fluid-filled system components
 
located in the same space as safety-related equipment. The applicant defined a space as a
 
room or cubicle that is separated from other spaces by substantial objects (such as walls, floors, and ceilings).
Nonsafety-Related SSCs Directly Connected to Safety-Related SSCs. LRA Section 2.1.1.2.2 states that the scope of license renewal includes the nonsafety-related piping and supports up
 
to and including the first seismic anchor beyond the safety/nonsafety interface such that the
 
safety-related portion of the piping will be able to perform its intended function. For piping in this
 
structural boundary, pressure integrity is not required; however, piping within the safety class
 
pressure boundary depends on the structural boundary piping and supports so that the system
 
can fulfill its safety function. For IP2 and IP3, structural boundary is defined as the portion of a
 
piping system that, although outside the safety class pressure boundary, is relied on to provide
 
structural support for the pressure boundary.
2.1.4.2.2  Staff Evaluation
 
As detailed in 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 on to remain
 
functional during and following a DBE to ensure (1) the integrity of the RCPB; (2) the ability to
 
shut down the reactor and maintain it in a safe shutdown condition; or (3) the capability to
 
prevent or mitigate the consequences of accidents that could result in potential offsite
 
exposures, comparable to those referred to in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or
 
10 CFR 100.11.
Regulatory Guide 1.188, Revision 1, endorses the use of NEI 95-10, Revision 6. NEI 95-10 discusses the staffs position on the 10 CFR 54.4(a)(2) scoping criteria, including
 
nonsafety-related SSCs typically identified in the CLB; consideration of missiles, cranes, flooding, and high-energy line breaks (HELBs); nonsafety-related SSCs connected to
 
safety-related SSCs; nonsafety-related SSCs in proximity to safety-related SSCs; and the
 
mitigative and preventive options related to nonsafety-related and safety-related SSC
 
interactions.
In addition, the staffs position (as discussed in NEI 95-10, Revision 6) is that applicants should not consider hypothetical failures, but rather should base their evaluation on the plants CLB, engineering judgment and analyses, and relevant operating experience. NEI 95-10 further
 
describes operating experience as all documented plant-specific and industry-wide experience
 
that can be used to determine the plausibility of a failure. Documentation would include NRC generic communications and event reports, plant-specific condition reports, industry reports
 
such as safety operational event reports, and engineering evaluations. The staff reviewed LRA
 
Section 2.1.1.2, in which the applicant described the scoping methodology for nonsafety-related
 
SSCs under 10 CFR 54.4(a)(2). In addition, the staff reviewed the applicants results report, which documents the guidance and corresponding results of the applicants scoping review
 
under 10 CFR 54.4(a)(2). The applicant stated that it performed this review in accordance with
 
the guidance in NEI 95-10, Revision 6, Appendix F.
2-12Nonsafety-Related SSCs Required To Perform a Function That Supports a Safety-Related SSC. The staff determined that nonsafety-related SSCs required to remain functional to support a safety-related function were included within the scope of license renewal as safety-related as
 
if these SSCs were in scope under 10 CFR 54.4(a)(1). The applicants scoping report discusses
 
the evaluation criteria described in 10 CFR 54.4(a)(2). The staff finds that the applicant
 
implemented an acceptable method for scoping of the nonsafety-related systems that perform a
 
function that supports a safety-related intended function, as required by 10 CFR 54.4(a)(2).
Nonsafety-Related SSCs Directly Connected to Safety-Related SSCs. Based on a review of the information in the LRA and the applicants implementing documents, the staff determined that, to identify the nonsafety-related SSCs connected to safety-related SSCs and which require
 
structural soundness to maintain the integrity of the safety-related SSCs, the applicant used a
 
combination of the information contained in the IP2 and IP3 structural analysis to identify the
 
structural boundary. The applicant also applied the bounding approach as described in
 
NEI 95-10, Appendix F. The applicant reviewed the safety-related to nonsafety-related
 
interfaces for each mechanical system to identify the nonsafety-related components located
 
between the interface and the structural boundary. The applicant included all nonsafety-related
 
SSCs within the structural boundary that are within the scope of license renewal, in accordance
 
with 10 CFR 54.4(a)(2).
If a seismic support could not be located using the structural boundary, the applicant identified the portion of the nonsafety-related piping up to, and including, a base-mounted component, flexible connection, or the end of the piping run, in accordance with the guidance of Appendix F
 
to NEI 95-10. This guidance describes the use of bounding criteria as a method of determining
 
the portion of nonsafety-related SSCs that an applicant should include within the scope of
 
license renewal.
The staff noted during the scoping and screening methodology audit that the applicant included fluid-filled, nonsafety-related pipes located in a safety-related space within the scope of license
 
renewal based on the spaces approach; the applicant separately addressed nonsafety-related
 
piping attached to safety-related SSCs. However, the applicant did not provide sufficient
 
information in either the LRA or the implementing procedures to demonstrate that, when the
 
fluid-filled pipe was also attached to a safety-related SSC, an additional portion of the pipe, beyond the safety-related space, up to and including an appropriate seismic anchor, equivalent
 
anchor, or bounding condition, was also included within the scope of license renewal. The staff
 
determined that it needed additional information to complete the review of the applicants
 
scoping methodology.
In RAI 2.1-1(a), dated January 14, 2008, the staff requested that the applicant describe the process used to ensure that fluid-filled, nonsafety-related pipe, attached to safety-related SSCs
 
and exiting the safety-related space, was included within the scope of license renewal, up to
 
and including an appropriate seismic anchor, equivalent anchor, or bounding condition.
In its February 13, 2008, response to RAI 2.1-1(a), the applicant stated the following:
The process for determining the components to be included for 10 CFR 54.4(a)(2) included a review of all passive mechanical components at
 
IP2 and IP3 that were not already included in an AMR report under
 
10 CFR 54.4(a)(1) or (a)(3). The review began with a determination of which
 
components need to be in-scope due to their potential for spatial interaction with 2-13 components with a safety function. If piping and components for fluid-filled systems exit areas containing components with safety functions, further review
 
was performed. This occurred in only limited locations. For those few locations, IPEC [Indian Point Energy Center] reviewed the component database and
 
associated drawings and confirmed that those components required for structural
 
support are within the safety-related space.
The staff reviewed the applicants response to RAI 2.1-1(a) and determined that the applicant described an adequate process, which includes additional review of certain fluid-filled, nonsafety-related pipe to ensure that fluid-filled, nonsafety-related pipe attached to
 
safety-related SSCs that exits the safety-related space is included within the scope of license
 
renewal, up to and including an appropriate seismic anchor, equivalent anchor, or bounding
 
condition. The staffs concern described in RAI 2.1-1(a) is resolved.
Nonsafety-Related SSCs with the Potential for Spatial Interaction with Safety-Related SSCs
.The applicant considered physical impact (pipe whip, jet impingement), harsh environments, flooding, spray, and leakage when evaluating the potential for spatial interactions between
 
nonsafety-related systems and safety-related SSCs. The applicant used a spaces approach, as
 
described above, to identify the portions of nonsafety-related systems with the potential for
 
spatial interaction with safety-related SSCs. Physical Impact or Flooding. The applicant considered nonsafety-related supports for nonseismic piping systems and electrical conduit and cable trays with potential for spatial
 
interaction with safety-related SSCs for inclusion within the scope of license renewal, in
 
accordance with 10 CFR 54.4(a)(2). These supports and components are addressed in a
 
commodity fashion, (i.e., grouping structural components that typically do not have unique
 
identifiers based on common characteristics such as materials of construction, within civil/structural AMR reports). The applicants review of earthquake experience revealed no
 
occurrence of welded steel pipe segments falling during a strong motion earthquake. The
 
applicant, using the guidance in NEI 95-10, concluded that, as long as the effects of aging on
 
supports for piping systems are managed, collapse of piping systems is not credible (except from flow-accelerated corrosion as considered in the HELB analysis for high-energy systems)
 
and the piping sections are not within scope under 10 CFR 54.4(a)(2). The applicant evaluated
 
the missiles that could be generated from internal or external events such as failure of rotating
 
equipment or overhead-handling systems. The applicant included nonsafety-related design
 
features that protect safety-related SSCs from such missiles within the scope of license
 
renewal. In addition, the applicant included walls, curbs, dikes, doors, and similar structures that
 
provide flood barriers to safety-related SSCs within the scope of license renewal in accordance
 
with 10 CFR 54.4(a)(2). Pipe Whip, Jet Impingement, and Harsh Environment. The applicant evaluated nonsafety-related portions of high-energy lines in accordance with 10 CFR 54.4(a)(2). The
 
applicant based its evaluation on a review of documents including the UFSARs, DBDs, and
 
relevant site documentation. The applicant evaluated its high-energy systems to ensure
 
identification of components that are part of nonsafety-related, high-energy lines that can affect
 
safety-related equipment. If the applicants HELB analysis assumed that a nonsafety-related
 
piping system did not fail, or assumed failure only at specific locations, then the applicant
 
included that piping system (piping, equipment, and supports) within the scope of license
 
renewal, in accordance with 10 CFR 54.4(a)(2), and designated it as subject to an AMR to
 
ensure that those assumptions remain valid through the period of extended operation. Also, as 2-14 discussed in the IP2 and IP3 scoping report (in accordance with 10 CFR 54.4(a)(2)), the applicant reviewed the reference documents (primarily DBDs) that contain HELB analyses for
 
inside and outside containment and identified high-energy lines. Many of the identified systems
 
are safety-related or are required for a regulated event and are included within the scope of
 
license renewal in accordance with 10 CFR 54.4(a)(1) or (a)(3). The applicant included
 
remaining nonsafety-related, high-energy lines, which were determined to have potential
 
interaction with safety-related SSCs, within the scope of license renewal in accordance with
 
10 CFR 54.4(a)(2).
Spray and Leakage. The applicant evaluated moderate and low-energy systems that have the potential for spatial interactions from spray or leakage. Nonsafety-related systems and
 
nonsafety-related portions of safety-related systems with the potential for spray or leakage that
 
could prevent safety-related SSCs from performing their required safety function were
 
considered within the scope of license renewal. The applicant used a spaces approach to
 
identify the nonsafety-related SSCs located within the same space as safety-related SSCs, as
 
described above. After identifying the applicable mechanical systems, the applicant reviewed
 
the system functions to determine whether the system contained fluid, air, or gas. On the basis
 
of plant and industry operating experience, the applicant excluded the nonsafety-related SSCs
 
containing air or gas from the scope of license renewal. The applicant then determined whether
 
the system had any components located within a space containing safety-related SSCs. The
 
applicant included those nonsafety-related SSCs determined to contain fluid and located within
 
a space containing safety-related SSCs within the scope of license renewal.
RAI 2.1-1(b), dated January 14, 2008, states that during the staff audit, the audit team reviewed the applicants technical evaluation and onsite documentation for nonsafety-related SSCs
 
affecting safety-related SSCs. This technical evaluation found that certain nonsafety-related
 
SSCs affecting safety-related SSCs were not included within the scope of license renewal, based on the proximity of the nonsafety-related SSCs to the safety-related SSCs. The staff
 
requested that the applicant provide the rationale and basis for not including nonsafety-related
 
SSCs in the vicinity of safety-related SSCs within the scope of license renewal, based on their
 
proximity to safety-related SSCs.
In its February 13, 2008, response to RAI 2.1-1(b), the applicant stated the following:
Within a structure that contains components with safety functions, the proximity of components to components with a safety function is not used as a criterion for
 
exclusion of a system or component from (a)(2) scope due to spatial interaction.
 
The wording in the original version of the AMR report reviewed during the license
 
renewal scoping and screening audit did not clarify why fluid-filled components in
 
locations with safety-related equipment were excluded. Some systems have
 
fluid-filled nonsafety-related components located in structures that contain
 
components with safety functions but cannot spatially affect components with
 
safety functions due to physical barriers such as room separation within the
 
structure. During the license renewal scoping and screening audit, a portion of
 
the IP2 chlorination (CL) system was determined to be in proximity to service
 
water system components which perform a safety function. The CL system had
 
been excluded from 10 CFR 54.4(a)(2) scope. The CL system is added to the
 
scope of license renewal for 10 CFR 54.4(a)(2) with components to be managed
 
by the Periodic Surveillance and Preventive Maintenance, External Surfaces
 
Monitoring, and Bolting Integrity Programs.
2-15 The staff reviewed the applicants response to RAI 2.1-1(b) and determined that the applicant described an adequate process, including consideration of room boundaries to prevent
 
interaction, to ensure that fluid-filled, nonsafety-related pipes were not excluded from the scope
 
of license renewal based on the proximity of the nonsafety-related SSCs to safety-related SSCs.
 
The applicant also concluded that an additional system, the chlorination system, is included
 
within the scope of license renewal. SER Section 2.3A.3.19 documents the staffs review of the
 
IP2 chlorination system that was added to the scope. SER Section 3.3A.2 documents the staffs
 
evaluation of AMR results for the IP2 chlorination system components. The staffs concern
 
described in RAI 2.1-1(b) is resolved.
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 from fluid leakage, spray, or flooding. These
 
protective features are credited in the plant design and included within the scope of license
 
renewal.2.1.4.2.3  Conclusion
 
On the basis of its review of the applicants scoping process and systems (on a sampling basis), discussions with the applicant, and review of the information provided in the response to
 
RAIs 2.1-1(a) and (b), the staff concludes that the applicants methodology for identifying and
 
including nonsafety-related SSCs that could affect the performance of safety-related SSCs
 
within the scope of license renewal is consistent with the scoping criteria in 10 CFR 54.4(a)(2)
 
and, therefore, is acceptable.
2.1.4.3  Application of the Scoping Criteria in 10 CFR 54.4(a)(3) 2.1.4.3.1  Summary of Technical Information in the Application LRA Section 2.1.1.3, Application of Criterion for Regulated Events, describes the methodology for identifying those systems and structures within the scope of license renewal in accordance
 
with the Commissions criteria for five regulated events. These criteria appear in
 
(1) 10 CFR 50.48, Fire Protection, (2) 10 CFR 50.49, Environmental Qualification of Electric
 
Equipment Important to Safety for Nuclear Power Plants, (3) 10 CFR 50.61, Fracture
 
Toughness Requirements for Protection against Pressurized Thermal Shock Events,
 
(4) 10 CFR 50.62, Requirements for Reduction of Risk from Anticipated Transients without
 
Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants, and (5) 10 CFR 50.63, Loss of All Alternating Current Power.
Fire Protection. LRA Section 2.1.1.3.1, Commissions Regulations for Fire Protection (10 CFR 50.48), describes the scoping of systems and structures relied on in safety analyses
 
or plant evaluations to perform a function that demonstrates compliance with the fire protection
 
criterion. The LRA stated that in-scope systems and structures for fire protection include
 
equipment based on the functional requirements defined in 10 CFR 50.48. The applicant
 
identified this equipment based on a review of the CLB for systems and structures relied on for
 
compliance with 10 CFR 50.48. The applicant indicated in the LRA that those SSCs credited
 
with fire prevention, detection, and mitigation in areas containing equipment important to the
 
plants safe operation and equipment credited to achieve safe shutdown in the event of a fire
 
are within the scope of license renewal.
2-16Environmental Qualification. LRA Section 2.1.1.3.2, Commissions Regulations for Environmental Qualification (10 CFR 50.49), describes the scoping of systems and structures
 
relied on in safety analyses or plant evaluations to perform a function in compliance with the
 
environmental qualification (EQ) criterion. The LRA states that the EQ program satisfies the
 
requirements of 10 CFR 50.49 and that, because a bounding approach was used for scoping electrical equipment, the electrical and I&C systems and electrical equipment contained in
 
mechanical systems are included within the scope of license renewal by default. Pressurized Thermal Shock. LRA Section 2.1.1.3.3, Commissions Regulations for Pressurized Thermal Shock (10 CFR 50.61), describes the scoping of systems and structures relied on in
 
safety analyses or plant evaluations to perform a function that demonstrates compliance with
 
the pressurized thermal shock (PTS) criterion. The LRA states that for both IP2 and IP3, the
 
only system relied on to comply with the PTS regulation is the reactor coolant system (RCS),
specifically the reactor vessel.
Anticipated Transient without Scram. LRA Section 2.1.1.3.4, Commissions Regulations for Anticipated Transients without Scram (10 CFR 50.62), describes the scoping of systems and
 
structures relied on in safety analyses or plant evaluations to perform a function that
 
demonstrates compliance with the ATWS criterion. The LRA states that the applicant
 
determined the mechanical system intended functions supporting anticipated transient without
 
scram (ATWS) regulation based on CLB information for IP2 and IP3. The LRA also states that, because the applicant used a bounding approach for scoping electrical and I&C equipment, the
 
electrical and I&C systems contained in mechanical systems are included within the scope of
 
license renewal by default.
Station Blackout. LRA Section 2.1.1.3.5, Commissions Regulations for Station Blackout (10 CFR 50.63), describes the scoping of systems and structures relied on in safety analyses
 
or plant evaluations to perform a function that demonstrates compliance with the SBO criterion.
 
The LRA states that the applicant determined the system intended functions supporting
 
10 CFR 50.63 requirements based on information contained in the CLB. The LRA further states
 
that, because the applicant used a bounding approach for scoping electrical and I&C
 
equipment, the onsite electrical and I&C systems and electrical equipment contained in
 
mechanical systems are included within the scope of license renewal by default.
2.1.4.3.2  Staff Evaluation
 
The staff reviewed the applicants approach to identifying mechanical systems and structures relied on to perform functions meeting the requirements of the fire protection, EQ, PTS, ATWS, and SBO regulations. As part of its review, the staff (1) discussed the methodology with the
 
applicant, (2) reviewed the documentation developed to support the approach, and
 
(3) evaluated a sample of the mechanical systems and structures indicated as within the scope
 
of license renewal in accordance with 10 CFR 54.4(a)(3).
The applicants implementing procedures describe the process for identifying systems and structures within the scope of license renewal. The procedures state that all mechanical
 
systems and structures that perform functions addressed in 10 CFR 54.4(a)(3) are to be
 
included within the scope of license renewal and the results documented in scoping results
 
reports. The results reports reference the information sources used for determining the systems
 
and structures credited for compliance with the events listed in the specified regulations.
2-17 Fire Protection. The applicants scoping results reports indicate that the applicant considered CLB documents to identify in-scope systems and structures. These documents include the
 
(1) fire protection plan, which includes the fire protection program plan as required
 
by 10 CFR 50.48; (2) IP2 and IP3 fire hazards analyses; and (3) safe-shutdown analyses for the
 
requirements in Appendix R, Fire Protection Program for Nuclear Power Facilities Operating
 
Prior to January 1, 1979, to 10 CFR Part 50, Domestic Licensing of Production and Utilization
 
Facilities. The staff reviewed the scoping results reports in conjunction with the LRA and the
 
IP2 and IP3 CLB information to validate the methodology for including the appropriate systems
 
and structures within the scope of license renewal.
The staff found that the scoping results reports indicate which of the mechanical systems and structures are included within the scope of license renewal because they perform intended
 
functions that meet 10 CFR 50.48 requirements. As an example, for a mechanical system, the
 
applicants IP2 fire hazards analysis report credits the reactor coolant pump (RCP) oil collection
 
system, which is included under the IP2 fire protectionCO 2 , Halon, and RCP oil collection systems. From this report, the applicant identified a license renewal intended function for the
 
system as providing each RCP with an oil collection system designed to contain and direct the
 
oil to remote storage containers if leakage occurs. The scoping results also identify structures
 
within the scope of license renewal. For example, the foundation structures of the IP2 and IP3
 
fire water storage tanks are within the scope of license renewal because they maintain the
 
structural integrity of the fire water storage tanks that support equipment credited in
 
safe-shutdown capability analyses. The staff determined that the applicants scoping
 
methodology is adequate for including systems and structures credited in performing fire
 
protection functions. Environmental Qualification. The applicant employed a bounding approach for scoping plant electrical and I&C systems. All of these systems are included within the scope of license
 
renewal, and electrical and I&C components in mechanical systems are included in the
 
electrical systems. This method also includes within the scope of license renewal any
 
equipment relied on to perform functions that demonstrate compliance with the EQ regulation.
The staff reviewed the LRA, implementing procedures, scoping results reports, and the IP2 and IP3 master EQ component equipment lists to verify that the applicant identified SSCs within the
 
scope of license renewal that meet EQ requirements. The staff determined that the applicants
 
scoping methodology is adequate for identifying EQ SSCs within the scope of license renewal. Pressurized Thermal Shock. The applicant addressed PTS requirements for the reactor vessels in a TLAA in LRA Section 4.2.5. This methodology is appropriate for identifying SSCs with
 
functions credited for complying with the PTS regulation. For this requirement, the applicant
 
identified the IP2 and IP3 reactor vessels as the only components within the scope of license
 
renewal. SER Section 4.2.5 documents the staffs review of the applicants PTS TLAA.
Anticipated Transient without Scram. The applicants scoping results reports indicate that mechanical systems are included within the scope of license renewal because they perform
 
intended functions that meet 10 CFR 50.62 requirements. The applicant determined the
 
intended functions based on IP2 and IP3 CLB information and identified most in-scope
 
components as electrical equipment in mechanical systems. For scoping electrical equipment, the applicants bounding methodology included within the scope of license renewal all electrical
 
and I&C systems in mechanical systems, by default. The applicant also conservatively included 2-18 mechanical systems with ATWS intended functions based on CLB information from the SSFSs.
The staff determined that this scoping methodology is adequate for identifying systems with
 
functions credited for complying with the ATWS regulation.
Station Blackout. The scoping results reports identify the mechanical systems and structures credited with performing intended functions to comply with the SBO requirement. In its scoping
 
effort, the applicant considered CLB information, including the UFSARs, SSFS, and the SBO
 
report for electrical systems. The applicant used additional information (e.g., drawings and
 
engineering judgment) to identify other systems that support SBO functions.
The applicant included within the scope of license renewal electrical equipment, mechanical systems, and structures with intended functions meeting SBO requirements. For scoping
 
electrical equipment, the applicants bounding methodology included within the scope of license
 
renewal all electrical and I&C systems in mechanical systems by default. The mechanical
 
systems and structures within the scope of license renewal are those relied on in the CLB for
 
the 8-hour SBO coping duration phase and for the SBO recovery phase. The staff determined
 
that this scoping methodology is adequate for identifying systems and structures with functions
 
credited for complying with the SBO regulation. SER Section 2.5 documents the staffs review of
 
the results of the implementation of the SBO scoping methodology.
2.1.4.3.3  Conclusion
 
The staff concludes that the applicants methodology for identifying systems and structures meets the scoping criteria detailed in 10 CFR 54.4(a)(3) and, therefore, is acceptable. The staff
 
based this conclusion on sample reviews, discussions with the applicant, and review of the
 
applicants scoping process.
2.1.4.4  Plant-Level Scoping of Systems and Structures 2.1.4.4.1  Summary of Technical Information in the Application System- and Structure-Level Scoping. The applicant documented its methodology for performing the scoping of systems and structures in accordance with 10 CFR 54.4(a) in the
 
LRA, guidance documents, and scoping and screening reports. The applicants approach to
 
system and structure scoping provided in the site guidance documents and implementing
 
procedures is consistent with the methodology described in Section 2.1 of the LRA. Specifically, the implementing procedures require personnel performing license renewal scoping to use CLB
 
documents, describe the system or structure, and include a list of functions that the system or
 
structure is required to accomplish. Sources of information regarding the CLB for systems
 
include the UFSARs, DBDs, P&IDs, Maintenance Rule information, drawings, and docketed
 
correspondence. The applicant then compared identified system or structure function lists to the
 
scoping criteria to determine whether the functions meet the scoping criteria of 10 CFR 54.4(a).
 
The applicant documented the results of the plant-level scoping process in accordance with the
 
implementing procedures. The results were provided in the systems and structures documents
 
and reports that contain a description of the structure or system, a listing of functions performed
 
by the system or structure, identification of intended functions, the 10 CFR 54.4(a) scoping
 
criteria met by the system or structure, references, and the basis for the classification of the
 
intended functions of the system or structure.
2-19 Insulation. LRA Section 2.1.1, Scoping Methodology, states that insulation was treated as a bulk commodity for the purposes of scoping. LRA Section 2.4.4, Bulk Commodities, discusses
 
insulation and states that certain insulation has the specific intended functions of (1) controlling
 
the heat load during DBAs in areas with safety-related equipment or (2) maintaining integrity
 
such that falling insulation (such as reflective metallic-type reactor vessel insulation) does not
 
damage safety-related equipment and was included within the scope of license renewal in
 
accordance with 10 CFR 54.4(a)(1) or (a)(2) as applicable. Consumables. In LRA Section 2.1.2.4, Consumables, the applicant used the information in SRP-LR Table 2.1-3 to categorize and evaluate consumables. For the purpose of license
 
renewal, consumables were divided into four categories (a) packing, gaskets, component seals, and O-rings, (b) structural sealants, (c) oil, grease, and component filters, and (d) system filters, fire extinguishers, fire hoses, and air packs.
Group (a) consumables (packing, gaskets, component mechanical seals, and O-rings) are typically used to provide a leakproof seal when components are mechanically joined together.
 
These items are commonly found in components such as valves, pumps, heat exchangers, ventilation units or ducts, and piping segments. According to American National Standards
 
Institute (ANSI) B31.1 and American Society of Mechanical Engineers (ASME) Boiler and
 
Pressure Vessel (B&PV) Code Section III, the subcomponents of these pressure-retaining
 
components are not pressure-retaining parts. Therefore, these subcomponents are not relied on
 
to perform a pressure boundary intended function and are not subject to an AMR.
Group (b) consumables (elastomers and other materials used as structural sealants) are subject to an AMR if they are not periodically replaced and they perform an intended function, typically
 
supporting a pressure boundary, flood barrier, or rated fire barrier. Seals and sealants, including
 
pressure boundary sealants, compressible joints and seals, seismic joint filler, and
 
waterproofing membranes, are included in the AMR of bulk commodities. Sealants with a
 
pressure boundary function are included in the AMR of the containment buildings.
Group (c) consumables (oil, grease, and component filters) are treated as consumables because either (1) they are periodically replaced or (2) they are monitored and replaced based
 
on condition. They are not subject to an AMR. Group (d) consumables (system filters, fire hoses, fire extinguishers, self-contained breathing apparatus, and self-contained breathing apparatus cylinders) are considered consumables
 
because they are routinely tested and inspected and they are replaced when necessary.
 
Periodic inspection procedures specify the replacement criteria of these components that are
 
routinely checked by tests or inspections. Therefore, while these consumables are in the scope
 
of license renewal, they are not subject to an AMR.
2.1.4.4.2  Staff Evaluation
 
During the audit, the staff reviewed the applicants methodology for performing the scoping of plant systems and structures to ensure that it is consistent with 10 CFR 54.4(a). The
 
methodology used by the applicant to determine the systems and structures within the scope of
 
license renewal is documented in implementing procedures and scoping results reports for
 
mechanical systems. The scoping process defines the plant in terms of systems and structures.
 
Specifically, the implementing procedures identify the systems and structures that are subject to
 
review in accordance with 10 CFR 54.4(a) and describe the processes for capturing the results 2-20 of the review. The procedures are used to determine whether the system or structure performs intended functions consistent with the requirements of 10 CFR 54.4(a). The implementing
 
procedures indicate that the applicant completed this process for all systems and structures to
 
ensure that the entire plant was addressed. During the audit, the staff reviewed a sampling of
 
the documents and reports and concluded that the applicants scoping results contain an
 
appropriate level of detail to document the scoping process.
2.1.4.4.3  Conclusion
 
Based on its review of the LRA, site guidance documents, and scoping and screening implementing procedures, and based on a sampling of system scoping results reviewed during
 
the audit, the staff concludes that the applicants methodology for identifying systems and
 
structures within the scope of license renewal, and their intended functions, is consistent with
 
the requirements of 10 CFR 54.4 and, therefore, is acceptable.2.1.4.5  Mechanical Scoping 2.1.4.5.1  Summary of Technical Information in the Application LRA Section 2.1.1 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 the intended functions will be performed. The LRA
 
states that components needed to support each of the system-level intended functions identified
 
in the scoping process are included within the evaluation boundary.
The LRA states that, for mechanical system scoping, system boundaries were defined in part by the collection of components in the database assigned to the system code. The database
 
represents all systems and contains the vast majority of system components. The database was
 
useful in preparing the list of plant systems but could not be used alone to determine all system
 
boundaries.
In addition, the LRA states that flow diagrams were used with the component database to help define system boundaries. System functions were determined based on the functions performed
 
by the components within those boundaries. The LRA notes that, because of the differences in
 
IP2 and IP3 system boundaries, the intended functions for the systems are often different, even for similarly named systems. The applicant evaluated structural commodities associated with
 
mechanical systems, such as pipe hangers and insulation, with the structural bulk commodities, (i.e., grouping structural components that typically do not have unique identifiers that are
 
common to in-scope systems and structures (e.g., anchors, embedments, equipment supports, insulation)), while it evaluated electrical and I&C components separately. The evaluation
 
boundaries for mechanical systems were documented on license renewal drawings created by
 
marking mechanical P&IDs to indicate the components within the scope of license renewal. The
 
applicant evaluated mechanical systems against the criteria of 10 CFR 54.4(a)(1), (a)(2), and (a)(3).2.1.4.5.2  Staff Evaluation
 
The staff evaluated LRA Section 2.1 and the guidance in the implementing procedures and reports in its review of the mechanical scoping process. The implementing procedures and
 
reports provide instructions for identifying the evaluation boundaries. An understanding of 2-21 system operations in support of intended functions is required to determine the mechanical system evaluation boundary.
This process is based on the review of Maintenance Rule basis documents, DBDs, SSFSs, the fire hazards analysis, the safe-shutdown analysis, internal flooding analyses, technical
 
specifications, applicable sections of the UFSARs, and plant drawings. The evaluation
 
boundaries for mechanical systems are documented on license renewal boundary drawings that
 
were created by marking mechanical P&IDs to indicate the components within the scope of
 
license renewal and subject to an AMR. Components within the evaluation boundary were
 
reviewed to determine if they perform an intended function. Intended functions were established
 
based on whether a particular function of a component is necessary to support the system
 
functions that meet the scoping criteria.
The staff reviewed the implementing procedures and the CLB documents associated with mechanical system scoping and found that the guidance and CLB source information are 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
 
applicants license renewal project management personnel and reviewed documentation
 
pertinent to the scoping process. The staff assessed whether the applicant had appropriately
 
applied the scoping methodology outlined in the LRA and implementing procedures and
 
whether the scoping results are consistent with CLB requirements.
The staff determined that the applicants procedure is consistent with the description in LRA Section 2.1 and the guidance in SRP-LR Section 2.1 and was adequately implemented.
On a sampling basis, the staff reviewed the applicants methodology for identifying SW system mechanical component types meeting the scoping criteria of 10 CFR 54.4. The staff also
 
reviewed the implementing procedures for the scoping methodology and discussed the
 
methodology and results with the applicant. The staff verified that the applicant had identified
 
and used pertinent engineering and licensing information to determine the SW system
 
mechanical component types that fall within the scope of license renewal. As part of the review
 
process, the staff evaluated each system intended function identified for the SW 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 had identified and highlighted system
 
P&IDs to develop the license renewal boundaries in accordance with the procedural guidance.
Based on its review of the LRA, scoping implementing procedures, the sample system, and review and discussions with the applicant, the staff verified that the applicant is knowledgeable
 
about the process and conventions for establishing boundaries, as defined in the license
 
renewal implementing procedures, and that the applicant independently verified the results in
 
accordance with the implementing procedures. Specifically, other license renewal personnel
 
knowledgeable about the system independently reviewed the marked-up drawings to ensure
 
accurate identification of the system intended functions. The applicant performed additional
 
cross-discipline verification and independent reviews of the associated drawings before
 
approving the scoping effort.
2-22 2.1.4.5.3  ConclusionBased on its review of the LRA, scoping implementing procedures, the sample system review, and discussions with the applicant, the staff concludes that the applicants methodology for
 
identifying mechanical systems and components within the scope of license renewal is
 
consistent with the requirements of 10 CFR 54.4 and, therefore, is acceptable.
2.1.4.6  Structural Scoping 2.1.4.6.1  Summary of Technical Information in the Application In LRA Section 2.1.1, the applicant described the methodology for identifying structures that are within the scope of license renewal. The applicant developed a list of plant structures from a review of plant layout drawings, Maintenance Rule documentation, DBDs, and the UFSARs.
 
The structures list includes all structures that potentially support plant operations or could
 
adversely impact structures that support plant operations. In addition to buildings and facilities, the list of structures includes other structures that support plant operation.
The applicant identified intended functions for structures and mechanical systems based on reviews of applicable plant licensing and design documentation. The applicant reviewed
 
documents that included Maintenance Rule documents, DBDs, site SSFSs, the fire hazards
 
analysis, the safe-shutdown analysis, internal flooding analyses, technical specifications, the
 
UFSARs, and station drawing. The LRA states that the applicant evaluated each structure
 
against the criteria of 10 CFR 54.4(a)(1), (a)(2), and (a)(3).
2.1.4.6.2  Staff Evaluation
 
The staff reviewed the applicants approach for identifying structures relied on to perform the license renewal intended functions in accordance with 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 applicants review, and evaluated the scoping results for several structures that
 
were identified as within the scope of license renewal.
The applicant identified and developed a list of plant structures and the structures intended functions, through a review of the UFSARs, Maintenance Rule documents, the fire hazards
 
analysis, DBDs, and structural drawings. The applicant determined that the primary structural
 
safety functions applicable to the requirements of 10 CFR 54.4(a)(1) were to provide
 
(1) containment of radioactive products to mitigate post-accident offsite doses and (2) to support
 
or protect safety-related equipment. The applicant also included structures housing
 
safety-related SSCs within the scope of license renewal in accordance with 10 CFR 54.4(a)(2).
The staff reviewed selected portions of the UFSARs, Maintenance Rule documents, the fire hazards analysis, DBDs, structural drawings, implementing procedures, and selected AMR
 
reports to verify the adequacy of the methodology.
In addition, the staff reviewed the scoping results, including information contained in the source documentation for the turbine building, to verify that application of this methodology would
 
provide the results as documented in the LRA. The staff verified that the applicant had identified
 
and used pertinent engineering and licensing information to determine the turbine building
 
structural component types that fall within the scope of license renewal. As part of the review 2-23 process, the staff evaluated the intended functions identified for the turbine building, the basis for inclusion of the intended functions, and the process used to identify each of the component
 
types.2.1.4.6.3  Conclusion
 
Based on the staffs review of information in the LRA, the applicants detailed scoping procedures, and a review of a sample of structural scoping results, the staff concluded that the
 
applicants methodology for identification of the structures within the scope of license renewal is
 
consistent with the requirements of 10 CFR 54.4 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 states that, for the purposes of system-level scoping, all plant electrical and I&C systems are included in the scope of license renewal. The evaluation of electrical systems
 
includes electrical and I&C components in mechanical systems.
LRA Section 2.5, Scoping and Screening Results: Electrical and Instrumentation and Control Systems, states that the applicant included electrical and I&C components within the scope of
 
license renewal unless they were specifically screened out. When used with the plant spaces
 
approach, this method eliminates the need for unique identification of every component and its
 
specific location and ensures that components are not improperly excluded from an AMR.
The applicant began the electrical and I&C scoping process by grouping the total population of components into commodity groups. The commodity groups include similar electrical and I&C
 
components with common characteristics. The applicant identified component-level intended
 
functions of the commodity groups. During the IPA, commodity groups and specific plant
 
systems were eliminated from further review as the intended functions of commodity groups
 
were examined.
2.1.4.7.2  Staff Evaluation
 
The staff reviewed the applicants approach for identifying electrical and I&C SSCs relied on to perform the license renewal intended functions detailed in 10 CFR 54.4(a). As part of this
 
review, the staff reviewed the implementing procedures and documentation developed to
 
support the applicants review and evaluated, on a sampling basis, the scoping results for
 
several electrical systems identified as within the scope of license renewal.
The staff evaluated LRA Sections 2.1.1 and 2.5, scoping implementing procedures, scoping reports and aging management reports, as documented in the audit report, governing the
 
electrical scoping methodology. The staff determined that the scoping phase for electrical components began with placing all electrical components from plant systems within the scope of
 
license renewal. In addition, non-plant electrical systems including certain switchyard
 
components required to support SBO and to restore offsite power were included within the
 
scope of license renewal. The staff determined that the data sources used for scoping included
 
the UFSARs, DBDs, cable database, component database, the station single-line drawings, cable procurement specifications, electrical drawings, the EQ master list, the IP2 and IP3 fuse
 
list, and connection diagrams to identify the electrical and I&C components.
2-24 During the scoping methodology audit, the staff reviewed the applicants process for identifying fuse holders within the scope of license renewal. The staff determined that the applicant had
 
reviewed the plant fuse list and connection diagrams to identify fuses outside of complex
 
assemblies and had determined that no fuses were within the scope of license renewal. During
 
the scoping methodology audit, the staff reviewed the applicants process for identifying tie
 
wraps within the scope of license renewal. The staff determined that the applicant had reviewed
 
the CLB for credit taken for tie wrap installation and reviewed operating experience to determine
 
if the nonsafety-related tie wraps could affect a safety-related function, but did not identify any
 
tie wraps within the scope of license renewal. The staff reviewed selected portions of the data
 
sources and selected several examples of components for which the applicant demonstrated
 
the process used to determine that electrical components were within the scope of license
 
renewal.2.1.4.7.3  Conclusion
 
On the basis of the review of information contained in the LRA, the applicants scoping implementing procedures, and a review of a sample of electrical scoping results, the staff
 
concludes that the applicants methodology for identification of electrical components within the
 
scope of license renewal is consistent with the requirements of 10 CFR 54.4 and, therefore, is
 
acceptable.
SER Section 2.5 documents the results of the staffs review of the implementation of the SBO scoping methodology. 2.1.4.8  Conclusion for Scoping Methodology On the basis of its review of the LRA and the scoping implementation procedures, the staff concludes that the applicants scoping methodology is consistent with the guidance contained in
 
the SRP-LR and identifies those SSCs (1) that are safety related, (2) whose failure could affect
 
safety-related functions, and (3) that are necessary to demonstrate compliance with NRC
 
regulations for fire protection, EQ, PTS, ATWS, and SBO. The staff concludes that the
 
applicants methodology is consistent with the requirements of 10 CFR 54.4(a) and, therefore, is
 
acceptable.2.1.5  Screening Methodology 2.1.5.1  General Screening Methodology 2.1.5.1.1  Summary of Technical Information in the Application In LRA Section 2.1.2, Screening Methodology, the applicant described its process for determining which components and structural elements require an AMR. Screening is the
 
process by which the applicant identifies SCs within the scope of license renewal that perform
 
an intended function, as described in 10 CFR 54.4, without moving parts or without a change in
 
configuration or properties, and that are not subject to replacement based on a qualified life or
 
specified time period.
LRA Section 2.1.6 states that the screening process for IP2 and IP3 followed the recommendations of NEI 95-10. For the group of systems and structures that were within the 2-25 scope of license renewal, the applicant determined that passive long-lived components or structural elements that perform license renewal intended functions require an AMR.
 
Components or structural elements that are either active or subject to replacement based on a
 
qualified life do not require an AMR. Although the requirements for the IPA are the same for
 
each system and structure, in practice, the screening process differed for mechanical systems, electrical systems, and structures.
2.1.5.1.2  Staff Evaluation
 
As required by 10 CFR 54.21, each LRA must contain an IPA that identifies SCs that are 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 components), as well as components that are not subject to periodic replacement
 
based on a qualified life or specified time period (long-lived components). 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
 
are 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 relate to the
 
component types and commodity groups within the scope of license renewal.
The applicant applied the screening process to evaluate the component types and commodity groups included within the scope of license renewal and to determine which ones were passive
 
and long lived and, therefore, subject to an AMR. The staff reviewed LRA Sections 2.3, 2.4, and
 
2.5, which provide the results of the process used by the applicant to identify component types
 
and commodity groups subject to an AMR. During the scoping and screening methodology
 
audit, the staff discussed the processes used for each discipline, reviewed the implementing
 
procedures describing the screening methodology, and reviewed documentation of the
 
screening results. On a sampling basis, the staff also reviewed the screening results reports for
 
the SW system and the turbine building. The following sections of this SER discuss specific
 
methodologies for mechanical, electrical, and structural components.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, 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 that
 
are within scope under 10 CFR 54.4(a)(2) for physical interactions.
2-26 2.1.5.2.2  Staff Evaluation The staff evaluated the mechanical screening methodology discussed and documented in LRA Section 2.1.2.1, implementing procedures, AMR reports, and the license renewal drawings.
 
The mechanical system screening process began with the results from the scoping process.
 
The applicant reviewed each system evaluation boundary 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 a license renewal intended function are subject
 
to an AMR. The results of the review are documented in the AMR reports. The AMR reports
 
contain information such as the sources reviewed and the intended functions of the system.
During the scoping and screening methodology audit, the staff reviewed the results of the boundary evaluations and discussed the process with the applicant. The staff verified that
 
mechanical system evaluation boundaries were established for each system within the scope of
 
license renewal and that the boundaries were determined by mapping the system intended
 
function boundaries onto P&IDs. The applicant reviewed the components within the system
 
intended function boundary to determine whether the component supported the systems
 
intended function. Components that supported the systems intended function were reviewed to
 
determine whether the component was passive and long lived and, therefore, subject to an
 
AMR.The staff reviewed selected portions of the UFSARs, Maintenance Rule documents, the fire hazards analysis, DBDs, structural drawings, implementing procedures, and selected AMR
 
reports. The staff conducted detailed discussions with the applicants license renewal team and
 
reviewed documentation pertinent to the screening process. The staff assessed whether the
 
mechanical screening methodology outlined in the LRA and procedures was appropriately
 
implemented and whether the scoping results are consistent with CLB requirements. The staff
 
also reviewed the mechanical screening results for the SW system to verify proper
 
implementation of the screening process. These audit activities revealed no discrepancies
 
between the methodology documented and the implementation results.
2.1.5.2.3  Conclusion
 
Based on its review of the LRA, the implementing procedures, and a sample of the SW system screening results, the staff concludes that the applicant
=s mechanical component screening methodology is consistent with the SRP-LR guidance. The staff concludes that the applicants methodology for identification of passive, long-lived mechanical components within the scope of
 
license renewal and subject to an AMR is consistent with the requirements of
 
10 CFR 54.21(a)(1) and, therefore, is acceptable.
2.1.5.3  Structural Component Screening 2.1.5.3.1  Summary of Technical Information in the Application LRA Section 2.1.2.2, Screening of Structures, states that, for each structure within the scope of license renewal, the screening process identified those structural components that are
 
subject to an AMR. LRA Section 2.4 presents the results for structures. The screening process
 
for structural components involved a review of DBDs, design drawings, general arrangement
 
drawings, penetration drawings, the UFSARs, plant modifications, system descriptions, and
 
plant walkdowns to identify specific structural components and commodities that make up the 2-27 structure. The LRA states that structures are inherently passive and, with few exceptions, are long lived. Therefore, the screening of structural components and commodities was based
 
primarily on whether they perform an intended function. The applicant grouped structural
 
components as commodities based on materials of construction (steel, bolted connections, concrete, and other materials). The applicant evaluated structural components and commodity
 
groups to identify intended functions as they relate to license renewal.
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 by 10 CFR 54.21(a)(1). As part of this review, the staff discussed the methodology with the applicant, reviewed the documentation developed to support the
 
activity, and evaluated the screening results for several structures that were identified within the
 
scope of license renewal.
The staff reviewed the applicants methodology used for structural screening described in the LRA sections noted above and in the applicants implementing procedures and AMR reports.
 
The applicant performed the screening review in accordance with the implementing procedures
 
and identified pertinent structure design information, components, materials, environments, and
 
aging effects. The staff verified that the applicant determined that structures are inherently
 
passive and long lived, such that the screening of structural components and commodities was
 
based primarily on whether they perform an intended function. During the scoping and
 
screening methodology audit, the staff discussed the screening methodology and, on a
 
sampling basis, reviewed the screening reports for a selected group of structures.
The staff reviewed selected portions of the UFSARs, Maintenance Rule documents, the fire hazards analysis, DBDs, structural drawings, implementing procedures, and selected AMR
 
reports. The staff conducted detailed discussions with the applicants license renewal team and
 
reviewed documentation pertinent to the screening process. The staff assessed whether the
 
screening methodology outlined in the LRA and implementing procedures was appropriately
 
implemented and whether the scoping results are consistent with CLB requirements.
The staff also reviewed structural screening results for SCs contained in the turbine building to verify proper implementation of the screening process. Based on these audit activities, the staff
 
identified no discrepancies between the methodology documented and the implementation
 
results.2.1.5.3.3  Conclusion
 
On the basis of the staffs review of information contained in the LRA, the applicants detailed implementing procedures, and a review of a sample of structural screening results, the staff
 
concludes that the applicants methodology for identifying structural components within the
 
scope of license renewal and subject to an AMR is consistent with the requirements of
 
10 CFR 54.21(a)(1) and, therefore, is acceptable.
2-28 2.1.5.4  Electrical Component Screening 2.1.5.4.1  Summary of Technical Information in the Application In LRA Section 2.1.2.3, Electrical and Instrumentation and Control Systems, the applicant discussed the screening of electrical and I&C system components. For each electrical system
 
within the scope of license renewal, the screening process identified those electrical
 
components and commodity groups 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 LRA states that the process of electrical screening differs from the mechanical and structural processes because the electrical components were addressed completely within their
 
respective commodity groups. The applicant assigned each electrical component within the
 
scope of license renewal to an electrical component commodity group for the screening
 
evaluation. An electrical commodity group is a collection of electrical components grouped by
 
type of equipment or function.
In the LRA, the applicant indicated that 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. Appendix B to NEI 95-10 identifies the electrical commodity groups
 
considered to be passive and potentially requiring an AMR. For IP2 and IP3, electrical
 
commodity groups were identified and cross-referenced to the appropriate NEI 95-10
 
commodity, which identifies the passive commodity groups. Electrical commodity groups
 
determined to be active were not subject to an AMR. Electrical commodity groups that are not
 
subject to replacement based on a qualified life or specified time period were considered long
 
lived. The applicant further stated that components subject to replacement and addressed in
 
replacement programs, such as the EQ Program, are not subject to an AMR.
2.1.5.4.2  Staff Evaluation
 
The staff reviewed the applicants methodology for electrical screening, described in LRA Section 2.1.2.3, and the applicants implementing procedures and AMR reports. The applicant
 
used the screening process described in these documents to identify the electrical commodity
 
groups subject to AMR.
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 commodity groups
 
subject to an AMR. The applicant also reviewed additional IP2 and IP3 documents such as
 
electrical drawings and the EQ master list to validate the listing as complete.
The applicant determined that two commodity groups meet the passive criteria in accordance with NEI 95-10(1) high-voltage insulators and (2) cables and connections, bus, and electrical
 
portions of electrical and I&C penetration assemblies. The applicant evaluated the identified
 
passive commodity groups to determine whether they are 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 applicant determined that the other
 
electrical and I&C commodity groups are active and do not require an AMR. The staff reviewed
 
the screening of selected components to verify the correct implementation of the methodology.
 
The staff also reviewed selected electrical screening results, on a sampling basis, to verify 2-29 proper implementation of the screening process. Based on these audit activities, the staff identified no discrepancies between the methodology documented and the implementation
 
results.2.1.5.4.3  Conclusion
 
The staff reviewed the LRA, procedures, electrical drawings, and a sample of the results of the screening methodology. The staff concludes that the applicants methodology is consistent with
 
the description in the LRA and the applicants implementing procedures. On the basis of its
 
review of information contained in the LRA, the applicants implementing procedures, and a
 
review of a sample of electrical screening results, the staff concludes that the applicants
 
methodology for identifying electrical commodity groups within the scope of license renewal and
 
subject to an AMR is consistent with the requirements of 10 CFR 54.21(a)(1) and, therefore, is
 
acceptable.2.1.5.5  Screening MethodologyConclusion On the basis of a review of the LRA, the screening implementing procedures, discussions with the applicants staff, and a sample review of screening results, the staff concludes that the
 
applicants screening methodology is consistent with the guidance contained in the SRP-LR and
 
that the applicant identified those passive, long-lived components within the scope of license
 
renewal that are subject to an AMR. The staff concludes that the applicants methodology is
 
consistent with the requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable.2.1.6  Summary of Evaluation Findings The staffs 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 applicants responses dated
 
February 13, 2008, to the staffs RAIs formed the basis of the staffs evaluation. The staff
 
verified that the applicants scoping and screening methodology is consistent with the
 
requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff also confirmed that the
 
applicants description and justification of its scoping and screening methodology are adequate
 
to meet the requirements of 10 CFR 54.21(a)(1). From this review, the staff concludes that the
 
applicants methodology for identifying systems and structures within the scope of license
 
renewal and SCs requiring an AMR is acceptable.
2.2  Plant-Level Scoping Results SER Section 2.2A presents plant-level scoping results for IP2; SER Section 2.2B presents
 
plant-level scoping results for IP3.
2.2A  IP2 Plant-Level Scoping Results 2.2A.1  Introduction In LRA Section 2.1, the applicant described the methodology for identifying SSCs within the scope of license renewal and subject to an AMR. The applicant applied the scoping
 
methodology to determine which SSCs must be included within the scope of license renewal.
 
LRA Section 2.2 provides the results of the applicants review. The staff reviewed the plant-level 2-30 scoping results to determine whether the applicant had properly identified all systems and structures relied on to mitigate DBEs, as required by 10 CFR 54.4(a)(1); systems and structures
 
whose failure could prevent satisfactory accomplishment of any safety-related functions, as
 
required by 10 CFR 54.4(a)(2); and systems and structures relied on in safety analyses or plant
 
evaluations to perform functions in accordance with 10 CFR 54.4(a)(3).2.2A.2  Summary of Technical Information in the Application In LRA Table 2.2-1a-IP2, the applicant listed the plant mechanical systems within the scope of license renewal for IP2. In LRA Table 2.2-1b-IP2, the applicant listed the plant electrical and
 
I&C systems within the scope of license renewal for IP2. In LRA Table 2.2-3, the applicant listed
 
the structures that are within the scope of license renewal for IP2. In LRA Tables 2.2-2-IP2, Mechanical Systems Not within the Scope of License Renewal, and 2.2-4, the applicant listed
 
the systems and structures that are not within the scope of license renewal. Systems and
 
structures that exist only at one unit are marked in the tables, as appropriate. Based on the
 
DBEs considered in the plants CLB, other CLB information relating to nonsafety-related
 
systems and structures, and certain regulated events, the applicant identified plant-level
 
systems and structures within the scope of license renewal as defined by 10 CFR 54.4.
2.2A.3  Staff Evaluation The staff reviewed the scoping and screening methodology and provides its evaluation in SER Section 2.1. To verify that the applicant properly implemented its methodology, the staffs review
 
focused on the implementation results shown in LRA Tables 2.2-1a-IP2, 2.2-1b-IP2, 2.2-2-IP2, 2.2-3, and 2.2-4. In its review, the staff sought to confirm that the applicant had not omitted any
 
plant-level system or structure from the scope of license renewal.
The staff reviewed the systems and structures that the applicant did not identify as within the scope of license renewal to determine whether they perform any intended functions that would
 
require their inclusion within the scope of license renewal. The staff reviewed the applicants
 
implementation results in accordance with the guidance in SRP-LR Section 2.2, Plant-Level
 
Scoping Results.
During its review of LRA Section 2.2, the staff identified an area in which it required additional information to complete its review of the applicants plant-level scoping results. The applicants
 
responses to the staffs RAIs are discussed below.
In RAI 2.2A-1, dated December 7, 2007, the staff noted that LRA Table 2.2-2-IP2 excludes the hot penetration cooling system from the scope of license renewal and references UFSAR
 
Section 5.1.4.2.2 as the basis for this decision. The staff further noted that UFSAR
 
Section 5.1.4.2.2 provides a local area temperature limit of 250 degrees Fahrenheit (F) and
 
states that air-to-air heat exchangers provide cooling for hot penetrations. The staff noted that
 
cooling of hot containment penetrations minimizes age-related, heat-induced degradation of
 
local concrete surrounding the penetration; therefore, the system may have an intended
 
function, as defined in 10 CFR 54.4(a). The staff requested that the applicant justify the
 
exclusion of the hot penetration cooling system from the scope of license renewal.
In its response, dated January 4, 2008, the applicant stated that the hot penetration cooling system removes heat from penetrations for hot piping systems to limit the temperature of the
 
surrounding concrete during normal plant operation. The applicant further explained that the hot 2-31 penetration cooling system is not required to function during accident conditions and has no function that meets the requirements of 10 CFR 54.4(a)(1). Additionally, the applicant explained
 
that the hot penetration cooling system is not relied on to perform intended functions in
 
accordance with 10 CFR 54.4(a)(2) or 10 CFR 54.4(a)(3); therefore, it is not within the scope of
 
license renewal. The applicant provided the following evaluation:
In order to lose significant structural properties, concrete must be held at high temperatures for an extended period of time. The hottest penetrations at IPEC
 
are the MS lines, which normally operate at a temperature of 507&deg;F. The results
 
of a heat transfer analysis indicate that in the improbable case that all cooling air
 
would be lost to the main steam penetration; the surrounding concrete would
 
reach a maximum temperature of 200&deg;F in approximately 1000 hours. It is not
 
credible that cooling air would be lost for a significantly long period of time since
 
the failure of the air blower drive motors is alarmed in the control room.
 
Therefore, the failure of the hot penetration cooling system would not adversely
 
impact the concrete in the penetrations.
Based on its review, the staff finds the response to RAI 2.2A-1 acceptable because the applicant adequately explained that the hot penetration cooling system is not safety related and
 
its failure would not adversely affect a safety-related system or structure. The staff confirmed
 
that the hot penetration cooling system is not credited in any accident analyses in the
 
applicants CLB. The staffs concern described in RAI 2.2A-1 is resolved.
During the NRCs onsite scoping and screening audit, the staff reviewed the applicants onsite documentation for the potential interaction of SSCs based on the proximity of nonsafety-related
 
SSCs to safety-related SSCs. In RAI 2.1-1, dated January 14, 2008, the staff asked the applicant to provide a technical basis for excluding these systems from scope. In its response, dated February 13, 2008, the applicant provided an evaluation of these systems and amended
 
the LRA to include the IP2 chlorination system within the scope of license renewal in
 
accordance with 10 CFR 54.4(a)(2). Hence, as noted in the above section, the applicant added
 
the IP2 chlorination system to LRA Table 2.3.3-19-A-IP2. Additionally, the applicant added LRA
 
Table 2.3.3-19-44-IP2 to identify the component types subject to an AMR. Based on a review of
 
this response, the staff finds that the applicant has adequately identified systems required to be
 
within the scope of license renewal in accordance with 10 CFR 54.4(a)(2).
2.2A.4  Conclusion The staff reviewed LRA Section 2.2, the RAI responses, and the UFSAR supporting information to determine whether the applicant failed to identify any systems and structures within the scope
 
of license renewal. The staff found an instance in which the applicant omitted a system that
 
should have been included within the scope of license renewal. The applicant has satisfactorily
 
resolved this issue as discussed in the preceding staff evaluation. Therefore, on the basis of its
 
review, the staff concludes that the applicant has appropriately identified the mechanical
 
systems and structures within the scope of license renewal, as required by 10 CFR 54.4(a).
2-32 2.2B  IP3 Plant-Level Scoping Results 2.2B.1  Introduction In LRA Section 2.1, the applicant described the methodology for identifying SSCs within the scope of license renewal and subject to an AMR. The applicant applied the scoping
 
methodology to determine which SSCs must be included within the scope of license renewal.
 
LRA Section 2.2 provides the results of the applicants review. The staff reviewed the plant-level
 
scoping results to determine whether the applicant had properly identified all systems and
 
structures relied on to mitigate DBEs, as required by 10 CFR 54.4(a)(1); systems and structures
 
whose failure could prevent satisfactory accomplishment of any safety-related functions, as
 
required by 10 CFR 54.4(a)(2); and systems and structures relied on in safety analyses or plant
 
evaluations to perform functions in accordance with 10 CFR 54.4(a)(3).2.2B.2  Summary of Technical Information in the Application In LRA Table 2.2-1a-IP3, the applicant listed the plant mechanical systems within the scope of license renewal for IP3. In LRA Table 2.2-1b-IP3, the applicant listed the plant electrical and
 
I&C systems within the scope of license renewal for IP3. In LRA Table 2.2-3, the applicant listed
 
the structures that are within the scope of license renewal for IP3. In LRA Tables 2.2-2-IP3, Mechanical System Not within the Scope of License Renewal, and 2.2-4, the applicant listed
 
the systems and structures that are not within the scope of license renewal. Systems and
 
structures that exist only at one unit are marked in the tables, as appropriate. Based on the
 
DBEs considered in the plants CLB, other CLB information relating to nonsafety-related
 
systems and structures, and certain regulated events, the applicant identified plant-level
 
systems and structures within the scope of license renewal as defined by 10 CFR 54.4.
2.2B.3  Staff Evaluation The staff reviewed the scoping and screening methodology and provides its evaluation in SER Section 2.1. To verify that the applicant properly implemented its methodology, the staffs review
 
focused on the implementation results shown in LRA Tables 2.2-1a-IP3, 2.2-1b-IP3, 2.2-2-IP3, 2.2-3, and 2.2-4. In its review, the staff sought to confirm that no plant-level systems or
 
structures were omitted from the scope of license renewal.
The staff reviewed the systems and structures that the applicant did not identify as within the scope of license renewal to determine whether they perform any intended functions that would
 
require their inclusion within the scope of license renewal. The staff conducted its review of the
 
applicants implementation in accordance with the guidance in SRP-LR Section 2.2.
During its review of LRA Section 2.2, the staff identified areas in which it required additional information to complete its review of the applicants plant-level scoping results. The applicants
 
responses to the staffs RAIs are discussed below.
In RAI 2.2B-1, dated December 7, 2007, the staff noted that LRA Table 2.2-2-IP3 excludes the breathable air system from the scope of license renewal and references UFSAR Section 9.10 as
 
the basis for this decision. The staff further noted that UFSAR Section 9.10 states that the
 
breathable air system is a non-Category I system, except for the penetration into containment, where breathable air is provided inside containment through a spare penetration line. The staff
 
noted that the breathable air systems containment penetration should be within the scope of 2-33 license renewal in accordance with 10 CFR 54.4(a)(1), and requested that the applicant confirm whether the containment penetration is within the scope of license renewal.
In its response, dated January 4, 2008, the applicant stated that the breathable air containment penetration, designated as X-X, is within the scope of license renewal and was reviewed as
 
part of the containment penetration system in LRA Section 2.3.2.5. The applicant further
 
explained that the containment penetration for the breathable air system is subject to an AMR.
Based on its review, the staff finds the response to RAI 2.2B-1 acceptable because the applicant adequately explained that containment penetration X-X for the breathable air system
 
was evaluated with the containment penetration system. Furthermore, the staff confirmed that
 
the LRA identified the breathable air containment penetration as requiring an AMR. The staffs
 
concern described in RAI 2.2B-1 is resolved.
In RAI 2.2B-2, dated February 13, 2008, the staff noted that nonsafety-related SSCs directly connected to safety-related SSCs must be structurally sound to maintain the pressure boundary
 
integrity of safety class piping. The nonsafety-related piping and supports up to and including
 
the first seismic anchor beyond the safety/nonsafety interface may need to be within scope to
 
ensure that the safety-related portion of the piping will be able to perform its intended function.
LRA Table 2.2-2-IP3 excluded the hydrogen gas system from the scope of license renewal. This system, along with the nitrogen system, provides the volume control tank (VCT) with gas for
 
oxygen scavenging. Since the piping is directly connected to the VCT, the staff questioned
 
whether the system should be considered within the scope of license renewal, in accordance
 
with 10 CFR 54.4(a)(2), because of the potential for physical interaction between the nonsafety-
 
and safety-related equipment. The staff asked the applicant to evaluate placing the hydrogen
 
system or nitrogen system, or both, within scope under 10 CFR 54.4(a)(2) and to evaluate any
 
other interfaces of gas system interaction with safety-related equipment.
In its response, dated March 12, 2008, the applicant stated that the IP3 VCT is within scope and subject to an AMR, in accordance with 10 CFR 54.4(a)(1). The nitrogen system piping (and
 
associated valve components) upstream of check valve 270 are within scope and subject to an
 
AMR, in accordance with 10 CFR 54.4(a)(2), with component types evaluated in the LRA. In
 
addition, the piping and valves connected to check valve 270 have an intended function to
 
maintain integrity to ensure that physical interaction with safety-related components cannot
 
prevent satisfactory accomplishment of a safety function due to structural support. Therefore, the hydrogen system should be within scope, as required by 10 CFR 54.4(a)(2). The applicant
 
revised the LRA to include the hydrogen system. The applicant stated that no additional
 
changes to the LRA were required due to other gas system interaction with safety-related
 
equipment. The staffs concern described in RAI 2.2B-2 is resolved. SER Section 2.3B.3.19 documents the staffs review of the IP3 hydrogen system that the applicant added to the scope
 
of license renewal. SER Section 3.3.2.1 documents the staffs evaluation of AMR results for the
 
IP3 hydrogen system.
2.2B.4  Conclusion The staff reviewed LRA Section 2.2, the RAI responses, and the UFSAR supporting information to determine whether the applicant failed to identify any systems and structures within the scope
 
of license renewal. The staff identified the omission of the hydrogen system, which the applicant
 
should have included within the scope of license renewal. The applicant has satisfactorily 2-34 resolved this issue as discussed in the preceding staff evaluation. Therefore, on the basis of its review, the staff concludes that the applicant has appropriately identified the mechanical
 
systems and structures within the scope of license renewal, as required by 10 CFR 54.4(a). 2.3  Scoping and Screening Results: Mechanical Systems SER Section 2.3A presents the scoping and screening results for IP2 mechanical systems; SER
 
Section 2.3B presents the scoping and screening results for IP3 mechanical systems.
This section documents the staffs review of the applicants scoping and screening results for mechanical systems. Specifically, this section discusses the following:  RCS engineered safety features  auxiliary systems  steam and power conversion systems In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must identify and list passive, long-lived mechanical SSCs that are within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff focused its
 
review on the implementation results. This focus allowed the staff to confirm that the applicant
 
had not omitted any mechanical system components that meet the scoping criteria and are
 
subject to an AMR.
The staffs evaluation of the information in the LRA was the same for all mechanical systems.
The objective was to determine whether the applicant had identified, as required by
 
10 CFR 54.4, components and supporting structures for mechanical systems that appear to
 
meet the license renewal scoping criteria. Similarly, the staff evaluated the applicants screening
 
results to verify that all passive, long-lived components were subject to an AMR, in accordance
 
with 10 CFR 54.21(a)(1).
In its scoping evaluation, the staff reviewed the applicable LRA sections and license renewal drawings, focusing on components that the applicant had not included within the scope of
 
license renewal. The staff reviewed relevant licensing basis documents, including the UFSAR, for each mechanical system to determine whether the applicant had omitted from the scope of
 
license renewal any components with license renewal intended functions, as defined in
 
10 CFR 54.4(a). The staff also reviewed the licensing basis documents to determine whether
 
the LRA specified all license renewal 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 applicants screening results. For those SCs with intended functions, the staff sought to determine whether (1) the functions are
 
performed with moving parts or a change in configuration or properties or (2) the SCs are
 
subject to replacement after a qualified life or specified time period, as described in
 
10 CFR 54.21(a)(1). For SCs that did not meet either of these criteria, the staff sought to
 
confirm that they 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.
2-35 Two-Tier Scoping Review Process for Balance of Plant Systems The scope of license renewal as documented in the LRA, includes 144 mechanical systems, among which 96 systems are balance of plant (BOP) systems. These 96 systems include most
 
of the auxiliary systems and all of the steam and power conversion systems. The staff
 
performed a two-tier scoping review for these BOP systems.
In the two-tier scoping review, the staff reviewed the LRA and UFSAR description, focusing on the system intended function, and divided all of the BOP systems into two groups, those that
 
required a simplified Tier 1 review and those that required a more detailed Tier 2 review. The
 
staff selected the systems for a detailed Tier 2 review based on the following screening criteria:  safety importance and risk significance - high safety-significant systems
- common-cause failure of redundant trains  operating experience indicating likely passive failures  previous LRA review experience Examples of systems that are typically selected for safety importance and risk significance, based on the individual plant examination results, are the component cooling water (CCW)
 
system, the auxiliary feedwater (AFW) system, and the SW system. An example of a system, whose failure could cause failure of redundant trains is a drain system for flood protection.
 
Examples of systems with operating experience that indicates the potential for passive failures
 
include the main steam (MS), feedwater (FW), and SW systems. Examples of systems with
 
omissions identified in previous LRA reviews include the spent fuel cooling system and makeup
 
water sources to safety systems. In addition, the staff ensured that a minimum of 50 percent of
 
the BOP systems received a Tier 2 review.
For systems receiving a simplified Tier 1 review, the staff reviewed the LRA and the UFSAR to determine whether the applicant failed to identify any component types typically found within the
 
scope of license renewal. SER Sections 2.3A.3 and 2.3B.3 identify the IP2 and IP3 BOP
 
systems, respectively, for which the staff conducted a simplified Tier 1 review. For all other BOP
 
systems, the staff performed a detailed Tier 2 review.
For systems receiving a detailed Tier 2 review, the staff reviewed the LRA, UFSAR, and the detailed boundary drawings to determine whether the applicant failed to identify any
 
components within the scope of license renewal and any components subject to an
 
AMR. During its review, the staff evaluated the system functions described in the LRA
 
and UFSAR to verify that the applicant did not omit from the scope of license renewal
 
any components with intended functions, as defined in 10 CFR 54.4(a). The staff then
 
reviewed those components that the applicant identified as within the scope of license
 
renewal to verify that the applicant had not omitted any passive and long-lived
 
components subject to an AMR, in accordance with 10 CFR 54.21(a)(1).
2-362.3A  IP2 Scoping and Screening Results: Mechanical Systems2.3A.1  Reactor Coolant System LRA Section 2.3.1 identifies the RCS SCs subject to an AMR for license renewal.
The RCS includes mechanical components in the following subsystems. reactor vessel  reactor vessel internals  steam generators (SGs)  RCPs pressurizer control rod drives  in-core instrumentation The applicant described the supporting SCs of the RCS in the following LRA sections:  2.3.1.1, Reactor Vessel  2.3.1.2, Reactor Vessel Internals  2.3.1.3, Reactor Coolant Pressure Boundary  2.3.1.4, Steam Generators LRA Section 2.3.1 describes the following RCS subsystems:
 
Reactor Vessel. The cylindrical reactor vessel has a hemispherical bottom and a flanged and gasketed removable upper head. The upper reactor closure head and the reactor vessel flange
 
are joined by studs. Two metallic O-rings seal the reactor vessel when the reactor closure head
 
is bolted in place. A leak-off connection between the two O-rings monitors leakage across the
 
inner O-ring. The vessel design is in accordance with ASME Code, Section III, Nuclear
 
Vessels. Coolant enters the reactor vessel through inlet nozzles in a plane just below the
 
vessel flange and above the core, flows downward through the annular space between the
 
vessel wall and the core barrel into a plenum at the bottom of the vessel, reverses direction, and
 
flows up through the core. After mixing in the upper plenum, the mixed coolant stream then
 
flows out of the vessel through exit nozzles on the same plane as the inlet nozzles. The core
 
instrumentation nozzles are on the lower head and the control rod nozzle penetrations are on
 
the upper head.
Reactor Vessel Internals. The reactor vessel internals direct the coolant flow, support the reactor core, and guide the control rods. The reactor vessel contains the core support
 
assembly, upper plenum assembly, fuel assemblies, control cluster assemblies, surveillance
 
specimens, and in-core instrumentation. The lower core support structure, the upper core
 
support structure, and the incore instrumentation support structure are the three major parts of
 
the reactor vessel internals. A one-piece thermal shield, concentric with the reactor core, is
 
located between the core barrel and the reactor vessel. The shield, cooled by the coolant on its
 
downward pass, protects the vessel by attenuating much of the gamma radiation and some of
 
the fast neutrons which escape from the core.
Pressurizer. System pressure is controlled by the pressurizer, which maintains water and steam pressure through the use of electrical heaters and sprays. Steam can either be formed by the 2-37 heaters or condensed by a pressurizer spray to minimize pressure variations caused by contraction and expansion of the coolant. Control and protective circuits such as the
 
high-pressure trip and code relief valves connected to the top head of the pressurizer protect
 
the RCS against overpressure. The relief valves discharge into the pressurizer relief tank, which
 
condenses and collects the valve effluent. Two power-operated relief valves (PORVs) and three
 
code safety valves protect against pressure surges beyond the pressure-limiting capacity of the
 
pressurizer spray. The PORVs also operate from the overpressure protection system to prevent
 
RCS pressure from exceeding the limits of ASME Code, Section III, Appendix G during
 
low-temperature operation. Steam and water discharge from the power relief and safety valves
 
passes to the pressurizer relief tank partially filled with water at or near ambient containment
 
conditions. The tank normally contains water in a predominantly nitrogen atmosphere. Steam
 
discharged under the water level condenses and cools by mixing with the water. Rupture discs
 
that discharge into the reactor containment protect the tank against a discharge exceeding the
 
design value. Steam Generators. Each reactor coolant loop has a vertical shell and U-tube steam generator (SG). Reactor coolant enters the inlet side of the channel head at the bottom of the SG through
 
the inlet nozzle, flows through the U-tubes to an outlet channel, and exits the generator through
 
another bottom nozzle. The inlet and outlet channels are separated by a partition. Feedwater to
 
the SG enters just above the top of the U-tubes through a feedwater ring. The water flows
 
downward through an annulus between the tube wrapper and the shell and then upward
 
through the tube bundle where it converts to a steam-water mixture that passes through a
 
primary separator assembly that reduces the water content in the mixture. The separated water
 
combines with the feedwater for another pass through the tube bundle. The remaining higher
 
steam-content mixture rises through additional secondary separators which further reduce the
 
water content. Reactor Coolant Pumps. Each reactor coolant loop has a vertical single-stage centrifugal pump with a controlled-leakage seal assembly. Reactor coolant pumped by the impeller attached to
 
the bottom of the rotor shaft and drawn up through the impeller discharges through passages in
 
the diffuser and out through a discharge nozzle in the side of the casing. A flywheel at the top of
 
the rotor shaft extends the pump coastdown flow during any loss of power to the pump motor. A
 
portion of the flow from the chemical and volume control system (CVCS) charging pumps is
 
injected into the RCP between the impeller and the controlled-leakage seal. Component cooling
 
water flows to the motor-bearing oil coolers and the thermal barrier cooling coil.
The RCS contains safety-related components relied on to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the RCS potentially could prevent the
 
satisfactory accomplishment of a safety-related function. In addition, the RCS performs
 
functions that support fire protection, PTS, ATWS, and SBO.
Control Rod Drives. The control rod drive system positions the control rods within the core. The reactor uses the Westinghouse magnetic-type control rod drive assemblies on the upper reactor
 
vessel head to insert or withdraw control rods in the core to control generation of nuclear power.
 
The movement of the control rods is accomplished through the sequential operation of three
 
types of magnetic coils. Upon a loss of power to the coils, the released rod cluster control
 
assemblies with full-length absorber rods fall by gravity into the core. Each control rod drive
 
assembly is a hermetically-sealed unit to prevent leakage of reactor coolant. The design of all
 
pressure-containing components meets ASME Code, Section III, Division 1 requirements for
 
Class A vessels.
2-38 The control rod drive system contains safety-related components relied upon to remain functional during and following DBEs. In-Core Instrumentation. The in-core instrumentation system provides information on the neutron flux distribution and fuel assembly outlet temperatures at selected core locations to
 
confirm reactor core design parameters and calculated hot channel factors. The system
 
acquires data and performs no plant operation. The system consists of thermocouples
 
positioned to measure fuel assembly coolant outlet temperature at preselected locations, flux
 
thimbles running the length of selected fuel assemblies to measure the neutron flux distribution
 
within the reactor core by moveable in-core detectors, in-core drives, drive motors, positioning
 
equipment, and instruments. The flux thimbles, seal table, and guide tube form part of the
 
RCPB. The in-core instrumentation system includes the pressure-retaining guide tubes that form parts of the RCPB. For IP2, the RCS and the nuclear instrumentation system include other, nonpressure boundary portions of the in-core instrumentation (listed in LRA Table 2.2-1b-IP2
 
with the electrical and I&C systems).
The in-core instrumentation system contains safety-related components relied upon to remain functional during and following DBEs.
The RCS Class I piping evaluation boundary extends into portions of systems attached to the RCS. For both units, the RCS AMR includes the Class I components of the systems listed
 
below. The LRA section referenced below includes the non-Class 1 portions of the following
 
systems:  CVCS (LRA Section 2.3.3.6)  isolation valve seal water (LRA Section 2.3.2.3)  primary sampling system (LRA Section 2.3.3.19)  residual heat removal (RHR) (LRA Section 2.3.2.1)  safety injection system (LRA Section 2.3.2.4)
IP2 RCS components containing air are evaluated with compressed air systems (LRA Section 2.3.3.4). A small number of IP2 RCS components are evaluated with the primary water
 
makeup systems (LRA Section 2.3.3.7) and the nitrogen systems (LRA Section 2.3.3.5). IP2 RCP lube oil collection system components are part of the IP2 fire protection system, not the
 
RCS. IP2 RCS containment penetration components, which are not part of the RCPB, are
 
evaluated with containment penetrations (LRA Section 2.3.2.5).
Fuel assemblies are not subject to an AMR because they are replaced after a limited number of fuel cycles. The control rods are active components and are not subject to an AMR.
SER Sections 2.3A.1.1-2.3A.1.4 discuss the staffs findings based on its review of LRA Sections 2.3.1.1-2.3.1.4, respectively.
2.3A.1.1 Reactor Vessel 2.3A.1.1.1  Summary of Technical Information in the Application LRA Section 2.3.1.1 describes the reactor vessel, stating that the evaluation boundary for the reactor vessel encompasses the reactor vessel pressure boundary subcomponents, which 2-39 include the shell, top and bottom heads, closure head stud assembly, primary nozzles and safe-ends, control rod drive mechanism (CRDM) housing penetrations, bottom-mounted
 
instrumentation flux thimble tube penetrations, guide tubes, and seal table. LRA Section 2.3.1.1
 
also describes other subcomponents that support the intended functions of the reactor vessel, including the core support pads and core guide lugs, vessel flange, and closure head lifting
 
lugs.LRA Section 2.3.1 describes the functions of the reactor vessel. LRA Tables 2.3.1-1-IP2 and 2.3.1-1-IP3 identify reactor vessel component types within the scope of license renewal and
 
subject to an AMR, as well as their intended functions.
2.3A.1.1.2  Staff Evaluation The staff reviewed LRA Section 2.3.1.1 and the UFSARs 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 had not omitted from the scope of license renewal any components with
 
intended functions, as require by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3A.1.1.3  Conclusion
 
The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In addition, the
 
staff sought to determine whether the applicant failed to identify any components subject to an
 
AMR. The staff found no such omissions. On the basis of its review, the staff concludes that the
 
applicant has adequately identified the reactor vessel components within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3A.1.2  Reactor Vessel Internals 2.3A.1.2.1  Summary of Technical Information in the Application LRA Section 2.3.1.2 describes the reactor vessel internals. For both units, the lower core support structure, the upper core support structure, and the incore instrumentation support
 
structure are the three major parts of the reactor internals.
The lower core support structure is supported at its upper flange from a ledge in the reactor vessel. Within the core barrel are a core baffle and a lower core plate, both of which are
 
attached to the core barrel wall. The lower core support structure provides passageways for the
 
coolant flow. The lower core plate at the bottom of the core below the baffle plates provides
 
support and orientation for the fuel assemblies. Fuel alignment pins (two for each assembly) are
 
also inserted into this plate. Columns are placed between the lower core plate and core support
 
casting to provide stiffness and to transmit the core load to the core support casting. Adequate
 
coolant distribution is obtained through the use of the lower core plate and a diffuser plate.
2-40 The support columns establish the spacing between the upper support assembly and the upper core plate and are fastened at top and bottom to these plates and beams.
The rod cluster control assembly guide tube assemblies shield and guide the control rod drive shafts and control rods. They are fastened to the upper support and are guided by pins in the
 
upper core plate for proper orientation and support. The control rod shroud tube, which is
 
attached to the upper support plate and guide tube, provides additional guidance for the control
 
rod drive shafts.
An upper system (thermocouple conduit) is used to convey and support thermocouples penetrating the vessel through the head, and a lower system (flux thimble guide tube) is used to
 
convey and support flux thimbles penetrating the vessel through the bottom. The upper system
 
utilizes the reactor vessel head penetrations. Instrumentation port columns are slip-connected
 
to in-line columns that are in turn fastened to the upper support plate. These port columns
 
protrude through the head penetrations. The thermocouples are carried through these port
 
columns and the upper support plate at positions above their readout locations. The columns of
 
the upper core support system support the thermocouple conduits.
LRA Section 2.3.1 describes the functions of the reactor vessel internals. LRA Tables 2.3.1-2-IP2 and 2.3.1-2-IP3 identify reactor vessel internals component types within the
 
scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.1.2.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.1.2 and the UFSAR using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review, the staff identified an area in which additional information was necessary to complete its review. The applicant responded to the staffs RAI as discussed below.
In RAI 2.3A.1.2-1, dated January 28, 2008, the staff noted that if certain reactor vessel internals failed, they could potentially inhibit core coolability during an accident. Therefore, the staff
 
requested that the applicant clarify whether the sample tubing and sample tubing springs are
 
within the scope of license renewal.
In its response, dated February 27, 2008, the applicant stated that it had evaluated the sample tubing (also known as the irradiation specimen guide) and the sample tubing springs (also
 
known as the specimen plugs). The review included consideration of component functions and
 
the potential impact of component failure on the function of other components. The applicant
 
stated that sample tubing and the sample tubing springs have no license renewal intended
 
function and are not subject to an AMR. Additionally, the applicant stated that it had reviewed
 
Westinghouse Commercial Atomic Power (WCAP)-14577 Rev 1-A, License Renewal
 
Evaluation: Aging Management for Reactor Internals. Section 3.1 of the staffs SER, which 2-41 evaluated WCAP-14577 states, [t]he staff found the list of intended functions to be complete and in accordance with 10 CFR 54.4(a). Section 2.1.1 of the same SER details the list of
 
functions and states, Prevent failure of all nonsafety-related systems, structures, and
 
components whose failure could prevent any of these (previously listed) functions.
 
WCAP-14577A, Table 2-2, confirms the applicants conclusion that no AMR is required for the
 
sample tubing and the sample tubing springs because the components do not have a license
 
renewal function. Therefore, the staff finds the applicants response acceptable. The staffs
 
concern described in RAI 2.3A.1.2-1 is resolved.
2.3A.1.2.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and RAI response to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such
 
omissions. In addition, the staff sought to determine whether the applicant failed to identify any
 
components subject to an AMR. The staff found no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the reactor vessel internals
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3A.1.3  Reactor Coolant Pressure Boundary 2.3A.1.3.1  Summary of Technical Information in the Application LRA Section 2.3.1.3 describes the RCPB, which includes the pressurizer, RCPs, interconnecting piping and fittings, system valves, component bolting, and piping and valves
 
from connected systems. The RCPB includes multiple components from interconnecting
 
systems, since their safety function is to maintain the RCS pressure boundary integrity. RCPB
 
piping consists of the primary loops to and from the reactor pressure vessel, SG, and RCPs.
 
The main reactor coolant piping and fittings are austenitic stainless steel.
Smaller piping, including the pressurizer surge and spray lines, drains, and connections to other systems, is austenitic stainless steel. Piping connections are welded except for flanged
 
connections at the pressurizer relief tank and at the relief and safety valves. LRA
 
Section 2.3.1.3 provides a listing of the lines comprising the RCPB.
LRA Section 2.3.1 describes the functions of the RCPB.
 
LRA Tables 2.3.1-3-IP2, 2.3.3-19-30-IP2, 2.3.1-3-IP3, 2.3.3-19-43-IP3, 2.3.3-19-44-IP3, and 2.3.3-19-46-IP3 identify RCPB component types within the scope of license renewal and subject
 
to an AMR, as well as their intended functions.
2.3A.1.3.2  Staff Evaluation The staff reviewed LRA Section 2.3.1.3, the UFSARs, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that the applicant 2-42 had not omitted any passive and long-lived components subject to an AMR, in accordance with 10 CFR 54.21(a)(1).
During its review, the staff identified areas in which additional information was necessary to complete its review. The applicant responded to the staffs RAIs as discussed below.
In RAI 2.3A.1.3-1, dated November 9, 2007, the staff noted that License renewal drawing LRA-9321-2738, Sheet 1, depicts the RCPB for IP2. The staff was uncertain as to whether
 
additional drawings depicting the RCPB existed. Therefore, the staff asked the applicant to
 
clarify whether there were any additional sheets depicting the RCPB, and if so, to provide the
 
drawings to the staff.
In its response, dated December 6, 2007, the applicant stated that License renewal drawing LRA-9321-2738 consisted of only one sheet, and the drawing, which identifies the
 
major components in the RCS for IP2, includes the reactor vessel, pressurizer, RCPs, and SGs.
 
The other License renewal drawings listed on page 2.3-20 of the LRA depict the remaining
 
RCPB components for IP2 and IP3 that are in scope and subject to an AMR. License renewal
 
drawing LRA-9321-2738 shows the continuations of lines to the other drawings depicting
 
portions of the RCPB.
Based on its review, the staff finds the applicants response acceptable because it clarified which drawings depict the components of the RCBP that are in scope and subject to an AMR.
 
The response also confirmed that there were no additional drawings required staff review.
 
Therefore the staffs concern in RAI 2.3A.1.3-1 is resolved.
In RAI 2.3A.1.3-2, dated January 28, 2008, the staff requested that the applicant clarify whether the pressurizer manways are within the scope of license renewal and subject to an AMR. LRA
 
Tables 2.3.1-3-IP2 and 2.3.1-3-IP3 identified the pressurizer manway covers and insert plates
 
as within the scope of license renewal and subject to an AMR.
 
.
In its response, dated February 27, 2008, the applicant stated that the pressurizer manway is a
 
ring, integral to the shell of the pressurizer. The manway is part of the pressurizer shell included
 
within the "pressurizer shell and heads" entries in LRA Tables 2.3.1-3-IP2 and 2.3.1-3-IP3. All
 
portions of the manway assembly (i.e., the manway cover, the manway insert plate, and the
 
pressurizer shell including the manway itself) are within the scope of license renewal and
 
subject to AMR. Because the applicant clarified that this component is already within the scope
 
of license renewal, the staff finds the applicants response acceptable. The staffs concern
 
described in RAI 2.3A.1.3-2 is resolved.
In RAI 2.3A.1.3-3, dated January 28, 2008, the staff requested that the applicant provide additional information and, if necessary, justify the exclusion of the vents associated with the
 
level sensors, as shown on license renewal drawing LRA-208798-0. The applicant did not
 
highlight the level sensor vents in the reactor vessel level indication system as components that
 
are subject to an AMR. The sensor vents appear to provide an RCPB.
In its response, dated February 27, 2008, the applicant stated that the level elements on drawing LRA-208798, LE-1311, LE-1312, LE-1321 and LE-1322, are pressure transmitters. The
 
vents are part of the transmitter body. In accordance with 10 CFR 54.21(a)(1)(i) and NEI 95-10, pressure transmitters are active components that are not subject to an AMR. Normal operational
 
and surveillance activities readily monitor the performance or condition of active components.
2-43 Because this component is part of an active component and is monitored through normal operational activities, the staff finds the applicants response acceptable. The staffs concern
 
described in RAI 2.3A.1.3-3 is resolved.
In RAI 2.3.0-2, dated February 13, 2008, the staff noted that on license renewal drawings for the IP2 and IP3 RCP motors, various components of the upper and lower bearing heat exchangers
 
were marked Not A Long Lived Component, and thus, were not subject to an AMR.
 
Additionally, the staff noted that license renewal drawings of the IP2 and IP3 emergency diesel
 
generator (EDG) jacket water cooling systems also have components marked Not A Long
 
Lived Component. The staff noted that SRP-LR Section 2.1.3.2.2 describes long-lived SCs as
 
those that are not subject to periodic replacement based on a qualified life or specified time
 
period. Furthermore, this section states that replacement programs may be based on vendor
 
recommendations, plant experience, or any means that establishes a specific replacement
 
frequency under a controlled program.
Because the staff identified that previous LRAs typically have not designated pumps, motors, and heat exchangers as not long lived (i.e., these components, or portions thereof, are subject
 
to an AMR), the staff requested the applicant to: (a) Identify the component types serviced by the CCW system indicated in the above mentioned drawings that are marked Not A Long Lived Component. (b) Provide a basis for designating these components as not long lived to include details on how the qualified life of the components was established and describe the program
 
under which aging management activities for the components are performed and any
 
available plant-specific operating experience confirming the effectiveness of
 
management activities.
In its response, dated March 12, 2008, the applicant addressed the staffs concerns for the component types serviced by the CCW system. The applicant stated that it reviewed the
 
documentation specifying the RCP motor upper and lower bearing heat exchangers as short
 
lived and determined that they are actually not subject to periodic replacement. The applicant
 
stated that the RCP motor upper and lower bearing heat exchangers are therefore subject to an
 
AMR. Additionally, in its response, the applicant proposed changes to LRA Section 3.3.2.1.3
 
and LRA Tables 3.3.2-3-IP2 and 3.3.2-3-IP3 for the CCW system to include the aforementioned
 
heat exchangers with their materials, environments, and aging management programs (AMPs).
 
SER Section 3.3.2.1 documents the staffs review of the AMR line items. SER Sections
 
2.3A.3.14 and 2.3B.3.14 document the staffs evaluation of the applicants response for the
 
EDG jacket water cooling system.
Based on its review, the staff finds the applicants response to RAI 2.3.0-2 acceptable for the RCS because it adequately explained that the RCP motor upper and lower bearing cooler heat
 
exchangers in the CCW system were erroneously designated Not A Long-Lived Component
 
and are, therefore, subject to an AMR. Further, in its March 12, 2008, letter, the applicant
 
amended the LRA to include the heat exchangers and their AMP. Therefore, the staffs concern
 
described in RAI 2.3.0-2 is resolved.
2.3A.1.3.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no 2-44 such omissions. In addition, the staff sought to determine whether the applicant failed to identify any components subject to an AMR. The staff found an instance in which the applicant omitted
 
components that should have been subject to an AMR. The applicant has satisfactorily resolved
 
this issue as discussed in the preceding staff evaluation. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the RCPB components within the scope
 
of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3A.1.4  Steam Generators 2.3A.1.4.1  Summary of Technical Information in the Application The SGs are designed and manufactured in accordance with ASME Code, Section III. The IP2 SGs were constructed in accordance with the 1980 Edition, through the Winter 1981 Addenda, of the ASME Code. The IP3 SGs were constructed consistent with the 1983 Edition, through the
 
Summer 1984 Addenda, of the ASME Code. The SGs are constructed primarily of carbon (low
 
alloy) steel. The heat transfer tubes are Inconel: Alloy 600 for IP2 and Alloy 690 for IP3. The
 
tubes were thermally treated after tube-forming operations. The interior surfaces of the channel
 
heads and nozzles are clad with austenitic stainless steel, and the tubesheet surfaces in contact
 
with reactor coolant are clad with Inconel. The tube-to-tubesheet joints are welded. The primary
 
nozzles are provided with safe-ends with weld metal overlay.
LRA Section 2.3.1 describes the functions of the SGs. LRA Tables 2.3.1-4-IP2 and 2.3.1-4-IP3 identify SG component types within the scope of license renewal and subject to an AMR, as well
 
as their intended functions.
LRA Section 2.3.1 describes the functions of the SGs. LRA Tables 2.3.1-4-IP2 and 2.3.1-4-IP3 identify SG component types within the scope of license renewal and subject to an AMR, as well
 
as their intended functions.
2.3A.1.4.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.1.4, the UFSARs, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
10 CFR 54.21(a)(1).
2.3A.1.4.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff determined whether the applicant failed to identify any components subject to
 
an AMR. The staff found no such omissions. On the basis of its review, the staff concludes that
 
the applicant has adequately identified the SG components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 2-45 10 CFR 54.21(a)(1). 2.3A.2  Engineered Safety Features LRA Section 2.3.2 identifies the engineered safety features SCs subject to an AMR for license renewal.The applicant described the supporting SCs of the engineered safety features in the following LRA sections:  2.3.2.1, Residual Heat Removal  2.3.2.2, Containment Spray System  2.3.2.3, Containment Isolation Support Systems  2.3.2.4, Safety Injection Systems  2.3.2.5, Containment Penetrations SER Sections 2.3A.2.1-2.3A.2.5 discuss the findings of the staffs review of LRA Sections 2.3.2.1-2.3.2.5, respectively.
2.3A.2.1  IP2 Residual Heat Removal 2.3A.2.1.1  Summary of Technical Information in the Application LRA Section 2.3.2.1 describes the RHR system, which provides emergency core cooling, as part of the safety injection system, and removes residual heat during later stages of plant
 
cooldown. The RHR system is one of three (RHR, CCW, and spent fuel pit cooling (SFPC))
 
auxiliary coolant systems. The RHR system consists of two RHR heat exchangers, two seal
 
coolers, two RHR (low-head) pumps, and required piping, valves, and I&C components. The
 
RHR system provides emergency core cooling during the injection phase of a loss-of-coolant
 
accident (LOCA). The RHR heat exchangers, in conjunction with the safety injection
 
recirculation pumps, are used for post-accident heat removal during the LOCA recirculation
 
phase. Outlet flow from the RHR heat exchangers may be directed to the containment spray (CS) headers, to the RCS cold legs, or to the RCS hot legs via the high-head safety injection
 
pumps. The RHR pumps also back up the safety injection system recirculation pumps during a
 
LOCA recirculation phase. In this capacity, the RHR pumps may draw water from the
 
containment sump and deliver it to the RCS cold leg injection lines, to the suction of the
 
high-head safety injection pumps, or to the CS headers. The RHR system removes residual
 
heat during the later stages of plant cooldown and during cold shutdown and refueling
 
operations. After RCS temperature and pressure have been reduced to 350 degrees F and less
 
than 365 pounds per square inch gauge (psig), alignment of the RHR pumps initiates decay
 
heat cooling by taking suction from one reactor hot leg and discharging it through the RHR heat
 
exchangers into the reactor cold legs.
The RHR system contains safety-related components relied on to remain functional during and following DBEs. In addition, the RHR system performs functions that support fire protection and
 
SBO.In the LRA, ASME Code Class 1 components with the intended function of maintaining the RCPB are reviewed with the RCS (LRA Section 2.3.1). A small number of components are
 
reviewed with the safety injection system in LRA Section 2.3.2.4.
2-46 LRA Table 2.3.2-1-IP2 identifies RHR system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.2.1.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.1, the UFSAR, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR in accordance with
 
10 CFR 54.21(a)(1).
2.3A.2.1.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the RHR system components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3A.2.2  IP2 Containment Spray System 2.3A.2.2.1  Summary of Technical Information in the Application LRA Section 2.3.2.2 describes the CS system, which cools the containment and removes iodine following an accident. The CS system consists of two trains of pumps, valves, and headers that
 
automatically start and spray refueling water storage tank (RWST) borated water into the
 
containment atmosphere when the system senses high containment pressure following a LOCA
 
or MS line break accident. The spray water enters through nozzles connected to four ring
 
headers in the containment dome. Each spray pump supplies two ring headers. After injection
 
from the RWST is terminated, the system can supply the spray headers with recirculated water
 
from the recirculation sump or the containment sump by a diversion of a portion of the injection
 
flow from the safety injection system. Long-term, post-accident retention of iodine is achieved by
 
four sodium tetraborate baskets in the containment at an elevation (46 feet) that will be flooded
 
under accident conditions, allowing the sodium tetraborate to dissolve into the fluid for pH
 
control. The containment structural evaluation includes the four sodium tetraborate baskets, but
 
they are not described further because they have no license renewal intended function and are
 
therefore not subject to an AMR.
The CS system contains safety-related components relied on to remain functional during and following DBEs.
Containment spray system components that support the RHR system pressure boundary are reviewed in the RHR systems (LRA Section 2.3.2.1). A small number of components are 2-47 reviewed in the safety injection system (LRA Section 2.3.2.4).
LRA Table 2.3.2-2-IP2 and newly created Table 2.3.3-19-46-IP2 (see evaluation below) identify CS system component types within the scope of license renewal and subject to an AMR, as well
 
as their intended functions.
2.3A.2.2.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.2, UFSAR Section 6.3, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.2.2, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening
 
results.During its review of license renewal drawings for the containment spray system, the staff identified portions of piping of the CS system that were not highlighted, indicating that section of
 
piping had no intended functions in accordance with 10 CFR 54.4 (a)(1) or 10 CFR 54.4 (a)(3).
 
LRA Section 2.3.2.2 states that the CS system has no intended function for 10 CFR 54.4(a)(2).
 
However, this section of piping is directly connected to safety-related containment spray piping;
 
therefore, the staff determined that it should be in scope for 10 CFR 54.4(a)(2) for nonsafety-
 
related piping that is structurally attached to safety-related piping. In RAI 2.3A.2.2-1, dated
 
February 13, 2008, the staff asked the applicant to explain this discrepancy. The staff also
 
asked the applicant to indicate any portions of the CS system evaluated for inclusion in the
 
scope of license renewal in accordance with 10 CFR 54.4(a)(2), and to identify any other
 
instances whereby a system was identified as not having any 10 CFR 54.4(a)(2) function but did
 
have nonsafety-related components that were not identified as within scope for
 
10 CFR 54.4(a)(2).
In its response, dated March 12, 2008, the applicant stated that the components identified by the staff do have an intended function to maintain integrity such that no physical interaction with
 
safety-related components could prevent satisfactory accomplishment of a safety function.
 
Hence, the applicant amended the LRA to include the portions of the CS system within the
 
scope of license renewal under the requirements of 10 CFR 54.4(a)(2). The applicant
 
responded to the staffs request by performing a re-evaluation of those safety-related systems
 
that were identified in the LRA as only being in scope for (a)(1) and have no (a)(2) components.
 
The applicants re-examination identified three instances where a system that performs a safety
 
function was in scope for 10 CFR 54.4(a)(1), but nonsafety-related components were not
 
identified as in scope for 10 CFR 54.4(a)(2). The staffs evaluation of the affected systems is
 
discussed in SER Sections 2.3A.3.3, 2.3B.2.5, and 2.3B.3.3. For the IP2 CS system, in its letter
 
dated March 12, 2008, the applicant amended the LRA to reflect the following changes:
2-48(a) LRA Table 2.3.3-19-A-IP2 would reflect the CS system as a miscellaneous system within the scope of license renewal for 10 CFR 54.4(a)(2). (b) Removal of the CS system from the list of IP2 systems not reviewed for 10 CFR 54.4(a)(2) for spatial interaction. (c) Revision of LRA Table 2.3.3-19-B-IP2 to reflect that the CS system now has components subject to an AMR for 10 CFR 54.4(a)(2). (d) Creation of a new LRA Table 2.3.3-19-46-IP2 for the five added component types in the CS system for nonsafety-related components potentially affecting a safety function, and
 
subject to an AMR. (e) Creation of a new LRA Table 3.3.2-19-46-IP2 for the five added component types, their materials, environments, and AMPs.
Based on its review, the staff finds the applicants response to RAI 2.3A.2.2-1 for the IP2 CS system acceptable because it adequately explained that the applicants reevaluation of safety-
 
related systems identified components that should have been within scope under
 
10 CFR 54.4(a)(2). Additionally, the applicant amended the LRA to include those portions of the
 
CS system identified by the staff as being in scope under 10 CFR 54.4(a)(2). The staff reviewed
 
the applicants changes to the LRA tables and found that they adequately reflect those
 
components brought into the scope of license renewal, in accordance with 10 CFR 54.4(a)(2),
because of their potential for spatial interaction with safety-related components. Therefore, the
 
staffs concern described in RAI 2.3A.2.2-1 for the CS system is resolved. SER Section 3.2.2.1
 
documents the staffs evaluation of new AMR results for the CS system.
2.3A.2.2.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found one instance in which the applicant omitted
 
components that should have been subject to an AMR. The applicant has satisfactorily resolved
 
this issue as discussed in the preceding staff evaluation. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the CS system components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3A.2.3  IP2 Containment Isolation Support Systems 2.3A.2.3.1  Summary of Technical Information in the Application LRA Section 2.3.2.3 describes the containment isolation support systems, which include the isolation valve seal water systems and the weld channel and penetration pressurization system.
 
The containment isolation support systems consist of piping and valves routed to the various
 
system piping that penetrates the containment. The isolation valve seal water, weld channel, and penetration pressurization systems isolate the containment from the outside environment
 
for various systems with piping penetrating containment. The containment isolation support
 
systems inject fluid or air or gas into system lines between the containment isolation valves that
 
penetrate the containment for pressure boundary integrity against leakage of radioactive fluids
 
to the environment in the event of a LOCA. Individual lines define these barriers of piping and 2-49 isolation valves systems. Besides satisfying containment isolation criteria, the valving facilitates normal operation and maintenance of the systems for reliable operation of other engineered
 
safeguard systems.
The isolation valve seal water system provides sealing water or gas between the isolation and double-disk isolation valves of containment penetrations located in lines connected to the RCS
 
or exposed to the containment atmosphere during any condition that requires containment
 
isolation. This system limits fission product release from the containment. Although not credited
 
in post-accident dose analyses, the system ensures a containment leak rate in an accident
 
lower than that assumed in the accident analysis and the offsite dose calculations. System
 
components form parts of the containment penetration isolation boundary.
The weld channel and penetration pressurization system provides pressurized gas to all containment penetrations and most liner inner weld seams in the event of a LOCA, so there will
 
be no leakage through these potential paths from the containment to the atmosphere. The weld
 
channel and penetration pressurization system also serves spaces between selected isolation
 
valves. Although not credited in the post-accident dose analyses, the weld channel and
 
penetration pressurization system maintained at a pressure level above the peak accident
 
pressure is designed to keep any postulated leakage in rather than out of the containment. The
 
system supplies regulated clean, dry compressed air from either of the plants compressed air
 
systems outside the containment to all containment penetrations and most inner liner weld
 
channels. The instrument air system, backed up by the station air system and by a bank of
 
nitrogen cylinders as a standby source of gas pressure, is the primary source of air for this
 
system. The containment isolation support systems contain safety-related components relied upon to remain functional during and following DBEs.
Isolation valve seal water system components with the intended function of maintaining the RCPB are reviewed in the RCS (LRA Section 2.3.1.3).
LRA Table 2.3.2-3-IP2 identifies containment isolation support systems component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.2.3.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.3, UFSAR Sections 6.5.1, 6.6.2, and 14.3.6.1, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening results.
2-50 In RAI 2.3A.2.3-1, dated November 9, 2007, the staff identified several line-mounted components (valves PRV PCV 1193 through PRV PCV 1200) that were located in lines with a
 
pressure boundary function. However, the applicant had not identified the components
 
themselves as being subject to an AMR. Therefore, the staff requested that the applicant clarify
 
whether these components are subject to an AMR or justify their exclusion.
In its response, dated December 6, 2007, the applicant stated that the valves in question are within the scope of license renewal and subject to an AMR. Furthermore, the applicant noted that LRA Table 2.3.2-3-IP2 identified these valves as component type valve body, with AMR
 
results summarized in LRA Table 3.2.2-3-IP2. Some of the valves in question have aluminum
 
valve bodies with internal and external environments of gas (internal) and airindoor (external).
 
The applicant added a line item of valve body to LRA Table 3.2.2-3-IP2 to reflect the aluminum
 
material.Based on its review, the staff finds the applicants response to RAI 2.3A.2.3-1 acceptable because the applicant clarified that the subject valves are within the scope of license renewal
 
and subject to an AMR and added aluminum valve bodies to the AMR. The staffs concern
 
described in RAI 2.3A.2.3-1 is resolved. SER Section 3.2.2.1 discusses the staffs evaluation of
 
the added AMR for aluminum valve bodies.
By letter dated June 30, 2009, the applicant submitted an annual update to the LRA, identifying changes made to the CLB that materially affect the contents of the LRA. For the containment
 
isolation support system, the applicant identified buried piping in the containment isolation
 
support system that had not been previously identified as being within the scope of license
 
renewal . The piping is part of the air pressure supply that feeds Rack 15 for the steam and
 
feedwater penetrations shown on license renewal drawing LRA-9321-2726-0. The staff
 
reviewed the amendment and finds the addition to the scope to be acceptable. The staffs
 
evaluation of the corresponding AMR results is documented in SER Section 3.2.2.1.
2.3A.2.3.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found one instance in which the applicant omitted
 
components that should have been subject to an AMR. The applicant has satisfactorily resolved
 
this issue as discussed in the preceding staff evaluation. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the containment isolation support
 
systems components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3A.2.4  IP2 Safety Injection System 2.3A.2.4.1  Summary of Technical Information in the Application LRA Section 2.3.2.4 describes the safety injection system, which, in a LOCA, automatically delivers cooling water to the reactor core to limit the fuel clad temperature so the core remains
 
intact and in place with its essential heat transfer geometry preserved. Components comprising
 
the safety injection system code (i.e., the applicants code for designating systems and
 
boundaries) include the RWST, the three safety injection (high-head) pumps, the accumulators 2-51 (one for each reactor coolant loop), recirculation pumps and piping, valves, and other components of these subsystems. The three safety injection (high-head) pumps inject RWST
 
borated water into the RCS for core cooling. The safety injection signal automatically opens the
 
required safety injection system isolation valves and starts the safety injection pumps. The
 
injection piping and valves connect the accumulators containing borated water and pressurized
 
with nitrogen to the RCS. Two check valves isolate these tanks from the RCS during normal
 
operation. When RCS pressure falls below accumulator pressure the check valves open, discharging the tank contents into the RCS through the same injection piping used by the safety
 
injection pumps.
After the injection, the recirculation system cools and returns to the RCS any coolant spilled from the break and water collected from the CS. The system recirculation pumps take suction
 
from the recirculation sump in the containment floor and deliver spilled reactor coolant and
 
borated refueling water back to the core through the RHR heat exchangers. For smaller RCS
 
breaks in which recirculated water must be injected against higher pressures for long-term
 
cooling, the system delivers the water from an RHR heat exchanger to the high-head safety
 
injection pump suction and, by this external recirculation route, to the reactor coolant loops. The
 
system also allows either of the RHR pumps to take over the recirculation function.
The safety injection system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure
 
potentially could prevent the satisfactory accomplishment of a safety-related function. In
 
addition, the safety injection system performs functions that support fire protection.
ASME Code Class 1 components with the intended function of maintaining the RCPB are reviewed in the RCS (LRA Section 2.3.1.3). A small number of components are reviewed in the
 
containment system (LRA Section 2.3.2.2), RHR systems (LRA Section 2.3.2.1), and nitrogen
 
systems (LRA Section 2.3.3.5).
LRA Tables 2.3.2-4-IP2 and 2.3.3-19-37-IP2 identify safety injection system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.2.4.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.4, the UFSAR, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3A.2.4.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff 2-52 concludes that the applicant has adequately identified the safety injection system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an
 
AMR, as required by 10 CFR 54.21(a)(1).
2.3A.2.5  IP2 Containment Penetrations 2.3A.2.5.1  Summary of Technical Information in the Application LRA Section 2.3.2.5 describes the following containment penetrations, which are not an independent system but a grouping of containment penetration components that are not
 
evaluated with other systems:  electrical penetrations  fuel core component handling system  hydrogen recombiners The electrical penetrations pass electrical conductors through the containment boundary. The electrical penetrations system code (i.e., the applicants code for designating systems and
 
boundaries) is primarily structural and electrical components that are evaluated in the structural
 
and electrical AMRs; however, the system has mechanical components which are evaluated in
 
this section. The penetrations have a pressure connection for continuous pressurization by the
 
weld channel system, which is considered part of the containment isolation boundary.
The fuel core component handling system defuels and refuels the reactor core. The fuel handling system transports and handles fuel safely and effectively. Most system components
 
(e.g., fuel handling bridges) are structural and evaluated with their respective structures. The fuel transfer tube and blind flange are fuel core component handling system components that
 
together constitute a containment penetration.
The hydrogen recombiners system, which reduces the hydrogen concentration in the containment volume following a DBA, has two redundant passive autocatalytic recombiners that
 
replaced earlier flame units. The recombiners are passive devices with no moving parts and
 
need no electrical power or any other support system. Recombination is by attraction of oxygen
 
and hydrogen molecules to the surface of a palladium catalyst. The exothermic reaction of the
 
combination generates heat, which causes a convective flow that draws more gases from the
 
containment atmosphere into the unit. Since a recent license amendment (Amendment
 
No. 243), hydrogen recombination is no longer required as a safety function. The system
 
includes containment penetrations from the original flame hydrogen recombiners.
The containment penetrations contain safety-related components relied on to remain functional during and following DBEs.
Containment penetration components evaluated in this section maintain the system pressure boundary inside containment from the first weld from the penetration to the class boundary
 
change outside containment. Components in the Class 1 boundary are reviewed in the RCPB (LRA Section 2.3.1.3). Structural portions of the containment penetrations are evaluated with
 
the containment building (LRA Section 2.4.1). Electrical portions of electrical penetration
 
assemblies are evaluated with electrical components (LRA Section 2.5).
2-53 LRA Table 2.3.2-5-IP2 identifies containment penetrations component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.2.5.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.2.5; UFSAR Sections 5.1.4, 5.1.4.2.1, 6.8, and 9.5.2; and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3A.2.5, the staff identified an area in which additional information was necessary to complete the review of the results of the applicants scoping and
 
screening effort. The applicant responded to the staffs RAI as discussed below.
In RAI 2.3A.2.5-1, dated November 9, 2007, the staff noted that a drawing referenced for IP2 appeared to be applicable to IP3. Therefore, the staff requested that the applicant confirm the
 
accuracy of the referenced drawings.
In its response, dated December 6, 2007, the applicant stated that an administrative error occurred when transferring the License renewal drawing numbers from the site basis document
 
to the License renewal drawing list. Additionally, the applicant identified the drawings that
 
corresponded to the respective units.
Based on its review, the staff found the applicants response to RAI 2.3A.2.5-1 acceptable because the applicant identified and corrected an administrative error. Subsequently, the staff
 
reviewed and evaluated the components associated with the containment penetrations on the
 
referenced drawings and found no omissions from the scope of license renewal. The staffs
 
concern described in RAI 2.3A.2.5-1 is resolved.
2.3A.2.5.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its
 
review, the staff concludes that the applicant has adequately identified the containment
 
penetrations components within the scope of license renewal, as required by 10 CFR 54.4(a),
and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-542.3A.3  Scoping and Screening Results: IP2 Auxiliary Systems LRA Section 2.3.3 identifies the auxiliary systems SCs subject to an AMR for license renewal.
The applicant described the supporting SCs of the auxiliary systems in the following LRA sections: 2.3.3.1, Spent Fuel Pit Cooling  2.3.3.2, Service Water  2.3.3.3, Component Cooling Water  2.3.3.4, Compressed Air  2.3.3.5, Nitrogen Systems  2.3.3.6, Chemical and Volume Control  2.3.3.7, Primary Water Makeup  2.3.3.8, Heating, Ventilation and Air Conditioning  2.3.3.9, Containment Cooling and Filtration  2.3.3.10, Control Room Heating, Ventilation and Cooling  2.3.3.11, Fire Protection - Water  2.3.3.12, Fire Protection - CO 2 , Halon, and RCP Oil Collection Systems  2.3.3.13, Fuel Oil  2.3.3.14, Emergency Diesel Generators  2.3.3.15, Security Generators  2.3.3.16, Appendix R Diesel Generators  2.3.3.17, City Water  2.3.3.18, Plant Drains  2.3.3.19, Miscellaneous Systems In-Scope for (a)(2)
The applicant developed LRA Section 2.3.3.19 to capture all the systems or portions of systems that are within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). Among the
 
subsections included in LRA Section 2.3.3.19, the staff identified the following auxiliary systems
 
for simplified Tier 1 review:  chemical feed intake structure system  house service boiler  main generator  ignition oil  integrated liquid waste handling  nuclear service grade makeup  boiler blowdown  secondary sampling  technical support center diesel  main turbine The staff conducted a more detailed Tier 2 review for all remaining auxiliary systems.
 
Staff Requests for Additional Information During its review, the staff noted the applicant did not specifically identify components in scope under 10 CFR 54.4(a)(2) on the accompanied drawings. To ensure that the applicant did not 2-55 omit any components that should be in scope under 10 CFR 54.4(a)(2), the staff asked the applicant to verify that it had included segments of the selected systems in scope under
 
10 CFR 54.4(a)(2). In the following RAIs, dated February 13, 2008, the staff requested that the
 
applicant confirm its methodology for identifying nonsafety-related portions of systems with a
 
potential to adversely affect safety-related functions by describing the applicable specific
 
portions of system piping that the applicant included within the scope of license renewal, in
 
accordance with 10 CFR 54.4(a)(2):  RAI 2.3A.3.1-1  RAI 2.3A.3.2-1  RAI 2.3A.3.3-1  RAI 2.3A.3.5-1  RAI 2.3A.3.13-1  RAI 2.3A.3.14-2  RAI 2.3A.3.18-1 In its response, dated March 12, 2008, the applicant stated that all component types identified by the staff on the license renewal drawings in question are within the scope of license renewal
 
in accordance with 10 CFR 54.4(a)(2), and are subject to an AMR.
Based on its review, the staff finds the applicants response to these RAIs acceptable because the applicant has adequately explained that all component types identified by the staff are within
 
the scope of license renewal in accordance with 10 CFR 54.4(a)(2) and are subject to an AMR.
 
The staffs concern described in these RAIs is resolved.
SER Sections 2.3A.3.1 through 2.3A.3.19 provide the staffs reviews of IP2 systems described in LRA Sections 2.3.3.1 through 2.3.3.19, respectively. The following sections discuss the staffs
 
findings for these systems.
2.3A.3.1  IP2 Spent Fuel Pit Cooling System 2.3A.3.1.1  Summary of Technical Information in the Application LRA Section 2.3.3.1 describes the SFPC system, which removes residual heat from the spent fuel pit. The SFPC loop has two pumps, a heat exchanger, filter, demineralizer, piping, valves, and instrumentation. One of the pumps draws water from the pit, circulates it through the heat
 
exchanger cooled by CCW, and returns it to the pit. Loop piping is arranged so that any pipeline
 
failure does not drain the spent fuel pit below the top of the stored fuel elements. The spent fuel
 
pit pump suction line, which draws water from the pit, penetrates the spent fuel pit wall above
 
the fuel assemblies. The system also includes the spent fuel pit. Spent fuel storage racks at the
 
bottom of the pit for spent fuel assemblies are the full-length, top-entry type made of stainless
 
steel with Boraflex as a neutron absorber.
The SFPC system contains safety-related components relied upon to remain functional during and following DBEs. It also contains nonsafety-related components whose failure potentially
 
could prevent the satisfactory accomplishment of a safety-related function.
The spent fuel pit (including liner and the spent fuel racks) are included in the evaluation of the fuel storage buildings (LRA Section 2.4.3). The heat exchanger components forming parts of the
 
CCW system pressure boundary are evaluated with the CCW systems (LRA Section 2.3.3.3). A 2-56 small number of components are evaluated with the primary water makeup systems (LRA Section 2.3.3.7).
LRA Tables 2.3.3-1-IP2 and 2.3.3-19-35-IP2 identify the SFPC system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.3.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.1; UFSAR Sections 9.3.1, 9.5.2.1.5, and 14.2.1; a license renewal drawing; and IP2 Amendment 227, Credit for Soluble Boron and Burnup in Spent Fuel
 
Pit (TAC No. MB2989), dated May 29, 2002 (ADAMS Accession No. ML021230367), 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 had not omitted from the scope of license renewal any components with intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.3.1, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The discussion of the staffs RAIs in SER Section 2.3A.3 details the disposition of
 
RAI 2.3A.3.1-1, dated February 13, 2008.
2.3A.3.1.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and a drawing to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the SFPC components within the scope
 
of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3A.3.2  IP2 Service Water System 2.3A.3.2.1  Summary of Technical Information in the Application LRA Section 2.3.3.2 describes the SW system, which supplies cooling water from the Hudson River to various heat loads in both primary and secondary portions of the plant, in a continuous
 
flow to systems and components necessary for plant safety during either normal operation or
 
abnormal or accident conditions. Sufficient redundancy of active and passive components
 
maintains short- and long-term cooling to vital loads, in accordance with the single-failure
 
criterion. Six identical vertical, centrifugal sump-type pumps at the intake structure supply
 
service water to two independent discharge headers (each is supplied by three pumps). An
 
automatic, self-cleaning, rotary-type strainer in each pumps discharge removes solids. Each header connects to an independent supply line. Either of the two supply lines can supply the
 
essential load, while the other supplies the nonessential load. Essential loads must have an
 
assured supply of cooling water in the event of a loss of offsite power or a LOCA. Nonessential 2-57 loads are supplied with cooling water by an SW pump started manually, when required, following a LOCA. Nonessential loads include the CCW heat exchangers, circulating water (CW) pump seal injection, turbine building closed cooling water system, hydrogen coolers, stator cooling water heat exchanger, exciter air coolers, and isolated phase bus heat
 
exchangers. The system also provides backup water to clean the traveling screens.
The SW system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the SW system
 
performs functions that support fire protection and SBO.
Components that support safe shutdown in the event of a fire in the auxiliary feed pump room are reviewed in LRA Section 2.3.4.5. Components cooling the CCW systems are reviewed in
 
those systems (LRA Section 2.3.3.3). Components cooling the EDG systems are reviewed with
 
those systems (LRA Section 2.3.3.14).
LRA Tables 2.3.3-2-IP2 and 2.3.3-19-39-IP2 identify SW system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.3.2.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.2, UFSAR Section 9.6.1, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.3.2, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The discussion of the staffs RAIs in SER Section 2.3A.3 details the disposition of
 
RAI 2.3A.3.2-1, dated February 13, 2008.
2.3A.3.2.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has appropriately identified the SW system components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2-58 2.3A.3.3  IP2 Component Cooling Water System 2.3A.3.3.1  Summary of Technical Information in the Application LRA Section 2.3.3.3 describes the CCW system, which removes RCS residual and sensible heat via the RHR loop during plant shutdown, cools the letdown flow to the CVCS during power
 
operation, dissipates waste heat from various primary plant components, and cools engineered
 
safeguards and safe-shutdown components. The system includes the pumps, heat exchangers, distribution and return piping and valves, instruments, and controls to cool the following:  RHR heat exchangers  RCPs non-regenerative heat exchanger  excess letdown heat exchanger  CVCS seal water heat exchanger  sample heat exchangers  waste gas compressors  reactor vessel support pads  RHR pumps  safety injection pumps  recirculation pumps  spent fuel pit heat exchanger  charging pumps, fluid drive coolers, and crankcase Some of the CCW-cooled heat exchangers in other systems have no safety function; however, these nonsafety-related heat exchangers form parts of the CCW system pressure boundary.
 
These heat exchangers are within the scope of license renewal and have an intended function
 
to maintain the pressure boundary but not to transfer heat.
The CCW system was not designed to accommodate a passive failure during initial IP2 construction. The subsequent consideration of a passive failure required commitments for
 
alternate cooling water supplies to safety-related equipment. Connections to primary and city
 
water provide the alternate supplies.
The CCW system contains safety-related components relied on to remain functional during and following DBEs. In addition, the CCW system performs functions that support fire protection and
 
SBO.A few components within the CCW system support the RHR system pressure boundary and therefore are reviewed with the RHR systems (LRA Section 2.3.2.1). Components cooling the
 
safety injection systems are reviewed with those systems (LRA Section 2.3.2.4). Components
 
cooling the CVCS systems are reviewed with those systems (LRA Section 2.3.3.6).
LRA Table 2.3.3-3-IP2 and newly created Table 2.3.3-19-45-IP2 (see evaluation below) identify CCW system component types within the scope of license renewal and subject to an AMR, as
 
well as their intended functions.
2-59 2.3A.3.3.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.3, UFSAR Sections 6.2.2.3.4 and 9.3, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening results.
In RAI 2.3A.2.2-1, dated February 13, 2008, the staff asked the applicant to identify instances in which a safety-related system, which has nonsafety-related components, was scoped in per
 
10 CFR 54.4(a)(1), but those nonsafety-related components were not identified as in scope for
 
10 CFR 54.4(a)(2).
In its response, dated March 12, 2008, the applicant explained that it identified three instances in which nonsafety-related components were not considered to be within the scope of license
 
renewal under 10 CFR 54.4(a)(2). The applicant further explained that it should have included
 
the CCW systems at IP2 and IP3, as well as the IP3 building vent sampling (BVS) system, among those systems subject to the requirements of 10 CFR 54.4(a)(2). In these instances, the
 
applicant amended the LRA to reflect these changes. For the IP2 CCW system, in its letter
 
dated March 12, 2008, the applicant amended the LRA to reflect the following changes: (a) LRA Table 2.3.3-19-A-IP2 would reflect the CCW system as a miscellaneous system within the scope of license renewal pursuant to 10 CFR 54.4(a)(2). (b) Removal of the CCW system from the list of IP2 systems not reviewed for spatial interaction, in accordance with 10 CFR 54.4(a)(2). (c) Revision of LRA Table 2.3.3-19-B-IP2 to reflect that the CCW system now has components subject to an AMR, pursuant to 10 CFR 54.4(a)(2). (d) Creation of a new LRA Table 2.3.3-19-45-IP2 for the five added component types in the CCW system for nonsafety-related components, potentially affecting a safety-related
 
function, and subject to an AMR. (e) Creation of a new LRA Table 3.3.2-19-45-IP2 for the five added component types, their materials, environments, and AMPs.
Based on its review, the staff finds the applicants response to RAI 2.3A.2.2-1 for the IP2 CCW system acceptable because it adequately explained that the applicants reevaluation of
 
safety-related systems identified some components that should have been within scope for
 
meeting the requirements of 10 CFR 54.4(a)(2). Additionally, the staff finds that the applicants
 
response amended the LRA to include those portions of the CCW system identified by the staff
 
as being in scope under 10 CFR 54.4(a)(2). The staff reviewed the applicants addition of new
 
tables to the LRA and found that they adequately reflect those components brought into the 2-60 scope of license renewal under 10 CFR 54.4(a)(2) because of their potential for spatial interaction with safety-related components. The staffs concern described in RAI 2.3A.2.2-1 for
 
the IP2 CCW system is resolved. SER Section 3.3.2.1 documents the staffs evaluation of new
 
AMR results for the CCW system.
The discussion of the staffs RAIs in SER Section 2.3A.3 details the disposition of RAI 2.3A.3.3-1, dated February 13, 2008.
2.3A.3.3.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI response, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found one instance in which the applicant omitted
 
components that should have been subject to an AMR. The applicant has satisfactorily resolved
 
this issue as discussed in the preceding staff evaluation. On the basis of its review, the staff
 
concludes that the applicant has appropriately identified the CCW system components within
 
the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3A.3.4  IP2 Compressed Air Systems 2.3A.3.4.1  Summary of Technical Information in the Application LRA Section 2.3.3.4 describes the compressed air systems, including the instrument air and station air systems. The instrument air system continuously supplies dry, oil-free air from
 
duplicate compressors with duplicate dryers and filters for pneumatic instruments and controls.
 
Indian Point Nuclear Generating Unit 1 (IP1) and IP2 station air systems provide alternate
 
supplies. A connection in the station air system allows a backup supply from portable
 
compressed air equipment. The instrument air system, although designed to meet air capacity
 
requirements, utilizes the higher-capacity IP1 station air compressors as a primary source of
 
supply. Because of the high-capacity output of the IP1 air compressors, they can supply all IP1
 
and IP2 station and instrument air requirements. The IP2 station air compressor and both IP2
 
instrument air compressors serve as backups. The system includes the compressors, dryers, filters, receivers, distribution piping and valves, instruments, and controls. Items essential for
 
safe operation and cooldown have air reserves or gas bottles that enable the equipment to
 
function safely until its air supply resumes. The instrument air system includes piping, air
 
bottles, valves, and controls supporting this air reserve function, but excludes the air or gas
 
bottle parts of other systems. The system also may supply air to the post-accident venting
 
system to pressurize containment in support of hydrogen control, but this function is not safety
 
related.The station air system distributes compressed air to hose connections throughout the plant, primarily for maintenance activities. The station air system also serves as an alternate air supply
 
to the instrument air system. Either an IP2 air compressor or the IP1 compressors and equipment provide station air. The station air system consists of IP1 and IP2 station air
 
equipment, including air compressors, air receivers, filters, dryers, distribution piping, and
 
valves.
2-61 The compressed air system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure
 
potentially could prevent the satisfactory accomplishment of a safety-related function. In
 
addition, the compressed air system performs functions that support fire protection.
Instrument air system components that support safe shutdown in a fire in the auxiliary feed pump room are reviewed in LRA Section 2.3.4.5. Components containing nitrogen are reviewed
 
with the nitrogen systems (LRA Section 2.3.3.5).
LRA Tables 2.3.3-4-IP2, 2.3.3-19-18-IP2, and 2.3.3-19-33-IP2 identify compressed air system component types within the scope of license renewal and subject to an AMR, as well as their
 
intended functions.
2.3A.3.4.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.4, UFSAR Sections 9.6.4 and 9.6.4.2, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3A.3.4.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the compressed air system components
 
within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an
 
AMR, as required by 10 CFR 54.21(a)(1).
2.3A.3.5  IP2 Nitrogen Systems 2.3A.3.5.1  Summary of Technical Information in the Application LRA Section 2.3.3.5 describes the gas system, which stores and distributes gases, primarily hydrogen, carbon dioxide (CO 2), and nitrogen, for various uses around the plant. The gas system includes the hydrogen, CO 2 , and nitrogen gas subsystems. The system supplies hydrogen to the chemical and VCT for oxygen scavenging of RCS water to support water
 
chemistry control and to the main generator for cooling gas. CO 2 gas purges the main generator of hydrogen to support outage work on the generator. The nitrogen gas subsystem includes the
 
various nitrogen supplies of motive gas to components as a backup to the instrument air supply
 
and for process functions (including cover gas, purge gas, and gas required for operation of
 
level instrumentation). Nitrogen enters containment through several penetrations. For the safe
 
shutdown required by Appendix R to 10 CFR Part 50, nitrogen is necessary for pneumatically 2-62 actuated components. The nitrogen gas subsystem supplies the atmospheric dump valves, backup nitrogen to AFW system valve actuators, a portable nitrogen bottle that can be carried
 
into containment to operate the auxiliary spray valve, motive gas for the charging pumps suction
 
valve, and pneumatically powered instrumentation. An SBO event requires nitrogen to be
 
supplied to the atmospheric dump valves, the AFW system valve actuators, and pneumatically
 
powered instrumentation.
The gas system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the gas system
 
performs functions that support fire protection and SBO.
Gas system component parts of containment penetrations are reviewed with the containment penetrations (LRA Section 2.3.2.5). A small number of components are reviewed with the
 
compressed air systems (LRA Section 2.3.3.4), the city water system (LRA Section 2.3.3.17),
the plant drains (LRA Section 2.3.3.18), and the AFW systems (LRA Section 2.3.4.3).
LRA Tables 2.3.3-5-IP2 and 2.3.3-19-14-IP2 identify gas system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.3.5.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.5, UFSAR Sections 4.3.4.2, 7.2.1.5, 9.2, 10.2.2, and 10.2.6.3, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.3.5, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The discussion of the staffs RAIs in SER Section 2.3A.3 details the disposition of
 
RAI 2.3A.3.5-1, dated February 13, 2008.
2.3A.3.5.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI response, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its
 
review, the staff concludes that the applicant has appropriately identified the nitrogen system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-63 2.3A.3.6  IP2 Chemical and Volume Control System 2.3A.3.6.1  Summary of Technical Information in the Application LRA Section 2.3.3.6 describes the CVCS, which controls RCS inventory (amounts of makeup and letdown) and chemistry (RCS boron concentration and other chemical additions). The
 
system cleans up reactor coolant by degasification and purification, injects seal water to the
 
RCPs, depressurizes the RCS via a pressurizer auxiliary spray flowpath, and injects control
 
poison in the form of a boric acid solution from the boric acid storage tanks.
During normal plant operation, reactor coolant letdown flows through the shell side of the regenerative heat exchanger, which reduces its temperature by transferring heat to the charging
 
fluid. The coolant then flows through a letdown orifice, which regulates flow and reduces coolant
 
pressure. The cooled, low-pressure water leaves the reactor containment and enters the
 
primary auxiliary building (PAB). After passing through the non-regenerative heat exchanger
 
and one of the mixed-bed demineralizers, the fluid flows through the reactor coolant filter and
 
enters the VCT.
The coolant flows from the VCT to three positive-displacement, variable-speed charging pumps, which raise the pressure to a level above that in the RCS. The high-pressure water flows from
 
the PAB to the reactor containment along two parallel pathsone returning directly to the RCS
 
through the tube side of the regenerative heat exchanger to the RCS cold leg, and the other
 
injecting water into the RCP seals through seal injection filters. The RCP seal water returns to
 
the CVCS through a seal water filter and heat exchanger back to the VCT.
The RWST and the boric acid storage tank can supply borated water to the charging system.
The RWST is available to the charging pumps for injection of borated water. The boric acid
 
system has boric acid transfer pumps, a boric acid filter, and storage tanks to maintain a large
 
inventory of concentrated boric acid solution.
The CVCS contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the CVCS
 
performs functions that support fire protection, ATWS, and SBO.
CVCS components that maintain the RCS pressure boundary are reviewed with the RCS pressure boundary (LRA Section 2.3.1.3). Some system components are reviewed with the
 
primary water makeup systems (LRA Section 2.3.3.7).
LRA Tables 2.3.3-6-IP2 and 2.3.3-19-5-IP2 identify CVCS component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.3.6.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.6, UFSAR Section 9.2.2, and license renewal drawings 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 had not omitted from the scope of license renewal any components with 2-64 intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3A.3.6.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the CVCS components within the scope
 
of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1). 2.3A.3.7  IP2 Primary Water Makeup System 2.3A.3.7.1  Summary of Technical Information in the Application LRA Section 2.3.3.7 describes the primary water makeup system, which supplies makeup water to primary plant systems as required to support normal plant operation (e.g., tanks, piping, valves, pumps) The system includes containment penetration. The primary water makeup
 
system can supply backup cooling water to safety-related components in a passive failure of the
 
CCW system.
The primary water makeup system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose
 
failure potentially could prevent the satisfactory accomplishment of a safety-related function.
LRA Tables 2.3.3-7-IP2 and 2.3.3-19-29-IP2 identify primary water makeup system component types within the scope of license renewal and subject to an AMR, as well as their intended
 
functions.
2.3A.3.7.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.7, the UFSAR, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3A.3.7.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components 2-65 subject to an AMR. The staff found no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the primary water makeup system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3A.3.8  IP2 Heating, Ventilation and Air Conditioning Systems 2.3A.3.8.1  Summary of Technical Information in the Application LRA Section 2.3.3.8 describes the heating, ventilation, and air conditioning (HVAC) systems that maintain the area environment for personnel and equipment.
The HVAC systems include various ventilation subsystems serving various areas of the plant. With the exception of the containment cooling and filtration system and a few components in the
 
operation of other mechanical systems, the HVAC system encompasses all IP2 ventilation
 
systems and components and some from IP1. The main HVAC systems supporting plant
 
operation include the following systems:  containment purge supply and exhaust  containment pressure relief  containment iodine removal  control rod drive mechanism (CRDM) cooling  PAB ventilation  fuel storage building ventilation  cable spreading room/electrical tunnel ventilation  480 volt (V) switchgear room ventilation  battery room exhaust  EDG building ventilation  auxiliary feed pump room ventilation  diesel fire pump house ventilation  electric fire pump room ventilation  plant vent  shield wall area enclosure heating and ventilation system  SBO/Appendix R diesel generator ventilation  portable HVAC credited in Appendix R  security diesel room ventilation  turbine hall ventilation  technical support center ventilation  administration building ventilation LRA Section 2.3.3.9 addresses containment cooling and filtration, and LRA Section 2.3.3.10 addresses control room HVAC.
The containment purge supply and exhaust system supplies fresh air to purge the containment for personnel access. The system consists of a makeup air unit to supply fresh air, a filtration
 
unit to filter the air released from containment, supply and exhaust ductwork, containment
 
penetration piping, and valves. The system need not be in operation during DBAs or any
 
regulated events. The system has two penetrations with safety-related piping and valves that
 
support the containment isolation function. The pressure boundary function of system portions
 
are also necessary to prevent air from being drawn into the shared fan housing for the 2-66 containment purge and PAB exhaust fans.
The containment pressure relief system accommodates normal pressure changes in the containment during reactor power operation. This system consists of a filtration unit, fan, pressure relief ductwork, containment penetration piping, and valves. The system need not be in
 
operation during DBAs or any regulated events. The system has a penetration with
 
safety-related piping and valves that support the containment isolation function.
The containment iodine removal system consists of two auxiliary particulate and charcoal filter units in the containment, primarily used for pre-access cleanup. During power operation, the
 
containment air particulate and gas monitor indications help determine whether to use either or
 
both of these units. These units, wholly contained within containment, are not safety related or
 
required during DBAs or regulated events.
The CRDM cooling system maintains the control rod drive operating coil stacks below their maximum allowable temperature during normal operation. Four fans take suction from the
 
control rod drive shroud and discharge into the containment atmosphere. This equipment is not
 
required to function during accident conditions or in response to regulated events.
The PAB ventilation system ventilates the waste hold-up tank pit and enclosed spaces in the PAB. The waste hold-up tanks in the waste hold-up tank pit are the central collection points for
 
liquid radioactive waste. The PAB houses equipment and components required for normal plant
 
operation, as well as accident mitigation. The PAB heating and ventilation system maintains an
 
operating environment for personnel and equipment during normal operating and post-accident
 
conditions with supply and exhaust fans with ductwork and dampers. None of the applicants
 
dose consequence analyses credit filtration. The PAB ventilation system is in use during normal
 
operating conditions (plant start-up, power operation, and normal shutdown). This system must
 
also operate during DBAs and for safe shutdown following a fire.
The fuel storage building heating and ventilation system heats and ventilates that building, minimizes leakage of unfiltered air from the building during fuel-handling operations, and filters
 
building exhaust. The system has two fresh air tempering units with supply fans and heaters, exhaust roughing, high-efficiency particulate air (HEPA) and carbon filters, an exhaust fan, motor-operated dampers, and ducts. The applicant originally credited the system in the
 
fuel-handling accident; however, the analysis described in UFSAR Section 14.2.1.1, which uses the alternate source term, no longer assumes operation of the ventilation system or any holdup
 
of the radionuclides released from the spent fuel pit. Consequently, the system has no safety
 
functions.
The cable spreading room/electrical tunnel exhaust system ventilates the 33-foot elevation of the control building. The system consists of two exhaust fans mounted above the tunnel in a
 
plenum. Intake louvers on the north and south walls draw air into the cable- spreading room.
 
The system maintains an operating environment for personnel and equipment during normal
 
operating and post-accident conditions and is required for cooling during DBAs, as well as
 
regulated events.
The 480-V electrical switchgear room ventilation system ventilates that room at the 15-foot elevation of the control building, using three fans mounted in the north wall. The fans take
 
suction from the switchgear room and discharge outside. A fixed louver with fire damper allows
 
air to flow into the room. The system maintains an operating environment for personnel and 2-67 equipment during normal operating and post-accident conditions and is required for cooling during DBAs, as well as regulated events.
Battery rooms in the control and superheater buildings have exhaust fans to prevent long-term buildup of hydrogen during normal operation when the batteries charge. These exhaust fans
 
need not function during DBAs or regulated events. The EDG building ventilation system has exhaust fans, exhaust dampers, and intake louvers.
These HVAC components are required to support diesel operation during DBAs, as well as
 
regulated events such as the Appendix R safe shutdown.
The heating and ventilation system of the auxiliary boiler feed pump building, which is in use during normal operating conditions, consists of several exhaust fans for cooling. A roll-up door
 
can be opened for cooling during emergency operation of the AFW system. Following a fire, portable blowers can ventilate this area; therefore, the applicant stated that operation of the
 
auxiliary boiler feed pump building heating and ventilation system is not required during DBAs or
 
regulated events.
The diesel fire pump house ventilation system cools the structure housing the diesel fire pump.
This structure is cooled by louvers, and the diesel itself is cooled by fire water. These HVAC
 
components are required to support fire system operation credited in Appendix R evaluations.
The electric fire pumps are located in two rooms in the IP1 turbine building cooled by exhaust fans and dampers that cool the electric fire pumps. These HVAC components are required to
 
support fire system operation credited in Appendix R evaluations.
The plant vent system, which provides a flowpath for the exhaust to the atmosphere, includes the plant vent duct and some vent flow monitoring instrumentation. The offsite dose analyses
 
does not credit the plant vent as the release point but, because of its proximity to the control
 
room air intake, the control room dose calculations do consider the plant vent to be the release
 
point.The IP2 shield wall area enclosure heating and ventilation system heats and ventilates the shield wall area enclosure. Components and piping primarily associated with the MS and FW
 
systems are located in the main enclosure. The shield wall area enclosure heating and
 
ventilation system is in use during normal operating conditions, such as plant start-up, power
 
operation, and normal shutdown. The operation of this equipment is not required during DBAs
 
or regulated events.
IP2 installed a new SBO and Appendix R diesel generator credited with supplying backup power to the plant to assist in safe shutdown following a fire or an SBO. Its associated ventilation
 
equipment is required for its function. The IP2 SBO/Appendix R diesel generator ventilation
 
system utilizes louvers, an exhaust fan, and outlet ductwork. The fan will operate when the
 
diesel operates.
The Appendix R safe-shutdown report indicates that, for a fire in certain plant areas, portable blowers and flexible ductwork can ventilate the safe-shutdown equipment, and are therefore
 
required by Appendix R. Power can be supplied by portable generators.
2-68 The IP2 security diesel generator is credited for emergency lighting for some areas to support safe shutdown following a fire. The ventilation equipment that cools this diesel consists of
 
dampers, ductwork, and an engine-driven blower that ventilates the room when the engine
 
operates. This ventilation is required for the operation of the security diesel credited with
 
providing power for lighting, as required by Appendix R.
Using fixed and adjustable louvers and awning sashes, the turbine building ventilation system draws in air exhausted by power roof ventilators and wall exhaust fans. This cooling is not
 
required during DBAs and regulated events.
The technical support center ventilation system maintains environmental conditions in the center. The system, which includes fans, dampers, filters, and cooling equipment, performs no
 
safety-related functions during accident conditions and is not required for any regulated events.
The administration building ventilation system, which heats, ventilates, and provides air conditioning to administration building personnel and equipment, is not required during DBAs or
 
regulated events.
The HVAC system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure could prevent the
 
satisfactory accomplishment of a safety-related function. In addition, the HVAC system performs
 
functions that support fire protection and SBO.
Some HVAC components are reviewed with the compressed air systems (LRA Section 2.3.3.4) or with the containment cooling and filtration systems (LRA Section 2.3.3.9).
LRA Tables 2.3.3-8-IP2 and 2.3.3-19-17-IP2 identify HVAC system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.3.8.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.8; UFSAR Sections 5.3.2, 9.8, and 9.10; and a license renewal drawing 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
the applicant identified as within the scope of license renewal to verify that it had not omitted
 
any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3A.3.8.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and a drawing to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the HVAC system components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as 2-69 required by 10 CFR 54.21(a)(1).
2.3A.3.9  IP2 Containment Cooling and Filtration System 2.3A.3.9.1  Summary of Technical Information in the Application LRA Section 2.3.3.9 describes the containment cooling and filtration system. The IP2 containment cooling and filtration system cools the containment. Air-handling units, discharging
 
into a common header ductwork distribution system, achieve air recirculation cooling during
 
normal operation and ensure adequate flow of cooled air throughout the containment. Each
 
air-handling unit consists of equipment arranged so that, during normal and accident operation, air flows through the unit in the following sequence: cooling coils, moisture separators (demisters), centrifugal fan with direct-drive motor, and distribution header. The system rejects
 
heat to SW system cooling coils in normal operation, emergency operation, and safe-shutdown
 
cooling following a fire.
The containment cooling and filtration system contains safety-related components relied on to remain functional during and following DBEs. In addition, the containment cooling and filtration
 
system performs functions that support fire protection and SBO.
LRA Table 2.3.3-9-IP2 identifies containment cooling and filtration system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.3.9.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.9, UFSAR Sections 5.3.2.2 and 6.4.2, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
the applicant identified as within the scope of license renewal to verify that it had not omitted
 
any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3A.3.9.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the containment cooling and filtration
 
system components within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-70 2.3A.3.10  IP2 Control Room Heating, Ventilation and Cooling System 2.3A.3.10.1  Summary of Technical Information in the Application LRA Section 2.3.3.10 describes the control room ventilation system, which maintains the central control room in a safe, habitable environment during normal operation and under accident
 
conditions. The system has an air-conditioning unit with fan, steam heating coil, roughing filter
 
to recirculate air inside the control room, a backup fan in parallel with the air-conditioning unit, and a filter unit consisting of HEPA filters, charcoal filters, post-filters, and booster fans to permit
 
filtration of incoming air for a slight positive pressure in the control room during accident
 
conditions. System ducts, dampers, and controls allow three system operating modes: Mode 1 (normal operation) with outside air makeup, Mode 2 (safety injection or high radiation) with
 
outside filtered air, and Mode 3 (toxic gas or smoke) with all outside air isolated. Control room
 
dose analyses credit the operation of this system, including the filtration of incoming air. IP1 and
 
IP2 share a central control room. The IP1 control room ventilation equipment is modified for
 
recirculation mode only.
The central control room system contains safety-related components relied upon to remain functional during and following DBEs. It also contains nonsafety-related components whose
 
failure potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the central control room system performs functions to maintain the central control room
 
in a safe, habitable environment during an Appendix R event and SBO.
LRA Tables 2.3.3-10-IP2 and 2.3.3-19-17-IP2 identify central control room HVAC system component types within the scope of license renewal and subject to an AMR, as well as their
 
intended functions.
2.3A.3.10.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.10, UFSAR Section 9.9, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
the applicant identified as within the scope of license renewal to verify that it had not omitted
 
any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3A.3.10.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the central control room HVAC system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-71 2.3A.3.11  IP2 Fire Protection - Water 2.3A.3.11.1  Summary of Technical Information in the Application LRA Section 2.3.3.11 describes the fire protection system, which provides fire protection for the station through the use of water, dry chemicals, foam, detection and alarm systems, and rated
 
fire barriers, doors, and dampers. Passive mechanical components in the fire protection system
 
include many firefighting subsystem components and features, such as piping, fire dampers, valves, hydrants, portable fire extinguishers, and two fire water storage tanks. Also included
 
under this system code (i.e., the applicants code for designating systems and boundaries) are
 
the IP1 fire pumps and some associated IP1 fire protection components, such as hydrants, valves, fire extinguishers, and strainers. Plant drain components in the fire protection system
 
are passive fire protection features required to ensure adequate protection of safety-related
 
equipment from water damage in areas containing fixed suppression systems.
The fire protectionwater system draws water from two storage tanks, a 1.5-million-gallon tank supplied by the city water distribution system for fire protection purposes and a 300,000-gallon
 
fire water storage tank of city water as a redundant supply for the water-based fire protection
 
systems. The pumping facilities consist of two electric fire pumps taking suction from the sites
 
city water main. Two small electric pumps also maintain pressure for the fire water system. A
 
diesel fire pump for redundant pumping capabilities normally takes suction from the
 
300,000-gallon fire water storage tank. The pumping facilities meet flow and pressure
 
requirements for water-based fire protection systems. The fire protection water distribution
 
system consists of outdoor underground piping, indoor distribution piping, isolation valves, strainers, hose stations, and outdoor hydrants.
The water-based fire suppression systems include the wet pipe sprinkler systems, preaction sprinkler systems, deluge water spray systems, foam water spray systems, and hydrants and
 
hose stations.
According to the LRA, the fire protectionwater system has no intended function under 10 CFR 54.4(a)(1). The scoping and screening methodology identified the following fire water
 
system intended functions, in accordance with 10 CFR 54.4(a)(2):  Maintain integrity of nonsafety-related components such that no physical interaction with
 
safety-related components could prevent satisfactory accomplishment of a safety
 
function. Provide a backup source of makeup water to the spent fuel pit.
The scoping and screening methodology also identified the following the fire water system intended functions, in accordance with 10 CFR 54.4(a)(3):  Provide fixed automatic and manual fire suppression (including hydrants, hose stations
 
and portable extinguishers) to extinguish fires in vital areas of the plant (10 CFR 50.48). Ensure adequate protection of safety-related equipment from water damage in areas
 
susceptible to flooding (10 CFR 50.48). Ensure that drain systems in areas containing combustible materials prevent the
 
spreading of fires into other areas of the plant (10 CFR 50.48).
2-72 LRA Section 2.3.3.12 evaluates the fire protectionCO 2 , Halon 1301, and RCP oil collection systems.
The drain portion of the system is evaluated with plant drains (LRA Section 2.3.3.18). The fuel oil subsystem components are evaluated with fuel oil systems (LRA Section 2.3.3.13). A small
 
number of components are evaluated with city water systems (LRA Section 2.3.3.17).
The applicant evaluated those nonsafety-related components that were not evaluated with other systems and whose failure could prevent satisfactory accomplishment of safety functions with
 
miscellaneous systems within the 10 CFR 54.4(a)(2) scope of license renewal (LRA
 
Section 2.3.3.19).
LRA Tables 2.3.3-11-IP2 and 2.3.3-19-11-IP2 identify fire protectionwater system component types within the scope of license renewal and subject to an AMR, as well as their intended
 
functions.
2.3A.3.11.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.11, UFSAR Section 9.6.2, and license renewal drawings 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 had not omitted from the scope of license renewal any
 
components with intended functions, as required by 10 CFR 54.4(a). The staff then reviewed
 
those components that the applicant identified as within the scope of license renewal to verify
 
that it had not omitted any passive and long-lived components subject to an AMR in accordance
 
with 10 CFR 54.21(a)(1).
The staff also reviewed the following IP2 fire protection CLB documents listed in the IP2 Operating License Condition 2.K: NRC fire protection SERs for IP2, dated November 30, 1977;
 
February 3, 1978; January 31, 1979; October 31, 1980; August 22, 1983; March 30, 1984;
 
October 16, 1984; September 16, 1985; November 13, 1985; March 4, 1987; January 12, 1989; and March 26, 1996.
The staff also reviewed IP2 commitments made in response to the requirements of 10 CFR 50.48 (i.e., an approved fire protection program), using its commitment responses to
 
Branch Technical Position (BTP) Auxiliary and Power Conversion Systems Branch (APCSB)
 
9.5-1, Guidelines for Fire Protection for Nuclear Power Plants, dated May 1, 1976, and
 
Appendix A to BTP APCSB 9.5-1, dated August 23, 1976.
During its review of LRA Section 2.3.3.11, the staff identified areas in which additional information was necessary to complete its review of the applicants scoping and screening
 
results. The applicant responded to the staffs RAIs as discussed below.
In RAI 2.3A.3.11-1, dated October 24, 2007, the staff questioned why the license renewal drawings identified certain fire protection system components as not subject to an AMR.
Specifically, License renewal drawing LRA-227551-0 shows the following fire protection system
 
components as not subject to an AMR (i.e., they are not highlighted in green):  maintenance and outage building  PAB and boric acid building charcoal filter deluge system 2-73 License renewal drawing LRA-227552-0 shows the following fire protection system components as not subject to an AMR (i.e., they are not highlighted in green):  No. 11 fire pump room  fuel oil tank/water meter house  ignition oil tank and pump room deluge system  main and auxiliary transformer deluge system License renewal drawing LRA-227553-0 shows the following fire protection system components as not subject to an AMR (i.e., they are not highlighted in green):  staircase Nos. 2, 3, 4, 5 and 6  turbine oil piping system License renewal drawing LRA-227554-0 shows the following fire protection system component as not subject to an AMR (i.e., it is not highlighted in green):  staircase Nos. 1, 8, and 9 License renewal drawing LRA-9321-4006-0 shows the following fire protection system components as not subject to an AMR (i.e., they are not highlighted in green):  fire hydrants  fire hose connections  fire hose stations In the RAI, the staff requested that the applicant verify whether the above components are within the scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an AMR, in accordance with 10 CFR 54.21(a)(1). The staff requested that the applicant justify excluding
 
these components from the scope of license renewal and an AMR.
In its response, dated November 16, 2007, the applicant provided scoping and screening results for the fire protection system components in question in license renewal drawing LRA-227551-0.
 
For the maintenance and outage building, the applicant stated the following:
The maintenance and outage building adjacent to the fuel storage building of IP2 houses offices and facilities for maintenance personnel. The maintenance and
 
outage building fire protection components are not required for 10 CFR 50.48 as
 
the building does not house and is not in proximity to safety-related equipment, nor does it contain equipment required for safe-shutdown. The maintenance and
 
outage building fire protection components are not described in the
 
January 31, 1979, fire protection SER.
Based on its review, the staff finds the applicants response acceptable because the maintenance and outage building does not have a license renewal intended function. The
 
maintenance and outage building does not require fire protection in accordance with the
 
provisions of 10 CFR 50.48; therefore, the associated fire protection components are not within
 
the scope of license renewal.
2-74 For the PAB charcoal filter deluge system, the applicant stated the following:
Drawing LRA-227551-0 detail E shows piping and solenoid valves downstream of FP-587 for the PAB charcoal filter deluge system. These portions of the
 
system were inadvertently not highlighted on the drawing as subject to an AMR
 
for license renewal. The PAB charcoal filter deluge system is in-scope and
 
subject to an AMR. Applicable component types are included in LRA
 
Table 2.3.3-11-IP2 with the AMR results in LRA Table 3.3.2-11-IP2.
Based on its review, the staff finds the applicants response acceptable because it indicated that the PAB charcoal filter deluge system is within the scope of license renewal and subject to an
 
AMR.For the boric acid building charcoal filter deluge system, the applicant stated the following:
The boric acid building charcoal filter deluge system is in-scope and subject to an AMR as shown on drawing LRA-227551-0 in detail E and detail F. Applicable
 
component types are included in LRA Table 2.3.3-11-IP2 with the AMR results in
 
LRA Table 3.3.2-11-IP2.
Based on its review, the staff finds the applicants response acceptable because it indicated that the boric acid building charcoal filter deluge system is within the scope of license renewal and
 
subject to an AMR.
In its response, dated November 16, 2007, the applicant provided scoping and screening results for the fire protection system components in license renewal drawing LRA-227552-0. For the
 
No.11 Fire Pump Room, the applicant stated the following:
The portion of the fire protection system labeled on drawing LRA-227552-0 as No.11 fire pump room includes systems for gas turbine No. 1 Transformer, expanded portion of the maintenance area, the L&P Transformer, the bulk H2
 
storage (screenwell house) for Unit 1, and the maintenance material processing
 
area. This portion of the system is not required to meet 10 CFR 50.48
 
requirements for the following reasons. Deluge valve FP-294 feeds the line that
 
is blind-flanged to the gas turbine No. 1 Transformer which is retired in place. A
 
fire in this area cannot adversely impact safety-related equipment. Deluge valve
 
FP-1008 feeds the expanded portion of the maintenance area which houses no
 
safety-related equipment. A fire in this area cannot affect areas containing
 
safety-related equipment. Deluge valve FP-242 supplies spray system No. 1
 
which protects the L&P Transformer which is retired in place. A fire in this area
 
cannot adversely impact safety-related equipment. Deluge valve FP-261 supplies
 
the line for spray system No. 4 to the bulk H2 storage (screenwell house) for
 
Unit 1, and deluge valve FP-890 supplies the line for the maintenance material
 
processing area.
These areas do not contain safety-related equipment, and a fire in the areas cannot affect areas containing safety-related equipment. None of these fire
 
protection systems are described in the January 31, 1979, fire protection SER.
2-75 Based on its review, the staff finds the applicants response acceptable because the portion of the fire protection system identified does not have a license renewal intended function and is
 
not subject to an AMR, in accordance with 10 CFR 54.4(a) or 10 CFR 54.21(a)(1), respectively.
For the fuel oil tank/water meter house, the applicant stated the following:
As shown on drawing LRA-227552-0 detail J (fuel oil tank/water meter house), hydrants No. 18 and No. 19 provide fire protection coverage for fuel oil storage
 
tanks. The fuel oil storage tanks are associated with house service boiler and
 
ignition oil tanks. These fuel oil tanks have no intended function for license
 
renewal. They are not required to meet 10 CFR 50.48 requirements since a fire
 
in this portion of the yard cannot affect safety-related or safe-shutdown
 
equipment. In addition, this equipment is not described in the January 31, 1979, fire protection SER. Fire protection components associated with the water meter
 
house (piping and valves) are in-scope and subject to an AMR and are shown on
 
drawing LRA-192505. These components (piping and valves) are part of the city
 
water system discussed in Section 2.3.3.17 of the LRA.
Based on its review, the staff finds the applicants response acceptable. The fuel oil tank does not have a license renewal intended function and is, therefore, excluded from the scope of
 
license renewal and is not subject to an AMR. The staff notes that the water meter house fire
 
protection components are within the scope of license renewal, subject to an AMR, and shown
 
on drawing LRA-192505.
For the ignition oil tank and pump room deluge system, the applicant stated the following:
The ignition oil tank and pump rooms are in the Indian Point Nuclear Generating Unit 1 (IP1) super-heater building (not adjacent to IP2 areas containing
 
safety-related equipment). These rooms do not contain safety-related equipment
 
or systems required for safe-shutdown. Three-hour rated walls, penetrations, and
 
doors will prevent a fire in the ignition oil tank and pump room from spreading to
 
safety-related areas associated with IP2. The ignition oil tank and pump room
 
deluge system is not required to meet 10 CFR 50.48 and is not described in the
 
January 31, 1979, fire protection SER.
Based on its review, the staff finds the applicants response acceptable because the ignition oil tank and pump room deluge system is not required by 10 CFR 50.48 and is, therefore, outside
 
the scope of license renewal.
For the main and auxiliary transformer deluge system, the applicant stated the following:
The main and auxiliary transformer deluge systems and their associated components for the oil filled transformers adjacent to the control building were
 
initially determined to have no license renewal intended function. They were
 
considered required only to protect the transformers to satisfy requirements of
 
the plant insurance carrier. However, the spray systems provide for defense in
 
depth in addition to installed 3-hour rated fire barriers and are now considered
 
in-scope and subject to an AMR for license renewal. Applicable component types
 
that are subject to an AMR are included in LRA Table 2.3.3-11-IP2 with the AMR
 
results in LRA Table 3.3.2-11-IP2.
2-76 Based on its review, the staff finds the applicants response acceptable because it clarifies that (1) the main and auxiliary transformer deluge systems and their associated components have
 
no license renewal intended function and (2) the spray systems provide for defense in depth, in
 
addition to the installed 3-hour-rated fire barriers, and are considered in scope and subject to an
 
AMR for license renewal. The staffs concern is resolved.
In its response, dated November 16, 2007, the applicant provided scoping and screening results for the fire protection system components in license renewal drawing LRA-27553-0. For
 
staircase Nos. 2, 3, 4, 5 and 6, the applicant stated the following:
Staircase No. 2 is located in the IP1 service building adjacent to the IP1 turbine building. The service building for IP1 houses administrative offices. Staircases
 
No. 5 and No. 6 are located in the IP1 super-heater building at the south exterior
 
wall. None of these areas are in proximity to areas containing safety-related
 
equipment. Fires in the areas of Staircases No. 2, 5, and 6 are prevented from
 
spreading to nearby safety-related areas (IP2 control building) by three-hour
 
rated walls, penetrations, and doors. Fire protection equipment in Staircases
 
No. 2, 5, and 6 are not required for 10 CFR 50.48 and are not described in the
 
January 31, 1979, fire protection SER.
Fire protection equipment for Staircase No. 4 at Elevation 53, located in the control building, is in-scope and subject to an AMR as shown on drawing
 
LRA-227553-0 at detail WW.
The supply to the radwaste/HP offices downstream of valve FP-363 and components downstream of normally closed valve FP-155 are not required for
 
10 CFR 50.48 because these areas do not contain safety-related equipment nor
 
can a fire in the radwaste/HP offices impact areas containing safety-related
 
equipment.
Fire protection for Staircase No. 3 at Elevation 15, 33, and 53 in the control building is in-scope and subject to an AMR as shown on drawing LRA-227553-0
 
at detail W.
The supply to the technical support building (TSC) downstream of valve FP-865 is not required for 10 CFR 50.48 because this area does not contain
 
safety-related equipment nor can a fire in the technical support building impact
 
areas containing safety-related equipment.
Based on its review, the staff finds the applicants response acceptable because it clarifies that (1) fire protection systems in staircase Nos. 2, 5, and 6 are not required to comply with the
 
requirements of 10 CFR 50.48, (2) fire protection system equipment for staircase No. 4 is within
 
the scope of license renewal and subject to an AMR, as shown on license renewal drawing
 
LRA-227553-0, and (3) the fire protection system for staircase No. 3 also is in scope and
 
subject to an AMR, as shown on license renewal drawing LRA-227553.
For the turbine oil piping system, the applicant stated the following:
Turbine oil piping sprinkler system components downstream of valve FP-65 2-77 provide coverage for the file room, one stop shop building, and the work control center building, none of which contains, or can impact areas containing, safety-related equipment. The turbine oil piping sprinkler system is therefore not
 
required for compliance with 10 CFR 50.48. However, hose reel FP-66 and
 
associated piping are in-scope and subject to an AMR for license renewal as shown on drawing LRA-227553-0 at detail X.
Based on its review, the staff finds the applicants response acceptable because it clarifies the portion of the turbine oil piping sprinkler system components that are not required under
 
10 CFR 50.48. These components are not within the scope of license renewal because the
 
areas that they cover do not contain safety-related equipment and a fire in these locations
 
cannot impact areas containing safety-related equipment.
In its response, dated November 16, 2007, the applicant provided scoping and screening results for the fire protection system components in license renewal drawing LRA-227554-0. For staircase Nos. 1, 8, and 9, the applicant stated the following:
Staircase No. 1 is located in the IP1 nuclear service building and Staircases No. 8 and 9 are located in the IP1 nuclear service chemical system building. The
 
nuclear service building is adjacent to the IP1 containment building and houses
 
no safety-related equipment. The nuclear service chemical system building is
 
adjacent to the IP1 containment building and houses no safety-related
 
equipment. These buildings are not in proximity to areas containing
 
safety-related equipment. Fires in the areas of Staircases No. 1, 8, and 9 are
 
prevented from spreading to safety-related areas (control building) by three-hour
 
rated walls, penetrations, and doors. Fire protection equipment in Staircases
 
Nos. 1, 8, and 9 is not required for 10 CFR 50.48. These staircases are
 
associated with IP1 and the associated fire protection system components are no
 
longer required for compliance with 10 CFR 50.48 since the IP1 operating license
 
was revoked in June 1980 as stated in the October 31, 1980, supplement to the
 
January 31, 1979, fire protection SER.
Based on its review, the staff finds the applicants response acceptable because it clarifies that staircase Nos. 1, 8, and 9 are associated with IP1, and the associated fire protection system
 
components are no longer required for compliance with 10 CFR 50.48.
In its response, dated November 16, 2007, the applicant provided scoping and screening results for the fire protection system components depicted on license renewal
 
drawing LRA-9321-4006-0 that are in question. For fire hydrants, the applicant stated the
 
following:
Hydrants for the IP2 screenwell structure (Hydrants 21 and 22), main transformer yard (Hydrant 25), emergency diesel generators building (Hydrant 27), primary
 
auxiliary building (Hydrants 26, 28, and 29), and auxiliary feed pump building (Hydrant 24) are required for 10 CFR 50.48. These hydrants are highlighted on
 
LRA drawing LRA-9321-4006-0.
Hydrants that are not highlighted are those for the IP1 screenwell house (Hydrants 11 and 12), IP1 fuel oil tank farm (Hydrants 17 and 18), east of IP1 fuel
 
handling building (Hydrant 16), station security building (Hydrant 15), and 2-78 southeast of the IP1 containment building (Hydrants 13 and 14). These hydrants are not required for 10 CFR 50.48. The IP1 screenwell house does contain
 
equipment for safe-shutdown in the event of fire in another area. Fires are not
 
assumed to occur in multiple fire zones, so a fire in the screenwell house is not a
 
concern. The other areas listed do not present a significant fire hazard to areas
 
containing equipment used for safe-shutdown.
Based on its review, the staff finds the applicants response acceptable because it clarifies that hydrants 21, 22, 24, 25, 26, 27, 28, and 29 are required by 10 CFR 50.48. The applicant has
 
highlighted these hydrants on license renewal drawing LRA-9321-4006-0. In addition, hydrants
 
11, 12, 13, 14, 15, 16, 17, and 18 are not highlighted because they are associated with IP1. The
 
IP1 hydrants are no longer required for compliance with 10 CFR 50.48.
For fire hose connections, the applicant stated the following:
Fire hose connections that are not highlighted on drawing LRA-9321-4006-0 coordinates (B2) are located at the IP1 screenwell house dock and are not
 
required for 10 CFR 50.48. The hose connection at the IP1 screenwell house is
 
isolated with a blank flange.
Based on its review, the staff finds the applicants response acceptable because it clarifies that fire hose connections that are not highlighted on license renewal drawing LRA-9321-4006-0 are
 
associated with the IP1 screenwell house dock and are no longer required for compliance with
 
10 CFR 50.48, since the IP1 operating license was revoked in June 1980.
For fire hose stations, the applicant stated the following:
The fire hose stations that are not highlighted on drawing LRA-9321-4006-0 are in the IP1 fuel handling building and are not required for 10 CFR 50.48. This area
 
does not contain equipment used for safe-shutdown and is an area that does not
 
present a significant fire hazard to areas containing equipment used for
 
safe-shutdown. Fire hose stations associated with IP1 and the associated fire
 
protection system components are no longer required for compliance with
 
10 CFR 50.48 since the IP1 operating license was revoked in June 1980 as
 
stated in the October 31, 1980, supplement to the January 31, 1979, fire
 
protection SER.
Based on its review, the staff finds the applicants response acceptable because it clarifies that fire hose stations that are not highlighted on license renewal drawing LRA-9321-4006-0 are in
 
the IP1 fuel-handling building and are no longer required by 10 CFR 50.48, since the IP1
 
operating license was revoked in June 1980.
At the request of the staff, the applicant clarified its statements made in its November 16, 2007 response to RAI 2.3A.3.11-1 regarding IP1 fire protection components that were stated to be no
 
longer required for compliance with 10 CFR 50.48. By letter dated August 6, 2009, the applicant
 
clarified that IP1 fire protection components identified in its response dated November 16, 2007
 
that are specifically used only to support IP1 do not have an intended function for IP2 or IP3.
 
Since they are not required to demonstrate compliance with 10 CFR 50.48 for IP2 or IP3, the
 
applicant determined that they are not within the scope of license renewal. Entergy further
 
stated that the IP1 components are credited in the IP1 fire protection program which meets the 2-79 requirements in 10 CFR 50.48(f). The staff notes that 10 CFR 50.48(f) applies to reactors that have permanently ceased operations, and does not apply to IP2 or IP3.
The staff finds the applicants response acceptable because it clarified that the IP1 components that support IP1 fire protection program are not needed to support the operation of IP2 or IP3, and therefore, they are not within the scope of license renewal.
Based on its review, the staff finds the applicants response to RAI 2.3A.3.11-1, as clarified, acceptable. The staffs concern described in RAI 2.3A.3.11-1 is resolved.
In RAI 2.3A.3.11-2, dated October 24, 2007, the staff stated that LRA Tables 2.3.3-11-IP2 and 2.3.3-11-IP3 exclude several types of fire protection components that are discussed in the fire
 
protection SERs or UFSAR or both and which also appear on the license renewal drawings as
 
subject to an AMR (i.e., they are highlighted in green). These components include the following:  hose connections  hose racks  yard hose houses  interior fire hose stations  pipe fittings  pipe supports  couplings threaded connections  restricting orifices  interface flanges  chamber housings heat-actuated devices  tank heaters  thermowells water motor alarms  expansion joint  filter housing  gear box housing  heat exchanger (bonnet)  heat exchanger (shell)  heat exchanger (tube)  heater housing  diesel-driven fire pump engines muffler  orifice sight glass  strainer housing  turbocharger housing  flexible hose  latch door pull box  pneumatic actuators  actuator housing  dikes for oil spill confinement  buried underground fuel oil tanks for EDGs  expansion tank  fire water main loop valves 2-80 post-indicator valves  jacket cooling water keep-warm pump and heater  lubricating oil collection system components for each RCP  lubricating oil cooler  auxiliary lubricating oil makeup tank  rocker lubricating oil pump  floor drains and curbs for fire-fighting water  backflow prevention devices  flame retardant coating for cables fire retardant coating for structural steel supporting walls and ceilings The staff requested that the applicant verify whether LRA Tables 2.3.3-11-IP2 and 2.3.3-11-IP3 should include the components listed above. If they are excluded from the scope of license
 
renewal and not subject to an AMR, the staff requested that the applicant justify their exclusion.
In its response, dated November 16, 2007, the applicant provided the results of scoping and screening for the listed fire protection system component types as follows:
Hose connectionsAs stated in LRA Section 2.0 Page 2.0-1, the component type piping includes pipe, pipe fittings (such as elbows and reducers), flow
 
elements, orifices, and thermowells. Hose connections are pipe fittings subject to
 
an AMR as indicated in LRA Tables 2.3.3-11-IP2 and 2.3.3-11-IP3 under the
 
component type piping, with the AMR results provided in LRA
 
Tables 3.3.2-11-IP2 and 3.3.2-11-IP3.
Hose racksHose racks subject to an AMR are included in the structural AMR as component type fire hose reels. This item is included in LRA Table 2.4-4, with the AMR results provided in LRA Table 3.5.2-4.
Yard hose housesYard hose houses (small buildings over hydrants which contain fire hose and fire fighting equipment) are not subject to an AMR. Failure
 
of a yard hose house would not prevent fire suppression capability of the
 
associated hydrant.
Interior fire hose stationsInterior fire hose stations are subject to an AMR. They are included in LRA Table 2.4-4 under component type fire hose reels, with the
 
AMR results provided in LRA Table 3.5.2-4.
Pipe fittingsAs stated in LRA Section 2.0 on Page 2.0-1, the component type piping may include pipe, pipe fittings (such as elbows and reducers), flow
 
elements, orifices, and thermowells. Pipe fittings are subject to an AMR and
 
included in LRA Tables 2.3.3-11-IP2 and 2.3.3-11-IP3 under the component type
 
piping with the AMR results in LRA Tables 3.3.2-11-IP2 and 3.3.2-11-IP3.
Pipe supportsPipe supports are subject to an AMR and are included in the structural AMR as component type component and piping supports. This item is
 
included in LRA Table 2.4-4, with the AMR results provided in LRA Table 3.5.2-4.
CouplingsAs stated in LRA Section 2.0 Page 2.0-1, the component type piping may include pipe, pipe fittings (such as elbows and reducers), flow 2-81 elements, orifices, and thermowells. Couplings are subject to an AMR and included in LRA Tables 2.3.3-11-IP2 and 2.3.3-11-IP3 under the component type
 
piping, with the AMR results provided in LRA Tables 3.3.2-11-IP2 and
 
3.3.2-11-IP3.
Threaded connectionsAs stated in LRA Section 2.0 Page 2.0-1, the component type piping may include pipe, pipe fittings (such as elbows and reducers), flow
 
elements, orifices, and thermowells. Threaded connections are considered pipe
 
fittings and are included in LRA Tables 2.3.3-11-IP2 and 2.3.3-11-IP3 under the
 
component type piping, with the AMR results provided in LRA
 
Tables 3.3.2-11-IP2 and 3.3.2-11-IP3.
Restricting orificesAs stated in LRA Section 2.0 Page 2.0-1, the component type piping may include pipe, pipe fittings (such as elbows and reducers), flow
 
elements, orifices, and thermowells. Restricting orifices in the fire protection
 
water systems are included in the piping line item in LRA Tables 2.3.3-11-IP2
 
and 2.3.3-11-IP3, with the AMR results provided in LRA Tables 3.3.2-11-IP2 and
 
3.3.2-11-IP3.
Interface flangesAs stated in LRA Section 2.0 Page 2.0-1, the component type piping may include pipe, pipe fittings (such as elbows and reducers), flow
 
elements, orifices, and thermowells. Interface flanges are subject to an AMR and
 
included in LRA Tables 2.3.3-11-IP2 and 2.3.3-11-IP3 under the component type
 
piping, with the AMR results provided in LRA Tables 3.3.2-11-IP2 and
 
3.3.2-11-IP3.
Chamber housingsDeluge valves for IP2 and IP3 include a retard chamber, piping, and valves whose purposes are to prevent false alarms due to system
 
pressure surges and to provide a flow path to the water gong alarm during
 
system actuation. Since failure of these components of the deluge valve would
 
not prevent fire suppression capability for the sprinkler system, they are not
 
subject to an AMR.
Heat-actuated devicesHeat actuated devices are active components not subject to an AMR.
Tank heatersTank heaters are active components not subject to an AMR.
 
ThermowellsThermowells are included in Tables 2.3.3-11-IP2 and 2.3.3-11-IP3, with the AMR results provided in LRA Tables 3.3.2-11-IP2 and
 
3.3.2-11-IP3.
Water motor alarmsWater motor alarms are local bells mechanically driven by water flow. Water motor alarms are active components not subject to an AMR.
Expansion jointExpansion joint is a component type in the fire pump diesel exhaust system and is included in Tables 2.3.3-11-IP2 and 2.3.3-11-IP3, with the
 
AMR results provided  in LRA Tables 3.3.2-11-IP2 and 3.3.2-11-IP3.
2-82 Filter housingFilter housing is only associated with IP3 components shown on drawing LRA-9321-40903-0. Filter housing is a component type shown in
 
Table 2.3.3-11-IP3, with the AMR results provided in LRA Table 3.3.2-11-IP3.
Gear box housingGear box housings are part of the vendor supplied fire pump diesel engine assembly which is an active component not subject to an AMR.
Heat exchanger (bonnet)There is no heat exchanger (bonnet) associated with the fire protection systems.
Heat exchanger (shell)There is no heat exchanger (shell) associated with the fire protection systems.
Heat exchanger (tube)There is no heat exchanger associated with the fire water systems. The IP3 CO2 system includes a heat exchanger consisting of a coil (tube) in air, which is addressed in LRA Table 2.3.3.12-IP3 as component
 
type heat exchanger (tube), with the AMR results provided in LRA
 
Table 3.3.2-12-IP3.
Heater housingHeater housings are included in Tables 2.3.3-11-IP2 and 2.3.3 11-IP3, with the AMR results provided in LRA Tables 3.3.2-11-IP2 and
 
3.3.2-11-IP3.
Diesel driven fire pump engine mufflerThe diesel driven fire pump engine muffler is component type silencer included in Tables 2.3.3-11-IP2 and
 
2.3.3-11-IP3, with the AMR results provided in LRA Tables 3.3.2-11-IP2 and
 
3.3.2-11-IP3.
OrificeAs stated in LRA Section 2.0 Page 2.0-1, the component type piping may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Orifices in the fire protection water systems are
 
included in LRA Tables 2.3.3-11-IP2 and 2.3.3-11-IP3 under the component type
 
piping, with the AMR results provided in LRA Tables 3.3.2-11-IP2 and
 
3.3.2-11-IP3.
Sight glassSight glasses are not a component type in the fire protection systems subject to an AMR.
Strainer housingStrainer housings are included in Tables 2.3.3.11-IP2 and 2.3.3-11-IP3, with the AMR results provided in LRA Tables 3.3.2-11-IP2 and
 
3.3.2-11-IP3.
Turbocharger housingTurbocharger housing is a part of the fire pump diesel engine assembly, which is an active component not subject to an AMR.
Flexible hoseFlexible hoses are replaced at specified intervals and are therefore not subject to an AMR per 10 CFR 54.21(a)(1)(ii).
Latch door pull boxLatch door pull boxes are active electro-mechanical devices not subject to an AMR.
2-83 Pneumatic actuatorsPneumatic actuators are active components not subject to an AMR. Actuator housingThe actuator housing is part of the valve actuator which is an active assembly with no pressure boundary function; therefore, it is not subject to
 
an AMR. Dikes for oil spill confinementThere are no dikes for oil spill confinement within the scope of license renewal for fire protection.
Buried underground fuel oil tanks for emergency diesel generatorsBuried underground Fuel oil tanks for the emergency diesel generators are addressed in
 
LRA Section 2.3.3.13, Fuel Oil.
Expansion tankExpansion tank is not a component in the fire water system.
 
Fire water main loop valvesFire water main loop valves are included in component type valve body and are included in Tables 2.3.3.11-IP2 and
 
2.3.3.11-IP3, with the AMR results provided in LRA Tables 3.3.2-11-IP2 and
 
3.3.2-11-IP3.
Post-indicator valvesPost-indicator valves are included in component type valve body and are included in Tables 2.3.3.11-IP2 and 2.3.3.11-IP3, with the
 
AMR results provided in LRA Tables 3.3.2-11-IP2 and 3.3.2-11-IP3.
Jacket cooling water keep-warm pump and heaterThe jacket cooling water keep-warm pump and heater are parts of the diesel engine assembly, which is an
 
active assembly not subject to an AMR.
Lubricating oil collection system components for each reactor coolant pump The lubricating oil collection system components for each reactor coolant pump
 
are subject to an AMR and are addressed in LRA Section 2.3.3.12 and
 
Tables 2.3.2-12-IP2 and 2.3.2-12-IP3, with the AMR results provided in LRA
 
Tables 3.3.2-12-IP2 and 3.3.2-12-IP3.
Lubricating oil coolerThe lubricating oil cooler is a part of the fire pump diesel engine assembly, which is an active assembly not subject to an AMR.
Auxiliary lubricating oil makeup tankThe auxiliary lubricating oil makeup tank is not a component in the fire protection systems.
Rocker lubricating oil pumpThe rocker lubricating oil pump is a part of the fire pump diesel engine assembly, which is an active component and not subject to
 
an AMR. Floor drains and curbs for fire-fighting waterFloor drains for fire-fighting water are addressed in LRA Section 2.3.3.18, Plant Drains and Tables 2.3.3-18-IP2
 
and 2.3.3-18-IP3 under component type piping, with the AMR results provided
 
in LRA Tables 3.3.2-18-IP2 and 3.3.2-18-IP3. Curbs are included in the structural 2-84 AMR under component types floor slabs, interior walls and ceilings (for concrete). They are included in LRA Table 2.4-3, with the AMR results provided
 
in LRA Table 3.5.2-3.
Backflow prevention devicesBackflow prevention devices are addressed in LRA Section 2.3.3.18 and Tables 2.3.3-18-IP2 and 2.3.3-18-IP3 under the
 
component type valve body, with the AMR results provided in LRA
 
Tables 3.3.2-11-IP2 and 3.3.2-11-IP3.
Flame retardant coating for cablesFlame retardant coatings for cables are subject to an AMR and are included in the category of bulk commodities
 
evaluated in the structural AMR. Flame retardant coatings are a subcomponent
 
of component types fire barrier penetration seal and fire stop. These
 
component types are included in LRA Table 2.4-4, with the AMR results provided
 
in LRA Table 3.5.2-4.
Fire retardant coating for structural steel supporting walls and ceilingsFire retardant coating for structural steel supporting walls and ceilings are subject to
 
an AMR and are included in the structural AMR as component type fire
 
proofing. This line item is included in LRA Table 2.4-4, with the AMR results
 
provided in LRA Table 3.5.2-4.
In reviewing its response to the RAI, the staff found that the applicant had addressed and resolved each item in the RAI, as discussed in the following paragraphs. Although the
 
description of the piping line item provided in LRA Tables 2.3.3-11-IP2 and 2.3.3-11-IP3 does
 
not list these components specifically, the applicant stated that it considers this line item to
 
include the hose connections, pipe fittings, couplings, threaded connections, restricting orifices, interface flanges, and orifices. LRA Tables 3.3.2-11-IP2 and 3.3.2-11-IP3 provide the AMR
 
results for these components. In addition, the applicant addressed floor drains in LRA
 
Section 2.3.3.18, Plant Drains, and Tables 2.3.3-18-IP2 and 2.3.3-18-IP3 under component
 
type piping, with AMR results provided in LRA Tables 3.3.2-18-IP2 and 3.3.2-18-IP3. The
 
structural AMR includes curbs under component type floor slabs, interior walls and ceiling (for
 
concrete) in LRA Table 2.4-3, with AMR results provided in LRA Table 3.5.2-3. Further, the
 
applicant considers that some components in LRA Table 2.4-4, with AMR results in LRA
 
Table 3.5.2-4, include certain components identified in the RAI. Specifically, the applicant
 
indicated that (1) hose racks and interior fire hose stations are considered fire hose reels,
 
(2) pipe supports are considered piping supports, (3) flame retardant coating for cables is
 
considered a subcomponent of component types fire barrier penetration seal and fire stop,
 
and (4) fire retardant coating for structural steel supporting walls and ceilings is considered fire
 
proofing. The staff finds this portion of the applicant's response to RAI 2.3A.3.11-2 acceptable
 
because it confirms that the components in question are within the scope of license renewal and
 
subject to an AMR. In addition, the response also directed the staff to the AMR results in the
 
LRA.In its response, the applicant also confirmed that thermowells and expansion joints are a component type within the fire pump diesel exhaust system; the diesel-driven fire pump engine
 
muffler is included in component type silencer; and the fire water main loop valves, post-indicator valves, and backflow prevention devices are included in component type valve body
 
in LRA Tables 2.3.3-11-IP2 and 2.3.3-11-IP3, with the AMR results provided in LRA
 
Tables 3.3.2-11-IP2 and 3.3.2-11-IP3. Filter housing is only associated with IP3 components 2-85 shown on license renewal drawing LRA-9321-40903-0 and included in LRA Table 2.3.3-11-IP3, with the AMR results provided in LRA Table 3.3.2-11-IP3. LRA Section 2.3.3.13, Fuel Oil,
 
addresses buried underground fuel oil tanks for EDGs. Lubricating oil collection system
 
components for each RCP are addressed in LRA Section 2.3.3.12 and Tables 2.3.3-12-IP2 and
 
2.3.3-12-IP3, with the AMR results provided in LRA Tables 3.3.2-12-IP2 and 3.3.2-12-IP3. The
 
staff finds this portion of the applicants response to RAI 2.3A.3.11-2 acceptable because it
 
confirms that the components in question are within the scope of license renewal and subject to
 
an AMR. Furthermore, the response directed the staff to the AMR results in the LRA.
The staff found that the applicant did not include the following components in the line item descriptions in the LRA: (1) heat-actuated devices, (2) tank heaters, (3) water motor alarm, (4) gear box housings, (5) turbocharger housing, (6) latch door pull box, (7) pneumatic
 
actuators, (8) actuator housings, (9) jacket cooling water keep-warm pump and heater, (10) lubricating oil cooler, and (11) rocker lubricating oil pump. Because these components are
 
active, they are not subject to an AMR.
The following components are not part of the fire protection systems (water) in IP2 and IP3:
(1) heat exchanger (bonnet), (2) heat exchanger (shell), (3) heat exchanger (tube); (4) sight
 
glass expansion tanks, (5) auxiliary lubricating oil makeup tanks, and (6) dikes for oil spill
 
confinement. Since these components are not used in the fire protection systemwater at IP2
 
and IP3, the staff finds that the applicant appropriately omitted them from the scope of license
 
renewal.Although they are within the scope of license renewal, flexible hoses are replaced at specified intervals. Therefore, the staff finds that flexible hoses are not subject to an AMR, in accordance
 
with 10 CFR 54.21(a)(1)(ii).
The applicant determined that yard hose houses are not subject to an AMR because their failure will not result in a failure of the fire suppression function of the associated fire hydrant.
 
Similarly, the applicant determined that chamber housings are not subject to an AMR because
 
their failure will not result in a failure of the fire suppression function of the sprinkler system. The
 
yard hose houses and chamber housings are passive, long-lived components that were
 
identified as within the scope of license renewal. Therefore, the staff considers these
 
components to be subject to an AMR, in accordance with 10 CFR 54.21(a)(1). This was
 
identified as Open Item 2.3A.3.11-1.
Based on its review, the staff found the applicants response to RAI 2.3A.3.11-2 partially acceptable because it resolved the staffs concerns regarding scoping and screening of fire
 
protection system components listed in the RAI, with the exception of (a) yard hose houses and (b) chamber housings.
By the letter January 27, 2009, the applicant stated that yard hose houses for IP-2 are not a building; they are a metal cabinet storage location containing fire hoses and supporting tools (spanner, gated wyes and nozzles). The hose contained therein is subject to periodic
 
inspection, testing and replacement in accordance with NFPA standards. Yard hose houses
 
provide no function that supports 10 CFR 50.48 requirements: therefore, they are not in the
 
scope of license renewal.
Chamber housings are small surge suppression volumes that function to minimize false actuation alarms due to system pressure surges. The chambers receive water from a small 2-86 bypass line upon actuation of a deluge fire suppression system. When the chamber fills, water flow continues through the chamber to a drain line. Due to the limited amount of water flowing to
 
the chamber housings, neither normal operation nor failure of the chamber housing would
 
prevent satisfactory operation of the fire suppression system. In addition, the chamber housings
 
shown on IP2 drawings are associated with deluge valves that do not perform a function that is
 
credited for compliance with 10 CFR 50.48. The fire suppression systems with chamber
 
housings serve maintenance areas and a file room in the technical support center.
The applicant clarified that yard fire hydrants are housed in small sheds; and chamber housings are small surge suppression volumes that function to minimize false actuation alarms due to
 
system pressure surges. The staff determined that failure of these components, which is a
 
second level support system, need not be considered in determining the SCs within the scope
 
of the license renewal under 10 CFR 54.4(a)(3). The staff concludes that the above components
 
were correctly excluded from the scope of license renewal. The staffs concern identified in
 
Open Item 2.3A.3.11-1 has been resolved. Therefore, Open Item 2.3A.3.11-1 is closed.
2.3A.3.11.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine 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 fire protection - water system components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3A.3.12  IP2 Fire Protection-Carbon Dioxide, Halon, and RCP Oil Collection Systems 2.3A.3.12.1  Summary of Technical Information in the Application LRA Section 2.3.3.12 describes the fire protection
-CO 2 , Halon 1301 and RCP oil collection system, which consists of fixed fire suppression systems utilizing Halon 1301 as well as oil
 
leakage collection for the RCPs. IP2 does not have a CO 2 fire suppression system within the scope of license renewal. The Halon 1301 systems consist of gas storage tanks and the
 
necessary piping, valves, and instrumentation. The RCP oil collection system consists of drain
 
pans, collection tanks, and the necessary piping, valves, and instrumentation to collect any
 
leakage of the RCP lube oil system.
A fixed Halon fire suppression system meets 10 CFR 50.48 requirements for the cable spreading room as a total-flooding, manually-actuated system divided into four zones of
 
discharge nozzles. The RCP oil collection system can collect lube oil from all potential
 
pressurized and unpressurized RCP lube oil system leakage sites and drain it to a vented
 
closed tank that can hold the required lube oil system inventory.
The fire protection Halon and RCP oil collection systems have no intended function under 10 CFR 54.4(a)(1). The scoping and screening methodology identified the following RCP oil
 
collection system intended function, in accordance with 10 CFR 54.4(a)(2): Maintain integrity of
 
nonsafety-related components such that no physical interaction with safety-related components
 
could prevent satisfactory accomplishment of a safety function.
2-87 The scoping and screening methodology also identified the following Halon and RCP oil collection systems intended functions, in accordance with 10 CFR 54.4(a)(3):  Provide fixed automatic and manual fire suppression to extinguish fires in vital areas of
 
the plant (10 CFR 50.48). Provide each RCP an oil collection system that is designed to contain and direct the oil
 
to remote storage containers in the event of an oil leak.
LRA Tables 2.3.3-12-IP2 and 2.3.3-19-11-IP2 identify fire protection
-CO 2 , Halon 1301 and RCP oil collection system component types within the scope of license renewal and subject to
 
an AMR, as well as their intended functions.
2.3A.3.12.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.12, UFSAR Section 9.6.2, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
The staff also reviewed NRC fire protection SERs for IP2, dated November 30, 1977; February 3, 1978; January 31, 1979; October 31, 1980; August 22, 1983; March 30, 1984;
 
October 16, 1984; September 16, 1985; November 13, 1985; March 4, 1987; January 12, 1989;
 
and March 26, 1996.
The staff also reviewed IP2 commitments made in response to the requirements of 10 CFR 50.48 (i.e., an approved fire protection program), using its commitment documents
 
associated with BTP APCSB 9.5-1 and Appendix A to BTP APCSB 9.5-1.
During its review of LRA Section 2.3.3.12, the staff identified areas in which additional information was necessary to complete its review of the applicants scoping and screening
 
results. The applicant responded to the staffs RAIs as discussed below.
In RAI 2.3A.3.12-1, dated October 24, 2007, the staff questioned why LRA Table 2.3.3-12-IP2 and 2.3.3-12-IP3 excluded several types of CO 2 and Halon 1301 fire suppression system components discussed in the fire protection SERs or the UFSAR or both and which are
 
identified in the License renewal drawing as subject to an AMR (i.e., they are highlighted in
 
brown). These components include the following:  strainer housing  pipe fittings  pipe supports  couplings odorizer threaded connections 2-88 flexible hose  latch door pull box  pneumatic actuators The staff requested that the applicant verify whether LRA Tables 2.3.3-12-IP2 and 2.3.3-12-IP3 should include the components listed above. If they are excluded from the scope of license
 
renewal and not subject to an AMR, the staff requested that the applicant justify their exclusion.
In its response, dated November 16, 2007, the applicant provided the following:
Strainer housingsBased on a review of LRA drawings D-8775-002-0, D-8775-004-0, D-8775-005-0 and 9321-24403-0, there are no strainer housings
 
in the Halon systems.
Pipe fittingsAs stated in LRA Section 2.0 Page 2.0-1, the term piping may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Pipe fittings are subject to an AMR and included in LRA
 
Tables 2.3.3-12-IP2 and 2.3.3-12-IP3, with AMR results provided in
 
Tables 3.3.2-12-IP2 and 3.3.2-12-IP3, under the component type piping.
Pipe supportsPipe supports are subject to an AMR and are included in the structural AMR as shown in LRA Table 2.4-4, under component and piping
 
supports.
CouplingsAs stated in LRA Section 2.0, Page 2.0-1, the term piping may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Couplings are considered to be pipe fittings, subject to an AMR
 
and included in the piping line item in LRA Tables 2.3.3-12-IP2 and
 
2.3.3-12-IP3, with AMR results provided in Tables 3.3.2-12-IP2 and 3.3.2-12-IP3.
OdorizerAs stated in LRA Section 2.0, Page 2.0-1, the term piping may include pipe, pipe fittings (such as elbows and reducers), flow elements, orifices, and thermowells. Odorizer housings are subject to an AMR and are included in
 
component type piping in LRA Tables 2.3.3-12-IP2 and 2.3.3-12-IP3, with AMR
 
results provided in Tables 3.3.2-12-IP2 and 3.3.2-12-IP3. The internals of the
 
odorizer are active (short-lived components) subcomponents and not subject to
 
an AMR. Threaded connectionsAs stated in LRA Section 2.0 Page 2.0-1, the term piping may include pipe, pipe fittings (such as elbows and reducers), flow
 
elements, orifices, and thermowells. Threaded connections are pipe fittings
 
subject to an AMR and included in the piping line item in LRA
 
Tables 2.3.3-12-IP2 and 2.3.3-12-IP3, with AMR results provided in
 
Tables 3.3.2-12-IP2 and 3.3.2-12-IP3.
Flexible hoseThere are no flexible hoses utilized in the in-scope Halon systems. LRA drawing D-8775-005-0 is based on a vendor drawing that indicates
 
flex hoses at the gas cylinders. Flexible hoses are not used in the IP2 and IP3
 
configuration. Flexible hoses are utilized in the RCP oil collection system for IP2
 
and IP3 as indicated in Tables 2.3.3-12-IP2 and 2.3.3-12-IP3, with AMR results 2-89 provided in Tables 3.3.2-12-IP2 and 3.3.2-12-IP3. These hoses are stainless steel hoses that are not replaced on a specified frequency.
Latch door pull boxLatch door pull boxes are active electro-mechanical devices and not subject to an AMR.
Pneumatic actuatorsPneumatic actuators (in the form of gas operated pilot valves) are utilized in the in-scope Halon 1301 systems. Actuation is by means of
 
active electrical devices which actuate pilot valves utilizing gas pressure as the
 
motive force. The pilot valves and process valves are included under the
 
component type valve body and are subject to an AMR.
Based on its review, the staff finds the applicants response to RAI 2.3A.3.12-1 acceptable.
Although the description of the piping line item provided in LRA Tables 2.3.3-11-IP2 and
 
2.3.3-11-IP3 does not list these components specifically, the applicant stated that it considers
 
pipe fittings, pipe supports, couplings, odorizer, and threaded connections to be included in LRA
 
Tables 2.3.3-12-IP2 and 2.3.3-12-IP3 under the component type piping with the AMR results
 
provided in LRA Tables 3.3.2-12-IP2 and 3.3.2-12-IP3.
The applicant has included pneumatic actuators in LRA Tables 2.3.3-12-IP2 and 2.3.3-12-IP3 under the component type valve body, with the AMR results provided in LRA
 
Tables 3.3.2-12-IP2 and 3.3.2-12-IP3. In similar license renewal reviews, components excluded
 
from the list of components subject to an AMR and from the associated definition of a line item
 
term, such as the piping line item, are often modified to include components that were not
 
previously named, either in the component list or in the definition, for completeness. Because
 
the applicant considers the line items specified to include these components, the staff finds that
 
these components have been appropriately included within the scope of license renewal and
 
identified as being subject to an AMR.
Further, the applicant noted that some components in LRA Table 2.4-4 are presented in LRA Table 3.5.2-4. Specifically, the applicant indicated that (1) hose racks and interior fire hose
 
stations are considered fire hose reels, (2) pipe supports are considered piping supports,
 
(3) flame retardant coating is considered a subcomponent of fire barrier penetration seal and
 
fire stop, and (4) fire retardant coating for structural steel supporting walls and ceilings is
 
considered fire proofing.
Also, the applicant confirmed that the Halon 1301 systems do not utilize flexible hoses, and these systems do not include strainer housings.
The staff found that the line item descriptions in the LRA do not include latch door pull boxes.
The staff accepts the applicants explanation that latch door pull boxes are active components
 
and, therefore, not subject to an AMR. The staffs concern described in RAI 2.3A.3.12-1 is
 
resolved.2.3A.3.12.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its 2-90 review, the staff concludes that the applicant has adequately identified the fire protection Halon 1301, and RCP oil collection systems components within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3A.3.13  IP2 Fuel Oil Systems 2.3A.3.13.1  Summary of Technical Information in the Application LRA Section 2.3.3.13 describes the fuel oil systems for IP2 and IP3 EDGs, the IP2 security diesel generator, IP2 and IP3 Appendix R diesel generators, and IP2 and IP3 fire protection
 
diesel-driven fire pumps.
The IP2 fuel oil system code (i.e., the applicants code for designating systems and boundaries) which includes the 1-million-gallon IP1 fuel oil tank and many of its associated components, but
 
not the safety-related EDG fuel oil components, and has no safety-related components. The fuel
 
oil system includes components that supply the bulk fuel oil to site components, including the
 
house heating boiler and the bulk fuel oil supply to IP3. The IP1 fuel oil tank and its piping are
 
not required to support fire diesel or EDG operation. These components have separate fuel oil
 
tanks.The fuel oil section includes the gas turbine system description because the only intended function of the gas turbine system for license renewal is performed by its fuel oil subsystem. The
 
fuel supply for gas turbines in the IP2 gas turbine system supplements fuel oil storage for the
 
IP2 and IP3 EDGs. This shared fuel storage consists of two onsite 30,000-gallon fuel oil tanks
 
and a 200,000-gallon storage tank at the Buchanan Substation site. A 29,000-gallon minimum
 
from these storage tanks is dedicated for EDG use. The tanks are not connected directly to the
 
EDG fuel oil storage tanks, but trucking facilities can transfer oil within 1 days notice.
Each diesel fuel oil storage and transfer system supplying fuel to the EDGs has its own fuel oil day tank, as well as an underground storage tank. The day tanks are within the diesel generator
 
buildings. An engine-driven fuel oil pump feeds the fuel from the day tank to supply the engine.
The day tank fills automatically during engine operation from its dedicated underground storage
 
tank adjacent to the diesel generator building. Each underground storage tank has a
 
motor-driven pump to transfer fuel to the day tank.
Independent diesel fuel oil storage and transfer systems supply fuel to the IP2 and IP3 fire protection diesel engines. The IP2 fuel oil storage tank, pump, and components are in the IP2
 
diesel fire pump house.
An independent diesel fuel oil storage and transfer system supplies fuel to the IP2 security diesel generator, which has its own fuel oil day tank within the security access building diesel
 
generator room as well as an independent underground storage tank adjacent to that building.
An independent diesel fuel oil storage and transfer system supplies fuel to the IP2 SBO/Appendix R diesel generator from the gas turbine fuel oil storage tanks and transfer pumps
 
in the oil room. The SBO/Appendix R diesel generator has its own day tank, which supplies fuel to the engine. The day tank fills automatically during engine operation from the storage tanks by
 
the transfer pumps.
2-91 The fuel oil system and subsystems contain safety-related components relied on to remain functional during and following DBEs. They also contain nonsafety-related components whose
 
failure potentially could prevent the satisfactory accomplishment of a safety-related function. In
 
addition, the fuel oil system and subsystems perform functions that support fire protection and
 
SBO.LRA Tables 2.3.3-13-IP2 and 2.3.3-19-10-IP2 identify fuel oil system and subsystems component types within the scope of license renewal and subject to an AMR as well as their
 
intended functions.
2.3A.3.13.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13, UFSAR Sections 8.1, 8.2, and 8.2.3, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.3.13, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. For discussion and disposition of RAI 2.3A.3.13-1, dated February 13, 2008, see SER
 
Section 2.3A.3 in the discussion of Staffs RAIs.
2.3A.3.13.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI response, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its
 
review, the staff concludes that the applicant has appropriately identified the fuel oil system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3A.3.14  IP2 Emergency Diesel Generator System 2.3A.3.14.1  Summary of Technical Information in the Application LRA Section 2.3.3.14 describes the EDG system, which supplies emergency shutdown power upon loss of all other alternating current auxiliary power and consists of three EDG sets, each
 
with a diesel engine coupled to a 480-V generator. Each emergency diesel includes two
 
redundant air motors for automatic starting, an air storage tank and compressor system, its own
 
starting air subsystem, fuel oil subsystem, intake air subsystem, exhaust subsystem, lube oil
 
subsystem, and jacket water cooling subsystem. The EDG system also includes ventilation
 
equipment for the diesel generator building.
2-92 The EDG system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the EDG
 
system performs functions that support fire protection.
Some of the valves in this system are parts of the SW system pressure boundary reviewed with the SW system (LRA Section 2.3.3.2). The fuel oil subsystem components are reviewed with
 
fuel oil (LRA Section 2.3.3.13). A small number of components are reviewed with the city water
 
system (LRA Section 2.3.3.17).
LRA Tables 2.3.3-14-IP2 and 2.3.3-19-9-IP2 identify EDG system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.3.14.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.14, UFSAR Section 8.2.3, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.3.14, the staff identified areas in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The discussion of the staffs RAIs in SER Section 2.3A.3 details the disposition of
 
RAI 2.3A.3.14-2, dated February 13, 2008. The applicant responded to additional staff RAIs as
 
discussed below.
In RAI 2.3A.3.14-1, dated December 7, 2007, the staff noted that a license renewal drawing for the IP2 jacket water to the EDGs identifies that the jacket water pumps for diesel engine
 
Nos. 21, 22, and 23, respectively, are not subject to an AMR, in accordance with
 
10 CFR 54.21(a), because they are not long-lived components. The staff stated that SRP-LR, Table 2.3-2, Examples of Mechanical Components Screening and Basis for Disposition,
 
provides examples of passive, long-lived components, such as diesel engine jacket water skid-
 
mounted equipment. To complete its review, the staff requested that the applicant confirm that
 
the jacket water pumps are short-lived components and describe its method for periodic
 
replacement.
In its response, dated January 4, 2008, the applicant stated that the IP2 EDG maintenance procedures specify that the jacket water pumps in question are scheduled for replacement every
 
16 years, in accordance with station maintenance procedures. Therefore, they are not subject to
 
an AMR.Based on its review, the staff finds the applicants response to RAI 2.3A.3.14-1 acceptable because it adequately explained that the practice of replacing the jacket water pumps meets the
 
intent of 10 CFR 54.21(a)(1)(ii) for short-lived components and that the maintenance procedures 2-93 ensure the pumps periodic replacement. Therefore, the staff agrees that the jacket water pumps are not subject to an AMR. The staffs concern described in RAI 2.3A.3.14-1 is resolved.
In RAI 2.3A.3.14-2, dated December 7, 2007, the staff noted that license renewal drawings for the IP2 and IP3 EDG jacket water cooling systems and EDG fuel oil systems identify multiple
 
flexible conn [connections] as not being long-lived components; therefore, they are not subject
 
to an AMR. In LRA Section 2.1.2.1.3, Mechanical System Drawings, the applicant stated, Flexible elastomer hoses/expansion joints that are periodically replaced (not long-lived) and
 
therefore not subject to aging management review are indicated as such on the drawings.
 
Screening guidance provided in Table 2.1-3 of the SRP-LR describes items considered to be
 
consumables as short lived and subject to periodic replacement. The staff requested that the
 
applicant describe the programs that manage the replacement activities for these flexible
 
connections.
In its response, dated January 4, 2008, the applicant stated that EDG maintenance procedures specify that the flexible connections in the EDG jacket water and fuel oil systems are
 
components that are periodically replaced. The applicant further explained that, in accordance
 
with 10 CFR 54.21(a)(1)(ii), components that are subject to periodic replacement based on a
 
specified time period are not subject to an AMR.
Based on its review, the staff finds the applicants response to RAI 2.3A.3.14-2 acceptable because it adequately explained that flexible connections are periodically replaced, as directed
 
by EDG maintenance procedures. Therefore, these connections are not subject to an AMR, in
 
accordance with 10 CFR 54.21(a)(1)(ii). The staff agrees that the flexible connections
 
designated as not long lived are not subject to an AMR. The staffs concern described in
 
RAI 2.3A.3.14-2 is resolved.
In RAI 2.3.0-2, dated February 13, 2008, the staff noted that the license renewal drawings for the IP2 and IP3 EDG jacket water cooling systems have components marked Not a Long Lived
 
Component. The staff noted that SRP-LR Section 2.1.3.2.2 describes long-lived SCs as those
 
that are not subject to periodic replacement based on a qualified life or specified time period.
 
Furthermore, the LRA states that replacement programs may be based on vendor
 
recommendations, plant experience, or any means that establish a specific replacement
 
frequency under a controlled program.
Previous LRAs typically have not designated pumps, motors, and heat exchangers as not long lived. Therefore, the staff requested that the applicant do the following: (a) Identify the component types serviced by the CCW that are shown as Not a Long Lived Component.(b)  Provide a basis for designating these components as not long lived, including details as to how the qualified life of the components was established, a description of the
 
program under which aging management activities for the components are performed, and any available plant-specific operating experience confirming the effectiveness of
 
management activities.
In its response, dated March 12, 2008, the applicant identified the components designated as not long lived in the EDG jacket cooling water as flexible connections and pump casings. The
 
applicant explained that these components are replaced on an established frequency, in 2-94 accordance with vendor recommendations. The applicant stated that the plant-specific operating experience did not identify any instances of EDG jacket cooling water flexible
 
connection or pump failures, thus confirming the effectiveness of the replacement activities.
Based on its review, the staff finds the applicants response to RAI 2.3.0-2 for the EDG system acceptable because it adequately provides the basis for the applicants designation of the EDG
 
jacket cooling water flexible connections and pump casings as short-lived components, in
 
accordance with the guidance found in SRP-LR Section 2.1.3.2.2. The staffs concern described
 
in RAI 2.3.0-2 is resolved.
2.3A.3.14.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its
 
review, the staff concludes that the applicant has appropriately identified the EDG system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3A.3.15  IP2 Security Generator System 2.3A.3.15.1  Summary of Technical Information in the Application LRA Section 2.3.3.15 describes the security system, which provides plant security equipment, most of which is not mechanical. The security diesel generates back-up electrical power to
 
security equipment, including lighting of the operator access and egress routes for Appendix R
 
events.The security system performs functions that support fire protection.
 
The fuel oil subsystem components are reviewed with fuel oil (LRA Section 2.3.3.13).
 
LRA Table 2.3.3-15-IP2 identifies security system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.3.15.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.15 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 to verify that the applicant had not omitted from the scope of license renewal any components with intended
 
functions, as required by 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant identified as within the scope of license renewal to verify that it had not omitted any
 
passive and long-lived components subject to an AMR, in accordance with 10 CFR 54.21(a)(1).
2-95 2.3A.3.15.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In addition, the staff sought to
 
determine whether the applicant failed to identify any components subject to an AMR. The staff
 
found no such omissions. On the basis of its review, the staff concludes that the applicant has
 
adequately identified the security generator system components within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3A.3.16  IP2 Appendix R Diesel Generator System 2.3A.3.16.1  Summary of Technical Information in the Application By letter dated April 30, 2008, the applicant amended its LRA to reflect the installation of the IP2 SBO/Appendix R diesel generator.
LRA Section 2.3.3.16, as amended, describes the SBO/Appendix R diesel generator system, which supplies power to selected equipment and power supplies relied on in Appendix R and
 
SBO events. With sufficient power for safe-shutdown loads, the SBO/Appendix R diesel
 
generator is the source of alternate alternating current power for IP2, as required by
 
10 CFR 50.63. The SBO/Appendix R diesel generator provides power during Appendix R and
 
SBO events. The IPA for license renewal included the SBO/Appendix R diesel generator within
 
the scope of license renewal.
The SBO/Appendix R diesel is located inside the IP1 turbine building. The SBO/Appendix R diesel generator is designed to operate upon a complete loss of power. The SBO/Appendix R
 
diesel generator includes batteries, a battery charger, jacket water heater and cooler, turbochargers, aftercoolers, aftercooler coolers, jacket water pump, lube oil cooler, lube oil
 
pump, and necessary filters and piping. The SBO/Appendix R diesel generator can supply
 
safe-shutdown loads through the 6.9-kilovolt (kV) distribution system and the emergency 480-V
 
buses and motor control centers or the turbine building switchgear and motor control centers.
The SBO/Appendix R diesel generator system performs functions that support fire protection and SBO. Fuel oil supply components are evaluated with fuel oil (LRA Section 2.3.3.13). Appendix R diesel generator system ventilation is evaluated with the HVAC systems (LRA Section 2.3.3.8). LRA Table 2.3.3-16-IP2 identifies SBO/Appendix R diesel generator system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.3.16.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.16 and license renewal drawings 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 to verify that the applicant had not omitted from the scope of license renewal any components with intended
 
functions, as required by 10 CFR 54.4(a). The staff then reviewed those components that the 2-96 applicant identified as within the scope of license renewal to verify that it had not omitted any passive and long-lived components subject to an AMR, in accordance with 10 CFR 54.21(a)(1).
The staff reviewed the amended LRA, changes to the UFSAR, and two license renewal drawings to determine whether the applicant failed to identify any SSCs typically found within
 
the scope of license renewal. SER Sections 3.3.2.1 and 3.3A.2.3.13 document the staffs
 
evaluation of the amended AMR results for the SBO/Appendix R diesel generator system.
2.3A.3.16.3  Conclusion
 
The staff reviewed the LRA, the UFSAR, the LRA amendment, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff
 
found no such omissions. In addition, the staff sought to determine whether the applicant failed
 
to identify any components subject to an AMR. The staff found no such omissions. On the basis
 
of its review, the staff concludes that the applicant has adequately identified the
 
SBO/Appendix R diesel generator system components within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3A.3.17  IP2 City Water 2.3A.3.17.1  Summary of Technical Information in the Application LRA Section 2.3.3.17 describes the city water system, which supplies water to various plant components. Originally installed for IP1, the city water system now functions for all three units.
 
The city water system code includes IP1 and IP2 components. Water for the system comes
 
from the Village of Buchanan. Within the boundary of the plant system are the supply piping
 
from the water main, pressure-regulating valves, strainers, water meters, and backflow
 
preventers. After metering, the water flows to a manifold which directs it to either the plant or the
 
1.5-million-gallon city water storage tank. The plant uses city water to supply fire protection systems, the SBO/Appendix R diesel generator, sanitary and drinking facilities (e.g., emergency
 
showers, eye wash stations, humidifiers, hose connections, sinks, water coolers, water heaters, and lavatories), radiation monitors for purging, and various equipment for makeup or cooling; to
 
supply backup to the AFW pumps; and to serve other emergency purposes. The system is also
 
a CCW backup for bearing and seal water cooling for the charging, safety injection, and RHR
 
pumps.The city water system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the city
 
water system performs functions that support fire protection and SBO.
LRA Section 2.3.4.5 reviews components that support safe shutdown in the event of an auxiliary feed pump room fire.
LRA Tables 2.3.3-17-IP2 and 2.3.3-19-7-IP2 identify city water system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2-97 2.3A.3.17.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.17, UFSAR Sections 9.6.3 and 10.2.6.3, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.3.17, the staff identified areas in which additional information was necessary to complete the review of the applicants scoping and screening results. The applicant responded to the staffs RAIs as discussed below.
In RAI 2.3A.3.17-1, dated December 7, 2007, the staff noted that the applicant highlighted a small portion of 2-inch city water line No. 35 on a license renewal drawing in purple, indicating
 
that it is within the scope of license renewal and subject to an AMR for the city water system.
 
The staff also noted that the identified piping, which is shown in a detail, makes no reference to
 
a continuation drawing, and the detailed area of the drawing references another drawing, which
 
the applicant did not include in the LRA.
The staff questioned whether this piping section contains additional components that should be included within the scope of license renewal. Therefore, the staff requested that the applicant
 
either explain why the LRA did not list the parent drawing for the detailed area under license
 
renewal drawings for the city water system or provide the parent drawing and any other
 
continuation drawings that contain components within the scope of license renewal.
In its response, dated January 4, 2008, the applicant stated that the parent drawing is an equipment general arrangement drawing that includes all of the components shown on the
 
drawing which included the detail. The applicant further stated that no additional components
 
are shown on the parent drawing, and the section of 2-inch city water line No. 35 in the detail is
 
continued on another license renewal drawing that shows the ghost image of a valve
 
connecting to the 2-inch city water line No. 35.
Based on its review, the staff finds the applicants response to RAI 2.3A.3.17-1 acceptable because it adequately explained that the parent drawing is an equipment general arrangement
 
drawing that includes all of the components shown in the detail on the license renewal drawing.
 
The staff finds no need for the applicant to bring the additional components for the city water
 
system within the scope of license renewal. Although not identified on the license renewal
 
drawing, the applicant explained that the continuation of the 2-inch city water line No. 35
 
appears on another license renewal drawing, which had been provided to the staff with the LRA.
 
The staffs concern described in RAI 2.3A.3.17-1 is resolved.
In RAI 2.3A.3.17-2, dated December 7, 2007, the staff stated that a license renewal drawing shows piping highlighted in purple, indicating that the piping for the city water system is within
 
the scope of license renewal and subject to an AMR.
2-98 The staff noted that, at four fire protection system valves on the drawing, the system designation changes from the city water system to the fire protection system. Additionally, the staff noted that, at one other fire protection system valve on the drawing, the system designation changes from the city water system to the AFW system. Although the identified system designation
 
changes, the highlighting remains purple. The staff noted that the components indicated should
 
be subject to an AMR under the scope of the city water system. The staff requested that the
 
applicant explain how the color coding applies to the multiple systems identified above.
In its response, dated January 4, 2008, the applicant stated that the fire protection system, which is highlighted in green, is a high-pressure water system that serves structures and
 
strategically located hydrants. The applicant further explained that the city water system, which
 
is highlighted in purple, is a low-pressure system that provides backup to the high-pressure
 
system and includes the low-pressure hydrants. The applicant explained that components in
 
both systems are used for fire protection and that, when performing scoping and screening of
 
components for license renewal, the applicant included components that are part of the
 
low-pressure city water system flowpath and required to accomplish city water system functions
 
in the city water system, regardless of their component identification or the system designator
 
shown on the drawing. Further, the applicant explained that it included components that are part
 
of the high-pressure fire protection system flowpath and required to accomplish fire protection
 
system functions in the fire protection system, regardless of their component identification or the
 
system designator shown on the drawing. The applicant also stated that the system designators
 
shown on the license renewal drawings do not define system boundaries, thus ensuring that all
 
components required to accomplish system functions are included within the scope of license
 
renewal. The applicant included the fire protection valves as part of the city water system with a
 
pressure boundary intended function because they are fed by the low-pressure city water
 
system and are required to accomplish the city water system functions identified in LRA
 
Section 2.3.3.17.
Based on its review, the staff finds the applicants response to RAI 2.3A.3.17-2 acceptable because it adequately explained that system designators shown on the license renewal
 
drawings do not define system boundaries. The applicant included the fire protection valves as
 
part of the city water system with a pressure boundary intended function because they are fed
 
by the low-pressure city water system and are needed to accomplish the city water system
 
functions related to fire protection. The staffs concern described in RAI 2.3A.3.17-2 is resolved.
In RAI 2.3A.3.17-3, dated December 7, 2007, the staff stated that, in the upper left corner of a license renewal drawing for the city water system, two 6-inch pipe lines are shown with a fire
 
protection designation highlighted in purple, indicating that they are within the scope of license
 
renewal and subject to an AMR. The staff requested that the applicant explain why the two fire protection lines are highlighted in purple (indicating that they are part of the city water system
 
for license renewal) instead of green (indicating that they are part of the fire protectionwater
 
system). In its response, dated January 4, 2008, the applicant stated that the fire protection system, which is highlighted in green, is a high-pressure water system that serves structures and
 
strategically located hydrants. The city water system, which is highlighted in purple, is a low-
 
pressure system that provides backup to the high-pressure system and includes the low-
 
pressure hydrants. The applicant further explained that it included components that are part of
 
the high-pressure fire protection system flowpath and required to accomplish fire protection
 
system functions in the fire protection system, regardless of their component identification or the 2-99 system designator shown on the drawing. The applicant also explained that the system designators shown on the license renewal drawings do not define system boundaries.
Based on its review, the staff finds the applicants response to RAI 2.3A.3.17-3 acceptable because it adequately explained that the fire protection lines are within the scope of license
 
renewal as part of the city water system, and they have a pressure boundary intended function.
 
The fire protection lines are fed by the low-pressure city water system and are needed to
 
accomplish the city water system functions related to fire protection. Therefore, the staffs
 
concern described in RAI 2.3A.3.17-3 is resolved.
In RAI 2.3A.3.17-4, dated December 7, 2007, the staff stated that a license renewal drawing shows a short piece of piping for the city water system highlighted in purple, indicating that it is
 
within the scope of license renewal and subject to an AMR. The staff noted that this short piece
 
of city water system piping refers to two drawings for upstream piping. Since this short piece of
 
city water system piping is within the scope of license renewal and continues onto the two
 
upstream drawings, these two drawings should also have city water system piping within the
 
scope of license renewal. However, the staff noted that the applicant did not list these two
 
drawings in the LRA as license renewal drawings for the IP2 and IP3 city water system. The
 
staff requested that the applicant explain why it had not listed the two referenced drawings in
 
the LRA under license renewal drawings for the city water system.
In its response, dated January 4, 2008, the applicant stated that the two referenced drawings are not system flow diagrams, but equipment general arrangement drawings, which were not
 
clear enough to use as license renewal drawings. The applicant further explained that it
 
reviewed these two drawings to confirm that all components shown on them that are required to
 
accomplish city water system functions were included within the scope of license renewal and
 
subject to an AMR. The applicant concluded that the only components shown on these
 
drawings are piping and 11 valves, all of which are within the scope of license renewal and
 
subject to an AMR.
Based on its review, the staff finds the applicants response to RAI 2.3A.3.17-4 acceptable because it adequately explained that the two drawings are equipment general arrangement
 
drawings for which a review was performed to confirm that all components shown are required
 
for city water system functions and were included within the scope of license renewal and
 
subject to an AMR. The staff understands that the only components shown on these two
 
drawings are piping and 11 valves, which are already within the scope of license renewal and
 
subject to an AMR. The staffs concern described in RAI 2.3A.3.17-4 is resolved.
In RAI 2.3A.3.17-5, dated December 7, 2007, the staff noted that, in the LRA, the applicant stated that the IP2 city water system has the intended function under 10 CFR 54.4(a)(3) of
 
providing a supply of water to fire protection system components, including the fire pumps, fire
 
hydrants, hose reel stations inside containment, fire water tank, and various sprinkler and
 
deluge systems. The staff also noted that a license renewal drawing shows piping for the city
 
water system highlighted in blue, indicating that it is within the scope of license renewal and
 
subject to an AMR. The piping continues onto three additional drawings for downstream piping, which are not listed in the LRA. The staff noted that this additional piping and associated components are necessary for the city water system to accomplish its intended function to
 
supply water from the IP2 city water system to the hose reel stations inside containment. The
 
staff was concerned that the additional drawings might show city water system components that
 
were not identified in the LRA. The staff requested that the applicant provide the three drawings 2-100 and any other drawings, as necessary, showing the LRA scope of the IP2 city water system.
In its response, dated January 4, 2008, the applicant stated that the three drawings referenced are not system flow diagrams, but equipment general arrangement drawings, which were not
 
clear enough to use as license renewal drawings. The applicant explained that it reviewed these
 
three drawings to confirm that all of the components shown on them that are required to
 
accomplish city water system functions were included within scope of license renewal and
 
subject to an AMR. The only components shown on these drawings are piping and 19 valves, which are within the scope of license renewal and subject to an AMR.
Based on its review, the staff finds the applicants response to RAI 2.3A.3.17-5 acceptable because it adequately explained that the three drawings are equipment general arrangement
 
drawings for which a review was performed to confirm that all the components shown on them
 
that are required for city water system functions were included within the scope of license
 
renewal and subject to an AMR. The staff understands that the only components shown on
 
these three drawings are piping and 19 valves, which are already within the scope of license
 
renewal and subject to an AMR. The staffs concern described in RAI 2.3A.3.17-5 is resolved.
In RAI 2.3A.3.17-6, dated December 7, 2007, the staff stated that a license renewal drawing for the city water system showed a fire hydrant highlighted in purple, indicating that it is within the
 
scope of license renewal and subject to an AMR because it supports an intended function, in
 
accordance with 10 CFR 54.4(a). The staff noted that the LRA component table for the city
 
water system does not include the component type hydrant. The staff stated that
 
10 CFR 54.21(a)(1) requires that the applicant identify and list those components subject to an
 
AMR. The staff requested that the applicant identify where it evaluated the hydrants in the IP2
 
city water system for aging management.
In its response, dated January 4, 2008, the applicant stated that the site component database identifies the hydrants in the IP2 city water system as valves, and this designation was
 
maintained during the AMR process. The applicant further explained that it included the
 
hydrants in component type valve body in LRA Table 2.3.3-17-IP2, with AMR results provided
 
in LRA Table 3.3.2-17-lP2.
Based on its review, the staff finds the response to RAI 2.3A.3.17-6 acceptable because it adequately explained that the applicants site component database identifies the hydrants in the
 
IP2 city water system as valves. The staff noted that the applicant has included hydrants in the
 
component type valve body in the LRA component table and AMR results table for the IP2 city
 
water system. The staffs concern described in RAI 2.3A.3.17-6 is resolved.
2.3A.3.17.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its
 
review, the staff concludes that the applicant has appropriately identified the city water system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-101 2.3A.3.18  IP2 Plant Drains 2.3A.3.18.1  Summary of Technical Information in the Application LRA Section 2.3.3.18 describes the plant drains, which are passive fire protection features required for adequate protection of safety-related equipment from water damage in areas with
 
fixed-suppression systems. Plant drain components also prevent drain systems in areas with
 
combustible materials from spreading fires into other areas of the plant. Some plant drains
 
protect safety-related equipment from flooding effects.
Various systems include plant drain components, but, for the purposes of this evaluation, all plant drain components are grouped. SRP-LR Section 2.1.3.1 allows the grouping of similar components from various plant systems into a single, consolidated evaluation.
Both the fire protection and waste disposal systems include plant drain components. The waste disposal system collects and processes all potentially radioactive primary plant wastes, both
 
gaseous and liquid, for removal from the site. The system collects, compresses, stores, samples, and releases gaseous waste from the primary and auxiliary systems. Gases vented to
 
the vent header flow to the waste gas compressor suction header. One of the two compressors
 
operates continuously, while the second unit serves as backup for peak load conditions. From
 
the compressors, gas flows to one of the four large gas decay tanks. The header arrangement
 
at the inlet allows the operator to fill the tank, reuse the gas, or discharge it to the environment.
 
Six additional small gas decay tanks can be used during degassing of the reactor coolant before
 
a cold shutdown. The system collects and processes liquid wastes throughout the plant from
 
equipment, radioactive chemical laboratory, decontamination, demineralizer regeneration, and
 
floor drains. Waste liquids drain by gravity to the waste holdup tank, the collection point for
 
liquid wastes, or to the sump tank, the containment, or the PAB sumps, from which they are
 
pumped to the waste holdup tank. The system sends the liquid waste holdup tank contents to
 
the IP1 waste collection system and collects and transfers liquid drained from the RCS directly
 
to the CVCS for processing.
The system includes the vent header, waste gas compressors, large and small waste gas decay tanks, waste gas analyzer, pumps, collection tanks, station drainage piping, floor drains, instruments and controls, piping, valves, several containment penetrations and accompanying
 
isolation components, and piping, valves, instruments and controls to monitor condensation
 
from the containment fan cooler units.
The plant drains system contains safety-related components relied on to remain functional during and following DBEs. The system also contains nonsafety-related components whose
 
failure potentially could prevent the satisfactory accomplishment of a safety-related function. In
 
addition, the plant drains system performs functions that support fire protection.
A small number of waste disposal system components are reviewed with the CS system (LRA Section 2.3.2.2), the safety injection system (LRA Section 2.3.2.4), the city water system (LRA
 
Section 2.3.3.17), the primary water makeup system (LRA Section 2.3.3.7), the CCW systems (LRA Section 2.3.3.3), and the RCS pressure boundary (LRA Section 2.3.1.3).
LRA Tables 2.3.3-18-IP2 and 2.3.3-19-42-IP2 identify plant drains system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2-102 2.3A.3.18.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.18, UFSAR Section 11.1, and a license renewal drawing 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.3.18, the staff identified an area in which additional information was necessary to complete its review of the applicants scoping and screening results. The discussion of the staffs RAIs in SER Section 2.3A.3 details the disposition of
 
RAI 2.3A.3.18-1, dated February 13, 2008.
2.3A.3.18.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI response, and a drawing to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its
 
review, the staff concludes that the applicant has appropriately identified the plant drains system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.3A.3.19  IP2 Miscellaneous Systems in Scope for 10 CFR 54.4(a)(2) 2.3A.3.19.1  Summary of Technical Information in the Application In LRA Section 2.3.3.19, Miscellaneous Systems In Scope for (a)(2), the applicant described those systems that it included within the scope of license renewal with the potential for physical
 
interaction with safety-related components, as required by 10 CFR 54.4(a)(2), and described the
 
components in these systems subject to an AMR. LRA Table 2.3.3-19-A-IP2 lists all of these
 
systems, as well as the LRA section in which the applicant evaluated these systems. LRA
 
Section 2.3.3.19 describes in detail those systems without correlating LRA sections, which
 
include the following:  boiler blowdown  chemical feed  house service boiler  intake structure system  ignition oil  integrated liquid waste handling  main generator  main turbine  miscellaneous nuclear service grade makeup 2-103 post-accident containment air sample  post-accident containment vent (retired in place)  primary sampling  radiation monitoring  secondary sampling  technical support center diesel  chlorination (added by applicant by letter dated February 13, 2008)
Also in LRA Section 2.3.3.19, the applicant identified the following IP2 systems that were not reviewed for 10 CFR 54.4(a)(2) for spatial interaction because the applicant included all of the
 
systems passive mechanical components as (a)(1), functional (a)(2), or (a)(3):  AFW containment cooling and filtration  CCW control rod drive  CS system  electrical penetrations  fuel and core component handling  in-core instrumentation  isolation valve seal water The following briefly describes the IP2 systems included within the scope of license renewal based only on the criterion of 10 CFR 54.4(a)(2) and subject to an AMR. Chemical Feed
. The chemical feed system provides the means to add chemicals to secondary water systems for proper water chemistry control. LRA Table 2.3.3-19-3-IP2 identifies the
 
chemical feed system component types within the scope of license renewal and subject to an
 
AMR, as well as their intended functions.
Intake Structure System
. The intake structure system provides coarse filtering of the Hudson River water supplied to the CW system and the SW system. The system also includes
 
mechanical components associated with the chlorine and hypochlorite addition subsystems.
 
LRA Table 2.3.3-19-8-IP2 identifies the intake structure system component types within the
 
scope of license renewal and subject to an AMR, as well as their intended functions.
Main Generator
. The main generator system produces the primary electrical output of the unit.
The system includes the main generator, its supporting auxiliaries, and components in the stator
 
cooling water and hydrogen seal oil systems. LRA Table 2.3.3-19-15-IP2 identifies the main
 
generator system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
House Service Boiler
.The house service boiler system produces steam for plant heating via the auxiliary steam system. The system includes the house service boilers and components in the
 
fuel oil, FW, and condensate collection systems. LRA Table 2.3.3-19-16-IP2 identifies the house
 
service boiler system component types within the scope of license renewal and subject to an
 
AMR, as well as their intended functions.
Ignition Oil
.The ignition oil system supplies ignition oil to the house service boilers. Most of the ignition oil components are associated with the house service boiler system. LRA 2-104 Table 2.3.3-19-20-IP2 identifies the ignition oil system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
Integrated Liquid Waste Handling
.The integrated liquid waste handling system processes liquid waste collected by the waste disposal system. LRA Table 2.3.3-19-21-IP2 identifies the
 
integrated liquid waste handling system component types within the scope of license renewal
 
and subject to an AMR, as well as their intended functions.
Miscellaneous
.The applicant created the miscellaneous system for the purpose of license renewal to group together various structural, electrical, and mechanical components that were
 
not described elsewhere. LRA Table 2.3.3-19-24-IP2 identifies the miscellaneous system
 
component types within the scope of license renewal and subject to an AMR, as well as their
 
intended functions.
Nuclear Service Grade Makeup
.The nuclear service grade makeup system supplies water to various service systems. The system includes components of the IP1 water treatment facility.
LRA Table 2.3.3-19-25-IP2 identifies the nuclear service grade makeup system component
 
types within the scope of license renewal and subject to an AMR, as well as their intended
 
functions.Post-Accident Containment Air Sample.
The post-accident containment air sample system provides a means to monitor hydrogen concentration inside containment following an accident.
 
Based upon a recent license amendment (License Amendment No. 243), hydrogen monitoring
 
is no longer required as a safety function; however, the system contains component in scope of
 
license renewal under 10CFR 54.4 (a)(2). LRA Table 2.3.3-19-26-IP2 identifies the
 
post-accident containment air sample system component types within the scope of license
 
renewal and subject to an AMR as well as their intended functions. Post-Accident Containment Vent.
The post-accident containment vent system backs up the hydrogen recombiner to reduce post-LOCA hydrogen concentration in containment atmosphere.
 
Based upon a recent license amendment (License Amendment No. 243), the hydrogen recombiner is no longer required as a safety function; however, the system contains component
 
in scope of license renewal under 10CFR 54.4 (a)(2). LRA Table 2.3.3-19-27-IP2 identifies
 
post-accident containment vent system component types within the scope of license renewal
 
and subject to an AMR as well as their intended functions. Primary Sampling
.The primary sampling system performs high-radiation sampling and in-line monitoring and laboratory analysis of representative samples under normal or post-accident
 
conditions. Some of the primary sampling system components support and are reviewed with
 
other systems (e.g., RHR (LRA Section 2.3.2.1), safety injection (LRA Section 2.3.2.4), and
 
containment penetrations (LRA Section 2.3.2.5)). LRA Table 2.3.3-19-28-IP2 identifies primary
 
sampling system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
Radiation Monitoring
.The radiation monitoring system warns of any radiation health hazard and any plant malfunction that might cause health hazards or plant damage. Some of the radiation monitoring system components support, and are reviewed with, other systems (e.g., SW system (LRA Section 2.3.3.2) and containment penetrations (LRA Section 2.3.2.5)). LRA
 
Table 2.3.3-19-31-IP2 identifies radiation monitoring system component types within the scope
 
of license renewal and subject to an AMR, as well as their intended functions.
2-105 Boiler Blowdown
.The boiler blowdown purification system collects and stores or processes blowdown from an SG with a primary-to-secondary leak. LRA Table 2.3.3-19-34-IP2 identifies
 
boiler blowdown system component types within the scope of license renewal and subject to an
 
AMR, as well as their intended functions. Secondary Sampling
.The secondary sampling system continuously samples and analyzes plant secondary systems. The system has components necessary to collect and transport samples to the sampling stations located in the turbine building. LRA Table 2.3.3-19-38-IP2
 
identifies secondary sampling system component types within the scope of license renewal and
 
subject to an AMR, as well as their intended functions.
Technical Support Center Diesel
.The technical support center diesel system backs up the power supply to the technical support center. The technical support center diesel system
 
includes the diesel generator, fuel oil supply, and supporting instruments and controls. LRA
 
Table 2.3.3-19-40-IP2 identifies technical support center diesel system component types within
 
the scope of license renewal and subject to an AMR, as well as their intended functions.
Main Turbine
.The main turbine system receives steam from the SGs, converts a portion of the steam thermal energy to electricity from the main generator, and supplies extraction steam for FW heating. LRA Table 2.3.3-19-41-IP2 identifies main turbine system component types within
 
the scope of license renewal and subject to an AMR, as well as their intended functions.
Chlorination (added by applicant by letter dated February 13, 2008)
.The chlorination system provides sodium hypochlorite to the intake bays to limit microorganism fouling in these bays and
 
in the systems that use raw water. LRA Table 2.3.3-19-44-IP2 identifies chlorination system
 
component types within the scope of license renewal and subject to an AMR, as well as their
 
intended functions. SER Sections 3.3.2.1 and 3.3A.2.3.36 document the staffs review of the
 
AMR results.
2.3A.3.19.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.19 and the following UFSAR (IP2) or safety analysis report (SAR) (IP1) Sections that were associated with these systems:  boiler blowdown 1    UFSAR Section 10.2.1.5  chemical feed 1    UFSAR Section 10.2.6.4  main generator 1    UFSAR Section 8  house service boiler 1    UFSAR Section 9.6.5  integrated liquid waste handling 1  SAR Section 3.7.3 and UFSAR Section 11.1.2.1  main turbine 1      UFSAR Section 10.2.2  nuclear service grade makeup 2  SAR Section 3.7.2  post-accident containment air sample 2  UFSAR Section 6.8.2.3  post-accident containment vent (retired in place) 2 UFSAR Section 6.8.2.2  primary sampling 2    UFSAR Section 9.4  radiation monitoring 2    UFSAR Section 11.2.3 1The staff conducted a simplified Tier 1 system review of these systems, as described in SER Section 2.3.
2The staff conducted a detailed Tier 2 system review of these systems, as described in SER Section 2.3.
2-106 secondary sampling 1    UFSAR Section 9.4  miscellaneous 2    UFSAR Sections 5.1.9, 5.1.11, and
 
====5.2.2 intake====
structure system 1      ignition oil 1        technical support center diesel 1    chlorination 1For those systems receiving a simplified Tier 1 evaluation, the staff reviewed the applicable LRA sections and UFSAR or SAR sections (if applicable) using the evaluation methodology
 
described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. For those systems
 
receiving a detailed Tier 2 evaluation, the staff reviewed the applicable LRA sections, UFSAR or
 
SAR sections (if applicable), and license renewal drawings (system components are shown on
 
other associated system drawings). Based on information provided in the UFSAR or SAR and
 
LRA, the staff evaluated the system functions described in LRA Section 2.3.3.19 to verify that
 
the applicant had not omitted from the scope of license renewal any components with intended
 
functions, as required by 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant identified as within the scope of license renewal to verify that it had not omitted any
 
passive and long-lived components subject to an AMR, in accordance with 10 CFR 54.21(a)(1).
The staff reviewed the list of IP2 systems the applicant identified in LRA Section 2.3.3.19 as not having any components in scope for 10 CFR 54.4(a)(2) for spatial interaction because they
 
were already included in scope under 10 CFR 54.4(a)(1), functional (a)(2), or (a)(3). In RAI
 
2.3A.2.2-1, dated February 13, 2008, the staff requested the applicant to explain why piping
 
segments directly attached to IP2 CS system (a)(1) piping were not highlighted on boundary
 
drawings to show included in scope for license renewal. The staffs review of the applicants
 
response, dated March 12, 2008, is documented in SER Section 2.3A.2.2.2.
In RAI 2.1-1, dated January 14, 2008, the staff asked the applicant to provide a technical basis for excluding nonsafety-related systems located in proximity to safety-related systems from the
 
scope of license renewal. In its response, dated February 13, 2008, the applicant provided an
 
evaluation of these systems and amended the LRA to include the IP2 chlorination system within
 
the scope of license renewal under 10 CFR 54.4(a)(2). Additionally, the applicant added LRA
 
Table 2.3.3-19-44-IP2 to identify the component types subject to an AMR.
During its review, the staff noted the applicant did not specifically identify components within the scope of license renewal under 10 CFR 54.4(a)(2) on the license renewal drawings. To
 
determine that the applicant did not omit any components from scope under 10 CFR 54.4(a)(2),
the staff used a sampling approach, as recommended in SRP-LR Section 2.3.3.1. In multiple
 
RAIs, dated February 13, 2008, the staff asked the applicant to verify that various segments of
 
selected systems were included in scope under 10 CFR 54.4(a)(2). This sampling approach
 
enabled the staff to confirm that the applicant had properly implemented its methodology for
 
identifying nonsafety-related portions of systems with a potential to adversely affect
 
safety-related functions, in accordance with 10 CFR 54.4(a)(2).
In its response, dated March 12, 2008, the applicant stated that all components identified by the staff on the license renewal drawings are within the scope of license renewal, in accordance
 
with 10 CFR 54.4(a)(2), and subject to an AMR. Based on a review of the applicants response, the staff finds that the applicant has adequately identified the components required to be within
 
the scope of license renewal, in accordance with 10 CFR 54.4(a)(2), as well as those subject to 2-107 an AMR. 2.3A.3.19.3  Conclusion
 
For each system described above, the staff reviewed LRA Section 2.3.3.19, the applicable UFSAR or SAR section, and license renewal drawings to determine whether the applicant failed
 
to identify any SSCs within the scope of license renewal. In addition, the staff sought to
 
determine whether the applicant failed to identify any components subject to an AMR. The staff
 
found instances in which the applicant omitted systems and components that should have been
 
included within the scope of license renewal. The applicant has satisfactorily resolved these
 
issues as discussed in the preceding staff evaluation. On the basis of its review, the staff finds
 
that, for all of the systems identified in LRA Section 2.3.3.19, the applicant has appropriately
 
identified the components within the scope of license renewal as required by 10 CFR 54.4(a),
and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.3A.4  Scoping and Screening Results: Steam and Power Conversion Systems Unit 2 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, Main Steam  2.3.4.2, Main Feedwater  2.3.4.3, Auxiliary Feedwater  2.3.4.4, Steam Generator Blowdown  2.3.4.5, IP2 AFW Pump Room Fire Event  2.3.4.6, Condensate SER Sections 2.3A.4.1-2.3A.4.6, respectively, describe the staffs review of the IP2 systems described in LRA Sections 2.3.4.1-2.3.4.6. The staffs findings for these systems are discussed
 
below.2.3A.4.1  IP2 Main Steam System 2.3A.4.1.1  Summary of Technical Information in the Application LRA Section 2.3.4.1 describes the MS system, which conducts steam from the four SGs inside the containment structure to the turbine generator unit in the turbine generator building. The
 
system has four MS pipes, one from each SG to the turbine stop and control valves, connected
 
near the turbine. Each steam pipe has a main steam isolation valve (MSIV) and a non-return
 
valve outside the containment. There are five code safety valves and one PORV on each MS
 
line outside the reactor containment and upstream of the isolation and non-return valves. A flow
 
venturi upstream of the isolation valve measures steam flow. Steam pressure is also measured upstream of the isolation valve. The MS system supplies steam to the main boiler FW pump
 
turbines and the AFW pump turbine. The system includes the main boiler FW pump turbines
 
and the turbine steam bypass and low-pressure steam dump systems, which channel excess
 
steam flow to the condenser. The steam generator blowdown (SGBD) flowpath also includes
 
MS system components.
2-108 The MS system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the MS system
 
performs functions that support fire protection and SBO.
Main steam components in the SGBD flowpath are reviewed with the SGBD system (LRA Section 2.3.4.4). Components supporting the AFW system are reviewed with the AFW system (LRA Section 2.3.4.3). Components that support safe shutdown in a fire in the auxiliary feed
 
pump room are evaluated in AFW pump room fire event (LRA Section 2.3.4.5). A small number
 
of components are reviewed with the compressed air systems (LRA Section 2.3.3.4).
LRA Tables 2.3.4-1-IP2 and 2.3.3-19-23-IP2 identify MS system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.4.1.2  Staff Evaluation The staff reviewed LRA Section 2.3.4.1, UFSAR Section 10.2, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.4.1, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The applicant responded to the staffs RAI as discussed below.
In RAI 2.3A.4.1-1, dated December 7, 2007, the staff noted that license renewal drawings for the IP2 MS system show the following valves within the scope of license renewal and subject to
 
an AMR: PCV-1134, PCV-1135, PCV-1136, PCV-1137, MS-1-21, MS-1-22, MS-1-23, MS-1-24, PCV-1120, PCV-1121, PCV-1122, PCV-1123, PCV-1124, PCV-1125, PCV-1126, PCV-1127, PCV-1128, PCV-1129, PCV-1130, and PCV-1131. The staff also noted that these valves are air
 
operated and have associated air cylinders and air tubing that the applicant excluded from the
 
scope of license renewal. Since some of these valves appear to rely on pressurized air (pneumatic operation) to change position and fulfill their intended function, the staff requested
 
that the applicant explain why the instrument air system, its tubing, and associated
 
solenoid-operated valves (SOVs) to the valves in question are not within the scope of license
 
renewal, in accordance with 10 CFR 54.4(a).
In its response, dated January 4, 2008, the applicant stated that the air operators are active components; therefore, they are not subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1)(i) and NEI 95-10, Appendix B. The applicant explained that the SOVs and
 
air tubing associated with air-operated valves in the MS system are within the scope of license
 
renewal, but are not subject to an AMR because the majority of the air-operated valves shown
 
on the MS license renewal drawings to be within the scope of license renewal fail to their 2-109 required position for accident mitigation. As such, these valves do not require pressurized air to fulfill their intended function, and pressure boundary of the air tubing is not necessary. The
 
applicant stated that an exception is the atmospheric dump valves and MSIVs, which close on
 
loss of air but are credited with being reopened, as necessary, in an accident scenario using
 
standby nitrogen in bottles or compressed air stored in accumulators. The applicant explained
 
that components used to reopen the MS system valves are subject to an AMR.
Based on its review, the staff finds the applicants response to RAI 2.3A.4.1-1 acceptable because it explained that, for most of the air-operated valves, a failure of the air supply system
 
will not result in a loss of the intended function because the MS valves fail to their safe
 
positions. This explanation is consistent with Section 5.2.3.1 of NEI 95-10, Revision 6, which
 
governs fail-safe components. For those air-operated valves that rely on an air supply system (i.e., those MS system valves that do not fail to their safe position), the applicant included the
 
passive pneumatic components (accumulator tanks, tubing, and valves) of those air-operated
 
valves within the scope of license renewal, in accordance with 10 CFR 54.4(a); these
 
components are subject to an AMR, in accordance with 10 CFR 54.21(a)(1). The staffs concern
 
described in RAI 2.3A.4.1-1 is resolved.
2.3A.4.1.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI response, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its
 
review, the staff concludes that the applicant has appropriately identified the MS system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.3A.4.2  IP2 Main Feedwater System 2.3A.4.2.1  Summary of Technical Information in the Application LRA Section 2.3.4.2 describes the main FW system, which has two half-size, steam-driven main FW pumps that increase condensate pressure for delivery through the final stage of FW heating
 
and the FW regulating valves to the SGs. The FW system includes the high-pressure FW
 
heaters, the SGs, the piping and valves from the outlet of the main feed pumps through the
 
heaters to the SGs, and the main feed pump turbine drip tank drain pumps. The main feed
 
pumps are part of the condensate system, and the main feed pump turbines are part of the MS
 
system. The main FW system contains safety-related components relied on to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the main FW system could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the main FW
 
system performs functions that support fire protection.
The SGs and secondary-side instrumentation piping and valves are reviewed with the SGs (LRA Section 2.3.1.4). Components that support safe shutdown in the auxiliary feed pump room
 
fire are evaluated in LRA Section 2.3.4.5. System components containing air are reviewed with
 
the compressed air systems (LRA Section 2.3.3.4).
2-110 LRA Tables 2.3.4-2-IP2 and 2.3.3-19-12-IP2 identify main FW system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.4.2.2  Staff Evaluation The staff reviewed LRA Section 2.3.4.2, UFSAR Section 10.2.6, and a license renewal drawing using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR
 
Section 2.3.
The staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with intended
 
functions, as required by 10 CFR 54.4(a). The staff then reviewed those components that the
 
applicant identified as within the scope of license renewal to verify that the applicant had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.4.2, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The applicant responded to the staffs RAI as discussed below.
In RAI 2.3A.4.2-1, dated December 7, 2007, the staff noted that license renewal drawings identify that valves FCV-417-L, FCV-417, FCV-427-L, FCV-427, FCV-437-L, FCV-437, FCV-447-L, FCV-447, BF2-21, and BF2-22 for the IP2 main FW system are within the system
 
evaluation boundary but are not highlighted, indicating that they are not subject to an AMR. The
 
staff asked the applicant to explain the valves exclusion from an AMR.
In its response, dated January 4, 2008, the applicant explained that these FW system valves are located upstream of the containment isolation check valves in nonsafety-related piping but
 
are classified as safety-related because of their active function to provide FW isolation. The
 
applicant also stated that these valves have no passive intended function for 54.4(a)(1) or (a)(3) because their failure would accomplish the safety function of isolating feedwater flow to
 
the SGs. The applicant further stated that these valves perform their function with moving parts;
 
therefore, in accordance with 10 CFR 54.21(a)(1)(i), they are not subject to an AMR and are not
 
highlighted on the license renewal drawing. However, the applicant did indicate that the valves
 
in question are within the scope of license renewal for meeting the requirements of
 
10 CFR 54.4(a)(2) because of their potential for spatial interaction with safety-related equipment
 
and are, therefore, subject to an AMR.
The staff did not agree with the applicants rationale that the valves do not have a passive intended function in accordance with 10 CFR 54.4(a)(1). The staff discussed the applicants
 
view during a telephone call on March 7, 2008. The applicant subsequently amended its RAI
 
response by letter dated March 24, 2008, and reiterated that the FW system valves are safety-
 
related; however, although not highlighted, the applicant stated that these valves and the
 
remainder of the FW system components on the associated license renewal drawing are in
 
scope and subject to an AMR based upon meeting the requirements of 10 CFR 54.4(a)(2)
 
because of their potential for spatial interaction with safety-related equipment.
Based on its review, the staff finds the applicants amended response to RAI 2.3B.4.2-1 acceptable because the applicant confirmed that the valves in question are within the scope of
 
license renewal pursuant to 10 CFR 54.4(a) and subject to an AMR pursuant to 10 CFR 2-111 54.21(a)(1). Although the staff does not agree with the applicants basis for determining how the valve bodies are subject to an AMR, the staffs concern is resolved because the AMR was
 
performed, and the AMR results were provided in LRA Table 3.3.2-19-12-IP2. The staffs
 
concern described in RAI 2.3A.4.2-1 is resolved.
In RAI 2.3A.4.2-2, dated December 30, 2007, the staff noted that UFSAR Section 14.1.10, Excessive Heat Removal Due To Feedwater System Malfunctions, states that accidental full
 
opening of a feedwater control valve causes excessive feedwater flow, resulting in a transient is
 
similar to, but less severe than, the hypothetical steamline break transient described in UFSAR
 
Section 14.2.5. Therefore, the excessive feedwater flow failure is bounded by the steamline
 
break analysis. In the steamline break analysis, in the event of the failure of the main feedwater
 
control valve, the applicant takes credit the main feedwater stop valves, BFD-5s, to close within
 
120 seconds. In its revised response to RAI 2.3A.4.2-1, dated March 24, 2008, the applicant
 
stated that the feedwater control valves and the remainder of the feedwater system components
 
on the associated license renewal drawing are within scope of license renewal based upon
 
meeting the requirements of 10 CFR 54.4(a)(2), having the potential for spatial interaction with
 
safety-related equipment, and are subject to an AMR.
Based the applicants UFSAR, the main feedwater stop valves (BFD-5s) have an intended function that meets the criteria of 10 CFR 54.4(a)(1); however, these valves are neither included
 
within the system intended function boundary, nor are they highlighted on the license renewal
 
drawings for having a intended function in accordance with 10 CFR 54.4(a)(1). By letter dated
 
December 30, 2008, the staff requested the applicant to justify the exclusion of the main
 
feedwater stop valves (BFD-5s), from scope of license renewal in accordance with 10 CFR
 
54.4(a)(1). This issue was also identified as Open Item 2.3.4.2-1.
By letter dated January 27, 2009, the applicant stated that based upon a review of the qualifications of the main feedwater stop valves, the BFD-5s are classified as nonsafety-related.
 
Further, the applicant explained that the valves are classified nonsafety-related in the site
 
component database and are located outside the Class I boundary [as corrected by letter dated
 
March 13, 2009] on license renewal drawing LRA-9321-2019-0. As indicated in the IP2 UFSAR, these valves provide a backup isolation function for feedwater in the event of such accidents as
 
a feedwater or steamline break. Credit for nonsafety-related components as a backup to safety-
 
related components in mitigating breaks in seismically-qualified steam line piping is consistent
 
with regulatory guidance provided in Section 15.1.5, Steam System Piping Failures Inside and
 
Outside of Containment (PWR), of the Standard Review Plan (NUREG-0800) and is also
 
consistent with the allowance for feedwater regulating and bypass valves to be nonsafety-
 
related, as discussed in NUREG-0138, Staff Discussion of Fifteen Technical Issues Listed in
 
Attachment to November 3, 1976 Memorandum from Director, NRR to NRR Staff. The
 
applicant concluded that, consistent with the CLB, regulatory guidance, and NUREG-0138, the
 
BFD-5 valves are classified as nonsafety-related, and as such, meet the criteria to be included
 
in scope for license renewal under 10 CFR 54.4(a)(2).
Based on the information provided by the applicant, the staff finds applicants response to RAI 2.3A.4.2-2 acceptable because the BFD-5 isolation valves are nonsafety-related
 
components, and the valves are included in the scope for license renewal under
 
10 CFR 54.4(a)(2). Therefore, the staffs concern described in RAI 2.3A.4.2-2 is resolved. As a
 
result, Open Item 2.3.4.2-1 is closed.
2-112 2.3A.4.2.3  Conclusion The staff reviewed the LRA, UFSAR, RAI responses, and a drawing to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. The staff concludes
 
that the applicant has appropriately identified the main FW system components within the scope
 
of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3A.4.3  IP2 Auxiliary Feedwater System 2.3A.4.3.1  Summary of Technical Information in the Application LRA Section 2.3.4.3 describes the AFW system, which supplies adequate feedwater to the SGs to remove reactor decay heat under all circumstances, including loss of power and normal heat
 
sink (e.g., condenser isolation or loss of CW flow), and identifies, as major components, the
 
condensate storage tank (CST) and three AFW pumpsone steam turbine driven and two
 
electric motor driven. Diverse AFW supplies come from two pumping systems using separate
 
sources of motive power for their pumps. Each system supplies AFW to all four SGs. Two of the
 
SGs can supply the steam turbine-driven pump. The AFW system operates during plant startup
 
at low power levels before the main FW pump is available.
The CST is the safety-grade water source for the system, with a minimum water level maintained for an adequate inventory. The AFW pumps can draw an alternative supply from the
 
city water storage tank for long-term cooling.
The AFW system contains safety-related components relied on to remain functional during and following DBEs. In addition, the AFW system performs functions that support fire protection, ATWS, and SBO.
Instrument air components included in the AFW system are reviewed with the compressed air systems (LRA Section 2.3.3.4). A small number of components are reviewed with the city water
 
system (LRA Section 2.3.3.17).
LRA Table 2.3.4-3-IP2 identifies AFW system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.4.3.2  Staff Evaluation The staff reviewed LRA Section 2.3.4.3, UFSAR Section 10.2.6.3, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2-113 During its review of LRA Section 2.3.4.3, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The applicant responded to the staffs RAI as discussed below.
In RAI 2.3A.4.2-2, dated February 13, 2008, the staff noted that LRA Section 2.3.4.3 states that the AFW system has no intended function under 10 CFR 54.4(a)(2). The staff indicated that the
 
applicant had not highlighted components adjacent to safety-related systems on license renewal
 
drawings; these components adjacent to safety-related systems may need to be considered
 
under 10 CFR 54.4(a)(2) because of the potential for adverse spatial interaction. For IP2, these
 
components include piping to the AFW pump bearing cooling line and the chemical FW line to
 
AFW. The staff requested that the applicant confirm that it had evaluated the aforementioned
 
components for inclusion within the scope of license renewal, in accordance with
 
10 CFR 54.4(a)(2).
In its response, dated March 12, 2008, the applicant stated that it assigned the bearing cooling lines to the AFW pumps identified by the staff to the city water system, and these lines are
 
subject to an AMR based on the requirements of 10 CFR 54.4(a)(2). The applicant explained
 
that several valves and components shown in dashed lines on one drawing indicate that they
 
appear on the main drawing associated with that system. The applicant identified these
 
components as part of the AFW system and as being within the scope of license renewal and
 
subject to an AMR, in accordance with 10 CFR 54.4(a)(1). The applicant scoped the piping and
 
components on the chemical feed line identified by the staff as part of the chemical feed
 
system. The applicant included the chemical feed system components within the scope of
 
license renewal under 10 CFR 54.4(a)(2), and these components are subject to an AMR.
During the review of the applicants response to RAI 2.3A.4.2-2, the staff identified other piping lines on license renewal drawing LRA-9321-20183-001 that the applicant had not highlighted, but that were directly connected to highlighted lines. In a telephone conference held on
 
May 30, 2008 (ADAMS Accession No. ML081720557), the staff asked the applicant to indicate
 
whether these lines were within the scope of license renewal under 10 CFR 54.4(a)(2). The
 
applicant explained that it had made a drawing error. The non-highlighted piping line for the
 
AFW system, which includes valve CT-711, is within the scope of license renewal, in
 
accordance with 10 CFR 54.4(a)(1), and should be highlighted. The applicant also explained
 
that the non-highlighted short segments of piping coming off the highlighted valves, CT-709 and
 
CT-710, are valve sealing water under the condensate system and are within the scope of
 
license renewal under 10 CFR 54.4(a)(2).
Based on its review, the staff finds the applicants response to RAI 2.3A.4.2-2 acceptable because it adequately explained that the components in question are within the scope of license
 
renewal under 10 CFR 54.4(a)(2) because of their potential to adversely interact spatially with
 
safety-related equipment; furthermore, these components are subject to an AMR, in accordance
 
with 10 CFR 54.21(a)(1). The staffs concern described in RAI 2.3A.4.2-2 is resolved.
2.3A.4.3.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its 2-114 review, the staff concludes that the applicant has appropriately identified the AFW system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3A.4.4  IP2 Steam Generator Blowdown System 2.3A.4.4.1  Summary of Technical Information in the Application LRA Section 2.3.4.4 describes the SGBD system, which can control the concentration of solids in the shell side of the SGs. The system, which operates normally with a continuous blowdown
 
and sample flow, has a drain connection and two blowdown connections (nozzles) at the bottom
 
of each SG. Pipes from the connections (nozzles) join to form a stainless steel blowdown
 
header. Four individual blowdown headers extend from each SG to the PAB through
 
containment isolation valves. Blowdown flows normally to the flash tank, flashed vapor
 
discharges to the atmosphere, and the condensate drains by gravity through an SW discharge
 
line into the CW discharge canal. The system combines, cools, and monitors the sample flows
 
for radiation.
The SGBD system contains safety-related components relied upon to remain functional during and following DBEs. It also contains nonsafety-related components whose failure potentially
 
could prevent the satisfactory accomplishment of a safety-related function. In addition, the
 
SGBD system performs functions that support fire protection, ATWS, and SBO.
The applicant reviewed a small number of SGBD components with the SW system in LRA Section 2.3.3.2.
LRA Tables 2.3.4-4-IP2 and 2.3.3-19-36-IP2 identify SGBD system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3A.4.4.2  Staff Evaluation The staff reviewed LRA Section 2.3.4.4, UFSAR Section 10.2.1.5, and a license renewal drawing 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3A.4.4.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and a drawing to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the SGBD system components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as 2-115 required by 10 CFR 54.21(a)(1).
2.3A.4.5  IP2 Auxiliary Feedwater Pump Room Fire Event 2.3A.4.5.1  Summary of Technical Information in the Application LRA Section 2.3.4.5 describes the IP2 AFW pump room fire event, which supplies and supports main FW flow to the SGs during a shutdown (IP2 only). The applicant credits this combination of
 
systems for supplying makeup water to the SGs during a fire in the auxiliary boiler feed pump
 
room for an assumed duration of at least 1 hour. This method was necessary because the
 
current design and CLB assume that plant personnel cannot reenter the area for at least 1 hour
 
following onset of a fire. A combination of secondary systems and components supplies the
 
SGs if a fire in the AFW pump room makes it unavailable for operator actions. These plant
 
systems and components supply FW flow through the main FW isolation valves to the SGs from
 
the IP1 CSTs. Feedwater flows from the IP1 tanks through the hotwell dump, condensate
 
transfer pump, condensate pumps, boiler feed pumps, and main FW isolation valves to the SGs.
 
The following systems support this flowpath (the LRA section reference is included for those
 
systems described elsewhere):  auxiliary steam  conventional closed cooling  condensate (LRA Section 2.3.4.6)  CW city water (LRA Section 2.3.3.17)  FW (LRA Section 2.3.4.2)  fresh water cooling (IP1 system)  instrument air (LRA Section 2.3.3.4)  instrument air closed cooling  lube oil  MS (LRA Section 2.3.4.1)  river water service (IP1 system)  SW (LRA Section 2.3.3.2)  station air (IP1 system) (LRA Section 2.3.3.4)  water treatment plant (IP1 system)  wash water These systems are normally in service and available prior to a fire in the auxiliary feed pump room. For those systems not described elsewhere in the LRA, a brief description is provided
 
below.Auxiliary Steam
.The auxiliary steam system supplies steam for room and area heating, including the containment and the control room, and for various plant components, such as the
 
RWST heating coil. The system includes IP1 and IP2 components. The heating function is not
 
safety related. However, the system has several containment penetrations with safety-related
 
components, and the RWST heating coil has a pressure boundary safety function. In the event
 
of an AFW pump room fire, auxiliary steam supports the condenser water box priming steam jet
 
air ejectors and preheats oil in the lube oil system.
Conventional Closed Cooling
.The conventional closed cooling system supplies cooling water to various components, including condensate and heater drain pumps, main boiler feed pump 2-116 pedestals, and station air compressors. This system has circulating pumps, heat exchangers (cooled by service water), a head tank, distribution piping valves, instruments, and controls.
 
Cooling water from the conventional closed cooling system is not required to support any
 
system safety function.
Circulating Water
.The CW system supplies cooling water to the condenser to condense the steam exiting the low-pressure and main boiler feed pump turbines. The Hudson River supplies
 
the condenser circulating water. The six condenser CW pumps are in the intake structure. The
 
system pipes circulating water to the condensers and discharges it back into the river via the
 
discharge canal. The system includes the CW pumps, condenser inlet and outlet water boxes, piping, valves, instruments, and controls.
Fresh Water Cooling
.The fresh water cooling system cools miscellaneous, nonsafety-related heat loads, including IP1 air compressors and house service boiler components. The system
 
includes the fresh water cooling recirculating tank, fresh water circulating pumps, heat
 
exchangers cooled by river water, distribution piping, and valves. This system does not include
 
any safety-related components. Instrument Air Closed Cooling.
The instrument air closed cooling system removes heat from the instrument air compressors and after-coolers. The system consists of a separate closed loop
 
cooling water system of two small pumps, valves, piping, and heat exchangers that supply
 
cooling water to the instrument air compressors and after-coolers and reject that heat to the
 
SWS.Lube Oil.The lube oil system, which supplies oil for lubrication and control of the main turbine and the main boiler FW pumps and turbines, includes the main lubricating/control oil reservoirs, pumps, coolers, piping, valves, indicators, and components of the main turbine controls. The
 
applicant credits two turbine control components for turbine trip for Appendix R safe shutdown.
 
The auto-stop trip solenoid has only an active function for turbine trip. The auto-stop oil turbine
 
trip solenoid releases oil pressure to trip and need not maintain a pressure boundary. Neither of
 
these components has a passive mechanical intended function.
River Water Service
.The river water service system supplies cooling water from the Hudson River to the fresh water cooling system heat exchangers. This system consists primarily of IP1
 
equipment used to support IP2. The system provides backup to the SW system by providing
 
nonessential loads. It includes four Class A pipe segments that support the SW system. The
 
pipe segments are part of the SW supply and return from the instrument air cooling water heat
 
exchanger.Water Treatment Plant
.The water treatment plant system supplies water for various uses throughout the plant. The water treatment plant consists primarily of IP1 equipment in the
 
superheater building. The system, which takes city water through demineralization for all three
 
units, includes demineralization and deaeration equipment, distribution piping, valves, instruments, controls, and the IP1 CSTs. In the event of an AFW pump room fire, the IP1 CSTs
 
provide make-up water to the SGs. The make-up water flows from the IP1 CSTs to the IP2
 
hotwell dump and condensate transfer pump.
Wash Water
.The wash water system washes fish and debris from the traveling screens for return to the river. The system includes the pumps, piping, strainers, valves, instruments, and
 
controls for the screen wash function. Wash water components are not required to support SW 2-117 system operation.
The IP2 AFW pump room fire event systems contain safety-related components relied on to remain functional during and following DBEs. They also contain nonsafety-related components
 
whose failure could prevent the satisfactory accomplishment of a safety-related function. In addition, the IP2 AFW pump room fire event systems perform functions that support fire
 
protection.
The IP2 AFW pump room fire event systems contain components that are evaluated with other systems. Auxiliary steam system components supporting the RWST pressure boundary are
 
evaluated with the safety injection systems (LRA Section 2.3.2.4). River water system
 
components supporting the SW system pressure boundary are evaluated with the SW system (LRA Section 2.3.3.2). Containment penetrations are evaluated with other containment
 
penetrations (LRA Section 2.3.2.5).
Nonsafety-related components not evaluated with other systems whose failure could prevent satisfactory accomplishment of safety-related functions are evaluated with miscellaneous
 
systems that are in scope under 10 CFR 54.4(a)(2) (LRA Section 2.3.3.19). For these systems, the following LRA tables identify IP2 AFW pump room fire event component types within the
 
scope of license renewal under 10 CFR 54.4(a)(2), as well as their intended functions:  LRA Table 2.3.3-19-1-IP2  LRA Table 2.3.3-19-2-IP2  LRA Table 2.3.3-19-6-IP2  LRA Table 2.3.3-19-13-IP2  LRA Table 2.3.3-19-19-IP2  LRA Table 2.3.3-19-22-IP2  LRA Table 2.3.3-19-32-IP2  LRA Table 2.3.3-19-43-IP2 The staff notes that the LRA does not identify 10 CFR 54.4(a)(2) components of the wash water system. The applicant stated that it performed a review of the liquid-filled components that were
 
not included in other AMRs and determined that the wash water system components are
 
located where they cannot affect equipment with safety-related functions.
The intended function of the IP2 AFW pump room fire event component types within the scope of license renewal is primarily to provide pressure boundary integrity for adequate flow and
 
pressure delivery. For license renewal, the primary intended function of AFW pump room fire
 
event components is to maintain system pressure boundary integrity. Some components retain
 
other functions (e.g., the heat exchangers have the function of heat transfer, and the filters
 
provide filtration).
Aging management of the systems required to supply feedwater to the SGs during an AFW pump room fire is not based on the analysis of materials, environments, and aging effects.
 
System components required to supply feedwater to the SGs during the short duration of such a
 
fire are in service or available when the event occurs. Required components are separated from
 
the AFW pump room; therefore, normal plant operation continuously confirms the integrity of the
 
systems and components required for post-fire intended functions for at least 1 hour.
During the event, these systems and components must continue to perform their intended 2-118 functions by supplying feedwater to the SGs for the 1-hour minimum duration assumed by the applicant. Significant degradation that could threaten the performance of intended functions will
 
be apparent in the period immediately preceding the event, and corrective action will be
 
required to sustain continued operation. For the minimal 1-hour period that these systems are
 
required to supply make-up water to the SGs, further aging degradation apparent before the
 
event is negligible; therefore, the applicants evaluation considered no aging effects.
The IP1 CSTs are subject only to intermittent service; therefore, a daily check of tank level and intermittent usage of piping and valves from the IP1 CSTs to the IP2 condenser confirm
 
availability. Significant degradation that could threaten the performance of the intended
 
functions will be apparent in the period immediately preceding the event, and corrective action
 
will be required to sustain continued operation.
Normal plant operation ensures adequate pressure boundary integrity, as well as the post-fire intended function to supply feedwater to the SGs; therefore, no specific AMP is required.
The intended function of the IP2 AFW pump room fire event component types within the scope of license renewal is to provide pressure boundary integrity for adequate flow and pressure
 
delivery.2.3A.4.5.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.5 and the UFSAR using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.4.5, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The applicant responded to the staffs RAI as discussed below.
In RAI 2.3A.4.5-1, dated December 7, 2007, the staff noted that, in LRA Section 2.3.4.5, the applicant stated that water treatment plant components are credited for the AFW pump fire
 
event to support safe shutdown in the event of a fire in the IP2 AFW pump room. The applicant
 
indicated that water from the IP1 CSTs is used as makeup water for the IP2 SGs. The applicant
 
further described a combination of IP1 and IP2 systems that are used to complete this flowpath.
 
The applicant stated that the current design and licensing bases requires this flowpath to be
 
available for at least 1 hour following onset of the fire because the applicant assumes that
 
personnel are unable to re-enter the area for at least 1 hour. The staff noted that, although the
 
LRA states that the IP1 components comprising the required flowpath have an intended function
 
under 10 CFR 54.4(a)(3) to support safe shutdown in a fire event, license renewal drawings do
 
not identify the flowpath or its components.
The staff asked to applicant to identify those long-lived components comprising the required flowpath and to indicate whether they are subject to an AMR, in accordance with 2-119 10 CFR 54.21(a).
In its response, dated January 4, 2008, the applicant stated that it verifies the levels in the IP1 CSTs on a daily basis. The applicant also indicated that the majority of the components in this
 
flowpath, as part of the water treatment plant system, are included within the scope of license
 
renewal, in accordance with 10 CFR 54.4(a)(2), and are subject to an AMR. Finally, the
 
applicant agreed that a few outdoor components (e.g., tanks, piping and valves) are not
 
included in LRA Section 2.3.4.5. The applicant amended the LRA to include the components to
 
provide further assurance that their intended functions can be performed. The applicant revised
 
LRA Table 3.3.2-19-43-IP2 to add the line items that were not previously included (i.e
., carbon steel for the IP1 CSTs).
Based on its review, the staff finds the response to RAI 2.3A.4.5-1 acceptable because the applicant adequately explained that the majority of the components in this flowpath are included
 
within the scope of license renewal as part of the water treatment plant system. The applicant
 
added the few outdoor components that had not been included in this LRA section as within the
 
scope of license renewal and subject to an AMR. For these components, the staffs concern
 
described in RAI 2.3A.4.5-1 is resolved. SER Sections 3.3.2.1 and 3.3A.2.3.33 document the
 
staffs evaluation of new AMR results for the carbon steel CSTs.
In LRA Section 2.3.4.5, the applicant described systems not discussed elsewhere in the LRA that are credited for mitigating the consequences of an IP2 fire event in the AFW pump room.
 
The intended function of each system listed is to support safe shutdown in the event of a fire in
 
the auxiliary feed pump room (10 CFR 50.48), in accordance with 10 CFR 54.4(a)(3). The
 
applicant stated that no License renewal drawings are provided based on the intended function
 
of supporting safe shutdown in the event of a fire in the auxiliary feed pump room. However, the applicant stated in LRA Section 2.2 that [c]omponents subject to aging management review
 
are highlighted on license renewal drawings, with the exception of components in scope for
 
10 CFR 54.4(a)(2). Since the SCs that support mitigating the consequences of a fire event are
 
in scope under 10 CFR 54.4(a)(3) and are subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1), the applicant should have highlighted the components on the license
 
renewal drawings. However, the applicant did not highlight the components or flowpaths needed
 
to support this event. In addition, the applicant did not, in accordance with 10 CFR 54.21(a)(1),
identify and list the SCs that are subject to an AMR. Therefore, based on the information
 
provided in the LRA, the staff was unable to verify those components that are included within
 
the scope of license renewal to perform the stated function and are subject to an AMR.
In RAI 2.3A.4.5-2, dated December 30, 2008, the staff asked the applicant to (a) identify the system support function for the AFW pump room fire event for each system that supports the
 
flowpath, (b) clearly identify the portion of the systems flowpaths that support these functions
 
and are subject to an AMR, and (c) identify the portion of these flowpaths that are not already in
 
scope under 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(2). This issue was identified as Open
 
Item 2.3.4.5-1.
By letter dated January 27, 2009, the applicant explained that its mitigating strategy in the event of a fire in the AFW pump room is to use equipment that the plant typically uses during normal
 
operation. The applicant assumed that if the equipment is available for normal operations, then
 
it would be available in the event of a fire in the AFW pump room. In its response, the applicant
 
identified those systems and their functions that it credits for use in an AFW pump room fire
 
event.
2-120 The applicant amended LRA Section 2.2 to explain that it did not highlight those components required for the AFW pump room fire event, as described in Section 2.3.4.5, on license renewal
 
drawings. The applicant described, for each system required to mitigate the AFW pump room
 
fire event, the systems safety functions and the component types, along with their respective
 
intended function. In addition, the applicant identified any components of these systems that it
 
had not previously identified as within the scope of license renewal under 10 CFR 54.4(a)(1) or
 
10 CFR 54.4(a)(2).
Among those systems required for the AFW pump room fire event, the applicant identified four IP1 systems that it credited as continuously in service during normal plant operation: river water, station air, water treatment plant, and fresh water cooling. The normal condensate flowpath from
 
the IP2 CST may be lost during a fire in the AFW pump room; therefore, the applicant credited
 
the use of the IP1 CSTs, which are not typically in service. As described in its response to
 
RAI 2.3A.4.5-1, the applicant added those components in the flowpath from the IP1 CSTs to the
 
scope of license renewal, in accordance with 10 CFR 54.4(a)(3), that were not already included
 
in the scope for license renewal under 10 CFR 54.4(a)(2). The other three IP1 systems
 
supplement the respective IP2 systems and typically operate to support the normal operations
 
of IP2. Based on its review, the staff finds the applicants response to RAI 2.3A.4.5-2 acceptable because it included the components required to support the safety function in the event of a fire
 
in the AFW pump room within scope, in accordance with 10 CFR 54.4(a)(3), and identified
 
passive long-lived components requiring an AMR, in accordance with 10 CFR 54.21. Therefore, the staffs concern described in RAI 2.3A.4.5-2 is resolved. (The staff evaluated the adequacy of
 
the AMR performed for these components in its review of the applicants response to RAI 3.4.2-
: 1. SER Section 3.4.2 includes the results of this evaluation.)
2.3A.4.5.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and RAI responses to determine whether the applicant failed to identify any SSCs within the scope of license renewal or failed to identify any
 
components subject to an AMR. As described above, the applicant satisfactorily resolved the
 
omission of components from an AMR. The staff found no further omissions. On the basis of its
 
review, the staff concludes that the applicant has appropriately identified the IP2 AFW pump
 
room fire event system components within the scope of license renewal, as required by
 
10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3A.4.6  IP2 Condensate System 2.3A.4.6.1  Summary of Technical Information in the Application LRA Section 2.3.4.6 describes the condensate system, which transfers condensate and low-pressure heater drainage from the condenser hotwell through five stages of FW heating to
 
the main FW pumps. Three condensate pumps, arranged in parallel, take suction from the
 
bottom of the condenser hotwells and discharge into a common header that carries a portion of
 
the condensate through three steam jet air ejector condensers arranged in parallel and one
 
gland steam condenser. The condensate passes through the tube sides of three parallel strings
 
of two low-pressure FW heaters. The flows from these heaters combine in a common line which
 
divides to go to the remaining three strings of three low-pressure heaters. After the No.5 FW 2-121 heater, the three condensate lines join into a common header. The heater drain pump discharge enters this header and continues on to the suction of the main FW pumps.
The condensate system includes most components from the condenser to the outlet of the main boiler FW pumps, the main condensers, the condensate and main boiler FW pumps, low-pressure FW heaters, piping, valves, instruments, and controls. Most of the system is not
 
safety related; however, the air ejector discharge to containment penetration is in this system
 
code.Some system components support the pressure boundary of the AFW system flowpath from the CST to the AFW pumps.
The condensate system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure
 
potentially could prevent the satisfactory accomplishment of a safety-related function.
Condensate system components that support safe shutdown in the event of an auxiliary feed pump room fire are evaluated in LRA Section 2.3.4.5. Components that support the AFW
 
system flowpath pressure boundary are reviewed with the AFW systems (LRA Section 2.3.4.3).
 
Containment penetration components are reviewed with containment penetrations (LRA
 
Section 2.3.2.5).
2.3A.4.6.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.6 and UFSAR Section 10.2.6 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant has identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3A.4.6.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant had adequately identified the condensate system components
 
within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an
 
AMR, as required by 10 CFR 54.21(a)(1).
2-1222.3B  IP3 Scoping and Screening Results: Mechanical Systems2.3B.1  Reactor Coolant System LRA Section 2.3.1 identifies the RCS SCs subject to an AMR for license renewal.
The RCS includes mechanical components in the following subsystems:  reactor vessel  reactor vessel internals  SGs RCPs pressurizer control rod drives  in-core instrumentation  reactor vessel level instrumentation SG secondary-side instrumentation  SG level control The applicant described the supporting SCs of the RCS in the following LRA sections:  2.3.1.1, Reactor Vessel  2.3.1.2, Reactor Vessel Internals  2.3.1.3, Reactor Coolant Pressure Boundary  2.3.1.4, Steam Generators LRA Section 2.3.1 describes the following RCS subsystems:
Reactor Vessel. The cylindrical reactor vessel has a hemispherical bottom and a flanged and gasketed removable upper head. The upper reactor closure head and the reactor vessel flange
 
are joined by studs. Two metallic O-rings seal the reactor vessel when the reactor closure head
 
is bolted in place. A leak-off connection between the two O-rings monitors leakage across the inner O-ring. Vessel design was in accordance with ASME Code,Section III. Coolant enters the
 
reactor vessel through inlet nozzles in a plane just below the vessel flange and above the core, flows downward through the annular space between the vessel wall and the core barrel into a
 
plenum at the bottom of the vessel, reverses direction, and flows up through the core. After
 
mixing in the upper plenum, the mixed coolant stream then flows out of the vessel through exit
 
nozzles on the same plane as the inlet nozzles. The core instrumentation nozzles are on the
 
lower head, and the control rod nozzle penetrations are on the upper head.
Reactor Vessel Internals. The reactor vessel internals direct the coolant flow, support the reactor core, and guide the control rods. The reactor vessel contains the core support
 
assembly, upper plenum assembly, fuel assemblies, control cluster assemblies, surveillance
 
specimens, and in-core instrumentation. The reactor vessel internals consist of three major
 
parts: the lower core support structure, the upper core support structure, and the in-core
 
instrumentation support structure. A one-piece thermal shield, concentric with the reactor core, is between the core barrel and the reactor vessel. The shield, cooled by the coolant on its
 
downward pass, protects the vessel by attenuating much of the gamma radiation and some of
 
the fast neutrons that escape from the core.
2-123Steam Generators. Each loop has a vertical shell and a U-tube SG. Reactor coolant enters the inlet side of the channel head at the bottom of the SG through the inlet nozzle, flows through the
 
U-tubes to an outlet channel, and exits the generator through another bottom nozzle. The inlet
 
and outlet channels are separated by a partition. Feedwater to the SG enters just above the top
 
of the U-tubes through an FW ring, flows downward through an annulus between the tube
 
wrapper and the shell, and then flows upward through the tube bundle where it converts to a
 
steam-water mixture that passes through a primary separator assembly that reduces the water
 
content in the mixture. The separated water combines with the feedwater for another pass
 
through the tube bundle. The remaining higher steam content mixture rises through additional
 
secondary separators to further reduce its water content. Reactor Coolant Pumps. Each reactor coolant loop has a vertical, single-stage centrifugal pump with a controlled leakage seal assembly. Reactor coolant pumped by the impeller attached to
 
the bottom of the rotor shaft and drawn up through the impeller discharges through passages in
 
the diffuser and out through a discharge nozzle in the side of the casing. A flywheel at the top of
 
the rotor shaft extends the pump coastdown flow during any loss of power to the pump motor. A
 
portion of the flow from the CVCS charging pumps is injected into the RCP between the impeller
 
and the controlled leakage seal. CCW flows to the motor bearing oil coolers and the thermal
 
barrier cooling coil.
The RCS contains safety-related components relied on to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the RCS could prevent the satisfactory
 
accomplishment of a safety-related function. In addition, the RCS performs functions that
 
support fire protection, PTS, ATWS, and SBO.
Pressurizer. The pressurizer system maintains the required reactor coolant pressure during steady-state operation, limits the pressure changes of coolant thermal expansion and
 
contraction during normal load transients, and prevents RCS pressure from exceeding design
 
pressure. The pressurizer maintains pressure by electrical heaters and sprays. Steam can be
 
formed by the heaters or condensed by a pressurizer spray to minimize pressure variations due
 
to coolant contraction and expansion. The pressurizer design accommodates inflow and outflow
 
surges caused by load transients. The surge line attached to the bottom of the pressurizer
 
connects it to the hot leg of a reactor coolant loop. The pressurizer protects the RCS from
 
overpressure by code relief valves connected to its top head. Two PORVs and three code
 
safety valves protect against pressure surges beyond the pressure-limiting capacity of the
 
pressurizer spray. The PORV also operates from the overpressure protection system to prevent
 
RCS pressure from exceeding the limits found in ASME Code, Section III, Appendix G, during
 
low-temperature operation. Steam and water discharge from the power relief and safety valves
 
passes to the pressurizer relief tank partially filled with water at or near ambient containment
 
conditions. The tank normally contains water in a predominantly nitrogen atmosphere. Steam
 
discharged under the water level condenses and cools by mixing with the water. Rupture discs
 
that discharge into the reactor containment protect the tank against a discharge exceeding the
 
design value. The system includes the pressurizer, pressurizer relief valves, PORVs, spray line
 
components, pressurizer relief tank, piping, valves, instruments, controls, and several
 
containment penetrations supporting the pressurizer relief tank.
The pressurizer system contains safety-related components relied on to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the pressurizer system
 
could prevent the satisfactory accomplishment of a safety-related function. In addition, the
 
pressurizer system performs functions that support fire protection and SBO.
2-124 Control Rod Drives. The control rod drive system positions the control rods within the core. The reactor uses the Westinghouse magnetic-type control rod drive assemblies on the upper reactor
 
vessel head to insert or withdraw the rods to control generation of nuclear power. Control rod
 
motion is accomplished through the sequential operation of three different magnetic coils. Upon
 
a loss of power to the coils, the released rod cluster control assemblies with full-length absorber
 
rods fall by gravity into the core. Each control rod drive assembly is designed as a
 
hermetically-sealed unit to prevent leakage of reactor coolant. The design of all
 
pressure-containing components meets the requirements of ASME Code, Section III, Division 1, for Class A vessels.
The control rod drive system contains safety-related components relied on to remain functional during and following DBEs. In-Core Instrumentation. The in-core instrumentation system provides information on the neutron flux distribution and fuel assembly outlet temperatures at selected core locations to
 
confirm the reactor core design parameters and calculated hot channel factors. The system
 
acquires data and performs no operational plant control. The system consists of thermocouples
 
positioned to measure fuel assembly coolant outlet temperature at preselected locations, flux
 
thimbles running the length of selected fuel assemblies to measure the neutron flux distribution
 
within the reactor core using moveable in-core detectors, and in-core drives, drive motors, positioning equipment, and instruments. The flux thimbles, seal table, and guide tube form part
 
of the RCPB.
The in-core instrumentation system contains safety-related components relied on to remain functional during and following DBEs. Reactor Vessel Level Instrumentation. The reactor vessel level instrumentation monitors the water level in the reactor vessel or relative voids in the RCS during accident conditions. The
 
instrumentation indicates levels from the bottom of the reactor vessel to the top of the reactor
 
head during natural circulation conditions and indicates reactor vessel liquid level for any
 
combination of running RCPs. The instrumentation utilizes RCS penetrations leading to manual
 
isolation valves at which sealed capillary impulse lines transmit pressure measurements to
 
transmitters outside the containment building. Sensor bellows serving as hydraulic couplers seal
 
the capillary impulse lines at the RCS end and at the penetrations. The impulse lines extend
 
through the containment wall to hydraulic isolators which seal and isolate the lines and
 
hydraulically couple them to capillary tubes going to the transmitters.
The reactor vessel level instrumentation system (RVLIS) contains safety-related components relied on to remain functional during and following DBEs. The failure of nonsafety-related SSCs
 
in the RVLIS could prevent the satisfactory accomplishment of a safety-related function. Steam Generator (Secondary-Side Instrumentation). The SG system has secondary-side instrumentation. The SG system code includes the passive mechanical instrument piping and
 
valves for the SG secondary-side-level instrumentation. These components are safety related
 
because they form part of the SG pressure boundary.
The SG system contains safety-related components relied on to remain functional during and following DBEs. In addition, the SG system performs functions that support fire protection and
 
SBO.
2-125Steam Generator Level Control. The SG level control system supports the control of FW flow to maintain SG secondary-side level. Primarily an electrical system, it includes several level
 
instrument vent valves. These components are safety related because they form part of the SG
 
pressure boundary.
The SG level control system contains safety-related components relied on to remain functional during and following DBEs. In addition, the SG level control system performs functions that
 
support fire protection and SBO.
The RCS Class I piping evaluation boundary extends into portions of systems attached to the RCS. For both units, the RCS AMR includes the Class I components of the systems listed
 
below. The applicant evaluated the non-Class 1 system portions in the LRA section indicated: CVCS (LRA Section 2.3.3.6)  isolation valve seal water (LRA Section 2.3.2.3)  primary sampling (LRA Section 2.3.3.19)  RHR system (LRA Section 2.3.2.1)  safety injection system (LRA Section 2.3.2.4)
IP3 RCS RCP lube oil collection system components are reviewed with the fire protectionCO 2 , Halon, and RCP oil collection systems (LRA Section 2.3.3.12).
Components in the IP3 nitrogen supply to the PORVs are reviewed with the nitrogen systems (LRA Section 2.3.3.5). A small number of IP3 pressurizer components are reviewed with the
 
primary water makeup systems (LRA Section 2.3.3.7).
The following components are evaluated with containment penetrations (LRA Section 2.3.2.5):  IP3 pressurizer system containment penetration components  certain mechanical IP3 RVLIS components Fuel assemblies replaced after a limited number of fuel cycles are not subject to an AMR. The control rods are active components and, therefore, are not subject to an AMR.
The intended function of the RCS component types within the scope of license renewal is to provide pressure boundary integrity for adequate flow and pressure delivery.
Because the IP2 and IP3 RCS and supporting SCs are very similar, SER Sections 2.3A.1.1-2.3A.1.4, respectively, document the staffs review findings for LRA Sections 2.3.1.1-2.3.1.4 for
 
IP3.2.3B.2  Engineered Safety Features LRA Section 2.3.2 identifies the engineered safety features SCs subject to an AMR for license renewal.The applicant described the supporting SCs of the engineered safety features in the following LRA sections:
2-126 2.3.2.1, Residual Heat Removal 2.3.2.2, Containment Spray System  2.3.2.3, Containment Isolation Support Systems 2.3.2.4, Safety Injection Systems  2.3.2.5, Containment Penetrations The staff summarized the findings of its review of LRA Sections 2.3.2.1-2.3.2.5 in SER Sections 2.3B.2.1-2.3B.2.5, respectively.
2.3B.2.1  IP3 Residual Heat Removal 2.3B.2.1.1  Summary of Technical Information in the Application LRA Section 2.3.2.1 describes the RHR system, which provides emergency core cooling as part of the safety injection system and removes residual heat during later stages of plant cooldown.
 
The RHR system is one of three (RHR, CCW, SFPC) auxiliary coolant systems. The RHR
 
system consists of two RHR heat exchangers, two seal coolers, two RHR (low-head) pumps, and required piping, valves, and I&C components. The RHR system provides emergency core
 
cooling during the injection phase of a LOCA. The RHR heat exchangers, in conjunction with
 
the safety injection recirculation pumps, provide post-accident heat removal during the LOCA
 
recirculation phase. Outlet flow from the RHR heat exchangers may be directed to the CS
 
headers, to the RCS cold legs, or to the RCS hot legs via the high-head safety injection pumps.
The RHR pumps also back up the safety injection system recirculation pumps during the LOCA
 
recirculation phase. In this capacity, the RHR pumps may draw water from the containment
 
sump and deliver it to the RCS cold leg injection lines, to the suction of the high-head safety
 
injection pumps, or to the CS headers. The RHR system removes residual heat during later
 
stages of plant cooldown, as well as during cold shutdown and refueling operations. After the
 
RCS temperature and pressure have been reduced to 350 degrees F and less than 450 psig, alignment of the RHR pumps initiates decay heat cooling by taking suction from one reactor hot
 
leg and discharging it through the RHR heat exchangers into the reactor cold legs.
The RHR system contains safety-related components relied on to remain functional during and following DBEs. In addition, the RHR system performs functions that support fire protection and
 
SBO.In the LRA, ASME Code Class 1 components with the intended function of RCPB maintenance are reviewed with the RCS (LRA Section 2.3.1). A small number of components are reviewed
 
with the CCW system (LRA Section 2.3.3.3).
LRA Table 2.3.2-1-IP3 identifies RHR system component types within the scope of license renewal and subject to an AMR as well as their intended functions.
2.3B.2.1.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.1, the UFSAR, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components 2-127 that the applicant identified as within the scope of license renewal to verify that it had not omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3B.2.1.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the RHR system components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3B.2.2  IP3 Containment Spray System 2.3B.2.2.1  Summary of Technical Information in the Application LRA Section 2.3.2.2 describes the CS system, which cools the containment and removes iodine following an accident. The system consists of two trains of pumps, valves, and spray headers
 
that spray borated water into the containment automatically when the system senses high
 
containment pressure following a LOCA or MS line break accident. The CS system sprays a
 
portion of the RWST contents into the containment atmosphere through nozzles connected to
 
four ring headers in the containment dome. Each spray pump supplies two ring headers. The
 
CS pumps take their suction from the RWST. After injection from the RWST has been
 
terminated, the spray headers can be supplied with recirculated water from the recirculation
 
sump or the containment sump by a diversion of a portion of the injection flow from the safety
 
injection system. By letter dated June 30, 2009, the applicant submitted Amendment 8, Revision
 
1 to the LRA to reflect a modification to the containment spray system. The applicant stated that the buffer chemical in the containment spray system was changed from sodium hydroxide (liquid injection) to sump baskets containing sodium tetraborate. Retention of iodine during long-
 
term post-accident conditions is assured by the sodium tetraborate baskets located in the
 
containment that will be flooded under accident conditions, allowing the sodium tetraborate to
 
dissolve into the fluid for pH control. The containment spray system also includes a dousing
 
system for the carbon filter bank of each fan cooler unit of the containment air recirculation
 
cooling and filtration system. Each dousing system can be started manually if high-temperature
 
conditions occur.
The CS system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the CS system
 
performs functions that support fire protection.
Containment spray system components that support the RHR system pressure boundary are reviewed with the RHR system (LRA Section 2.3.2.1). A small number of components are
 
reviewed with the safety injection system (LRA Section 2.3.2.4).
LRA Tables 2.3.2-2-IP3 and 2.3.3-19-10-IP3 identify CS system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2-128 2.3B.2.2.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.2, UFSAR Section 6.3, and license renewal drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR
 
Section 2.3. In addition, the staff reviewed the applicants letter dated June 30, 2009, which
 
provided a modification to LRA Section 2.3.2.2 to reflect a change in the buffer chemical and the
 
method of adding it to the containment spray system for pH control.
During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3B.2.2.3  Conclusion
 
The staff reviewed the LRA, UFSAR and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the CS system components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3B.2.3  IP3 Containment Isolation Support Systems 2.3B.2.3.1  Summary of Technical Information in the Application LRA Section 2.3.2.3 describes the containment isolation support systems, which include the isolation valve seal water systems and the weld channel and containment penetration
 
pressurization systems. For IP3, this evaluation also includes the PAB system, which has a
 
containment penetration. The containment isolation support systems consist of piping and
 
valves routed to the various system piping that penetrates the containment. The isolation valve
 
seal water, weld channel, and containment penetration pressurization systems isolate the
 
containment from the outside environment for various systems with piping penetrating containment. The containment isolation support systems inject fluid or either air or gas into
 
system lines between the containment isolation valves penetrating the containment to ensure
 
pressure boundary integrity against leakage of radioactive fluids to the environment in the event
 
of a LOCA. These barriers of piping and isolation valves systems are defined by individual lines.
 
Besides satisfying containment isolation criteria, the valving facilitates normal operation and
 
maintenance of the systems for reliable operation of other engineered safeguard systems.
The isolation valve seal water system provides sealing water or gas between the isolation and double-disk isolation valves of containment penetrations located in lines connected to the RCS
 
or exposed to the containment atmosphere during any condition which requires containment
 
isolation. This system limits fission product release from the containment. Although not credited
 
in post-accident dose analyses, the system ensures a containment leak rate in an accident that
 
is lower than that assumed in the accident analysis and the offsite dose calculations. System
 
components form parts of the containment penetration isolation boundary.
2-129 The weld channel and containment penetration pressurization systems provide pressurized gas to all containment penetrations and most liner inner weld seams so that, in a LOCA, no leakage
 
occurs through these potential paths from the containment to the atmosphere. The system also
 
serves spaces between selected isolation valves. Although not credited in the post-accident
 
dose analyses, weld channel and penetration pressurization systems maintained at some
 
pressure level above the peak accident pressure will keep any postulated leakage in, rather
 
than out of, the containment. The plants compressed air systems supply regulated clean, dry
 
compressed air outside the containment to all containment penetrations and most inner liner weld channels. The primary source of air for this system is the instrument air system backed up
 
by the station air system and by a bank of nitrogen cylinders as a standby source of gas
 
pressure.The PAB houses and protects emergency safeguards equipment and other systems supporting safe reactor operation. This system code is primarily structural but, because it also includes the guard pipe and enclosure containment leakage boundary for a containment sump penetration, the system has a mechanical intended function which is discussed in this section. This
 
enclosure (tank) is a second leakage boundary for the primary containment penetration from the
 
containment sump.
The containment isolation support systems contain safety-related components relied on to remain functional during and following DBEs. They also contain nonsafety-related components
 
whose failure potentially could prevent the satisfactory accomplishment of a safety-related
 
function.The isolation valve seal water system components with the intended function of maintaining the RCPB are reviewed with the RCS (LRA Section 2.3.1.3).
LRA Tables 2.3.2-3-IP3 and 2.3.3-19-62-IP3 identify containment isolation support systems component types within the scope of license renewal and subject to an AMR, as well as their
 
intended functions.
2.3B.2.3.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.3; UFSAR Sections 6.2.2, 6.5, and 6.6; and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.2.3, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The applicant responded to the staffs RAI as discussed below.
2-130 In RAI 2.3B.2.3-1, dated November 9, 2007, the staff identified line-mounted components (valves PCV 1076 and PCV 1090) located on sensing lines that have a pressure boundary
 
function. However, the applicant did not identify the sensing lines (i.e., those connecting these
 
components to the main line) as being subject to an AMR. Therefore, the staff requested that
 
the applicant clarify whether these sensing lines are subject to an AMR.
In its response, dated December 6, 2007, the applicant stated that the sensing lines are internal to the valve bodies and provide a control function for operation of the valves. The valves (with
 
internal sensing lines) are subject to an AMR and are identified in LRA Table 2.3.2-3-1P3 as
 
component type valve body, with AMR results summarized in LRA Table 3.2.2-3-1P3.
Based on its review, the staff found the applicants response to RAI 2.3B.2.3-1 acceptable because the applicant clarified that the subject sensing lines are within the scope of license
 
renewal and subject to an AMR. The staffs concern described in RAI 2.3B.2.3-1 is resolved.
In RAI 2.3B.2.3-2, dated November 9, 2007, the staff identified several line-mounted components (valves PCV 1193 through PCV 1199) located in lines (i.e., 3/8-inch stainless steel
 
tubing) with a pressure boundary function. However, the applicant did not identify the
 
components themselves as being subject to an AMR. Therefore, the staff requested that the
 
applicant clarify whether these components are subject to an AMR or justify their exclusion.
In its response, dated December 6, 2007, the applicant stated that the line-mounted components are aluminum pressure-regulating valves. These components are within the scope
 
of license renewal and subject to an AMR. The applicant amended the application to add the
 
line item valve body to LRA Table 3.2.2-3-IP3 to reflect the aluminum material.
Based on its review, the staff finds the applicants response to RAI 2.3B.2.3-2 acceptable because the applicant clarified that the subject valves are within the scope of license renewal
 
and subject to an AMR. In addition, the applicant added aluminum valve bodies to the AMR.
 
The staffs concern described in RAI 2.3B.2.3-2 is resolved. SER Section 3.2.2.1 discusses the
 
staffs evaluation of the added AMR for aluminum valve bodies.
2.3B.2.3.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found an instance in which the applicant omitted
 
components that should have been subject to an AMR. The applicant has satisfactorily resolved
 
this issue as discussed in the preceding staff evaluation. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the containment isolation support
 
systems components within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3B.2.4  IP3 Safety Injection System 2.3B.2.4.1  Summary of Technical Information in the Application LRA Section 2.3.2.4 describes the safety injection system, which automatically delivers cooling water to the reactor core in a LOCA to limit the fuel clad temperature so that the core remains 2-131 intact and in place with its essential heat transfer geometry preserved. Components comprising the safety injection system code include the RWST, the three safety injection (high-head)
 
pumps, the accumulators (one for each reactor loop), recirculation pumps and piping, valves, and other components of these subsystems. The three safety injection (high-head) pumps inject
 
RWST borated water into the RCS for core cooling. The safety injection signal automatically
 
opens the required safety injection system isolation valves and starts the safety injection
 
pumps. The accumulators containing borated water pressurized with nitrogen are connected to
 
the RCS by injection piping and valves. Two check valves isolate these tanks from the RCS
 
during normal operation. When RCS pressure falls below accumulator pressure the check
 
valves open, discharging the contents of the tanks into the RCS through the same injection
 
piping used by the safety injection pumps.
After the injection, the recirculation system cools and returns the coolant spilled from the break and water collected from the CS to the RCS. The system recirculation pumps take suction from
 
the recirculation sump in the containment floor and deliver spilled reactor coolant and borated
 
refueling water back to the core through the RHR heat exchangers. For smaller RCS breaks in
 
which recirculated water must be injected against higher pressures for long-term cooling, the system delivers the water from an RHR heat exchanger to the high-head safety injection pump
 
suction and, by this external recirculation route, to the reactor coolant loops. The system also
 
allows either of the RHR pumps to take over the recirculation function.
For IP3, the engineered safeguards initiation logic system was evaluated with the safety injection system. The system actuates (depending on the severity of the condition) the safety
 
injection, containment isolation, containment air recirculation, and CS systems. The engineered
 
safeguards initiation logic system is primarily electrical, but does include some mechanical
 
components, specifically the piping and valves from the containment to the containment
 
pressure transmitters, and has mechanical intended functions.
The safety injection system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure
 
potentially could prevent the satisfactory accomplishment of a safety-related function. In
 
addition, the safety injection system performs functions that support fire protection.
ASME Code Class 1 components with the intended function of maintaining the RCPB are reviewed with the RCS (LRA Section 2.3.1.3). A small number of components are reviewed with
 
the CS system (LRA Section 2.3.2.2), RHR systems (LRA Section 2.3.2.1), or nitrogen systems (LRA Section 2.3.3.5).
LRA Tables 2.3.2-4-IP3 and 2.3.3-19-53-IP3 identify safety injection system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3B.2.4.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.4, the UFSAR, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not 2-132 omitted any passive and long-lived components subject to an AMR, in accordance with 10 CFR 54.21(a)(1).
2.3B.2.4.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the safety injection system components
 
within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an
 
AMR, as required by 10 CFR 54.21(a)(1).
2.3B.2.5  IP3 Containment Penetrations 2.3B.2.5.1  Summary of Technical Information in the Application LRA Section 2.3.2.5 describes the containment penetrations, which is not an independent system but a grouping of containment penetration components not evaluated with other
 
systems. These penetrations include the following:  electrical penetrations  fuel core component handling system  hydrogen recombiners  BVS fuel handling  integrated leak rate testing The BVS system draws samples from the building ventilation to identify radioactive gases that may be present and verifies whether plant radioactive gaseous effluents are within technical
 
specification limits. The system has several containment penetrations and a flowpath to two
 
process radiation monitors.
The fuel-handling system defuels and refuels the reactor core and is designed to transport and handle fuel safely and effectively. The structural evaluations address most components shown
 
in the database and the fuel storage racks and pools. The fuel transfer tube blind flange in this
 
system code is a passive mechanical component for that containment penetration.
The integrated leak rate testing system, which tests containment integrated leak rates during shutdown conditions, has piping, valves, and equipment to pressurize containment, instrumentation to monitor containment parameters during the test, and containment
 
penetrations isolated by blind flanges during normal operation.
The containment penetrations contain safety-related components relied on to remain functional during and following DBEs.
Components in the containment penetrations evaluated in this section are those that maintain the system pressure boundary inside containment from the first weld from the penetration to the
 
class boundary change outside containment. Components in the Class 1 boundary are
 
evaluated with the RCPB (LRA Section 2.3.1.3). Structural portions of the containment 2-133 penetrations are evaluated with the containment building (LRA Section 2.4.1). Electrical portions of electrical penetration assemblies are evaluated with electrical components (LRA Section 2.5).
 
Containment penetrations not included in other systems AMRs are evaluated in LRA Section
 
2.3.2.5. This evaluation includes the BVS system process flowpath to the radiation monitors.
LRA Table 2.3.2-5-IP3 and newly created Table 2.3.3-19-63-IP3 (see evaluation below) identify containment penetration component types within the scope of license renewal and subject to an
 
AMR, as well as their intended functions.
2.3B.2.5.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.5; UFSAR Sections 1.2.2, 5.1.4, 9.4.2, 9.5, and 11.2; and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.2.5, the staff identified areas in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The applicant responded to the staffs RAIs as discussed below.
In RAI 2.3A.2.2-1, dated February 13, 2008, during review of license renewal drawings for the CS system, the staff identified portions of piping in the CS system that were not highlighted, indicating that a particular section of piping had no intended functions, in accordance with
 
10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3). LRA Section 2.3.2.2 states that the CS system has no
 
intended function under 10 CFR 54.4(a)(2). This section of piping is directly connected to
 
safety-related CS piping; therefore, the staff believed that it should be in scope, in accordance
 
with 10 CFR 54.4(a)(2), as nonsafety-related piping that is structurally attached to safety-related
 
piping. The staff asked the applicant to explain this apparent discrepancy. The staff also asked
 
the applicant to indicate any portions of the CS system that it evaluated for inclusion in the
 
scope of license renewal, in accordance with 10 CFR 54.4(a)(2), and to identify any other
 
instances in which it identified a system as not having any 10 CFR 54.4(a)(2) components, but
 
having nonsafety-related components that were not identified as within scope under
 
10 CFR 54.4(a)(2).
In its response, dated March 12, 2008, the applicant determined that the components identified by the staff do have an intended function to maintain integrity such that no physical interaction
 
with safety-related components could prevent satisfactory accomplishment of a safety function.
 
The applicant responded to the staffs request by performing a reevaluation of those safety-
 
related systems that the LRA identified as only being in scope under 10 CFR 54.4(a)(1) and that
 
have no 10 CFR 54.4(a)(2) components. The applicant explained that it should have included
 
the IP3 BVS system within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2).
2-134 For the BVS system, the applicant amended the LRA to reflect the changes described below: a) LRA Table 2.3.3-19-A-IP3 would reflect the BVS system as a miscellaneous system within the scope of license renewal for 10 CFR 54.4(a)(2). b) Removal of the BVS system from the LRA Section 2.3.3.19 table of areas excluded from an AMR based on their lack of potential for spatial interaction. c) Revision of LRA Table 2.3.3-19-B-IP3 to reflect that the BVS system has components subject to an AMR for meeting 10 CFR 54.4(a)(2). d) Creation of a new LRA Table 2.3.3-19-63-IP3 for the four added component types in the BVS system for nonsafety-related components potentially affecting safety function
 
subject to AMR. e) Creation of a new LRA Table 3.3.2-19-63-IP3 for the four added component types, their materials, environments, and AMPs.
Based on its review, the staff finds the applicants response to RAI 2.3A.2.2-1 for the BVS system acceptable because it adequately explained that the applicants reevaluation of
 
safety-related systems identified components that should have been in scope for meeting the
 
requirements of 10 CFR 54.4(a)(2). The staff reviewed the applicants amended LRA to ensure
 
that the new LRA tables include those components that have been brought into the scope of
 
license renewal under 10 CFR 54.4(a)(2) because of their potential for spatial interaction with
 
safety-related components. The staff finds the tables acceptable. Therefore, the staffs concern
 
described in RAI 2.3A.2.2-1 for the BVS system is resolved. SER Sections 3.2.2.1 and
 
3.3B.2.3.41 document the staffs evaluation of new AMR results for the IP3 BVS system.
2.3B.2.5.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI response, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found an instance in which the applicant omitted
 
components that should have been subject to an AMR. The applicant has satisfactorily resolved
 
this issue as discussed in the preceding staff evaluation. On the basis of its review, the staff
 
concludes that that the applicant has adequately identified the containment penetrations
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.3B.3  Scoping and Screening Results: Auxiliary Systems Unit 3 LRA Section 2.3.3 identifies the auxiliary systems SCs subject to an AMR for license renewal.
The applicant described the supporting SCs of the auxiliary systems in the following LRA sections: 2.3.3.1, Spent Fuel Pit Cooling 2.3.3.2, Service Water 2.3.3.3, Component Cooling Water  2.3.3.4, Compressed Air  2.3.3.5, Nitrogen Systems 2-135 2.3.3.6, Chemical and Volume Control  2.3.3.7, Primary Water Makeup  2.3.3.8, Heating, Ventilation and Air Conditioning  2.3.3.9, Containment Cooling and Filtration  2.3.3.10, Control Room Heating, Ventilation and Cooling 2.3.3.11, Fire ProtectionWater  2.3.3.12, Fire ProtectionCO 2 , Halon, and RCP Oil Collection Systems  2.3.3.13, Fuel Oil  2.3.3.14, Emergency Diesel Generators  2.3.3.15, Security Generators  2.3.3.16, Appendix R Diesel Generators  2.3.3.17, City Water 2.3.3.18, Plant Drains 2.3.3.19, Miscellaneous Systems In-Scope for (a)(2)
The applicant created LRA Section 2.3.3.19 to capture all systems or portions of systems that are within the scope of license renewal only under 10 CFR 54.4(a)(2). Among the subsections
 
identified in LRA Section 2.3.3.19, the staff identified the following auxiliary systems for
 
simplified Tier 1 reviews:  ammonia morpholine addition  CL CW extraction steam  floor drains  hydrazine addition  heater drain/moisture separator drains/vents  lube oil  low pressure steam dump  main turbine generator  nuclear equipment drains  river water service  main generator seal oil  secondary plant sampling  turbine hall closed cooling water The staff conducted a more detailed Tier 2 review for all of the remaining auxiliary systems.
 
Staffs RAIs During its review, the staff noted that the applicant did not specifically identify components that were in scope under 10 CFR 54.4(a)(2) on the associated drawings. To determine that the
 
applicant did not omit any components from scope under 10 CFR 54.4(a)(2), the staff asked the
 
applicant to verify that it had included segments of the selected systems in scope under
 
10 CFR 54.4(a)(2). In the following RAIs, dated February 13, 2008, the staff asked that the
 
applicant confirm its methodology for identifying nonsafety-related portions of systems with a
 
potential for adversely affecting safety-related functions, in accordance with 10 CFR 54.4(a)(2),
by describing the applicable portions of system piping that it included within the scope of license
 
renewal under 10 CFR 54(a)(2):
2-136 RAI 2.3B.3.1-2  RAI 2.3B.3.2-1  RAI 2.3B.3.3-1  RAI 2.3B.3.13-1  RAI 2.3B.3.14-2  RAI 2.3B.3.18-1 In its response to the RAIs referenced above, dated March 12, 2008, the applicant stated that all of the component types identified by the staff on the license renewal drawings in question are
 
within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2), and are subject to
 
an AMR. Based on its review, the staff finds the applicants response to these RAIs acceptable because the applicant adequately explained that all of the component types identified by the staff are
 
within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2), and subject to an
 
AMR. The staffs concern described in these RAIs is resolved.
SER Sections 2.3B.3.1-2.3B.3.19, respectively, discuss the staffs review of the IP3 systems described in LRA Sections 2.3.3.1-2.3.3.19. The following sections discuss the staffs findings
 
for these systems.
2.3B.3.1  IP3 Spent Fuel Pit Cooling System 2.3B.3.1.1  Summary of Technical Information in the Application LRA Section 2.3.3.1 describes the SFPC system, which removes residual heat from the spent fuel pit. The SFPC loop consists of pumps (main and standby), a heat exchanger, filters, demineralizer, piping, valves, and instrumentation. The operating pump draws water from the pit
 
for circulation through the heat exchanger and return. CCW cools the heat exchanger, which
 
forms part of the CCW system pressure boundary. Loop piping is arranged so that any pipeline
 
failure does not drain the spent fuel pit below the top of the stored fuel elements. The spent fuel
 
pit pump suction line, which draws water from the pit, penetrates the spent fuel pit wall above
 
the fuel assemblies. A purification loop circulates spent fuel pit water through the demineralizer
 
and filter for purification. A portion of the system piping supporting the RWST purification loop
 
with the spent fuel pit demineralizer forms part of the safety injection system pressure boundary.
 
The system includes the spent fuel pit. Spent fuel storage racks at the bottom of the pit for spent
 
fuel assemblies are a full-length, top-entry type made of stainless steel with Boral as a neutron
 
absorber.The SFPC system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure potentially could
 
prevent the satisfactory accomplishment of a safety-related function.
The spent fuel pit and the spent fuel racks are reviewed with the fuel storage buildings (LRA Section 2.4.3). Components supporting the CCW system pressure boundary are reviewed with
 
the CCW systems (LRA Section 2.3.3.3). Components supporting the pressure boundary of the
 
safety injection system are reviewed with the safety injection systems (LRA Section 2.3.2.4). A
 
small number of components are reviewed with the primary water makeup systems (LRA
 
Section 2.3.3.7).
2-137 LRA Tables 2.3.3-1-IP3 and 2.3.3-19-49-IP3 identify SFPC system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3B.3.1.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.1, UFSAR Sections 9.3 and 9.5, and a license renewal drawing 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.3.1, the staff identified areas in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The applicant responded to the staffs RAIs as discussed below.
In RAI 2.3B.3.1-1, dated December 7, 2007, the staff noted that the UFSAR for IP3 references a backup SFPC system that operates in parallel with the normal SFPC system during refueling
 
activities. Further, the LRA stated that the normal SFPC system is within the scope of license
 
renewal under 10 CFR 54.4(a)(1), with the intended function of providing a pressure boundary
 
for the CCW system and the safety injection system, and under 10 CFR 54.4(a)(2) because of
 
possible physical interaction. The staff noted that the scope of license renewal excludes the
 
backup spent fuel cooling system and requested that the applicant explain the exclusion of
 
these components from scope.
In its response, dated January 4, 2008, the applicant stated that the backup SFPC system is a nonsafety-related system that has no functions under 10 CFR 54.4(a)(1) and is not relied on to
 
perform a function that demonstrates compliance with 10 CFR 54.4(a)(3). The applicant
 
explained that the system is normally drained when the plant is in normal power operation, such
 
that its failure cannot prevent satisfactory accomplishment of any 10 CFR 54.4(a)(1) functions
 
through spatial interaction. Lastly, the applicant explained that no components in the backup
 
SFPC system are directly connected to safety-related equipment, and none meet the scoping
 
requirements of 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), or 10 CFR 54.4(a)(3).
Based on its review, the staff finds the applicants response to RAI 2.3B.3.1-1 acceptable because it adequately explained that the components in the backup SFPC system do not have
 
intended functions under 10 CFR 54.4(a). The applicant adequately explained that the backup
 
SFPC system is a nonsafety-related system, is normally drained when the plant is in normal
 
power operation, and is not credited with performing functions identified in 10 CFR 54.4(a)(3).
 
The staffs concern described in RAI 2.3B.3.1-1 is resolved.
The discussion of the staffs RAIs in SER Section 2.3B.3 details the disposition of RAI 2.3B.3.1-2, dated February 13, 2008.
2-138 2.3B.3.1.3  Conclusion The staff reviewed the LRA, UFSAR, RAI responses, and a drawing to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its
 
review, the staff concludes that the applicant has appropriately identified the SFPC system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3B.3.2  IP3 Service Water System 2.3B.3.2.1  Summary of Technical Information in the Application LRA Section 2.3.3.2 describes the SW system, which supplies cooling water from the Hudson River to various heat loads in both the primary and secondary portions of the plant in a
 
continuous flow to systems and components necessary for plant safety during either normal
 
operation or abnormal or accident conditions. Sufficient redundancy of active and passive
 
components maintains short- and long-term cooling to vital loads in accordance with the
 
single-failure criterion. Six identical, vertical, centrifugal sump-type pumps at the intake structure
 
supply service water to two independent discharge headers, each supplied by three pumps. An
 
automatic, self-cleaning, rotary-type strainer in the discharge of each pump removes solids.
Each header connects to an independent supply line. Either of the two supply lines can supply
 
the essential loads while the other line supplies the nonessential loads. Three nonseismic-class
 
pumps independent of the intake structure can supply an SW system backup by drawing suction
 
from the discharge canal. The applicant credits one of these pumps with supplying service
 
water during a safe shutdown following a fire.
The SW system supplies cooling water to nonessential loads, including SGBD heat exchangers, CW pump seal coolers, the turbine building CCW system, hydrogen coolers, exciter air coolers, and the isolated phase bus heat exchangers, to support normal operation.
The SW system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the SW system
 
performs functions that support fire protection.
LRA Tables 2.3.3-2-IP3 and 2.3.3-19-56-IP3 identify SW system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3B.3.2.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.2, UFSAR Section 9.6.1, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not 2-139 omitted any passive and long-lived components subject to an AMR, in accordance with 10 CFR 54.21(a)(1).
The staffs review of LRA Section 2.3.3.2 identified an area in which additional information was necessary to complete the review of the applicants scoping and screening results. The
 
discussion of the staffs RAIs in SER Section 2.3B.3 details the disposition of RAI 2.3B.3.2-1, dated February 13, 2008.
2.3B.3.2.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI response, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its
 
review, the staff concludes that the applicant has appropriately identified the SW system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3B.3.3  IP3 Component Cooling Water System 2.3B.3.3.1  Summary of Technical Information in the Application LRA Section 2.3.3.3 describes the CCW system, which removes RCS residual and sensible heat via the RHR loop during plant shutdown, cools the letdown flow to the CVCS during power
 
operation, and dissipates waste heat from various primary plant components. It also cools
 
engineered safeguards and safe-shutdown components. The system has pumps, heat
 
exchangers, distribution and return piping and valves, instruments, and controls to cool the
 
following: RHR heat exchangers  RCPs non-regenerative heat exchanger  excess letdown heat exchanger  CVCS seal water heat exchanger  sample heat exchangers  waste gas compressors  reactor vessel support pads  RHR pumps  safety injection pumps  recirculation pumps  spent fuel pit heat exchanger  charging pumps, fluid drive coolers, and crankcase  gross failed fuel detector Some of the CCW-cooled heat exchangers in other systems have no safety function; however, these nonsafety-related heat exchangers form parts of the CCW system pressure boundary.
 
These heat exchangers are within the scope of license renewal with an intended function to
 
maintain the pressure boundary but not to transfer heat. The heat exchangers within the CCW
 
system are safety-related components.
2-140 The CCW system contains safety-related components relied upon to remain functional during and following DBEs. In addition, the CCW system performs functions that support fire
 
protection.
A few components in the CCW system support the RHR system pressure boundary and are reviewed with the RHR systems (LRA Section 2.3.2.1). Component cooling water system
 
components that service the safety injection system are reviewed with the safety injection
 
systems (LRA Section 2.3.2.4).
LRA Table 2.3.3-3-IP3 and newly created Table 2.3.3-19-64-IP3 (see evaluation below) identify CCW system component types within the scope of license renewal and subject to an AMR, as
 
well as their intended functions.
2.3B.3.3.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.3, UFSAR Section 9.3, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.3.3, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The applicant responded to the staffs RAI as discussed below.
During its review of license renewal drawings for the CS system, the staff identified portions of the system that were not highlighted, indicating that sections of piping had no intended functions
 
under 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3). In RAI 2.3A.2.2-1, dated February 13, 2008, the
 
staff asked the applicant to identify any instances in which a system was identified as having no
 
intended functions under 10 CFR 54.4(a)(1), but having nonsafety-related components not
 
identified as within the scope of license renewal.
In its response, dated March 12, 2008, the applicant identified, in addition to the CS system, three other instances in which it had not identified nonsafety-related components as being
 
within the scope of license renewal under 10 CFR 54.4(a)(2). SER Sections 2.3A.2.2, 2.3A.3.3, and 2.3B.2.5 discuss the staffs evaluation of the affected systems. The applicant further
 
explained that it should have identified the CCW systems for IP2 and IP3 and the IP3 BVS
 
system as meeting the requirements of 10 CFR 54.4(a)(2). In these instances, the applicant
 
amended the LRA for IP3 CCW system to include the following: a) LRA Table 2.3.3-19-A-IP3 would reflect the CCW system as a miscellaneous system within the scope of license renewal pursuant to 10 CFR 54.4(a)(2). b) Removal of the CCW system from the list of IP3 systems not reviewed for spatial interaction, pursuant to 10 CFR 54.4(a)(2).
2-141c) Revision of LRA Table 2.3.3-19-B-IP3 to reflect that the CCW system now has components subject to an AMR pursuant to 10 CFR 54.4(a)(2). d) Creation of a new LRA Table 2.3.3-19-64-IP3 for the six added component types in the CCW system for nonsafety-related components potentially affecting safety function, subject to an AMR. e) Creation of a new LRA Table 3.3.2-19-64-IP3 for the six added component types, their materials, environments, and AMPs.
Based on its review, the staff finds the applicants response to RAI 2.3A.2.2-1 for the IP3 CCW system acceptable because it adequately explained that the applicants reevaluation of
 
safety-related systems identified components that should have been within scope for meeting
 
the requirements of 10 CFR 54.4(a)(2). Additionally, the applicant amended the LRA to include
 
portions of the CCW system within the scope of license renewal under 10 CFR 54.4(a)(2). The
 
staff reviewed the applicants addition of new tables to the LRA to ensure that they include
 
those components with the potential for spatial interaction with safety-related components as
 
within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2). The staffs concern
 
described in RAI 2.3A.2.2-1 for the IP3 CCW system is resolved. SER Section 3.3.2.1
 
documents the staffs evaluation of new AMR results for the IP3 CCW system.
The discussion of the staffs RAIs in SER Section 2.3B.3 details the disposition of RAI 2.3B.3.3-1, dated February 13, 2008.
2.3B.3.3.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found an instance in which the applicant omitted
 
components that should have been subject to an AMR. The applicant has satisfactorily resolved
 
this issue as discussed in the preceding staff evaluation. On the basis of its review, the staff
 
concludes that the applicant has appropriately identified the CCW system components within
 
the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3B.3.4  IP3 Compressed Air Systems 2.3B.3.4.1  Summary of Technical Information in the Application LRA Section 2.3.3.4 describes the compressed air systems, including the instrument air and station air systems. The instrument air system continuously supplies dry, oil-free air from
 
duplicate compressors with duplicate dryers and filters for pneumatic instruments and controls.
 
Each compressor discharges into a common air receiver and takes a backup supply from the
 
station air system. To meet current and future instrument air loads, a third compressor-dryer
 
package is available to supply the conventional plant. This compressor also can supply the
 
station air system with backup air, if necessary. The system has compressors, dryers, filters, receivers, distribution piping and valves, instruments, and controls. Items essential for safe
 
operation and safe cooldown have air reserves or gas bottles that enable the equipment to
 
function safely until its air supply resumes. The instrument air system includes piping, valves, and controls supporting this air reserve function, but does not include air or gas bottles, which 2-142 are part of other systems.
The station air system, which supplies compressed air for pneumatic tools, CW pump priming, and miscellaneous cleaning and maintenance purposes throughout the primary and secondary
 
plants, has diesel-driven and motor-driven air compressors, inter- and after-coolers, a receiver, piping, valves, instruments, and controls. Distribution piping to the containment includes
 
containment isolation valves.
The compressed air system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure
 
potentially could prevent the satisfactory accomplishment of a safety-related function. In
 
addition, the compressed air system performs functions that support fire protection and SBO.
LRA Tables 2.3.3-4-IP3, 2.3.3-19-29-IP3, and 2.3.3-19-48-IP3 identify compressed air system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3B.3.4.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.4, UFSAR Section 9.6.3, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3B.3.4.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the compressed air system components
 
within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an
 
AMR, as required by 10 CFR 54.21(a)(1).
2.3B.3.5  IP3 Nitrogen System 2.3B.3.5.1  Summary of Technical Information in the Application LRA Section 2.3.3.5 describes the nitrogen system, which supplies motive gas as a backup to the instrument air supply and nitrogen to various components for process functions (including
 
cover gas, calibration gas, purge gas, and gas for operation of level instrumentation). Nitrogen
 
enters containment through several penetrations that must isolate for containment isolation
 
capability under accident conditions. The containment penetration pressurization system also
 
has nitrogen-filled components not included with this system code.
2-143 The nitrogen system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure potentially
 
could prevent the satisfactory accomplishment of a safety-related function. In addition, the
 
nitrogen system performs functions that support fire protection.
A small number of nitrogen system components are reviewed with the AFW systems (LRA Section 2.3.4.3).
LRA Tables 2.3.3-5-IP3 and 2.3.3-19-37-IP3 identify nitrogen system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3B.3.5.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.5; UFSAR Sections 7.3, 9.6.2.5, 9.9.2, and 10.2.6; and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3B.3.5.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the nitrogen system components within
 
the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3B.3.6  IP3 Chemical and Volume Control System 2.3B.3.6.1  Summary of Technical Information in the Application LRA Section 2.3.3.6 describes the CVCS, which controls RCS inventory (amounts of makeup and letdown) and chemistry (RCS boron concentration and other chemical additions). The
 
system cleans up reactor coolant by degasification and purification, injects seal water to the
 
RCPs, depressurizes the RCS via a pressurizer auxiliary spray flowpath, and injects control
 
poison in the form of boric acid solution from the boric acid storage tanks.
During normal plant operation, reactor coolant letdown flows through the shell side of the regenerative heat exchanger, which reduces its temperature by transferring heat to the charging
 
fluid. The coolant then flows through a letdown orifice, which regulates flow and reduces the
 
coolant pressure. The cooled, low-pressure water leaves the reactor containment and enters
 
the PAB. After passing through the nonregenerative heat exchanger and one of the mixed-bed 2-144 demineralizers, the fluid flows through the reactor coolant filter and enters the VCT.
The coolant flows from the VCT to three positive-displacement, variable-speed charging pumps, which raise the pressure above that in the RCS. The high-pressure water flows from the PAB to
 
the reactor containment along two parallel paths, one returning directly to the RCS through the
 
tube side of the regenerative heat exchanger to the RCS cold leg, and the other injecting water
 
into the RCP seals through seal injection filters. The RCP seal water returns to the CVCS
 
through a seal water filter and heat exchanger back to the VCT.
The RWST and the boric acid storage tanks can provide borated water to the charging system.
The RWST is available to the charging pumps for injection of borated water. The boric acid
 
system has boric acid transfer pumps, a boric acid filter, and storage tanks to maintain a large
 
inventory of concentrated boric acid solution.
The CVCS contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the CVCS
 
performs functions that support fire protection and ATWS.
CVCS components that maintain the RCS pressure boundary are reviewed with the RCS pressure boundary (LRA Section 2.3.1.3). A small number of system components are reviewed
 
with the primary water makeup systems (LRA Section 2.3.3.7) and with the CCW systems (LRA Section 2.3.3.3).
LRA Tables 2.3.3-6-IP3 and 2.3.3-19-11-IP3 identify CVCS component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3B.3.6.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.6, UFSAR Section 9.2.2, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3B.3.6.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the CVCS components within the scope
 
of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2-1452.3B.3.7  IP3 Primary Water Makeup System 2.3B.3.7.1  Summary of Technical Information in the Application LRA Section 2.3.3.7 describes the primary water makeup system, which supplies makeup water to primary plant systems as required in support of normal plant operation. Among other components, this system includes tanks, piping, valves, and pumps. It is also a source of fire
 
water to the containment. The system has a containment penetration and one safety-related
 
component part of the RWST pressure boundary.
The demineralized water system is evaluated with the primary water system. The system supplies demineralized water for normal plant operation and refueling activities to the spent fuel
 
pit, refueling cavity, and RWST; for decontamination, hydrostatic testing, and flushing during
 
refueling outages; for condensate polisher regeneration through the sluice water pumps; and for
 
fire protection in containment.
The system includes safety-related position indicators for the containment penetration isolation valves, which are in the primary water makeup system; therefore, this system has no
 
safety-related mechanical function.
The primary water makeup system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose
 
failure potentially could prevent the satisfactory accomplishment of a safety-related function. In
 
addition, the primary water makeup system performs functions that support fire protection.
Portions of the primary water makeup system that support the RWST pressure boundary are reviewed with the safety injection system (LRA Section 2.3.2.4).
LRA Tables 2.3.3-7-IP3, 2.3.3-19-15-IP3, and 2.3.3-19-42-IP3 identify primary water makeup system component types within the scope of license renewal and subject to an AMR, as well as
 
their intended functions.
2.3B.3.7.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.7; UFSAR Sections 9.2.2, 9.6.2.3, and 9.11.1; and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3B.3.7.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components 2-146 subject to an AMR. The staff found no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the primary water makeup system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3B.3.8  IP3 Heating, Ventilation and Air Conditioning Systems 2.3B.3.8.1  Summary of Technical Information in the Application LRA Section 2.3.3.8 describes the HVAC systems, which maintain the area environment for personnel and equipment. HVAC systems for specific buildings or areas of buildings, including
 
portions of ventilation systems serving various areas of the plant, generally have separate
 
system codes. The HVAC system includes fans and dampers for the electrical tunnels, intake
 
structure, and fire pump house and portable ventilation equipment for safe-shutdown
 
requirements.
The IP3 HVAC systems evaluation includes the following HVAC systems:  control building heating and ventilation  fire barriers  fuel storage building heating and ventilation  HVAC PAB heating and ventilation  plant vent  security heating and ventilation  vapor containment purge and supply  vapor containment pressure relief  Appendix R diesel generator heating and ventilation  EDG building heating and ventilation LRA Section 2.3.3.9 describes containment cooling and filtration, and LRA Section 2.3.3.10 discusses the control room HVAC.
The control building heating and ventilation system heats and ventilates the 15-foot and 33-foot elevations of the control building and ventilates battery rooms 31, 32, and 34 to maintain
 
hydrogen concentrations below maximum acceptable limits during normal plant operation. The
 
system includes dampers, ductwork, heaters, and fans.
The fire barriers system has structural barriers and components for penetrations to prevent or delay the spread of fire to adjoining areas. This system includes fire doors and fire dampers that
 
also support the HVAC systems like that for the diesel generator building. The fire doors and fire
 
dampers are evaluated with their respective structures for their fire barrier function. Fire damper
 
housings that form part of an HVAC system pressure boundary within the scope of license
 
renewal are included in the HVAC evaluation to maintain the housing function of HVAC system
 
support.The fuel storage building heating and ventilation system heats and ventilates the fuel storage building, minimizes leakage of unfiltered air from the building during fuel-handling operations, and filters building exhaust. The system has two fresh-air-tempering units with supply fans and
 
heaters; exhaust-roughing, HEPA, and carbon filters; an exhaust fan; motor-operated dampers; 2-147 and ducts. During normal operation, the fresh-air-tempering units and exhaust fan ventilate and heat the fuel storage building with exhaust air, which passes through the roughing and HEPA
 
filters. During fuel handling, the system maintains a slight negative pressure in the building and
 
passes all ventilation exhaust through the roughing, HEPA, and charcoal filters before release
 
through the plant vent. Originally credited in the fuel-handling accident, the system has no
 
safety functions because the new analysis (described in UFSAR Section 14.2.1), which uses
 
the alternate source term, no longer assumes operation of the ventilation system or any holdup
 
of the radionuclides released from the spent fuel pit.The HVAC system maintains the area environment for personnel and equipment. HVAC systems for specific buildings or areas of buildings generally have a separate system code. The
 
HVAC system includes portions of various ventilation systems serving different areas of the
 
plant. The HVAC system includes fans and dampers for various areas, such as the electrical
 
tunnels, intake structure, and fire pump house. This system also includes portable ventilation
 
equipment supporting safe-shutdown requirements.
The PAB heating and ventilation system heats and ventilates the waste hold-up tank pit and the PAB enclosed spaces. The waste hold-up tank pit contains the waste hold-up tanks which are
 
central collection points for liquid radioactive waste. The PAB houses equipment and
 
components required for normal plant operation as well as accident mitigation, including pumps
 
for the CCW, safety injection, RHR, CS, and other systems. Also located in the PAB are tanks
 
for the waste disposal system that collect radioactive liquids and gases. The PAB heating and
 
ventilation system maintains an environment for personnel and equipment during normal
 
operating and post-accident conditions. The PAB and tank pit are ventilated by a balanced flow
 
between supply and exhaust, maintaining a slight negative pressure in the PAB. Air supplied to
 
each building enters areas of low contamination. A set of fans exhausts air out the plant vent
 
from areas of higher contamination after passing it through filters. No dose consequence
 
analyses credit filtration.
The plant vent system with its plant vent duct and vent flow monitoring instrumentation provides a flowpath for plant ventilation systems to exhaust to the atmosphere. The offsite dose analyses
 
do not credit the plant vent; however, this vent is the release point for control room dose
 
calculations and its structural integrity must be maintained for this purpose.
The security heating and ventilation system heats and ventilates the security building and supports operation of the security propane generator. The system includes fans, heaters, and
 
dampers.The vapor containment purge and supply system filters, monitors, and purges containment air to the plant vent for exhaust to the environment and supplies makeup air to the containment.
 
Operation of the purge system during reactor shutdown maintains radioactivity concentrations
 
inside containment within acceptable limits. The purge system is isolated to maintain
 
containment integrity whenever the plant is above the cold shutdown condition. The system has
 
filters, heating coils, fans, penetration isolation valves, ductwork, instruments, and controls.
 
Some system components share a common pressure boundary with PAB heating and
 
ventilation system components.
The vapor containment pressure relief system relieves the normal pressure changes in containment during reactor power operation. This system consists of a pressure relief line
 
equipped with three isolation valves, one inside and two outside the containment. The pressure 2-148 relief line discharges through roughing, HEPA, and charcoal filters to the plant vent.
The IP3 Appendix R diesel generator has its own enclosure in the yard. Ventilation to the engine is by exhaust fans that draw outside air through covered intake dampers or louvers when
 
required. Exhaust fans that draw outside air in through louvers provide ventilation to the
 
electrical enclosure and the battery enclosure. This equipment is required to support operation
 
of the IP3 Appendix R diesel generator credited for both 10 CFR Part 50, Appendix R, requirements and SBO response.
The IP3 EDG building houses and protects the EDGs. The rooms have outside-air fixed louvers, pneumatically-operated adjustable louvers, and exhaust fans with motor-operated discharge
 
dampers. The pneumatically-operated dampers operate from control air supplied by the EDG
 
starting air system. EDG building ventilation is relied on to support EDG operations during DBAs
 
and regulated events.
The HVAC system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the HVAC
 
system performs functions that support fire protection.
Instrument air volume tanks, tubing, and valves in the vapor containment pressure relief system needed for the containment penetration valves to close are reviewed with the compressed air
 
systems (LRA Section 2.3.3.4).
LRA Tables 2.3.3-8-IP3, 2.3.3-19-21-IP3, 2.3.3-19-39-IP3, 2.3.3-19-60-IP3, and 2.3.3-19-61-IP3 identify HVAC system component types within the scope of license renewal and subject to an
 
AMR, as well as their intended functions.
2.3B.3.8.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.8; UFSAR Sections 1.3.6, 5.3.2.3, 5.3.2.5, 9.5, 9.6.2.2, 9.8, and 14.2.1; and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3B.3.8.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the HVAC system components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2-149 2.3B.3.9  IP3 Vapor Containment Building Ventilation System 2.3B.3.9.1  Summary of Technical Information in the Application LRA Section 2.3.3.9 describes the IP3 vapor containment building ventilation system, which by recirculation cooling and filtration removes normal heat losses from equipment and piping in
 
containment during plant operation, ensures personnel access and safety during shutdown, and
 
depressurizes the containment vessel following an accident. Air recirculation cooling and
 
filtering during normal operation is achieved using all five air-handling units discharging to a
 
common header ductwork distribution system. Each air-handling unit consists of cooling coils, a
 
centrifugal fan with direct-drive motor, and a distribution header. In an accident, the system diverts the flowpath first through a compartment with moisture separators, HEPA filters, and charcoal filters. Dose analyses for some accidents credit the HEPA filters but not the charcoal
 
filters for fission product removal.
The vapor containment building ventilation system contains safety-related components relied on to remain functional during and following DBEs. In addition, the vapor containment building
 
ventilation system performs functions that support fire protection.
LRA Table 2.3.3-9-IP3 identifies vapor containment building ventilation system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3B.3.9.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.9, UFSAR Sections 5.3.2.2 and 6.4.2, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3B.3.9.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the vapor containment building ventilation
 
system components within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-150 2.3B.3.10  IP3 Control Room Heating, Ventilation and Cooling System 2.3B.3.10.1  Summary of Technical Information in the Application The IP3 Appendix R diesel generator has its own enclosure in the yard. Ventilation to the engine is by exhaust fans that draw outside air through covered intake dampers or louvers when
 
required. Exhaust fans that draw outside air in through louvers provide ventilation to the
 
electrical enclosure and the battery enclosure. This equipment is required to support operation
 
of the IP3 Appendix R diesel generator credited for both 10 CFR Part 50, Appendix R, requirements and SBO response.
The IP3 EDG building houses and protects the EDGs. The rooms have outside-air fixed louvers, pneumatically-operated adjustable louvers, and exhaust fans with motor-operated discharge
 
dampers. The pneumatically-operated dampers operate from control air supplied by the EDG
 
starting air system. EDG building ventilation is relied on to support EDG operations during DBAs
 
and regulated events.
The control room HVAC system contains safety-related components relied on to remain functional during and following DBEs. In addition, the control room heating, ventilation and
 
cooling system performs functions that support fire protection.
LRA Table 2.3.3-10-IP3 identifies control room HVAC component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3B.3.10.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.10, UFSAR Section 9.9, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3B.3.10.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the control room HVAC system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-151 2.3B.3.11  IP3 Fire Protection - Water 2.3B.3.11.1  Summary of Technical Information in the Application LRA Section 2.3.3.11 describes the fire protection system, which provides fire protection for the station through the use of water, foam, Halon 1301, detection and alarm systems, and rated fire
 
barriers, doors, and dampers. The fire water system components include fire water and foam
 
subsystem pumps, piping, hydrants, hose reels, valves, tanks, and drains. This system also
 
includes the fuel oil supply to the fire pump house diesel. Fire protection systems include the fire
 
detection and alarm system, as described below. LRA Section 2.3.3.12 describes the CO 2 and Halon 1301 systems. LRA Section 2.3.3.8 discusses the fire barrier system code.
The fire protection water distribution system has two ground-level storage tanks supplied by the city water distribution system. Heating provisions for the storage tanks consist of two sets of
 
dual electric heaters and two sets of dual circulating pumps. The pumping facilities maintain
 
system pressure and, using jockey pumps, supply makeup for system leakage. Two main fire
 
pumps (one electric motor driven and the other diesel engine driven) provide an automatic water
 
supply during a fire. The pumping facilities provide flow and pressure requirements for the
 
water-based fire protection systems. The fire protection water distribution system consists of
 
outdoor underground and aboveground piping and indoor distribution piping in all buildings
 
except the containment building. Demineralized water piping is for fire protection inside
 
containment. IP3 underground piping has two connections with the IP1 fire protection system, providing defense in depth for the IP3 fire protection systems in terms of both water supply and
 
pumping capacity. The distribution system also has isolation valves, strainers, hose stations, and outdoor hydrants. The distribution piping delivers anticipated fire water requirements to
 
individual suppression systems. The yard hydrants provide effective hose stream protection for exterior hazards and for supplementary use for fire conditions within the main buildings of the
 
plant. The water-based fire suppression systems include the wet pipe sprinkler systems, preaction sprinkler systems, deluge water spray systems, foam water spray systems, hydrants, and hose stations. To prevent local flooding, areas with safety-related equipment, or equipment
 
required for safe plant shutdown with automatically operated fire protection, have either gravity
 
or pump drains to handle the maximum quantity of spray water. The fire water system includes
 
plant drain components that protect safety-related equipment from the effects of Class III
 
component failures. The fire water system can supply makeup to the spent fuel pit. While not a
 
safety function, this feature of the fire water system is included as a license renewal intended
 
function.According to the LRA, the fire protectionwater system has no intended function under 10 CFR 54.4(a)(1). The scoping and screening methodology identified the following fire water
 
system intended functions, in accordance with 10 CFR 54.4(a)(2):  Maintain integrity of nonsafety-related components such that no physical interaction with
 
safety-related components can prevent satisfactory accomplishment of a safety function. Provide a backup source of makeup water to the spent fuel pit.
The scoping and screening methodology also identified the following fire protectionwater system intended functions, in accordance with 10 CFR 54.4(a)(3):  Provide fixed automatic and manual fire suppression (including hydrants, hose stations 2-152 and portable extinguishers) to extinguish fires in vital areas of the plant (10 CFR 50.48). Ensure adequate protection of safety-related equipment from water damage in areas susceptible to flooding (10 CFR 50.48).
The fire detection and alarm system transmits fire alarm and supervisory signals to the control room audible and visual alarms. The system has signals for actuation of fire detectors, status
 
indicators for most installed fire suppression systems, control and indicating lights for the fire
 
pumps, level indicators for the fire water storage tanks, and door status indicator lights for
 
operator notification of critical fire doors. The fire detection and alarm system is primarily
 
electrical, but includes instrument air-operated valve and piping parts of an electrical tunnel fire
 
alarm that actuates upon a loss of pressure within the piping.
The fire detection and alarm system has no intended function under 10 CFR 54.4(a)(2). The scoping and screening methodology identified the following fire detection and alarm system
 
intended function, in accordance with 10 CFR 54.4(a)(3):  Support a fire alarm in the electrical tunnel (10 CFR 50.48).
The mechanical portions of the fire detection and alarm system are within the scope of license renewal, but the pressure boundary for the instrument air piping is not required for the system to
 
perform its intended function. Therefore, the components of the fire detection and alarm system
 
are not subject to an AMR. The system drain portion is evaluated with plant drains (LRA
 
Section 2.3.3.18). The fuel oil subsystem components are evaluated with fuel oil systems (LRA
 
Section 2.3.3.13).
Nonsafety-related components not evaluated with other systems but whose failure could prevent satisfactory accomplishment of safety functions are evaluated with miscellaneous
 
systems within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2) (LRA
 
Section 2.3.3.19). The remaining fire protectionwater system and fire detection and alarm
 
system components are evaluated in LRA Section 2.3.3.12.
LRA Tables 2.3.3-11-IP3 and 2.3.3-19-20-IP3 identify the fire protectionwater system component types within the scope of license renewal and subject to an AMR, as well as their
 
intended functions.
2.3B.3.11.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.11, UFSAR Sections 9.6.2.3 and 9.6.2.4, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2-153 The staff also reviewed NRC fire protection SERs for IP3, dated September 21, 1973; March 6, 1979; May 2, 1980; November 18, 1982; December 30, 1982; February 2, 1984;
 
April 16, 1984; January 7, 1987; September 9, 1988; October 21, 1991; April 20, 1994; and
 
January 5, 1995.
The staff also reviewed the IP3 commitments associated with 10 CFR 50.48 (i.e., an approved fire protection program) using its commitment responses to BTP APCSB 9.5-1 and Appendix A
 
to BTP APCSB 9.5-1.
During its review of LRA Section 2.3.3.11, the staff identified areas in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The applicant responded to the staffs RAIs as discussed below.
In RAI 2.3B.3.11-1, dated October 24, 2007, the staff asked the applicant to explain why LRA license renewal drawings indicate that certain fire protection system components are not subject to an AMR. Specifically, license renewal drawing LRA-9321-40903-0 indicates that the following
 
fire protection system component is not subject to an AMR (i.e., the component is not
 
highlighted in green):
* FP-T-4 pneumatic tank and components
 
License renewal drawing LRA-9321-40913-001-0 indicates that the following fire protection system components are not subject to an AMR (i.e., these components are not highlighted in
 
green): turbine generator building foam system  turbine building wall spray system No. 3  yard transformer separation spray system  main transformer No. 31 deluge system  main transformer No. 32 deluge system  unit auxiliary transformer deluge system  station auxiliary transformer deluge system  north half sprinkler No. 6  boiler room sprinkler system  sprinkler system for AFW pump room lube oil storage tank  lube oil reservoir  manual/spray system No. 2 for the boiler feed pump  hydrogen seal oil unit  manual boiler feed pump oil accumulators Nos. 31 and 32  boiler feed console pump The staff requested that the applicant verify whether the above components are within the scope of license renewal, as required by 10 CFR 54.4(a), and subject to an AMR, in accordance
 
with 10 CFR 54.21(a)(1). The staff requested that the applicant justify excluding any of these
 
components from the scope of license renewal and an AMR.
2-154 In its response, dated November 16, 2007, the applicant provided scoping and screening results applicable to fire protection system components. With respect to the FP-T-4 pneumatic tank and
 
components indicated on license renewal drawing LRA-9321-40903-0, the applicant stated the
 
following:
FP-T-4 pneumatic tank and components are not required for compliance with 10 CFR 50.48 and are not described in fire protection SERs, for the response to
 
BTP APCSB 9.5-1, Appendix A. The pneumatic tank and components were used
 
in the past to aid the two jockey pumps in maintaining fire loop pressure. They are no longer used and are isolated from the rest of the system by normally
 
closed valve FP-84. Jockey pumps FP-P-5 and 6 maintain sufficient pressure on
 
the fire protection piping system during non-fire conditions to prevent
 
unnecessary starting of the main fire pumps.
Based on its review, the staff finds the applicants response acceptable because the applicant clarified that it no longer relies on the FP-T-4 pneumatic tank and components to demonstrate
 
compliance with 10 CFR 50.48. Jockey pumps FP-P-5 and FP-P-6 maintain sufficient pressure
 
on the fire protection piping system during non-fire conditions to prevent the main fire pumps
 
from unnecessarily starting.
With respect to license renewal drawing LRA-9321-40913-001-0, the applicant addressed each item in the staffs RAI. For the turbine generator building foam systems, the applicant stated the
 
following:
Fluid-containing portions of the turbine generator building foam systems are included with miscellaneous systems in-scope in compliance with
 
10 CFR 54.4(a)(2) and are subject to an AMR. The AMR for the fluid-containing
 
portions of the systems are in LRA Table 3.3.2-19-20-IP3. Based on discussion
 
in the SER for IP3 dated March 6, 1979, the foam suppression systems for
 
various areas in the turbine building are considered to meet the scoping
 
requirements of 10 CFR 54.4(a)(3), in addition to 10 CFR 54.4(a)(2). The AMR
 
results in LRA Table 3.3.2-11 IP3 are applicable to the portions of the turbine
 
generator building foam systems normally containing air.
Based on its review, the staff finds the applicants response acceptable because it indicated that the generator building foam systems are included in the scope of license renewal with
 
miscellaneous systems, in accordance with 10 CFR 54.4(a)(2), and are subject to an AMR.
For the turbine building wall spray system No. 3, the applicant stated the following:
The turbine building wall spray system No. 3 is in-scope as shown on drawing LRA-9321- 40913-001-0, coordinates D5. The absence of boundary flags where
 
highlighted piping enters a text box indicates that the portion of the system
 
described in the text box is in-scope and subject to an AMR.
Based on its review, the staff finds the applicants response acceptable because it indicated that the turbine building wall spray system No. 3 is within the scope of license renewal and subject
 
to an AMR.
2-155 For the yard transformer separation spray system, the applicant stated the following:
The yard transformer separation spray system is in-scope as shown on drawing LRA-9321- 40913-001-0, coordinates D5. The absence of boundary flags where
 
highlighted piping enters a text box indicates that the portion of the system
 
described in the text box is in-scope and subject to an AMR.
Based on its review, the staff finds the applicants response acceptable because it indicated that the yard transformer separation spray system is within the scope of license renewal and subject
 
to an AMR as shown on license renewal drawing LRA-9321- 40913-001-0.
For the main transformer No. 31 deluge system, the applicant stated the following:
The deluge system and associated components for main transformer No. 31, adjacent to the control building, were initially determined to have no license renewal intended function. They were considered as required only to protect the
 
transformer, to satisfy requirements of the plant insurance carrier. However, the
 
spray systems provide for defense-in-depth, in addition to installed 3-hour rated
 
fire barriers between the transformer and the turbine building, and are now
 
considered in-scope and subject to an AMR. Applicable component types that
 
are subject to an AMR are included in LRA Table 2.3.3-11-IP3, with the AMR
 
results provided in LRA Table 3.3.2-11-IP3.
Based on its review, the staff finds the applicants response acceptable because it clarified that (1) the main transformer No. 31 deluge system and its associated components have no license
 
renewal intended function and (2) the water spray systems provide for defense in depth, in
 
addition to the installed 3-hour-rated fire barriers, and are considered within the scope of license
 
renewal and subject to an AMR.
For the main transformer No. 32 deluge system, the applicant stated the following:
The deluge system and associated components for main transformer No. 32, adjacent to the control building, were initially determined to have no license
 
renewal intended function. They were considered as required only to protect the
 
transformer to satisfy requirements of the plant insurance carrier. However, the
 
spray systems provide for defense-in-depth, in addition to installed 3-hour rated
 
fire barriers between the transformer and the turbine building, and are now
 
considered in-scope and subject to an AMR. Applicable component types that
 
are subject to an AMR are included in LRA Table 2.3.3-11-IP3, with the AMR
 
results provided in LRA Table 3.3.2-11-IP3.
Based on its review, the staff finds the applicants response acceptable because it clarified that (1) the main transformer No. 32 deluge system and its associated components have no license
 
renewal intended function and (2) the water spray systems provide for defense in depth, in
 
addition to the installed 3-hour-rated fire barriers, and are considered within the scope of license
 
renewal and subject to an AMR. For the unit auxiliary transformer deluge system, the applicant stated the following:
The deluge system and associated components for the unit auxiliary transformer, 2-156 adjacent to the control building, were initially determined to have no license renewal intended function. They were considered as required only to protect the
 
transformer to satisfy requirements of the plant insurance carrier. However, the
 
spray systems provide for defense-in-depth, in addition to installed 3-hour rated
 
fire barriers between the transformer and the turbine building, and are now
 
considered in-scope and subject to an AMR. Applicable component types that
 
are subject to an AMR are included in LRA Table 2.3.3-11-IP3, with the AMR
 
results provided in LRA Table 3.3.2-11-IP3.
Based on its review, the staff finds the applicants response acceptable because it clarified that (1) the unit auxiliary transformer deluge systems and their associated components have no
 
license renewal intended function and (2) the water spray systems provide for defense in depth, in addition to the installed 3-hour-rated fire barriers, and are considered within the scope of
 
license renewal and subject to an AMR.
For the station auxiliary transformer deluge system, the applicant stated the following:
The deluge system and associated components for the station auxiliary transformer, adjacent to the control building, were initially determined to have no
 
license renewal intended function. They were considered as required only to
 
protect the transformer to satisfy requirements of the plant insurance carrier.
 
However, the spray systems provide for defense-in-depth, in addition to installed
 
3-hour rated fire barriers between the transformer and the turbine building, and
 
are now considered in-scope and subject to an AMR. Applicable component
 
types that are subject to an AMR are included in LRA Table 2.3.3-11-IP3, with
 
the AMR results provided in LRA Table 3.3.2-11-IP3.
Based on its review, the staff finds the applicants response acceptable because it clarified that (1) the station auxiliary transformer deluge systems and their associated components have no
 
license renewal intended function and (2) the water spray systems provide for defense in depth, in addition to installed 3-hour-rated fire barriers, and are considered within the scope of license
 
renewal and subject to an AMR.
For the north half sprinkler No. 6, the applicant stated the following:
Turbine building north half sprinkler No. 6 system was initially determined to have no license renewal intended function, since a fire in the area protected by the
 
system cannot disable the credited safe-shutdown equipment, which is located
 
outside the area. However, based on discussion in the SER for IP3 dated
 
March 6, 1979, the turbine building north half sprinkler No. 6 system provides
 
defense-in-depth, in addition to hose stations throughout the turbine building, and
 
fire barriers between the turbine building and control building. The system is
 
therefore considered within the scope of license renewal and subject to an AMR, in accordance with 10 CFR 54.4(a)(3). The AMR results in LRA
 
Table 3.3.2-11-IP3 are applicable to the turbine building north half sprinkler
 
system No. 6.
Based on its review, the staff finds the applicants response acceptable because it indicated that the turbine building north half sprinkler No. 6 system is within the scope of license renewal and
 
subject to an AMR.
2-157 For the boiler room sprinkler system, the applicant stated the following:
The boiler room sprinkler system is not required to satisfy the provisions of BTP APCSB 9.5-1, Appendix A and is not credited in fire protection SERs. The
 
boiler room sprinkler system is maintained to satisfy requirements of the plant
 
insurance carrier. The boiler room sprinkler system does not protect
 
safety-related equipment and is not located near any building housing
 
safety-related equipment. Fire in the area of the boiler room will be contained
 
within that area and not affect safe-shutdown equipment, due to its location and
 
limited amount of combustibles.
Based on its review, the staff finds the applicants response acceptable because it clarified that the provisions of 10 CFR 50.48 do not require the boiler room sprinkler system and components
 
because this system does not protect safety-related equipment and is not located near any
 
building housing safety-related equipment.
For the sprinkler system for AFW pump room, the applicant stated the following:
The sprinkler system for the auxiliary feedwater pump room is in-scope as shown on drawing LRA-9321-40913-001-0, coordinate (E8). The absence of boundary
 
flags where the highlighted piping enters the text box indicates that the portion of
 
the system described in the text box is in-scope and subject to an AMR.
Based on its review, the staff finds the applicants response acceptable because it indicated that the sprinkler system for the AFW pump room is within the scope of license renewal and subject
 
to an AMR.
For the lube oil storage tank foam system, the applicant stated the following:
Fluid-containing portions of the LO storage tank foam suppression systems are included with miscellaneous systems in-scope pursuant to 10 CFR 54.4(a)(2)
 
and are subject to an AMR. The AMR results for the fluid-containing portions of
 
the system are included in LRA Table 3.3.2-19-20-IP3. Based on discussion in
 
the SER for IP3 dated March 6, 1979, the LO storage tank foam suppression
 
system is considered as meeting the scoping requirements of 10 CFR 54.4(a)(3),
in addition to 10 CFR 54.4(a)(2). The AMR results in LRA Table 3.3.2-11-IP3 are
 
applicable to the portions of the LO storage tank foam suppression system
 
normally containing air.
Based on its review, the staff finds the applicants response acceptable because it clarified that lube oil storage tank foam suppression systems are included in the scope of license renewal
 
with miscellaneous systems in accordance with 10 CFR 54.4(a)(2) and are subject to an AMR.
For the lube oil reservoir foam system, the applicant stated the following:
Fluid-containing portions of the LO reservoir foam suppression systems are included with miscellaneous systems in-scope pursuant to 10 CFR 54.4(a)(2)
 
and are subject to an AMR. The AMR results for the fluid-containing portions of
 
the system are provided in LRA Table 3.3.2-19-20-IP3. Based on discussion in 2-158 the SER for IP3 dated March 6, 1979, the LO reservoir foam suppression system is considered as meeting the scoping requirements of 10 CFR 54.4(a)(3), in
 
addition to 10 CFR 54.4(a)(2). The AMR results in LRA Table 3.3.2-11-IP3 are
 
applicable to the portions of the LO reservoir foam suppression system normally
 
containing air.
Based on its review, the staff finds the applicants response acceptable because it clarified that the lube oil reservoir foam suppression systems are included in the scope of license renewal
 
with miscellaneous systems, in accordance with 10 CFR 54.4(a)(2), and are subject to an AMR.
For the manual/spray system No. 2 for the boiler feed pump, the applicant stated the following:
The manual/spray system No. 2 for the boiler feed pump is not required to satisfy the provisions of BTP APCSB 9.5-1, Appendix A, and is not credited in fire
 
protection SERs. The manual spray system No. 2 satisfies requirements of the
 
plant insurance carrier. SER Section 5.9.1 states there is no safety-related
 
equipment or electrical cables located within the turbine building. SER
 
Section 5.9.6 discusses modifications to provide three-hour fire-rated doors and
 
dampers in the barriers between the turbine building and the control building, as
 
well as upgrading penetrations to a three-hour fire-rating.
Based on its review, the staff finds the applicants response acceptable because it explained that the manual/spray system No. 2 for the boiler feed pump does not have a license renewal
 
intended function. The manual/spray system No. 2 for the boiler feed pump does not provide a
 
fire protection function as part of the applicants approach to complying with 10 CFR 50.48;
 
thus, the associated fire protection components are not within the scope of license renewal.
For the hydrogen seal oil unit foam system, the applicant stated the following:
Fluid-containing portions of the H 2 seal oil unit foam suppression systems are included with miscellaneous systems in-scope pursuant to 10 CFR 54.4(a)(2)
 
and are subject to an AMR. The AMR results for the fluid-containing portions of
 
the system are included in LRA Table 3.3.2-19-20-IP3. Based on discussion in
 
the SER for IP3 dated March 6, 1979, the H 2 seal oil unit foam suppression system is considered as meeting the scoping requirements of 10 CFR 54.4(a)(3),
in addition to 10 CFR 54.4(a)(2). The AMR results in Table 3.3.2-11-IP3 are
 
applicable to the portions of the H 2 seal oil unit foam suppression system normally containing air.
Based on its review, the staff finds the applicants response acceptable because it clarified that hydrogen seal oil unit foam suppression systems are included in the scope of license renewal
 
with miscellaneous systems, in accordance with 10 CFR 54.4(a)(2), and are subject to an AMR.
For the manual boiler feed pump oil accumulators Nos. 31 and 32 foam system, the applicant stated the following:
Fluid-containing portions of the manual boiler feed pump oil accumulators No. 31 and 32 foam suppression systems are included with miscellaneous systems
 
in-scope pursuant to 10 CFR 54.4(a)(2) and are subject to an AMR. The AMR
 
results for the fluid-containing portions of the system are shown in LRA 2-159 Table 3.3.2-19-20-IP3. Based on discussion in the SER for IP3 dated March 6, 1979, the manual boiler feed pump oil accumulators No. 31 and 32
 
foam suppression system is considered as meeting the scoping requirements of
 
10 CFR 54.4(a)(3), in addition to 10 CFR 54.4(a)(2). The AMR results in LRA
 
Table 3.3.2-11-IP3 are applicable to the portions of the manual boiler feed pump
 
oil accumulators No. 31 and 32 foam suppression system normally containing air.
Based on its review, the staff finds the applicants response acceptable because it clarified that the manual boiler feed pump oil accumulators No. 31 and 32 foam suppression systems are
 
included in the scope of license renewal with miscellaneous systems, in accordance with
 
10 CFR 54.4(a)(2), and are subject to an AMR.
For the boiler feed console pump foam system, the applicant stated the following:
Fluid-containing portions of the boiler feed console pump foam suppression systems are included with miscellaneous systems in-scope pursuant to
 
10 CFR 54.4(a)(2) and are subject to an AMR. The AMR results for the
 
fluid-containing portions of the system are shown in LRA Table 3.3.2-19-20-IP3.
 
Based on discussion in the SER for IP3 dated March 6, 1979, the boiler feed
 
console pump foam suppression system is considered as meeting the scoping
 
requirements of 10 CFR 54.4(a)(3), in addition to 10 CFR 54.4(a)(2). The AMR
 
results in LRA Table 3.3.2-11-IP3 are applicable to the portions of the boiler feed
 
console pump foam suppression system normally containing air.
Based on its review, the staff finds the applicants response acceptable because it clarified that the boiler feed console pump foam suppression systems are included in the scope of license
 
renewal with miscellaneous systems in accordance with 10 CFR 54.4(a)(2) and are subject to
 
an AMR. Based on its review, the staff finds the applicants response to RAI 2.3B.3.11-1 acceptable. The staffs concern described in RAI 2.3B.3.11-1 is resolved.
In RAI 2.3B.3.11-2, dated October 24, 2007, the staff stated that Section 3.1.8 of the fire protection SER for IP3, dated March 6, 1979, discusses dry-pipe, pre-action sprinkler systems
 
for all cable trays in the electrical tunnels, electrical penetration areas, and cable trays in the
 
motor control center areas. LRA Section 2.3.3.11 does not indicate that the dry-pipe pre-action
 
sprinkler systems are within the scope of license renewal and subject to an AMR. The staff
 
requested that the applicant verify whether the dry-pipe pre-action sprinkler systems for all cable
 
trays in the electrical tunnels, electrical penetration areas, and cable trays in the motor control
 
center areas are within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
subject to an AMR, in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope
 
of license renewal and are not subject to an AMR, the staff asked the applicant to justify their
 
exclusion.
In its response, dated November 16, 2007, the applicant stated that the dry-pipe, pre-action sprinkler systems for all cable trays in the electrical tunnels, electrical penetration areas, and
 
cable trays in the motor control center areas are within the scope of license renewal and subject
 
to an AMR. License renewal drawing LRA-9321-40913-001-0 shows the electrical tunnel dry
 
pipe pre-action sprinkler systems 8, 8A, 9, and 9A at coordinates G6. The electrical tunnel
 
sprinkler systems cover areas in the electrical penetration area and cable trays in the motor 2-160 control center areas, in addition to the cable trays in the electrical tunnels. The absence of boundary flags where the highlighted piping enters the text box indicates that the portion of the
 
system described in the text box is within scope and subject to an AMR.
Based on its review, the staff finds the response to RAI 2.3B.3.11-2 acceptable because the applicant identified the dry-pipe, pre-action sprinkler systems for all cable trays in the electrical
 
tunnels, electrical penetration areas, and cable trays in the motor control center areas as within
 
the scope of license renewal and subject to an AMR. Therefore, the staff concludes that the
 
applicant correctly identified these dry-pipe, pre-action sprinkler systems and the associated
 
components as within the scope of license renewal and subject to an AMR. The staffs concern
 
described in RAI 2.3B.3.11-2 is resolved.
In RAI 2.3B.3.11-3, dated October 24, 2007, the staff stated that Section 5.9.1 of the March 6, 1979, fire protection SER for IP3 discusses automatic deluge foam suppression
 
systems for various areas in the turbine building. LRA Section 2.3.3.11 does not indicate that
 
the foam suppression systems are within the scope of the license renewal and subject to an
 
AMR. The staff requested that the applicant verify whether the foam suppression systems for
 
various areas in the turbine building are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and subject to an AMR, in accordance with 10 CFR 54.21(a)(1). If the systems
 
are excluded from the scope of license renewal and are not subject to an AMR, the staff asked
 
the applicant to justify their exclusion.
In its response, dated November 16, 2007, the applicant stated that the fluid-containing portions of the foam suppression systems for various areas in the turbine building are included with
 
miscellaneous systems, in accordance with 10 CFR 54.4(a)(2), and are subject to an AMR. LRA
 
Table 3.3.2-19-20-IP3 summarizes the AMR results for the fluid-containing portions of the
 
systems. Based on the discussion in the March 6, 1979, fire protection SER for IP3, the foam
 
suppression systems for various areas in the turbine building meet the scoping requirements of
 
10 CFR 54.4(a)(3), in addition to 10 CFR 54.4(a)(2). The applicant further identified the system
 
components that are subject to an AMR, in accordance with 10 CFR 54.21(a)(1). The applicant
 
indicated that LRA Table 3.3.2-11-IP3 summarizes the AMR results.
Based on its review, the staff finds the applicants response to RAI 2.3B.3.11-3 acceptable because fluid-containing portions of the foam systems for various areas in the turbine building
 
were identified as being within the scope of license renewal and subject to an AMR. The AMR
 
results are summarized in LRA Table 3.3.2-20-IP3.
In RAI 2.3B.3.11-4, dated October 24, 2007, the staff stated that Section 5.11.1 of the March 6, 1979, fire protection SER for IP3 discusses wet pipe automatic sprinklers in the diesel
 
generator building sump area beneath each diesel engine and on the diesel day tank. On
 
license renewal drawing LRA-9321-40913-0, at coordinate E3, the wet pipe automatic sprinkler
 
system does not appear to be within the scope of the license renewal and subject to an AMR (i.e., the box surrounding the sprinklers in question is not highlighted). The staff requested that
 
the applicant verify whether the wet pipe sprinkler system designed to protect the diesel
 
generator building sump area and diesel day tank is within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and subject to an AMR, in accordance with 10 CFR 54.21(a)(1). If
 
the system is excluded from the scope of license renewal and is not subject to an AMR, the staff
 
asked the applicant to justify its exclusion.
2-161 In its response, dated November 16, 2007, the applicant stated that the IP3 wet pipe automatic sprinklers in the diesel generator building sump area beneath each diesel engine and on the
 
diesel day tanks are in scope and subject to an AMR, as shown on license renewal drawing
 
LRA-9321-40913-001-0, coordinate E3. The absence of boundary flags where the highlighted
 
piping enters the text box indicates that the portion of the system described in the text box is
 
within the scope of license renewal and subject to an AMR, along with the highlighted
 
components on the drawing.
Based on its review, the staff finds the response to RAI 2.3B.3.11-4 acceptable because the applicant identified wet pipe automatic sprinklers in the diesel generator building sump area
 
beneath each diesel engine and on the diesel day tank as within the scope of license renewal
 
and subject to an AMR. Further, the applicant clarified that the absence of boundary flags where
 
the highlighted piping enters the text box indicates that the portion of the system described in
 
the text box is within the scope of license renewal and subject to an AMR, along with the
 
highlighted components on license renewal drawing LRA-9321-40913-001-0. Therefore, the
 
staff concludes that the applicant correctly identified the wet pipe automatic sprinklers in
 
question as within the scope of license renewal and subject to an AMR. The staffs concern
 
described in RAI 2.3B.3.11-4 is resolved.
In RAI 2.3B.3.11-5, dated October 24, 2007, the staff stated that Section 5.13.1 of the March 6, 1979, fire protection SER for IP3 discusses the charcoal filter manual water spray
 
system. LRA Section 2.3.3.11 does not indicate that the manual water spray system and its
 
associated components are within the scope of the license renewal and subject to an AMR. The
 
staff requested that the applicant verify whether the charcoal filter manual water spray system
 
and its associated components are within the scope of license renewal, as required by
 
10 CFR 54.4(a), and subject to an AMR, in accordance with 10 CFR 54.21(a)(1). If the system
 
is excluded from the scope of license renewal and is not subject to an AMR, the staff asked the
 
applicant to justify its exclusion.
In its response, dated November 16, 2007, the applicant stated that the IP3 charcoal filter manual water spray system is in scope, as shown on license renewal drawing
 
LRA-9321-40913-001-0 at coordinates H8. The absence of boundary flags where the
 
highlighted piping enters the text box indicates that the portion of the system described in the
 
text box is in scope and subject to an AMR, along with the highlighted components on the
 
drawing. License renewal drawing LRA-9321-40913-001-0 continues to an equipment
 
arrangement drawing which is not available as a license renewal drawing.
Based on its review, the staff finds the response to RAI 2.3B.3.11-5 acceptable because the applicant identified the charcoal filter manual water spray system in question as within the
 
scope of license renewal and subject to an AMR. Further, the applicant clarified that the
 
absence of boundary flags where the highlighted piping enters the text box indicates that the
 
portion of the system described in the text box is within the scope of license renewal and
 
subject to an AMR, along with the highlighted components on license renewal drawing
 
LRA-9321-40913-001-0.
In RAI 2.3B.3.11-6, dated October 24, 2007, the staff stated that Section 5.15.1 of the March 6, 1979, fire protection SER for IP3 discusses automatic water spray systems for oil-filled
 
transformers located adjacent to the control building. LRA Section 2.3.3.11 does not indicate
 
that the automatic water spray systems and their associated components are within the scope
 
of license renewal and subject to an AMR. The staff requested that the applicant verify whether 2-162 the automatic water spray systems for oil-filled transformers are within the scope of license renewal, as required by 10 CFR 54.4(a), and subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1). If the systems are excluded from the scope of license renewal and are not
 
subject to an AMR, the staff asked the applicant to justify their exclusion.
In its response, dated November 16, 2007, the applicant stated that it initially determined that the automatic water spray systems and their associated components for the oil-filled
 
transformers located adjacent to the control building did not have a license renewal intended
 
function. The applicant believed that they were only required to protect the transformers, satisfying requirements of the plant insurance carrier. However, the spray systems provide for
 
defense in depth, in addition to the installed 3-hour-rated fire barriers between the control
 
building and the transformer yard, and are considered in scope and subject to an AMR. LRA
 
Table 2.3.3-11-IP3 includes the applicable component types subject to an AMR, and LRA
 
Table 3.3.2-11-IP3 provides the AMR results.
Based on its review, the staff finds the response to RAI 2.3B.3.11-6 acceptable because the applicant concluded that the automatic spray system for the oil-filled transformer performs a
 
defense-in-depth function and, therefore, is within the scope of license renewal and subject to
 
an AMR. The staff confirmed that LRA Table 3.3.2-11-IP3 provides the AMR results. Therefore, the staff finds that the applicant correctly identified the automatic water spray systems and their
 
associated components for the oil-filled transformers as within the scope of license renewal and
 
subject to an AMR. The staffs concern described in RAI 2.3B.3.11-6 is resolved.
2.3B.3.11.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its
 
review, the staff concludes that the applicant has adequately identified the fire protection - water
 
system components within the scope of license renewal, as required by 10 CFR 54.4(a), and
 
those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3B.3.12  IP3 Fire Protection-Carbon Dioxide, Halon, and RCP Oil Collection Systems 2.3B.3.12.1  Summary of Technical Information in the Application LRA Section 2.3.3.12 describes the fire protectionCO 2 , Halon, and RCP oil collection system, which is listed under the following system codes:  CO 2 system: system code CO2  Halon: system code HAL  RCP oil collection components: system code RCS The CO 2 system provides fire protection and supplies CO 2 gas to purge the main generator. The CO 2 fire protection system has two 10-ton-capacity, low-pressure tanks, a distribution header, piping, and valves. An automatic total-flooding CO 2 fire suppression system protects the 480-V switchgear room, cable spreading room, diesel generator rooms, and the turbine generator
 
exciter enclosure. A local application CO 2 fire suppression system protects the turbine building, including the main boiler FW pumps, turbine governor, MS and reheat valves, and generator 2-163 bearings. Before maintenance work on the main generator, the hydrogen gas must be evacuated from the system. Inert CO 2 gas from a CO 2 gas-vaporizing system purges the generator. The IP2 CO 2 gas-vaporizing system also may operate through a supply line from the IP1 intake structure area. The Halon 1301 system suppresses fires in the administration/service building technical support center/computer room, in the Appendix R diesel enclosure, and in the meteorological building.
 
The Halon system does not protect any safety-related plant equipment. Protection of the
 
Appendix R diesel enclosure from fire is not a required function under Appendix R. For IP3, the
 
Halon 1301 system has no intended functions under 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), or
 
10 CFR 54.4(a)(3).
The RCP oil collection system is designed, engineered, and installed so an RCP lube oil system failure will not lead to fire during normal or DBA conditions or impact any safety-related system
 
capability during a safe-shutdown earthquake. The collection system can collect lube oil from all
 
pressurized and unpressurized potential leakage sites in the RCP lube oil systems and drain it
 
to a vented closed tank that can hold the required lube oil system inventory. A flame arrester in
 
each tank vent prevents fire flashback. The collection system consists of leakproof enclosures
 
or pans under oil-bearing components to contain leaks.
The fire protectionCO 2 and RCP oil collection systems have no intended functions under 10 CFR 54.4(a)(1).
The scoping and screening methodology identified the following RCP oil collection system intended function, in accordance with 10 CFR 54.4(a)(2):  Maintain integrity of nonsafety-related components such that no physical interaction with
 
safety-related components could prevent satisfactory accomplishment of a safety
 
function.The scoping and screening methodology also identified the following CO 2 and RCP oil collection systems intended functions, in accordance with 10 CFR 54.4(a)(3):  Provide automatic and manual CO 2 flooding for areas of the plant that (1) contain safety-related equipment or (2) pose significant hazards to plant areas containing
 
safety-related equipment (10 CFR 50.48) or both. Provide each RCP with an oil collection system that is designed to contain and direct the
 
oil to remote storage containers in the event of an oil leak.
LRA Table 2.3.3-12-IP3 identifies fire protectionCO 2 and RCP oil collection systems component types within the scope of license renewal and subject to an AMR, as well as their
 
intended functions.
2.3B.3.12.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.11, UFSAR Sections 9.6.2.3 and 9.6.2.4, and license renewal drawings using the evaluation methodology described in SER Section 2.3 and the
 
guidance in SRP-LR Section 2.3.
2-164 During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
The staff also reviewed the following IP3 fire protection CLB documents listed in the IP3 Operating License Condition 2.H: NRC fire protection SERs for IP3 dated September 21, 1973;
 
March 6, 1979; May 2, 1980; November 18, 1982; December 30, 1982; February 2, 1984;
 
April 16, 1984; January 7, 1987; September 9, 1988; October 21, 1991; April 20, 1994; and
 
January 5, 1995.
The staff also reviewed IP3 commitments associated with 10 CFR 50.48 (i.e., an approved fire protection program), using its commitment responses to BTP APCSB 9.5-1 and BTP APCSB 9.5-1, Appendix A.
During its review of LRA Section 2.3.3.12, the staff identified areas in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The applicant responded to the staffs RAIs as discussed below.
In RAI 2.3B.3.12-1, dated October 24, 2007, the staff asked the applicant to explain why license renewal drawing LRA-9321-24403-0 indicated that the following fire protection system
 
components were not subject to an AMR (i.e., they are not highlighted in brown):  Appendix R diesel generator Halon 1301 system  technical support center/plant computer Halon system  IP3 record room vault Halon 1301 system The staff requested that the applicant verify whether the above components are within the scope of license renewal, as required by 10 CFR 54.4(a), and subject to an AMR, in accordance
 
with 10 CFR 54.21(a)(1). If these components are excluded from the scope of license renewal
 
and are not subject to an AMR, the staff asked the applicant to justify their exclusion.
In its response, dated November 16, 2007, the applicant addressed each system individually.
For the Appendix R diesel generator Halon 1301 system, the applicant stated that the
 
Appendix R diesel generator is located in a standalone structure separated from other plant
 
structures and equipment. The applicant further explained that the technical support
 
center/plant computer and the record room vault are located in an administration building
 
attached to the turbine building. The applicant added that a sprinkler system had replaced the
 
IP3 record room vault Halon 1301 system.
The applicant stated that the areas referenced in the RAI response do not contain systems or components required for safe shutdown of the plant, do not provide an exposure hazard to any
 
building or area required for safe shutdown, and are not located in safety-related areas. The
 
applicable IP3 fire protection SER, dated March 6, 1979, credits no fire suppression systems for
 
these areas. The Halon systems are not required for compliance with 10 CFR 50.48. The fire
 
protection SER does not stipulate the addition of suppression systems for the Appendix R diesel
 
generator, technical support center/plant computer, or the IP3 record room vault.
2-165 Based on its review, the staff finds the applicants response to RAI 2.3B.3.12-1 acceptable. The applicant does not credit the Halon 1301 systems for the Appendix R diesel generator room, technical support center/plant computer room, and record room vault toward meeting the
 
requirements of Appendix R to 10 CFR Part 50 for achieving safe shutdown in the event of a
 
fire. Although the IP3 March 6, 1979, fire protection SER addresses the Halon 1301 systems for
 
the Appendix R diesel generator room, technical support center/plant computer room, and
 
record room vault, NRC fire protection regulations do not require these systems. The
 
Appendix R diesel generator room, technical support center/plant computer room, and record
 
room vault are not safety related and cannot affect safety-related equipment by spatial
 
interaction. Furthermore, they are not required for safe shutdown. Therefore, they have no
 
intended function under 10 CFR 54.4(a)(2). In addition, the staff reviewed commitments made
 
by the applicant to satisfy BTP APCSB 9.5-1, Appendix A, which discusses Halon 1301 systems
 
and found no intended function associated with 10 CFR 54.4(a)(2). Therefore, the staff finds
 
that the applicant correctly excluded the Halon 1301 systems for the Appendix R diesel
 
generator room, technical support center/plant computer room, and record room vault from the
 
scope of license renewal and an AMR. The staffs concern described in RAI 2.3B.3.12-1 is
 
resolved.2.3B.3.12.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its
 
review, the staff concludes that the applicant has adequately identified the fire protection CO 2 , Halon, and RCP oil collection system components within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3B.3.13  IP3 Fuel Oil Subsystems 2.3B.3.13.1  Summary of Technical Information in the Application LRA Section 2.3.3.13 describes the IP3 fuel oil subsystems, which include the IP3 EDGs, the IP3 fire protection diesel engines, and the IP3 Appendix R diesel generator.
Each diesel fuel oil storage and transfer system supplying fuel to the EDGs has its own fuel oil day tank and an underground storage tank. The day tanks are within the diesel generator
 
buildings. An engine-driven fuel oil pump supplies the fuel from the day tank to the engine. The
 
day tank fills automatically during engine operation from its dedicated underground storage
 
tank, which is adjacent to the diesel generator building. Each underground storage tank has a
 
motor-driven transfer pump to transfer fuel to the day tank.
Independent diesel fuel oil storage and transfer systems supply fuel to the IP2 and IP3 fire protection diesel engines. The IP3 fuel oil storage tank and components are located in the IP3
 
fire protection pump house.
An independent diesel fuel oil storage and transfer system supplies fuel to the IP3 Appendix R diesel generator, which has its own fuel oil day tank and underground storage tank. The day
 
tank supplies fuel directly to the engine. A transfer pump fills the fuel oil day tank automatically
 
from its storage tank during engine operation.
2-166 The fuel oil subsystems contain safety-related components relied on to remain functional during and following DBEs. They also contain nonsafety-related components whose failure potentially
 
could prevent the satisfactory accomplishment of a safety-related function. In addition, the fuel
 
oil subsystems perform functions that support fire protection and SBO.
LRA Table 2.3.3-13-IP3 identifies fuel oil subsystem component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3B.3.13.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13; UFSAR Sections 1.3.1, 8.2, and 16.1.3; and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.3.13, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The discussion of the staffs RAIs in SER Section 2.3B.3 details the disposition of
 
RAI 2.3B.3.13-1, dated February 13, 2008.
2.3B.3.13.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI response, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its
 
review, the staff concludes that the applicant has appropriately identified the fuel oil system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, in accordance with 10 CFR 54.21(a)(1).
2.3B.3.14  IP3 Emergency Diesel Generator System 2.3B.3.14.1  Summary of Technical Information in the Application LRA Section 2.3.3.14 describes the EDG system, which supplies emergency shutdown power upon loss of all other alternating current auxiliary power. The system consists of three EDG
 
sets, each with a diesel engine coupled to a 480-V generator. Each emergency diesel is started
 
automatically by two redundant air motors and has an air storage tank and compressor system, its own starting air subsystem, fuel oil subsystem, intake air subsystem, exhaust subsystem, lube oil subsystem, and jacket water cooling subsystem. The EDG system also has ventilation
 
equipment for the diesel generator building.
2-167 The EDG system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure could prevent the
 
satisfactory accomplishment of a safety-related function. In addition, the EDG system performs
 
functions that support fire protection.
The HVAC component parts of this system code are reviewed with HVAC systems (LRA Section 2.3.3.8). Fuel oil subsystem components are evaluated with fuel oil (LRA Section
 
2.3.3.13). Nonsafety-related components not evaluated with other systems and whose failure
 
could prevent satisfactory accomplishment of safety functions are evaluated with miscellaneous
 
systems (LRA Section 2.3.3.19). Remaining components are evaluated in LRA Section 2.3.3.14.
LRA Tables 2.3.3-14-IP3, 2.3.3-19-16-IP3, and 2.3.3-19-17-IP3 identify EDG system component types within the scope of license renewal and subject to an AMR, as well as their intended
 
functions.
2.3B.3.14.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.14, UFSAR Sections 8.2 and 16.1.3, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.3.14, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The applicant responded to the staffs RAI as discussed below.
In RAI 2.3B.3.14-1, dated December 7, 2007, the staff noted that a license renewal drawing for the IP3 jacket water to EDGs identified that the jacket water pumps for diesel engine Nos. 31, 32, and 33 are not subject to an AMR, in accordance with 10 CFR 54.21(a), because they are
 
not long-lived components. The staff noted that SRP-LR, Table 2.3-2, provides examples of
 
passive, long-lived components, such as diesel engine jacket water skid-mounted equipment.
 
To complete its review, the staff requested that the applicant confirm that the jacket water
 
pumps are short-lived components and describe its method for periodic replacement of these
 
components.
In its response, dated January 4, 2008, the applicant stated that IP3 EDG maintenance procedures specify that the jacket water pumps in question are scheduled for replacement every
 
16 years, in accordance with station maintenance procedures, and, therefore, they are not
 
subject to an AMR.
Based on its review, the staff finds the response to RAI 2.3B.3.14-1 acceptable because the applicant adequately explained that the practice of replacing the jacket water pumps meets the
 
intent of 10 CFR 54.21(a)(1)(ii) for short-lived components and that the maintenance procedures
 
control the pumps periodic replacement. Therefore, the staff agrees that the jacket water 2-168 pumps are not subject to an AMR. The staffs concern described in RAI 2.3B.3.14-1 is resolved.
In RAI 2.3A.3.14-2, dated December 7, 2007, the staff noted that license renewal drawings for the EDG jacket water cooling systems and EDG fuel oil systems for IP2 and IP3 label multiple
 
flexible conn [connections] as not long-lived components. By letter dated January 4, 2008, the
 
applicant responded to the staffs RAI. SER Section 2.3A.3.14 documents the RAI, the
 
applicants response, and the staffs evaluation.
The discussion of the staffs RAIs in SER Section 2.3B.3 details the disposition of RAI 2.3B.3.14-2, dated February 13, 2008.
2.3B.3.14.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its
 
review, the staff concludes that the applicant has appropriately identified the EDG system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3B.3.15  IP3 Security Generator System 2.3B.3.15.1  Summary of Technical Information in the Application LRA Section 2.3.3.15 describes the security propane generator system, which supplies power for the security lighting system and other security functions. The applicant credits a portion of
 
this security lighting under Appendix R, Section III.J (emergency lighting), to illuminate ingress
 
and egress to the Appendix R diesel generator, main and backup SW pumps, CST, and RWST.
The security propane generator system performs functions that support fire protection.
 
LRA Table 2.3.3-15-IP3 identifies security propane generator system component types within the scope of license renewal and subject to an AMR as well as their intended functions.
2.3B.3.15.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.15 and UFSAR Section 9.6.2.6 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2-169 2.3B.3.15.3  Conclusion The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In addition, the
 
staff sought to determine whether the applicant failed to identify any components subject to an
 
AMR. The staff found no such omissions. On the basis of its review, the staff concludes that the
 
applicant has adequately identified the security propane generator system components within
 
the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3B.3.16  IP3 Appendix R Diesel Generator System 2.3B.3.16.1  Summary of Technical Information in the Application LRA Section 2.3.3.16 describes the Appendix R diesel generator system, which supplies power to selected equipment and power supplies relied on in Appendix R and SBO events. The
 
Appendix R diesel generator complies with SBO requirements and can supply sufficient power
 
for safe-shutdown loads through the 6.9-kV distribution and the emergency 480-V buses and
 
motor control centers or the turbine building switchgear and motor control centers. Located in a
 
separate structure in the yard area, the Appendix R diesel generator installation is a
 
self-contained package that operates upon a complete loss of power and includes a starting air
 
compressor, batteries, battery charger, jacket water heater, lube oil heater, fuel oil pump and
 
lube oil pumps, and necessary filters and strainers.
The Appendix R diesel generator system performs functions that support fire protection and SBO.Fuel oil subsystem components are reviewed with fuel oil (LRA Section 2.3.3.13). Ventilation for the Appendix R diesel generator system is reviewed with HVAC systems (LRA Section 2.3.3.8).
 
Remaining components are evaluated in LRA Section 2.3.3.16. LRA Table 2.3.3-16-IP3 identifies Appendix R diesel generator system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3B.3.16.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.16, UFSAR Sections 8.1.1 and 8.2.3, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant has identified as within the scope of license renewal to verify it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2-170 2.3B.3.16.3  Conclusion The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the Appendix R diesel generator system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3B.3.17  IP3 City Water System 2.3B.3.17.1  Summary of Technical Information in the Application LRA Section 2.3.3.17 describes the city water system, which supplies water to various components throughout the plant. The city water supply was installed originally for IP1, but now
 
has functions for all three units. The IP2 city water description includes the city water tank and
 
many of the shared site components. This system includes only the IP3 components. City water
 
is used for a variety of purposes throughout IP3, such as supplying water to fire protection
 
systems, to equipment for makeup or cooling, and to sanitary and potable facilities (e.g.,
emergency showers, eye wash stations, hose connections, sinks, water coolers, water heaters, and lavatories). The system also supplies a backup, but not a safety-grade, source of water to
 
the AFW pumps and can supply makeup to the spent fuel pit.
The city water system contains nonsafety-related components whose failure could potentially prevent the satisfactory accomplishment of a safety-related function. In addition, the city water
 
makeup performs functions that support fire protection.
Components of the city water system that provide water to the AFW system are reviewed with the AFW systems (LRA Section 2.3.4.3). LRA Tables 2.3.3-17-IP3 and 2.3.3-19-13 identify city water system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3B.3.17.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.17, UFSAR Sections 6.1.1 and 10.3.1, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.3.17, the staff identified areas in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The applicant responded to the staffs RAIs as discussed below.
2-171 In RAI 2.3B.3.17-1, dated December 7, 2007, the staff noted that the LRA states that the IP3 city water system has the intended function under 10 CFR 54.4(a)(3) of providing water to the
 
fire protection tanks. The staff further noted that the applicant did not highlight on a license
 
renewal drawing for the city water system a portion of the city water system piping upstream of
 
the eight isolation valves to fire water storage tanks 1 and 2 to indicate that it is within the scope
 
of license renewal. This piping connects to the 16-inch water main from the Village of Buchanan
 
and provides makeup water for the fire water supply function. The staff asked the applicant to
 
explain why it considered all of the city water system piping from the 16-inch water main for the
 
Village of Buchanan to the fire water storage tanks to be outside the scope of license renewal
 
under 10 CFR 54.4(a)(3) and not subject to an AMR.
In its response, dated January 4, 2008, the applicant stated that the 16-inch water main from the Village of Buchanan is a source of makeup water for the city water system. The applicant
 
explained that city water is the normal source of makeup water to the two fire water storage
 
tanks; however, the city water source is not required to support any fire scenarios or Appendix R
 
events, since each of the storage tanks has a sufficient reserve for fire fighting, without makeup, available to handle all fire scenarios. Therefore, although the city water system can provide a
 
water supply to the fire water tanks, it is not a license renewal intended function, since makeup
 
is not required for compliance with 10 CFR 50.48 fire scenarios or Appendix R events. As a
 
result, the applicant changed LRA Section 2.3.3.17, for IP3, to delete the intended function
 
bullet item, provide water supply to the fire protection tanks (10 CFR 50.48), as a
 
10 CFR 54.4(a)(3) function.
Based on its review, the staff finds the applicants response to RAI 2.3B.3.17-1 acceptable because it adequately explained that, although city water is the normal source of makeup water
 
to the two fire water storage tanks, the source is not required to support any fire scenarios or
 
Appendix R events. Each of the storage tanks has a sufficient reserve for firefighting that can
 
handle all fire scenarios without the need for continued makeup. Since makeup is not required
 
for 10 CFR 50.48 fire scenarios or Appendix R events, the applicant has changed LRA
 
Section 2.3.3.17, for IP3, to delete the intended function bullet item, provide water supply to the
 
fire protection tanks (10 CFR 50.48), as a 10 CFR 54.4(a)(3) function. The staffs concern
 
described in RAI 2.3B.3.17-1 is resolved.
In RAI 2.3B.3.17-2, dated December 7, 2007, the staff noted that the LRA states that the IP3 city water system has no intended functions, in accordance with 10 CFR 54.4(a)(1). However, the staff noted that, on a license renewal drawing for the city water system under General
 
Notes, the applicant stated under the heading Class I Piping, (1) above ground city water
 
make-up to closed cooling water systemexpansion tank in control room and EDG jacket water
 
expansion tank, and (2) city water from Unit 1 tie into AFW pumps suction. The staff also
 
noted that under the heading Class III Piping, the LRA states, (1) above ground city water
 
make-up to closed cooling water systemhead tank in turbine building, and (2) above ground
 
city water supply to nuclear services.
In addition, the staff found that a license renewal drawing for the condensate and boiler feed pump suction system shows a small portion of the city water system piping. This portion of city
 
water system piping is highlighted in purple, indicating that it is within the scope of license
 
renewal and subject to an AMR. The drawing identifies this portion of city water system piping
 
as Class I. By definition, all Class I and Class III piping should have intended functions under
 
10 CFR 54.4(a)(1). The staff requested that the applicant address the following:
2-172(a) Explain why the Class I and Class III city water system piping on the two drawings do not have an intended function, in accordance with 10 CFR 54.4(a)(1). (b) Explain why the city water piping up to the closed cooling water system expansion tank, EDG jacket water expansion tank, closed cooling water system head tank, and nuclear
 
services on the one city water system license renewal drawing is not highlighted in
 
purple, indicating that it is within the scope of license renewal and subject to an AMR. (c) Explain why the city water system piping that continues from one city water license renewal drawing onto another drawing for supplying the 40-gallon EDG jacket water
 
expansion tanks is also not highlighted in purple, indicating that it is within the scope of
 
license renewal and subject to an AMR.
In its response, dated January 4, 2008, the applicant stated the following: (a) Class I and Class Ill refer to seismic classification; not to ASME safety class, and that Class I components include safety-related equipment. The
 
applicant further stated that Class I SSCs also include components that
 
do not perform a safety function. The applicant explained Class Ill is the
 
designation for SSCs which are not directly related to reactor operation
 
and containment, and which do not have to maintain structural integrity
 
during or following an SSE. Further, when defining the city water system
 
components required to support a 10 CFR 54.4(a)(1) system intended
 
functions for license renewal, the seismic classification boundaries were
 
not used, since they do not accurately reflect the portions of the system
 
required to meet system intended functions. Finally, the applicant
 
explained that all components needed to accomplish system intended
 
functions were included within scope regardless of the class breaks on
 
the drawings.(b) The license renewal drawings only highlight portions of systems within scope and subject to an aging management review for 10 CFR 54.4(a)(1)
 
or (a)(3). The city water piping up to the closed cooling water system
 
expansion tank, EDG jacket water expansion tank, closed cooling water
 
system head tank, and nuclear services on the city water license renewal
 
drawing is not required to meet any system intended functions described
 
in 10 CFR 54.4(a)(1) or (a)(3); therefore, the piping is not highlighted.
 
However, this piping and valves are within scope for 10 CFR 54.4(a)(2)
 
due to the potential for spatial interaction and are included in LRA tables
 
for components subject to an AMR. (c) The LRA drawings only reflect portions of systems in scope and subject to aging management review for 10 CFR 54.4(a)(1) or (a)(3). The city
 
water piping up to the diesel generator jacket water expansion tank on
 
drawings LRA-9321-20343-001 and 9321-H-20283 is not required to
 
meet any system intended functions described in 10 CFR 54.4(a)(1) or (a)(3) and therefore is not highlighted. However, this piping and valves
 
are in scope for 10 CFR 54.4(a)(2) due to the potential for spatial
 
interaction. They are included in LRA Tables 2.3.3-19-13-1P3 and
 
3.3.2-19-13-1P3.
2-173 City water is the source of makeup water to the 40-gallon diesel generator jacket water expansion tanks. Makeup water is not required for the EDGs to perform
 
their intended function.
Based on its review, the staff finds the response to RAI 2.3B.3.17-2(a) acceptable because the applicant adequately explained that Class I and Class Ill on the license renewal drawing refer to
 
seismic classification, rather than ASME safety class. Class I SSCs at IP2 and IP3 include
 
components that do not perform a safety function. At IP2 and IP3, Class Ill is the designation for
 
SSCs that are not directly related to reactor operation and containment and that do not have to
 
maintain structural integrity during or following a safe-shutdown earthquake. The applicant did
 
not use the seismic classification boundaries when defining the city water system components
 
that are required to comply with 10 CFR 54.4(a)(1) system intended functions for license renewal, since they do not accurately reflect the portions of the system required to meet system
 
intended functions. The applicant included all components needed to accomplish system
 
intended functions within the scope of license renewal, regardless of the seismic class breaks
 
on the drawings. The staffs concern described in RAI 2.3B.3.17-2(a) is resolved.
Based on its review, the staff finds the applicants response to RAI 2.3B.3.17-2(b) acceptable because it adequately explained that the license renewal drawings reflect only the portions of
 
systems within scope and subject to an AMR, in accordance with 10 CFR 54.4(a)(1) or
 
10 CFR 54.4(a)(3). The city water piping up to the closed cooling water system expansion tank, EDG jacket water expansion tank, closed cooling water system head tank, and nuclear services, as depicted on the city water license renewal drawing, is not required to meet any system
 
intended functions under 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3); therefore, it was not
 
highlighted. Although not highlighted, the applicant has included the piping and valves within the
 
scope of license renewal, in accordance with 10 CFR 54.4(a)(2), because of the potential for
 
spatial interaction. The applicant also included the piping and valves in city water LRA tables for
 
components subject to an AMR. The staffs concern described in RAI 2.3B.3.17-2(b) is resolved.
Based on its review, the staff finds the applicants response to RAI 2.3B.3.17-2(c) acceptable because it adequately explained that the license renewal drawings reflect only the portions of
 
systems within the scope of license renewal and subject to an AMR, under 10 CFR 54.4(a)(1) or
 
10 CFR 54.4(a)(3). The city water piping up to the EDG jacket water expansion tank is not
 
required to meet any system intended functions, in accordance with 10 CFR 54.4(a)(1) or
 
10 CFR 54.4(a)(3); therefore, it was not highlighted. Although not highlighted, the applicant
 
considered the piping and valves to be within scope, in accordance with 10 CFR 54.4(a)(2),
because of the potential for spatial interaction. The applicant included the piping and valves in
 
city water LRA tables for components subject to an AMR. City water, as a makeup water source
 
to the EDG jacket water expansion tanks, is not required for the EDGs to perform their intended
 
function. The staffs concern described in RAI 2.3B.3.17-2(c) is resolved.
2.3B.3.17.3  Conclusion
 
The staff reviewed the LRA, UFSAR, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In
 
addition, the staff sought to determine whether the applicant failed to identify any components
 
subject to an AMR. The staff found no such omissions. On the basis of its review, the staff concludes that the applicant has appropriately identified the city water system components
 
within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an 2-174 AMR, as required by 10 CFR 54.21(a)(1).
2.3B.3.18  IP3 Plant Drains 2.3B.3.18.1  Summary of Technical Information in the Application LRA Section 2.3.3.18 describes the plant drains, which are passive fire protection features required for adequate protection of safety-related equipment from water damage in areas with
 
fixed suppression systems. Plant drain components also prevent drain systems in areas with
 
combustible materials from spreading fires into other areas of the plant. Some plant drains
 
protect safety-related equipment from flooding effects.
Plant drain components are included in various systems, but grouped for this evaluation.
SRP-LR Section 2.1.3.1 indicates that it is appropriate to group similar components from various
 
plant systems into one consolidated review.
To prevent local flooding, areas with automatically operated fire protection have either gravity or pump drains to handle the maximum quantity of spray water. Plant drains protect safety-related
 
equipment in the diesel generator rooms, electrical tunnels, PAB, and auxiliary feed pump room
 
from the effects of Class III component failure. Either floor drains remove fire suppression water
 
adequately or the water flows through other passages to protect safety-related equipment.
 
When safety-related equipment may be lost as a result of inadvertent actuation of a fire system, redundant systems are available for safe shutdown.
The floor drains, fire water, and liquid waste disposal systems include plant drain components.
Other sections do not address the waste disposal and liquid waste disposal systems. The floor
 
drains system is not required for regulated events. Other systems provide drainage for flooding
 
protection.
The liquid waste disposal system collects and processes liquid wastes from throughout the plant, including wastes from equipment drains, radioactive chemical laboratory drains, decontamination drains, demineralizer regeneration, and floor drains. The system also collects
 
and transfers liquid drained from the RCS directly to the CVCS for processing. The system
 
includes piping, valves, pumps, collection tanks, instruments, and controls. The system includes
 
several containment penetrations and accompanying isolation components.
SER Section 2.3B.3.19 describes the floor drains system. SER Section 2.3B.3.11 describes the fire water system.
The plant drains system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure
 
potentially could prevent the satisfactory accomplishment of a safety-related function. In
 
addition, the plant drains system performs functions that support fire protection.
A small number of liquid waste disposal system components are reviewed with the safety injection systems (LRA Section 2.3.2.4) and the primary water makeup systems (LRA
 
Section 2.3.3.7).
LRA Tables 2.3.3-18-IP3 and 2.3.3-19-33-IP3 identify plant drains system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2-175 2.3B.3.18.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.18 and UFSAR Sections 9.6.2.3, 11.1, and 16.1.3 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR
 
Section 2.3.
During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.3.18, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The discussion of the staffs RAIs in SER Section 2.3B.3 details the disposition of
 
RAI 2.3B.3.18-1, dated February 13, 2008.
2.3B.3.18.3  Conclusion
 
The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In addition, the
 
staff sought to determine whether the applicant failed to identify any components subject to an
 
AMR. The staff found no such omissions. On the basis of its review, the staff concludes that the
 
applicant has appropriately identified the plant drains system components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1). 2.3B.3.19  IP3 Miscellaneous Systems in Scope for 10 CFR 54.4(a)(2) 2.3B.3.19.1  Summary of Technical Information in the Application In LRA Section 2.3.3.19, the applicant described those systems that it included within the scope of license renewal because of their potential for physical interactions with safety-related
 
components, as required by 10 CFR 54.4(a)(2). In this section, the applicant also described the
 
components in these systems that are subject to an AMR. LRA Table 2.3.3-19-A-IP3 lists all of
 
these systems and the LRA section in which the applicant evaluated these systems. LRA
 
Section 2.3.3.19 describes in detail those systems, which are listed below, that do not have
 
correlating LRA sections:  ammonia/morpholine addition  boron and layup chemical addition  CL CW extraction steam  floor drains  gaseous waste disposal  hydrazine addition  heater drain/moisture separator drain/vent 2-176 instrument air closed cooling  lube oil  low-pressure steam dump  main turbine generator  nuclear equipment drains  process radiation monitoring  primary plant sampling  river water service  main generator seal oil  secondary plant sampling  turbine hall closed cooling  vapor containment hydrogen analyzer  hydrogen (added by applicant by letter dated March 12, 2008)
Also in LRA Section 2.3.3.19, the applicant identified the following IP3 systems that it did not review under 10 CFR 54.4(a)(2) for spatial interaction because the applicant included all of the
 
systems passive mechanical components under either 10 CFR 54.4(a)(1), another function of
 
10 CFR 54.4(a)(2), or 10 CFR 54.4(a)(3):  AFW control building HVAC  CCW control rod drive  control room HVAC  engineered safeguards initiation logic  isolation valve seal water  RHR reactor protection and control  SG SG level control  security propane generator The following are brief descriptions of IP3 systems that are included within the scope of license renewal and subject to an AMR, based only on the criterion of 10 CFR 54.4(a)(2). Ammonia/Morpholine Addition System.
The purpose of the ammonia/morpholine addition system is to provide ammonia or morpholine for pH control for the condensate system. LRA
 
Table 2.3.3-19-1-IP3 identifies ammonia/morpholine addition system component types within
 
the scope of license renewal and subject to an AMR as well as their intended functions. Boron and Layup Chemical Addition System
.The boron and layup chemical addition system supplies chemicals to the SGs for chemistry control, even during periods of wet layup.
Components in the boron and layup chemical addition system that support the AFW system
 
pressure boundary are evaluated with the AFW systems (LRA Section 2.3.4.3). LRA
 
Table 2.3.3-19-3-IP3 identifies boron and layup chemical addition system component types
 
within the scope of license renewal and subject to an AMR, as well as their intended functions.
Chlorination System
.The chlorination system supplies sodium hypochlorite to limit microorganism fouling in the intake bays and river water systems. LRA Table 2.3.3-19-5-IP3
 
identifies chlorination system component types within the scope of license renewal and subject 2-177 to an AMR, as well as their intended functions.
Circulating Water System
.The CW system supplies the condenser with Hudson River water to cool the steam exiting the low-pressure turbines. LRA Table 2.3.3-19-12-IP3 identifies CW system component types within the scope of license renewal and subject to an AMR, as well as
 
their intended functions. Extraction Steam System
.The extraction steam system utilizes steam to preheat feedwater.
LRA Table 2.3.3-19-18-IP3 identifies extraction steam system component types within the
 
scope of license renewal and subject to an AMR, as well as their intended functions.
Floor Drains System
.The floor drains system removes any water collected in the nonradioactive floor drains in the turbine building, intake structure, and diesel generator building. LRA
 
Table 2.3.3-19-19-IP3 identifies floor drains system component types within the scope of license
 
renewal and subject to an AMR, as well as their intended functions.
Gaseous Waste Disposal System
.The gaseous waste disposal system collects, compresses, stores, samples, and releases gaseous waste from the primary and auxiliary systems. LRA
 
Table 2.3.3-19-25-IP3 identifies gaseous waste disposal system component types within the
 
scope of license renewal and subject to an AMR, as well as their intended functions.
Hydrazine Addition System
.The hydrazine addition system injects hydrazine into the secondary system for oxygen control. LRA Table 2.3.3-19-26-IP3 identifies hydrazine addition system
 
component types within the scope of license renewal and subject to an AMR, as well as their
 
intended functions.
Heater Drain/Moisture Separator Drain/Vent System
.The heater drain/moisture separator drain/vent system collects and transfers FW heater and moisture separator-reheater drainage to
 
the suction of the main boiler FW pumps. LRA Table 2.3.3-19-27-IP3 identifies heater
 
drain/moisture separator drains/vents system component types within the scope of license
 
renewal and subject to an AMR, as well as their intended functions. Instrument Air Closed Cooling System
.The instrument air closed-cooling system is a separate closed-loop cooling water system. This system supplies cooling water to the instrument air
 
compressors and aftercoolers and rejects heat to the SW system. LRA Table 2.3.3-19-30-IP3
 
identifies instrument air closed-cooling system component types within the scope of license
 
renewal and subject to an AMR, as well as their intended functions.
Lube Oil System
.The lube oil system supplies oil for lubrication and control of the main turbine and the main boiler FW pumps and turbines. The lube oil system includes components that
 
make up the main turbine controls. LRA Table 2.3.3-19-31-IP3 identifies lube oil system
 
component types within the scope of license renewal and subject to an AMR, as well as their
 
intended functions. Low-Pressure Steam Dump System
.The low-pressure steam dump system prevents turbine overspeed by discharging steam from the high-pressure turbine exhaust to the condenser upon
 
turbine trip. LRA Table 2.3.3-19-32-IP3 identifies low-pressure steam dump system component
 
types within the scope of license renewal and subject to an AMR, as well as their intended
 
functions.
2-178 Main Turbine Generator System
.The main turbine generator system, which receives steam from the SGs, converts a portion of the steam thermal energy to electricity, and supplies
 
extraction steam for FW heating, consists of the turbine, generator, and instrumentation. This
 
system does not include the control valves, moisture separator/reheaters, condensers, and
 
generator cooling components. LRA Table 2.3.3-19-36-IP3 identifies main turbine generator
 
system component types within the scope of license renewal and subject to an AMR, as well as
 
their intended functions. Nuclear Equipment Drains System
.The nuclear equipment drains system collects leakage and drainage from the primary plant equipment (e.g., charging pumps, containment fan cooler units).
 
LRA Table 2.3.3-19-38-IP3 identifies nuclear equipment drains system component types within
 
the scope of license renewal and subject to an AMR, as well as their intended functions.
Process Radiation Monitoring System
.The process radiation monitoring system monitors fluid streams for increasing radiation levels and generates an alarm or automatic action under
 
abnormal conditions. LRA Table 2.3.3-19-40-IP3 identifies process radiation monitoring system
 
component types within the scope of license renewal and subject to an AMR, as well as their
 
intended functions. Primary Plant Sampling System
.The primary plant sampling system obtains samples for laboratory analysis of reactor coolant and other reactor auxiliary systems during normal
 
operation. The system also includes the post-accident reactor coolant sampling system, which
 
obtains pressurized coolant samples following accidents. LRA Table 2.3.3-19-41-IP3 identifies
 
primary plant sampling system component types within the scope of license renewal and subject
 
to an AMR, as well as their intended functions.
River Water Service System
.The river water service system functionally supports the CW system to supply cooling water from the Hudson River to the main condensers. LRA
 
Table 2.3.3-19-47-IP3 identifies river water system component types within the scope of license
 
renewal and subject to an AMR, as well as their intended functions.
Main Generator Seal Oil System
.The main generator seal oil system supplies oil to the main generator shaft seals to prevent hydrogen leakage from the generator into the turbine building.
 
LRA Table 2.3.3-19-54-IP3 identifies seal oil system component types within the scope of
 
license renewal and subject to an AMR, as well as their intended functions. Secondary Plant Sampling System
.The secondary plant sampling system collects and transports samples to the sample room for laboratory analysis of the condensate, FW, and MS
 
systems during normal operation. LRA Table 2.3.3-19-55-IP3 identifies secondary plant
 
sampling system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
Turbine Hall Closed Cooling System
.The turbine hall closed cooling system supplies cooling water to condensate pumps; heater drain pumps; main boiler feed pumps; and station, instrument, and administration building air compressors. LRA Table 2.3.3-19-58-IP3 identifies
 
turbine hall closed cooling system component types within the scope of license renewal and
 
subject to an AMR, as well as their intended functions. Vapor Containment Hydrogen Analyzer System
.The vapor containment hydrogen analyzer system monitors hydrogen and oxygen concentrations and post-LOCA hydrogen concentration 2-179 in the containment atmosphere. Since a recent license amendment (License Amendment No. 228), hydrogen monitoring is no longer required as a safety function; however, the system
 
remains available. LRA Table 2.3.3-19-59-IP3 identifies vapor containment hydrogen analyzer system component types within the scope of license renewal and subject to an AMR, as well as
 
their intended functions.
Hydrogen System (added by applicant by letter dated March 12, 2008). The hydrogen system provides hydrogen to the main generator for cooling and to the CVCS for the VCT cover gas.
LRA Table 2.3.3-19-65-IP3 identifies hydrogen system component types within the scope of
 
license renewal and subject to an AMR, as well as their intended functions.
2.3B.3.19.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.19 and the following UFSAR sections that were associated with these systems:  ammonia/morpholine addition 3  Section 10.2.6. auxiliary steam and condensate return 4  Section 9.6.4  circulating water 3    Section 10.2.4  extraction steam 3    Section 10.2  floor drains 3      Sections 9.6.2.3 and 16.1.3  gaseous waste disposal 4    Sections 11.1 and 14.2.3  hydrazine addition 3    Section 10.2.6  heater drain/moisture separator drain/vent 3  Section 10.2.6  instrument air closed cooling 4    Section 9.6.3  main turbine generator 3    Section 10.2  nuclear equipment drains 3    Section 6.7.1.2  process radiation monitoring 4    Section 11.2.3.1  primary plant sampling 4    Section 9.4  river water service 3    Section 10.2.4  main generator seal oil 3    Section 10.2.2  secondary plant sampling 3    Section 9.4  vapor containment hydrogen analyzer 4  Section 6.8  boron and layup chemical addition 3    chlorination 3        lube oil 3        low pressure steam dump 3      turbine hall closed cooling 3    For those systems receiving a simplified Tier 1 evaluation, the staff reviewed the applicable LRA and UFSAR sections using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. For those systems receiving a detailed Tier 2 evaluation, the
 
staff reviewed the applicable LRA sections, applicable UFSAR sections, and license renewal
 
drawings (system components are shown on other associated system drawings). Based upon
 
information provided in the UFSAR and the LRA, the staff evaluated the system functions
 
described in LRA Section 2.3.3.19 to verify that the applicant had not omitted from the scope of
 
license renewal any components with intended functions pursuant to 10 CFR 54.4(a). The staff 3The staff conducted a simplified Tier 1 system review for these systems as described in SER Section 2.3 4The staff conducted a detailed Tier 2 system review for these systems as described in SER Section 2.3.
2-180 then reviewed those components that the applicant identified as within the scope of license renewal to verify that the applicant had not omitted any passive and long-lived components
 
subject to an AMR, in accordance with 10 CFR 54.21(a)(1).
The staff reviewed the list of IP3 systems the applicant identified in LRA Section 2.3.3.19 as not having any components in scope for 10 CFR 54.4(a)(2) for spatial interaction because they
 
were already included in scope under 10 CFR 54.4(a)(1), functional (a)(2), or (a)(3). In RAI
 
2.3A.2.2-1, dated February 13, 2008, the staff asked the applicant to explain why it did not highlight on boundary drawings those piping segments directly attached to the IP2 CS system
 
10 CFR 54.4(a)(1) piping to indicate that they were included within the scope of license renewal.
 
SER Section 2.3A.2.2.2 documents the staffs review of the applicants response, dated March
 
12, 2008.
LRA Table 2.2-2-IP3 indicates that the hydrogen gas system is not within the scope of license renewal. This system, along with the nitrogen system, provides the VCT with gas for oxygen scavenging. Since the piping is directly connected to the VCT, the staff questioned whether the
 
applicant should include the system within scope, in accordance with 10 CFR 54.4(a)(2),
because of the potential for physical interaction between the nonsafety- and safety-related
 
equipment. In its response, dated March 12, 2008, the applicant stated that the hydrogen
 
system should be within scope, as required by 10 CFR 54.4(a)(2). The applicant amended the
 
LRA to include the hydrogen system. SER Section 2.2B.3 documents the staffs review of the
 
applicants response, dated March 12, 2008.
During its review, the staff noted that the applicant did not specifically identify components on the license renewal drawings that are within the scope of license renewal under
 
10 CFR 54.4(a)(2). To determine that the applicant did not omit any components from scope
 
under 10 CFR 54.4(a)(2), the staff used a sampling approach recommended in SRP-LR
 
Section 2.3.3.1. In multiple RAIs, dated February 13, 2008, the staff asked the applicant to verify
 
that it had included various segments of selected systems within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2). This sampling approach allowed the staff to confirm that
 
the applicant had properly implemented its methodology for identifying the nonsafety-related
 
portions of systems with a potential to adversely affect safety-related functions, in accordance
 
with 10 CFR 54.4(a)(2).
In its response, dated March 12, 2008, the applicant stated that all components identified by the staff on the license renewal drawings are within the scope of license renewal, in accordance
 
with 10 CFR 54.4(a)(2), and subject to an AMR. Based on a review of its response, the staff
 
finds that the applicant has adequately identified the components required to be within the
 
scope of license renewal, in accordance with 10 CFR 54.4(a)(2), and subject to an AMR.
2.3B.3.19.3  Conclusion
 
For each system described above, the staff reviewed LRA Section 2.3.3.19, the applicable UFSAR section and license renewal drawings to determine whether the applicant failed to
 
identify any SSCs within the scope of license renewal. In addition, the staff sought to determine
 
whether the applicant failed to identify any components subject to an AMR. The staff found
 
instances in which the applicant omitted systems and components that should have been
 
included within the scope of license renewal. The applicant has satisfactorily resolved these
 
issues as discussed in the preceding staff evaluation. On the basis of its review, the staff finds
 
that, for all the systems identified in LRA Section 2.3.3.19 the applicant has appropriately 2-181 identified the components within the scope of license renewal as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3B.4  Scoping and Screening Results: Steam and Power Conversion System Unit 3 LRA Section 2.3.4 identifies the IP3 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, Main Steam 2.3.4.2, Main Feedwater 2.3.4.3, Auxiliary Feedwater 2.3.4.4, Steam Generator Blowdown  2.3.4.5, IP2 AFW Pump Room Fire Event  2.3.4.6, Condensate SER Sections 2.3B.4.1 through 2.3B.4.6, respectively, provide the staffs reviews of IP3 systems described in LRA Sections 2.3.4.1 through 2.3.4.6. The staffs findings for these
 
systems are discussed below. 2.3B.4.1  IP3 Main Steam System 2.3B.4.1.1  Summary of Technical Information in the Application LRA Section 2.3.4.1 describes the MS system, which includes the auxiliary steam and condensate return, condenser air removal, gland seal steam, high-pressure steam dump, reactor protection and control, reheat steam, and turbine generator hydraulic control systems.
The MS system conducts steam from the four SGs inside the containment structure to the turbine generator unit in the turbine generator building. The system has four MS pipes, one from
 
each SG to the turbine stop and control valves, which are interconnected near the turbine. Each
 
steam pipe has an MSIV and a non-return valve outside the containment. Five code safety
 
valves and one PORV are located on each MS line outside the reactor containment and
 
upstream of the isolation and non-return valves. A flow venturi upstream of the isolation valve
 
measures steam flow. Steam pressure is also measured upstream of the isolation valve. The
 
MS system supplies steam to the main boiler FW pump turbines and the AFW pump turbine.
 
The MS system includes the main boiler FW pump turbines and the turbine steam bypass and
 
low-pressure steam dump systems, which channel excess steam flow to the condenser. The
 
SGBD flowpath includes MS system components.
The auxiliary steam and condensate return system supplies auxiliary steam to plant components for IP3 heating and for the recovery of condensate via the condensate return lines.
 
The system supplies steam for heating throughout the plant to room and area heating units, refueling water and primary water storage tanks, boric acid batch mixing tank, and other areas.
 
The system also supplies minor steam loads, such as the condenser waterbox air ejectors.
 
System supply by the house service boiler or steam reboiler includes heaters, air ejectors, steam distribution piping and valves, condensate return piping, valves, pumps, tanks, instruments, and controls.
2-182 The condenser air removal system removes air and non-condensable gases from the condensers to prevent gas buildup that would interfere with steam condensation. Each
 
condenser has a four-element, two-stage air ejector with a separate inter-condenser and
 
common after-condensers. Normal air removal requires one air ejector unit per condenser. For
 
initial condenser shell-side air removal, three non-condensing priming ejectors use steam from
 
the MS system supplied through a pressure-reducing valve. The system monitors the air ejector
 
exhaust for radioactivity. In an SG leak and the subsequent presence of radioactively
 
contaminated steam in the secondary system, this radiation monitor detects the radioactive non-
 
condensable gases that concentrate in the air ejector effluent. A high-activity-level signal
 
automatically diverts the exhaust gases from the vent stack to the containment.
The gland seal steam system supplies steam to the main turbine and boiler FW pump turbine gland seals. The system includes pressure-regulating valves and distribution piping and valves.
The high-pressure steam dump system provides an MS flowpath, bypassing the turbine to the main condenser when the turbine generator cannot accept the steam flow. Two MS bypass
 
lines, one on either side of the turbine, divert excess steam from the four MS lines directly to the condensers, when necessary, before they reach the turbine stop valves. From each of the MS
 
bypass lines, six lines, each with a bypass control valve, discharge into the condenser. The
 
system includes the bypass control valves and its piping, controls, and instruments.
The reactor protection and control system monitors primary and secondary plant parameters and trips the reactor to protect the reactor core and RCS. The reactor protection and control
 
system is primarily electrical, but includes a small number of mechanical instrumentation
 
components that form parts of the SG secondary-side pressure boundary.
The reheat steam system supplies reheated steam to the low-pressure turbines and steam from the MS system to the main boiler FW pump turbines. Steam from the high-pressure turbine
 
exhaust passes through the moisture separator reheaters, which remove moisture and reheat
 
the steam by main steam extracted before it reaches the turbine MS stop valves. Part of the
 
extracted main steam goes to the main boiler FW pump turbines. The system includes the
 
moisture separator reheaters, piping, valves, instruments, and controls.
The turbine generator hydraulic control system directly controls the main turbine. The system has electrical and mechanical components of the turbine hydraulic control system, including the
 
main turbine stop valves, and parts of the MS system pressure boundary for Appendix R safe
 
shutdown.The MS system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure could prevent the
 
satisfactory accomplishment of a safety-related function. In addition, the MS system performs
 
functions that support fire protection and SBO. Main steam components supporting the AFW system are reviewed with the AFW systems (LRA Section 2.3.4.3). Components containing air are reviewed with the compressed air systems (LRA Section 2.3.3.4). Condenser air removal system components in the containment
 
penetration are reviewed with containment penetrations (LRA Section 2.3.2.5). Reactor
 
protection and control components supporting the mechanical intended function are reviewed
 
with the SGs (LRA Section 2.3.1.4).
2-183 The following LRA tables identify IP3 MS system component types that are within the scope of license renewal and subject to an AMR, as well as their intended functions:  LRA Table 2.3.4-1-IP3  LRA Table 2.3.3-19-2-IP3  LRA Table 2.3.3-19-4-IP3  LRA Table 2.3.3-19-24-IP3  LRA Table 2.3.3-19-28-IP3  LRA Table 2.3.3-19-35-IP3  LRA Table 2.3.3-19-45-IP3  LRA Table 2.3.3-19-57-IP3 2.3B.4.1.2  Staff Evaluation The staff reviewed LRA Section 2.3.4.1; UFSAR Sections 7.2, 9.6.4, 10.2, 10.2.1, 10.2.2, and 10.2.5; and license renewal drawings 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 had 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 identified as within the scope of license renewal to verify that it had not omitted
 
any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.4.1, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The applicant responded to the staffs RAI as discussed below.
In RAI 2.3B.4.1-1, dated December 7, 2007, the staff noted that license renewal drawings for the IP3 MS system show the following valves within the scope of license renewal and subject to
 
an AMR: PCV-1134, PCV-1135, PCV-1136, PCV-1137, MS-1-31, MS-1-32, MS-1-33, MS-1-34, PCV-1120, PCV-1121, PCV-1122, PCV-1123, PCV-1124, PCV-1125, PCV-1126, PCV-1127, PCV-1128, PCV-1129, PCV-1130, PCV-1131. The staff also noted that these valves are air
 
operated and have associated air cylinders and air tubing that were excluded from the scope of
 
license renewal. Since some of these valves appear to rely on pressurized air (pneumatic
 
operation) to change position and fulfill their intended function, the staff asked the applicant to
 
explain why it did not include the instrument air system, its tubing, and associated SOVs to the
 
valves in question within the scope of license renewal, in accordance with 10 CFR 54.4(a).
In its response dated January 4, 2008, the applicant stated that the air operators are active components; therefore, they are not subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1)(i) and NEI 95-10, Appendix B. The applicant further explained that the
 
SOVs and air tubing associated with the air-operated valves in the MS system are within the
 
scope of license renewal, but are not subject to an AMR because the majority of the air-
 
operated valves shown on the MS license renewal drawings as within the scope of license
 
renewal fail to their required position for accident mitigation. As such, these valves do not
 
require pressurized air to fulfill their intended function, and pressure boundary of the air tubing is
 
not necessary. The applicant stated that the atmospheric dump valves and MSIVs are an 2-184 exception. These valves close upon loss of air, but are credited with being re-opened, as necessary, in an accident scenario, using standby nitrogen in bottles or compressed air stored
 
in accumulators. The applicant explained that components used to re-open the MS system
 
valves are subject to an AMR.
Based on its review, the staff finds the response to RAI 2.3B.4.1-1 acceptable because the applicant adequately explained that, for most of the air-operated valves, a failure of the air
 
supply system will not result in a loss of the intended function because the MS valves fail to
 
their safe positions. This explanation is consistent with NEI 95-10, Revision 6, Section 5.2.3.1, which governs fail-safe components. For those air-operated valves that rely on an air supply
 
system (i.e., those MS system valves that do not fail to their safe position), the passive
 
pneumatic components (accumulator tanks, tubing, and valves) of those air-operated valves are
 
included within the scope of license renewal and are subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1). The staffs concern described in RAI 2.3B.4.1-1 is resolved.
2.3B.4.1.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its
 
review, the staff concludes that the applicant has appropriately identified the MS system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.3B.4.2  IP3 Main Feedwater System 2.3B.4.2.1  Summary of Technical Information in the Application LRA Section 2.3.4.2 describes the FW system, which transfers condensate and heater drain flow through the final stage of FW heating to the SGs. Two half-size, steam-driven main FW
 
pumps increase the pressure of the condensate for delivery through the final stage of FW
 
heating and the FW regulating valves to the SGs.
The main FW system includes the high-pressure FW heaters and piping and valves from the main feed pumps through the heaters to the SGs. The FW system also includes the main feed
 
pump turbine drip tank drain pumps. The main FW pumps and services system supports the
 
main FW system by increasing the pressure of the condensate for delivery through the final
 
stage of FW heating and the FW regulating valves to the SGs.
The main FW system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure potentially
 
could prevent the satisfactory accomplishment of a safety-related function. In addition, the main
 
FW system performs functions that support fire protection.
Feedwater system components supporting the AFW system are reviewed with such systems (LRA Section 2.3.4.3).
LRA Tables 2.3.4-2-IP3, 2.3.3-19-22-IP3, and 2.3.3-19-23-IP3 identify main FW system component types within the scope of license renewal and subject to an AMR, as well as their 2-185 intended functions.
2.3B.4.2.2  Staff Evaluation The staff reviewed LRA Section 2.3.4.2, UFSAR Section 10.2.6, and a license renewal drawing 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that the applicant
 
had not omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review of LRA Section 2.3.4.2, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening
 
results. The applicant responded to the staffs RAI as discussed below.
In RAI 2.3B.4.2-1, dated December 7, 2007, the staff noted that license renewal drawings identify valves FCV-417-L, FCV-417, FCV-427-L, FCV-427, FCV-437-L, FCV-437, FCV-447-L, FCV-447, BF2-31, and BF2-32 for the IP3 main FW system as within the system evaluation
 
boundary. The staff noted that, although the aforementioned valves are passive and long lived, they are not highlighted, indicating that they are not subject to an AMR. The staff asked the
 
applicant to explain the valves exclusion from an AMR.
In its response, dated January 4, 2008, the applicant explained that, although these FW system valves are located upstream of the containment isolation check valves in nonsafety-related
 
piping, they are classified as safety related because of their active function to provide FW
 
isolation. The applicant also stated that these valves have no passive intended function for
 
54.4 (a)(1) or (a)(3) because their failure would accomplish the safety function of isolating
 
feedwater flow to the SGs. The applicant further stated that these valves perform their function
 
with moving parts; therefore, in accordance with 10 CFR 54.21(a)(1)(i), they are not subject to
 
an AMR and are not highlighted on the license renewal drawing. However, the applicant did
 
indicate that the valves in question are within the scope of license renewal under
 
10 CFR 54.4(a)(2) because of their potential for spatial interaction with safety-related
 
equipment; therefore, they are subject to an AMR.
The staff disagreed with the applicants rationale that the valves do not have a passive intended function in accordance with 10 CFR 54.4(a)(1). The staff discussed the applicants view during a
 
telephone call on March 7, 2008. The applicant subsequently amended its RAI response by
 
letter dated March 24, 2008, and reiterated that the FW system valves are safety related. The
 
applicant also stated that, although not highlighted, these valves and the remainder of the FW
 
system components on the associated license renewal drawing are in scope and subject to an
 
AMR under 10 CFR 54.4(a)(2) because of their potential for spatial interaction with
 
safety-related equipment.
Based on its review, the staff finds the applicants amended response to RAI 2.3B.4.2-1 acceptable because the applicant confirmed that the valves in question are within the scope of
 
license renewal pursuant to 10 CFR 54.4(a), and subject to an AMR pursuant to 10 CFR 2-186 54.21(a)(1). Although the staff does not agree with the applicants basis for determining how the valve bodies are subject to an AMR, the staffs concern is resolved because the AMR was
 
performed, and the AMR results were provided in LRA Table 3.3.2-19-34-IP3. The staffs
 
concern described in RAI 2.3B.4.2-1 is resolved.
In RAI 2.3B.4.2-2, dated December 30, 2007, the staff noted that UFSAR Section 14.2.5, Rupture of a Steam Pipe, states in the event of a main steam line break incident, the motor-
 
operated valves (MOVs) associated with each of the feedwater regulating valves (FRVs) will
 
close. UFSAR Section 14.2.5.1 states that redundant isolation of the main feedwater lines is
 
necessary, because sustained high feedwater flow would cause additional cooldown; therefore, in addition to the normal control action which will close the main feedwater valves, any safety
 
injection signal will rapidly close all feedwater control valves (including the motor-operated block
 
valves and low-flow bypass valves), trip the main feedwater pumps, and close the feedwater pump discharge valves. In addition, license renewal drawing 9321-20193 shows a HIGH
 
STEAM FLOW SI LOGIC signal going to these motor-operated isolation valves. The motor-
 
operated block valves shown on license renewal drawings are BFD-5s and BFD-90s for the
 
main FRVs, and the low flow bypass regulating valves, respectively.
The feedwater isolation valves, BFD-5s and BFD-90s, are not included within the "system intended function boundary," nor are they highlighted on the license renewal drawings as having
 
an intended function in accordance with 10 CFR 54.4(a)(1). By letter dated December 30, 2008, the staff requested the applicant to justify the exclusion of the BFD-5 and BFD-90 isolation
 
valves from scope of license renewal in accordance with 10 CFR 54.4(a)(1). This issue was also
 
identified as Open Item 2.3.4.2-1.
By letter dated January 27, 2009, the applicant stated that based upon a review of the qualifications of the isolation valves, the BFD-5 and BFD-90 valves are classified as nonsafety-
 
related in the site component database and are located outside the Class I boundary [as
 
corrected by letter dated March 13, 2009] on license renewal drawing LRA-9321-2019-0. As
 
indicated in the IP3 UFSAR, these valves provide a backup isolation function for feedwater in
 
the event of such accidents as a feedwater or steamline break. Credit for nonsafety-related
 
components as a backup to safety-related components in mitigating breaks in seismically-
 
qualified steam line piping is consistent with regulatory guidance provided in Standard Review
 
Plan (NUREG-0800), Section 15.1.5, Steam System Piping Failures Inside and Outside of
 
Containment (PWR), and is also consistent with the allowance for feedwater regulating and
 
bypass valves to be nonsafety-related, as discussed in NUREG-0138, Staff Discussion of
 
Fifteen Technical Issues Listed in Attachment to November 3, 1976 Memorandum from Director, NRR to NRR Staff. The applicant concluded that, consistent with the CLB, regulatory guidance, and NUREG-0138, the BFD-5 and BRD-90 valves are classified as nonsafety-related, and as
 
such, meet the criteria to be included in scope for license renewal under 10 CFR 54.4(a)(2).
Based on the information provided by the applicant, the staff finds applicants response to RAI 2.3B.4.2-2 acceptable because the BFD-5 and BFD-90 isolation valves are nonsafety-
 
related components, and the valves are included in the scope for license renewal under
 
10 CFR 54.4(a)(2). Therefore, the staffs concern described in RAI 2.3B.4.2-2 is resolved. As a
 
result, Open Item 2.3.4.2-1 is closed.
2-187 2.3B.4.2.3  Conclusion The staff reviewed the LRA, UFSAR, RAI response, and a drawing to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. The staff concludes
 
that the applicant has appropriately identified the main FW system components within the scope
 
of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3B.4.3  IP3 Auxiliary Feedwater System 2.3B.4.3.1  Summary of Technical Information in the Application LRA Section 2.3.4.3 describes the AFW system, which supplies a flow of water from the CST to the SGs when the main FW pumps are unavailable. One steam turbine-driven and two electric
 
motor-driven AFW pumps supply adequate feedwater to the SGs to remove reactor decay heat
 
under all circumstances, including loss of power and normal heat sink (e.g., condenser isolation
 
or loss of CW flow). The system can supply all four SGs. The steam-turbine-driven pump can be
 
supplied from two of the SGs. The AFW system operates during plant startup at low power
 
levels before the main FW pump is available. The system includes the AFW pumps, the turbine
 
for the turbine-driven pump, piping from both CST and city water supply (an alternate source)
 
through the pumps to the FW line supplying the SGs, valves, instruments, and controls.
 
However, the system does not include the CST, which is part of the condensate transfer
 
system. The AFW system contains safety-related components relied on to remain functional during and following DBEs. In addition, the AFW system performs functions that support fire protection, ATWS, and SBO. Instrument air components included in the AFW system are reviewed with the
 
compressed air systems (LRA Section 2.3.3.4).
LRA Table 2.3.4-3-IP3 identifies AFW system component types within the scope of license renewal and subject to an AMR, as well as their intended functions.
2.3B.4.3.2  Staff Evaluation The staff reviewed LRA Section 2.3.4.3, UFSAR Sections 7.2.2 and 10.2.6, and license renewal drawings 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
During its review, the staff identified an area in which additional information was necessary to complete the review of the applicants scoping and screening results. The applicant responded
 
to the staffs RAI as discussed below.
2-188 In RAI 2.3A.4.2-2, dated February 13, 2008, the staff noted that LRA Section 2.3.4.3 states that the AFW system has no intended function under 10 CFR 54.4(a)(2). However, the staff
 
identified an instance in which components adjacent to safety-related components were not
 
highlighted on license renewal drawings, but should have been considered for inclusion within
 
the scope of license renewal because of their potential adverse spatial interaction, in
 
accordance with 10 CFR 54.4(a)(2). For IP3, a license renewal drawing showed a section of
 
piping extending from the AFW system piping (which includes valve SS-189) that was not
 
highlighted. The staff asked the applicant to confirm that it evaluated the aforementioned
 
components for inclusion within the scope of license renewal, in accordance with
 
10 CFR 54.4(a)(2).
In its response, dated March 12, 2008, the applicant stated that the section of piping extending from the AFW system piping, which includes valve SS-189 is included within the scope of
 
license renewal, in accordance with 10 CFR 54.4(a)(2), and is subject to an AMR.
Based on its review, the staff finds the applicants response to RAI 2.3A.4.2-2 acceptable because it adequately explained that the components in question are within the scope of license
 
renewal, in accordance with 10 CFR 54.4(a)(2), and subject to an AMR because of their
 
potential to adversely interact spatially with safety-related equipment. The staffs concern
 
described in RAI 2.3A.4.2-2 is resolved.
2.3B.4.3.3  Conclusion
 
The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no
 
such omissions. In addition, the staff sought to determine whether the applicant failed to identify
 
any components subject to an AMR. The staff found no such omissions. On the basis of its
 
review, the staff concludes that the applicant has appropriately identified the AFW system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.3B.4.4  IP3 Steam Generator Blowdown System 2.3B.4.4.1  Summary of Technical Information in the Application LRA Section 2.3.4.4 describes the SGBD system, which includes the SGBD recovery and the SG sampling systems.
The SGBD system can control the concentration of solids in the shell side of the SGs. The system, which operates normally with a continuous blowdown and sample flow, has a drain
 
connection and two blowdown connections (nozzles) at the bottom of each SG. Pipes from the
 
connections (nozzles) join to form a stainless steel blowdown header. Four individual blowdown
 
headers are routed from each SG to the PAB through containment isolation valves.
Downstream of the containment isolation valves, blowdown flow can be diverted to either the SGBD recovery system (during normal operation) or the blowdown flash tank. The SGBD
 
recovery system consists of two heat exchangers, a filter and demineralizer package, piping, valves, and instrumentation.
2-189 The SG sampling system obtains representative secondary-side water samples for laboratory analysis of chemical and radiochemical conditions. The system has sample capability for each
 
SG from its blowdown line inside containment. Each line to the sample room, where the liquid is
 
cooled and the pressure reduced, has a containment penetration. Each sample is split into two
 
routesone to the sample sink for periodic chemical analysis and one to a conductivity cell, a
 
radiation monitor, and then to the blowdown flash tank. The second line handles a continuous
 
flow for constant conductivity reading and radiation monitoring.
The SGBD system contains safety-related components relied on to remain functional during and following DBEs. It also contains nonsafety-related components whose failure potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the SGBD
 
system performs functions that support fire protection, ATWS, and SBO.
A small number of SGBD components are reviewed with the SW system (LRA Section 2.3.3.2).
The SG sample heat exchangers (SG sampling system) are safety-related only for their cooling water pressure boundary function (heat transfer is not a required function). These heat
 
exchangers are reviewed with the CCW system (LRA Section 2.3.3.3).
LRA Tables 2.3.4-4-IP3, 2.3.3-19-50-IP3, 2.3.3-19-51-IP3, and 2.3.3-19-52-IP3 identify SGBD system component types within the scope of license renewal and subject to an AMR, as well as
 
their intended functions.
2.3B.4.4.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.4 and UFSAR Sections 9.4.1 and 10.2.1 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.
During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3B.4.4.3  Conclusion
 
The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In addition, the
 
staff sought to determine whether the applicant failed to identify any components subject to an
 
AMR. The staff found no such omissions. On the basis of its review, the staff concludes that the
 
applicant has adequately identified the SGBD system components within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3B.4.5  IP2 Auxiliary Feedwater Pump Room Fire Event (Not Applicable to IP3)
In the LRA, the applicant evaluates systems that in combination provide and support feedwater flow to the steam generators during a shutdown, and states that the evaluation applies to IP2
 
only. During its review, the staff considered whether a similar evaluation was needed for IP3.
2-190 Similar to IP2, the IP3 AFW pump room contains redundant trains of safe shutdown systems and equipment separated by 20 feet with intervening combustibles. The NRC granted an
 
exemption from the technical requirements of Section III.G.2 of 10 CFR Part 50, Appendix R on
 
January 7, 1987. However, the AFW pump room fire event is not an issue at IP3 because the
 
AFW pump room has area-wide coverage via automatic fire detection and a sprinkler system.
 
This area is also equipped with manual hose stations and portable fire extinguishers. The NRC
 
SER dated January 7, 1987, documents the staffs determination that fire protection features in
 
the IP3 AFW Pump Room are adequate.
The staff finds that the applicant has demonstrated that the IP3 AFW pump room contains sufficient automatic fire suppression, the fire hazard within this area is low, and alternate
 
shutdown capability exists. Therefore, an alternate feedwater flowpath is not required in the
 
event of a fire in the IP3 AFW pump room.
2.3B.4.6  IP3 Condensate System 2.3B.4.6.1  Summary of Technical Information in the Application LRA Section 2.3.4.6 describes the condensate system, which consists of components in the following systems: condensate, condensate polisher, condensate pump discharge, condensate
 
pump suction, and condensate transfer.
The condensate system transfers condensate and low-pressure heater drainage from the condenser hotwell through the condensate polisher and five stages of FW heating to the main
 
FW pump suctions. The condensate system is also the primary source of water to the AFW
 
pumps. As part of the main condensate flowpath, three condensate pumps, arranged in parallel, take suction from the bottom of the condenser hotwells and discharge into a common header to the condensate polisher system. From the polisher system, a portion of the condensate passes
 
through three steam jet air ejector condensers, arranged in parallel, and one gland steam
 
condenser. The condensate passes through the tube sides of three parallel strings of two
 
low-pressure FW heaters. The flows from these heaters combine in a common line, which then
 
divides to flow into the remaining three strings of three low-pressure heaters. After the No. 5 FW
 
heater, the three condensate lines join into a common header. The heater drain pump discharge
 
enters this header and continues on to the suction of the main FW pumps.
The condensate system contains mostly valves, including a large number of small valves supplying condensate as gland seal water to various secondary plant valves. Within the
 
condensate system, one valve has a safety function as part of the pressure boundary for the
 
flowpath from the CST to the AFW pumps.
The condensate polishing system removes dissolved and suspended solids from the condensate to maintain FW quality required for the SGs. The polishers are within the existing
 
condensate system between the condensate pumps and the first stage of FW heaters. The
 
condensate polishing system consists of six service vessels, six condensate post-filters, three
 
condensate booster pumps, piping, valves, instrumentation, and controls.
The condensate pump discharge system supports sampling of the condensate pump discharge.
Components in this system code include the small sampling piping and valves at the discharge
 
of the condensate pumps.
2-191 The condensate pump suction system supplies water to the condensate pumps from the main condenser. Components in this system code include the expansion joints, piping, and valves
 
between the condenser and the condensate pumps.
The condensate transfer system transfers condensate from the condenser to the suction of the main boiler FW pumps and from the CST to the AFW pumps. This system includes condensate
 
system components from the condensate pumps to the suction of the main boiler FW pumps (except the condensate polishers and their support equipment), the CST and piping and
 
components to the AFW pump suction header, the main condensers, the condensate and
 
low-pressure FW heaters, piping, valves, instruments, controls, and other condensate system
 
components.
The condensate system contains safety-related components relied on to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the condensate system
 
potentially could prevent the satisfactory accomplishment of a safety-related function. In
 
addition, the condensate system performs functions that support fire protection and SBO.
Components that support the pressure boundary of the AFW system flowpath are evaluated with the AFW systems (LRA Section 2.3.4.3).
LRA Tables 2.3.3-19-6-IP3, 2.3.3-19-7-IP3, 2.3.3-19-8-IP3, 2.3.3-19-9-IP3, and 2.3.3-19-14-IP3 identify condensate system component types within the scope of license renewal and subject to
 
an AMR, as well as their intended functions.
2.3B.4.6.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.6, UFSAR Section 10.2.6, and license renewal drawings (condensate system components are shown on drawings of other system) 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 had not omitted from the scope of license renewal any components with
 
intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR, in accordance with
 
10 CFR 54.21(a)(1).
2.3B.4.6.3  Conclusion
 
The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff found no such omissions. In addition, the
 
staff sought to determine whether the applicant failed to identify any components subject to an
 
AMR. The staff found no such omissions. On the basis of its review, the staff concludes that the
 
applicant has adequately identified the condensate system components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2-192 2.4  Scoping and Screening Results: Structures This section documents the staffs review of the applicants scoping and screening results for structures. Specifically, this section discusses the following:  containment buildings  water control structures  turbine buildings, auxiliary buildings, and other structures  bulk commodities In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the
 
applicant properly implemented its methodology, the staffs review focused on the
 
implementation results. This focus allowed the staff to confirm that there were no omissions of
 
SCs that meet the scoping criteria and are subject to an AMR.
The staffs evaluation of the information in the LRA for all structures sought to determine whether the applicant had identified, in accordance with 10 CFR 54.4, the components and
 
supporting structures, for structures that appear to meet the license renewal scoping criteria.
 
Similarly, the staff evaluated the applicants screening results to verify that all passive, long-lived 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, focusing on components that had not been identified as within the scope of license renewal. The staff
 
reviewed relevant licensing basis documents, including the UFSAR, for each structure to
 
determine whether the applicant had omitted from the scope of license renewal SCs with license
 
renewal intended functions in accordance with 10 CFR 54.4(a). The staff also reviewed the
 
licensing basis documents to determine whether the LRA specified all license renewal 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 applicants screening results. For those SCs with intended functions, the staff sought to determine whether (1) the functions are
 
performed with moving parts or a change in configuration or properties or (2) the SCs are
 
subject to replacement after a qualified life or specified time period, in accordance with
 
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.
During its review of LRA Section 2.4, the staff identified areas in which additional information was necessary to complete the evaluation of the applicants scoping and screening results for
 
structures. Therefore, the staff issued issue-specific RAIs by letter dated January 28, 2008, to
 
determine or confirm whether the applicant properly applied the scoping criteria of
 
10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a) to structures and structural
 
components. The applicant provided its responses to the staffs RAIs by letter dated
 
February 27, 2008, and supplemented it by Amendment 3 to the LRA, dated March 24, 2008.
 
The applicant further provided responses to the staffs followup RAIs by letter dated
 
June 11, 2008, and submitted Amendment 5 to the LRA, dated June 11, 2008.
2-193 The following discussion describes the staffs RAI related to the scoping of structures in LRA Section 2.4, and the applicants responses. Relative to the applicants scoping and screening
 
results for structures documented in LRA Section 2.4, the staff also reviewed LRA Table 2.2-3, which lists the plant-level structures that are within the scope of license renewal, and LRA
 
Table 2.2-4, which lists the plant-level structures that are not within the scope of license
 
renewal. The staff performed these reviews to determine if there were any omissions in the
 
structures scoped at the plant-level and to verify that all the scoped structures were addressed
 
in LRA Section 2.4.
Based on its review of the UFSAR, the staff identified certain structural components that do not appear to be included in LRA Tables 2.2-3 and 2.2-4 or in LRA Section 2.4. In the first part of
 
RAI 2.4-1, the staff requested that the applicant explain whether or not the structures listed
 
below are within the scope of license renewal and subject to an AMR:(i) pipe penetration tunnel (
 
==Reference:==
IP2 final safety analysis report (FSAR), Section 1.11.4.10) (ii) liquid waste storage building (
 
==Reference:==
IP3 FSAR, Sections 16.1.2 and 9.6.4)
(iii) condenser tube withdrawal/removal pit (
 
==Reference:==
IP3 FSAR, Chapter 1; Site Plan Drawing 64513; and IP2 FSAR, Figure 10.2-3) (iv) fuel oil storage tank and its foundation at Buchanan Substation (this tank provides backup fuel oil for emergency diesels and gas turbines)
In its response to RAI 2.4-1, Item (i), dated February 27, 2008, the applicant stated that the pipe penetration tunnel is located in the IP2 fan house and is included within the scope of license
 
renewal as part of the fan house structure, identified in LRA Table 2.2-3 as fan house (IP2).
 
The staff verified that LRA Table 2.2-3, as well as LRA Section 2.4.3, identified the fan house (IP2) as a structure. Therefore, the staff finds the applicants response acceptable. The staffs
 
concern described in RAI 2.4-1, Item (i), is resolved.
In its response to RAI 2.4-1, Item (ii), dated February 27, 2008, the applicant stated that the liquid waste storage building is located within the administration building. The applicant stated
 
that the liquid waste storage building is not within the scope of license renewal because it does
 
not perform a license renewal intended function, as required by 10 CFR 54.4(a). Therefore, LRA
 
Table 2.2-4 lists the liquid waste storage building as part of the line item administration building (IP3) (service admin complex). The staff verified that LRA Table 2.2-4 lists administration
 
building (IP3) (service admin complex) as a structure that is not within the scope of license
 
renewal. The staff further confirmed from UFSAR Section 16.1.2 for IP3 that the liquid waste
 
storage building is a seismic Class III component of the waste disposal system. Its failure will
 
not result in offsite doses in excess of the limits required by 10 CFR Part 20, Standards for
 
Protection against Radiation. Based on the above, the staff finds that the liquid waste storage
 
building does not perform a license renewal intended function, as detailed in 10 CFR 54.4(a).
 
Therefore, the staff finds the applicants response acceptable. The staffs concern described in
 
RAI 2.4-1, Item (ii), is resolved.
In its response to RAI 2.4-1, Item (iii), dated February 27, 2008, the applicant stated that the condenser tube withdrawal/removal pits are located in the lower level of the turbine buildings.
 
The applicant included these components in the scope of license renewal as part of the
 
structures identified in LRA Table 2.2-3 as turbine building and heater bay (IP2) and turbine
 
building and heater bay (IP3). The staff verified that LRA Table 2.2-3, as well as LRA 2-194 Section 2.4.3, identifies the turbine building and heater bay (IP2) and turbine building and heater bay (IP3) as structures. Therefore, the staff finds the applicants response acceptable.
 
The staffs concern described in RAI 2.4-1, Item (iii), is resolved.
In its response to RAI 2.4-1, Item (iv), dated February 27, 2008, the applicant stated that the fuel oil storage tank foundation at Buchanan Substation is within the scope of license renewal
 
and included within the line item gas turbine generator No. 2 and 3, enclosure and fuel tanks
 
foundation in LRA Table 2.2-3. The staff verified that LRA Table 2.2-3, as well as LRA
 
Section 2.4.3, identifies the line item gas turbine generator No. 2 and 3, enclosure and fuel
 
tanks foundation. Further, the staff verified that the fuel oil storage tanks are scoped and
 
screened as a mechanical fuel oil system component in LRA Section 2.3.3.13 and not in LRA
 
Section 2.4.3. The staff finds that the applicants response addressed the staffs question and, therefore, is acceptable. The staffs concern described in RAI 2.4-1, Item (iv), is resolved.
In its response, dated February 27, 2008, the applicant concluded that, as a result of this RAI, the applicant did not have to revise LRA Tables 2.2-3 or 2.2-4. The staff finds that the applicant
 
appropriately confirmed and justified the license renewal scoping of the specific structures and
 
structural components that were in question in the first part of RAI 2.4-1; therefore, the
 
applicants response to the first part of RAI 2.4-1 is acceptable. The staffs concerns described
 
in the first part of RAI 2.4-1 are resolved. SER Section 2.4.3.2 discusses the second part of
 
RAI 2.4-1.
Based on the information provided in the LRA, the RAI response discussed above, and the UFSAR, the staff concludes that, in LRA Section 2.4, the applicant identified, without omissions, the structures that are within the scope of license renewal for IP2 and IP3, in accordance with
 
10 CFR 54.4(a).
 
====2.4.1 Containment====
Buildings (IP2 and IP3)
 
2.4.1.1  Summary of Technical Information in the Application LRA Section 2.4.1 describes the containment buildings, which completely enclose the entire reactor and the RCS and ensures that essentially no leakage of radioactive materials to the
 
environment would result even if a design basis LOCA occurs. The reactor containment
 
structure is a seismic Class I, reinforced concrete vertical right cylinder with a flat base and
 
hemispherical dome. A welded steel liner attached to the inside face of the concrete shell
 
ensures a high degree of leak-tightness. The liner has accommodations for penetrations and
 
personnel access. For IP2, the steel liner plate is covered by polyvinyl chloride insulation in a
 
stainless steel jacket. For IP3, the steel liner plate is covered by urethane foam insulating
 
material covered with gypsum board and a stainless steel jacket and backed with a
 
fire-retardant paper on the unexposed side. The containment liner is anchored to the concrete
 
shell by stud anchors. The bottom liner plate on top of the reinforced concrete base mat is
 
covered with additional concrete, the top of which forms the floor of the containment. Internal
 
structures consist of equipment supports, shielding, reactor cavity and canal for fuel transfer, manipulator crane, containment crane, and miscellaneous concrete and steel for floors and
 
stairs. All internal structures are supported on the mat except equipment supports which are
 
secured to the intermediate floors.
The containment buildings contain safety-related components relied on to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the containment buildings 2-195 potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the containment buildings perform functions that support fire protection.
LRA Table 2.4-1 identifies containment buildings component types, grouped by material (steel/other metals, concrete, other materials) within the scope of license renewal and subject to
 
an AMR, as well as their intended functions.
2.4.1.2  Staff Evaluation The staff reviewed LRA Section 2.4.1; IP2 UFSAR Sections 1.2.2, 1.11.2, and 5.1.2; and IP3 UFSAR Sections 1.3.5, 5.1.2, and 16.1.2 using the evaluation methodology described in SER
 
Section 2.4 and the guidance in SRP-LR Section 2.4, Scoping and Screening Results:
 
Structures.
During its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
SCs with intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those SCs
 
that the applicant identified as within the scope of license renewal to verify that it had 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 Section 2.4.1, the staff identified areas in which additional information was necessary to complete the review of the applicants scoping and screening results. The
 
applicant responded to the staffs RAIs as discussed below.
In RAI 2.4.1-1, dated January 28, 2008, the staff noted that UFSAR Section 5.1.2.1 (IP2 and IP3) states that the containment structure serves as both a biological shield and a pressure
 
boundary component. Since the biological shield function was not explicitly listed among the
 
intended functions for containment buildings in LRA Section 2.4.1 and LRA Table 2.4-1, in
 
RAI 2.4.1-1, the staff requested that the applicant clarify and include biological shield function
 
as an intended function for containment buildings in the LRA.
In its response, dated February 27, 2008, the applicant stated that the biological shield function is an intended function for the IP2 and IP3 containment buildings. The applicant further stated
 
that this intended function is implicit in the definition of the shelter or protection function EN in LRA Table 2.0-1, which includes "radiation shielding. The staff verified that the definition of the
 
EN function in LRA Table 2.0-1 does include radiation shielding within parenthesis. The staff finds the response to be acceptable since it refers to an intended function. Therefore, the
 
applicants response to RAI 2.4.1-1 has adequately addressed the issue raised by the staff and
 
is acceptable. The staffs concern described in RAI 2.4.1-1 is resolved.
A lack of clarity in LRA Table 2.4-1 prompted the staff to seek clarification. In RAI 2.4.1-2, the staff requested that the applicant confirm and/or clarify whether the following components
 
associated with the containment buildings are included as components subject to an AMR in
 
LRA Table 2.4-1 or justify their exclusion. For the components that are subject to an AMR, the
 
applicant was requested to provide the appropriate AMR results in LRA Section 3.5. (i) primary shield wall around the reactor (ii) control rod drive missile shield 2-196(iii) retaining wall at the equipment hatch entrance and its missile shield (fixed and removable)(iv) blowout shield plug (v) insulation for the containment building liner (limits temperature rise in liner under accident conditions) (vi) protective coating for liner (vii) water proofing around fuel transfer tube (viii) waterproof membrane for containment wall against backfill (ix) reactor cavity seal ring (see UFSAR Figures 5.1-6 and 5.1-7)
(x) Seismic Class I debris screens at containment purge (Ref. UFSAR Section 5.1.4.2.4)
(xi) stud anchors that anchor the containment liner plate to the concrete shell In its response, dated February 27, 2008, the applicant addressed each of the components identified in the RAI with respect to whether they are subject to an AMR, as indicated below: (i)  The primary shield wall around the reactor is included as part of beams, columns, interior walls, slabs listed in LRA Table 2.4-1. AMR results are
 
provided in Table 3.5.2-1.(ii)  The control rod drive missile shield is included with the line item missile shields listed in Table 2.4-4. AMR results are provided in Table 3.5.2-4. (iii)  The retaining wall at the equipment hatch entrance is included as part of beams, columns, interior walls, slabs listed in LRA Table 2.4-1. AMR
 
results are provided in Table 3.5.2-1. The equipment hatch missile shield (fixed and removable) is included with the line item missile shields listed
 
in Table 2.4-4. AMR results are provided in Table 3.5.2-4. (iv)  Components/commodities identified in scope that provide missile protection are addressed in LRA Section 2.4-4 and Table 2.4-4. The
 
blowout shield plug is included with the line item missile shields listed
 
in LRA Table 2.4-4. AMR results are provided in Table 3.5.2-4. (v)  The insulation for the containment building liner is included in Table 2.4-1 with line item liner insulation jacket. AMR results are provided in Table
 
3.5.2-1.(vi)  Protective coatings are not in the scope of license renewal because they do not perform an intended function. Their failure will not prevent
 
satisfactory accomplishment of a safety function.(vii)  The waterproofing material around the fuel transfer tube is not in scope.
Waterproofing membranes have no license renewal intended function. (viii)  The waterproof membrane for containment wall against backfill is not in scope. Waterproofing membranes have no license renewal intended
 
function.(ix)  The reactor cavity seal ring identified in UFSAR Figures 5.1-6 and 5.1-7 has no license renewal intended function. This component is not 2-197 safety-related and is not required to demonstrate compliance with regulations identified in 10 CFR 54.4(a)(3). Failure of the seal ring will not
 
prevent satisfactory accomplishment of a safety function. The seal is
 
provided to prevent leakage during refueling operations. This component
 
is not listed in LRA Table 2.2-4 since it does not meet the threshold of a
 
major structural component.(x)  The seismic Class I debris screens at containment purge identified in UFSAR Section 5.1.4.2.4 do not perform a license renewal intended
 
function. The primary containment isolation valves in the containment
 
purge and pressure relief exhaust ducts are closed during normal plant
 
operation. Failure of the screens will not prevent the ventilation systems
 
from performing their intended function. These components are not
 
required during design basis accidents or for any regulated event. The
 
structural support of this component is included in scope and is included
 
with line item Structural steel: beams, columns, plates, trusses listed in
 
LRA Table 2.4-1. (xi)  The stud anchors that anchor the containment liner plate to the concrete shell are included in the line item anchorages/embedments listed in LRA
 
Table 2.4-4. AMR results are provided in Table 3.5.2-4.
In its response, dated February 27, 2008, the applicant has confirmed/clarified the screening of each of the components in question and provided justification of the components that are not
 
subjected to an AMR. The staff finds the applicants response to Items (ii), (iv), and (xi)
 
acceptable because the applicant explicitly clarified that the components in question are within
 
the scope of license renewal and are subject to an AMR. The staff finds the applicants response to Items (vii), (viii), and (x) acceptable because the applicant explicitly clarified that the
 
components in question do not have an intended function that meets any of the criteria in 10
 
CFR 54.4(a). Therefore, the staff finds that the applicants response to RAI 2.4.1-2 is
 
acceptable, with the following exceptions with regard to the response to Items (i), (iii), (v), (vi)
 
and (ix) of RAI 2.4.1-2. In a follow-up RAI to RAI 2.4.1-2, dated May 12, 2008, the staff
 
requested the applicant to clarify/address these exceptions. The applicant provided clarification
 
responses to the follow-up RAI items by letter dated June 11, 2008. The follow-up RAI items
 
and their resolution are discussed below. With regard to Item (i), the response stated that Primary Shield Wall is included as part of
 
line item Beams, columns, interior walls, slabs in LRA Table 2.4-1. The staff noted that
 
walls with lesser safety-significance, such as pressurizer shield, ring wall, and cylinder walls, have been listed as separate items in LRA Table 2.4-1. Considering that the primary shield
 
wall is subjected to a more severe environment (high temperature and radiation exposure)
 
and has a much higher safety-significance than the general interior wall, the staff requested, in a follow-up RAI dated May 12, 2008, that the applicant include the primary shield wall as
 
a separate line item in LRA Table 2.4-1, to make its inclusion in the scope of license renewal
 
and its consideration as being subject to AMR, explicitly clear.
In its response, dated June 11, 2008, the applicant added the primary shield wall as a separate concrete component item in LRA Tables 2.4-1 and 3.5.2-1 with the appropriate
 
intended functions. By doing so, the applicant has explicitly included the primary shield wall
 
as a component subject to AMR. Therefore, the staff finds the response acceptable. The
 
staffs evaluation of the AMR results for the primary shield wall is documented in SER 2-198 Section 3.5. With regard to Item (iii), the response stated that the retaining wall is included as part of line item Beams, columns, interior walls, slabs in LRA Table 2.4-1. The staff noted that the
 
retaining wall at the equipment hatch entrance is an exterior wall and is subjected to a
 
different environment than the interior wall. Therefore, in a follow-up RAI dated May 12, 2008, the staff requested the applicant to explicitly include the retaining wall at the
 
equipment hatch entrance in LRA Table 2.4-1 as a separate line item.
In its response, dated June 11, 2008, the applicant added the equipment hatch entry retaining wall (exists for IP2 only) as a separate concrete component item in LRA Tables
 
2.4-1 and 3.5.2-1 with the appropriate intended functions. By doing so the applicant has
 
explicitly included the IP2 retaining wall at the equipment hatch entrance as a component
 
subject to AMR. Therefore, the staff finds the response acceptable. With regard to Item (v), the response stated that liner plate insulation is included with line
 
item Insulation Jacket in LRA Table 2.4-1. The staff noted that materials for the insulation
 
jacket and the insulation itself are not the same. The jacket is stainless steel but the
 
insulation is PVC for IP2 and Urethane foam covered with gypsum board for IP3 (UFSAR
 
Section 5.1). The insulation itself is not included in LRA Table 2.4-1 or LRA Table 2.4-4; nor
 
are these materials identified in LRA Sections 3.5.2.1.1 or 3.5.2.1.4. They also were not
 
addressed in the response to RAI 2.4.4-2. In a follow-up RAI dated May 12, 2008, the staff
 
requested the applicant to appropriately address the scoping, screening, and AMR results
 
for these in-scope insulation materials in the LRA.
In its response, dated June 11, 2008, the applicant stated that the IP2 containment liner plate PVC insulation and IP3 containment liner urethane insulation are encapsulated within
 
stainless steel jacketing (IP2 UFSAR Section 6C.8.4, and IP3 UFSAR Section 5.5) and are
 
not exposed to containment atmosphere. The only visible and exposed parts of the
 
insulation are the stainless steel jacketing. The aging management review results in LRA
 
Table 3.5.2-1 for the liner plate insulation pertain to the stainless steel jacketing. The
 
applicant added that the containment liner plate insulation within the jacketing is in scope
 
and subject to aging management review for providing shelter and protection to the
 
containment liner plate. The PVC and urethane insulation materials have no aging effects in
 
the air-indoor environment and, therefore, no aging management program is necessary.
In the above response, the applicant has clarified that, for both IP2 and IP3, the containment liner plate insulation within the jacketing is within the scope of license renewal and subject to
 
AMR but does not need aging management since there are no aging effects in its protected
 
environment. Based on the above response, it is the staffs understanding that the PVC and
 
urethane insulation are encapsulated within the stainless steel insulation jacketing forming
 
one composite unit, and the AMR results in LRA Table 3.5.2-1 for the line item liner plate
 
insulation jacket includes the encapsulated insulation, which is exposed to an indoor air
 
environment that does not promote aging effects. The staff finds that the applicants
 
response addressed the staffs concern with regard to scoping and screening of the liner
 
insulation and, therefore, is acceptable. With regard to Item (vi), the response stated that protective coatings for the containment
 
liner are not in scope because they do not perform an intended function. Staff noted that, although protective coating on the containment liner does not directly perform a license 2-199renewal function, it prevents degradation of the liner if properly maintained. Section XI.S8 of NUREG-1801, Volume 2, which is the AMP for protective coatings, recommends
 
maintenance of the protective coatings to avoid clogging of the sumps. The GALL Report
 
requires that, if protective coatings are relied upon to manage the effects of aging, the
 
structures monitoring program is to include provisions to address protective coating
 
monitoring and maintenance (Item 25 in Table 5 of NUREG-1801, Volume 1). Therefore, in
 
a follow-up RAI dated May 12, 2008, the staff requested the applicant to provide justification
 
for excluding the protective coating on the containment liner from the scope of
 
license-renewal and from being subject to an AMR.
In its response, dated June 11, 2008, the applicant stated that the liner plates of IP2 and IP3 containment are provided with protective coatings. The applicant stated that, in response to
 
Generic Safety Issue (GSI)-191, Assessment of Debris Accumulation on PWR Sump
 
Performance, the applicants Civil/Structural Engineering group visually inspects coatings in
 
the vapor containment building during refueling outages. Sump clogging for IP2 and IP3 was
 
evaluated, and the evaluation results were provided by Entergy, Inc., in letter dated
 
September 1, 2005, in response to NRC generic letter 2004-02, Potential impact of debris
 
blockage on emergency recirculation during design basis accidents at pressurized water
 
reactors.
The applicant further added that the GALL Report states that, if protective coatings are relied upon to manage the effects of aging, the structures monitoring program should
 
include provisions to address protective coating monitoring and maintenance. The applicant
 
stated that, as indicated in LRA Table 3.5.1, Item 3.5.1-25, IP2 and IP3 containment liner
 
protective coatings are not relied upon to manage the effects of aging. As shown in LRA
 
Table 3.5.2-1, aging effects of liner plate and integral attachments are managed by the
 
Containment Inservice Inspection-IWE and Containment Leak Rate Test programs for
 
license renewal. Accordingly, the protective coating on the containment liner is not within the
 
scope of license renewal and, therefore, is not subject to aging management review.
In the above response, the applicant clarified that inspection commitments of protective coatings and sump clogging evaluations were addressed as part of its response to the
 
NRCs GSI-191 issue. The applicant reiterated that the aging effects of the liner plate are
 
managed by the containment inservice inspection program per IWE and the Appendix J
 
Containment Leakage Rate Testing Program, and that protective coatings are not relied
 
upon to manage the effects of aging of the liner. Therefore, the staff accepts the applicants
 
determination that the protective coating on the containment liner may be considered
 
outside the scope of license renewal and not subject to AMR. The staff finds the response
 
acceptable. With regard to Item (ix), the response stated that the reactor cavity seal ring has no license
 
renewal intended function. The staff notes that the reactor cavity seal ring is a flood barrier (FLB) to preclude borated water leaks through the seal and thereby prevent accumulation of
 
borated water in the gap between the reactor vessel and the primary shield wall, which
 
could induce corrosion of the reactor vessel and its supports as well as cause degradation
 
of the primary shield wall concrete. Considering the above, in a follow-up RAI dated May 12, 2008, the staff requested the applicant to provide justification for excluding the reactor cavity
 
seal from the scope of license-renewal and from being subject to an AMR.
In its response, dated June 11, 2008, the applicant stated that the reactor cavity seal ring is 2-200 a nonsafety-related component and it has no license renewal intended function pursuant to 10 CFR 54.4(a). Therefore, the reactor cavity seal is not within the scope of license renewal
 
nor subject to AMR. The applicant specifically explained that the reactor cavity seal ring is
 
installed prior to filling the refueling cavity to allow for fuel handling operations and that plant
 
procedures ensure proper installation to preclude leakage during refueling operations. The
 
applicant added that, even if the seal were to leak during the time the refueling cavity is
 
filled, sump pumps in the cavity beneath the reactor vessel would prevent water
 
accumulation in the gap between the reactor vessel and the primary shield wall.
The applicant further stated that plant operating experience does not indicate that leakage from the reactor cavity seal ring has caused corrosion of the reactor vessel or its supports;
 
nor has it caused degradation of primary shield wall concrete. Further, aging management
 
programs shown in LRA Tables 3.1.2-1 and 3.5.2-1 will manage the effects of aging from
 
corrosion, if any, of the reactor vessel and its supports and will manage degradation of the
 
interior concrete walls from exposure to borated water leakage during refueling.
Based on the above response, the staff understands that the reactor cavity seal is a nonsafety-related component installed during each refueling outage prior to flooding of the
 
reactor cavity for refueling operations using procedures to ensure a leaktight installation.
 
Also, the applicants operating experience has not indicated any degradation of the reactor
 
vessel, its supports, and the primary shield wall attributable to leakage through the reactor
 
cavity seal. Further, the applicant has procedures/programs in place to manage any effects
 
even if the seal were to leak during refueling operations. Therefore, the staff accepts the
 
applicants determination that the seal does not perform a license renewal intended function
 
pursuant to 10 CFR 54.4(a) and, therefore, the reactor cavity seal is not in scope of license
 
renewal nor subject to AMR. The applicants response resolved the staffs concern.
Based on the discussion above of the applicants clarifying responses, the staff finds the applicants response to RAI 2.4.1-2 acceptable.
In RAI 2.4.1-3, dated January 28, 2008, the staff requested that the applicant confirm whether the component identified as "Structural Steel: beams, columns, plates, trusses" in LRA
 
Table 2.4-1 includes bracings, welds, and bolted connections. The applicant also was requested
 
to confirm whether the pressurized channel shrouds used at liner welded joints (including those
 
at penetrations) are included in a structure/commodity group, or to justify their exclusion from an
 
AMR. In addition, the applicant was requested to confirm whether the components identified as "bellows penetrations" in LRA Table 2.4-1 include the refueling bellows, if refueling bellows are
 
used at IP2 and IP3.
In its response, dated February 27, 2008, the applicant stated that the component identified as Structural Steel: beams, columns, plates, trusses in LRA Table 2.4-1 includes bracing and
 
welds associated with the component. The applicant further clarified that bolted connections for
 
structures/components are addressed in LRA section 2.4.4 and Table 2.4-4. The applicant
 
stated that the pressurized channel shrouds associated with liner welded joints (including those
 
at penetrations) are not addressed as a separate component group. They are considered
 
integral to the components listed as liner plate and integral attachments and Electrical
 
penetration sleeves and Mechanical penetration sleeves in LRA Table 2.4-1. The applicant
 
stated that components identified as bellows penetrations in LRA Table 2.4-1 do not include
 
refueling bellows. The applicant further clarified that bellows penetrations in LRA Table 2.4-1
 
are associated with containment piping penetrations and that refueling bellows are not a feature 2-201 of the IP2 or IP3 design.
The staff finds that the applicants response adequately addressed the staffs questions with regard to the stated components and, the response to RAI 2.4.1-3 is acceptable, subject to
 
resolution of the additional clarifications requested below with regard to bellows. With regard to
 
bellows penetrations, the applicants response stated that the bellows penetrations in LRA
 
Table 2.4-1 are associated with containment piping penetrations and that refueling bellows are
 
not a feature of the IP2 or IP3 design. In the follow-up RAI dated May 12, 2008, the staff
 
requested the applicant to further describe the types of piping penetration bellows in each unit.
 
Also, the staff requested the applicant to clarify if there are transfer canal bellows (with the
 
number in each unit) at Indian Point and if they are in-scope of license renewal or not, with
 
justification.
In its response, dated June 11, 2008, the applicant stated that IP2 and IP3 containment penetrations consist of a sleeve embedded in the concrete and welded to the containment liner.
The applicant explained that differential expansion between a sleeve and one or more hot pipes
 
passing through it is accommodated by using a nickel alloy or stainless steel bellows-type
 
expansion joint between the outer end of the sleeve and the piping outside of the containment
 
wall. The applicant added that details of the containment penetrations and bellows for each unit
 
are shown in UFSAR Figures 5.1-30 (IP2) and 5.1-12 (IP3).
The applicant stated that, for each unit, a fuel transfer tube is provided for fuel movement between the refueling transfer canal in the reactor containment and the spent fuel pit. The fuel
 
transfer tube consists of a 20-in. stainless steel pipe installed inside a 24-in. pipe. The applicant
 
added that two bellows-type expansion joints (one inside containment and one in the spent fuel
 
pit) are provided on the tubes to compensate for any differential movement between the two
 
pipes and other structures. Figure 5.1-31 of IP2 UFSAR and Figure 5.1-14 of IP3 UFSAR show
 
details of the fuel transfer tube and bellows for each unit. These penetration bellows are within
 
the scope of license renewal and subject to an AMR. They are listed as bellows penetration in
 
LRA Tables 2.4-1 and 3.5.2-1.
In its above response, the applicant confirmed that, in addition to the piping penetrations bellows, the two fuel transfer tube bellows for each unit were in scope of license renewal and
 
subject to AMR and were included as part of line item bellows penetration in LRA Table 2.4-1.
 
The staff finds that the response addressed the staffs question with regard to the types of
 
bellows that were scoped and screened for license renewal. Therefore, the response is
 
acceptable.
During its review of components listed as Polar Crane, rails and girders and Manipulator Crane, crane rails and girders in LRA Table 2.4-1, the staff determined that additional
 
information was needed to complete its review. In RAI 2.4.1-4, dated January 28, 2008, the staff
 
requested that the applicant confirm whether the column structure; bridge and trolley of the
 
polar crane; and the bridge, trolley and mast of the manipulator crane were screened-in as
 
subject to an AMR. The staff also requested that the applicant confirm whether fasteners and
 
rail hardware associated with the polar crane and manipulator crane are within scope of license
 
renewal and subject to an AMR; and if they were excluded, the staff requested that the applicant
 
provide a justification. The staff also requested that the applicant indicate whether there were
 
any other hoists and lifting devices (e.g. for the reactor vessel head and reactor internals) that
 
should be included as components within the scope of license renewal and subject to an AMR;
 
and if so, the staff requested that the applicant provide scoping, screening, and AMR results 2-202 relevant to the LRA.
In its response, dated February 27, 2008, the applicant stated that the column structure; bridge and trolley of the polar crane; and the bridge, trolley and mast of the manipulator crane are
 
screened-in as subject to an AMR. The applicant indicated that these components are subparts
 
of crane, rails and girders. The applicant stated that fasteners (structural bolting) and rail
 
hardware (component support) associated with the polar crane and manipulator crane are
 
within the scope of license renewal and subject to an AMR. The applicant indicated that these
 
components are addressed in LRA Section 2.4.4, Bulk Commodities. The applicant clarified
 
that there were no hoists or lifting devices, other than those already identified in the LRA, that
 
perform a license renewal intended function.
Because the applicant stated that the structures and components in question are subject to an AMR, the staff finds that the applicant adequately addressed the staffs questions; therefore, the
 
response to RAI 2.4.1-4 is acceptable. The staffs concern described in RAI 2.4.1-4 is resolved.
Because of a lack of clarity in LRA Table 2.4-1 regarding components listed as Equipment Hatch and Personnel Lock, in RAI 2.4.1-5, dated January 28, 2008, the staff requested that the
 
applicant clarify whether the flange double-gaskets, hatch locks, hinges, and closure
 
mechanisms that help prevent loss of sealing/leak-tightness for these listed hatches were
 
included within the scope of license renewal and subject to an AMR. The staff also requested
 
that the applicant provide scoping, screening, and AMR results as appropriate or justify their
 
exclusion.
In its response, dated February 27, 2008, the applicant stated that the flange double-gaskets, hatch locks, hinges, and closure mechanisms for the equipment hatch and personnel lock are
 
within the scope of license renewal. The applicant clarified that the double gasket seals are
 
included under the line item equipment hatch and personnel lock seal in LRA Table 2.4-1, and
 
are subject to AMR. The AMR results are provided in Table 3.5.2-1. The applicant stated that
 
hatch locks, hinges, and closure mechanisms are active components and are, therefore, not
 
subject to aging management review as discussed in LRA Table 3.5.1, Line Item 3.5.1-17. The
 
applicant added that satisfactory performance of these active components is demonstrated
 
through routine testing under the Containment Leak Rate Program as required by Section 3.6.2
 
of the IP2 and IP3 Technical Specifications.
The staff finds that the applicant has adequately addressed the staffs concern with regard to the flange double-gaskets for the hatches in question. However, the response stated that the
 
hatch locks, hinges, and closure mechanisms are active components and, therefore, not subject
 
to AMR as discussed in LRA Table 3.5.1, Line Item 3.5.1-17. The staff noted that these
 
components are passive during plant operation, during which time they are (and need to
 
remain) in a closed position and are an integral part of the pressure boundary. Considering the
 
above, in a follow-up RAI, dated May 12, 2008, the staff requested the applicant to provide the
 
justification for excluding the hatch locks, hinges, and closure mechanisms from the scope of
 
license-renewal and from being subject to an AMR.
In its response, dated June 11, 2008, the applicant stated that the IP2 and IP3 hatch locks, hinges, and closure mechanisms are in scope of license renewal. However, since they perform
 
their functions with moving parts or change in configuration, they are not subject to AMR. The
 
applicant added that consistent with NUREG 1801, Volume 1, Revision 1, Table 5, Item 17, their
 
leaktightness in the closed position is demonstrated through routine testing under the 2-203 containment leakage rate test program as required by IP2 and IP3 Technical Specifications (Reference LRA Table 3.5.1, Line Item 3.5.1-17). Since the applicants response clarified that, in the closed position, the hatch locks, hinges, and closure mechanisms are considered integral
 
to the hatch itself, whose leaktightness is demonstrated by routine local leak rate testing under
 
the Containment Leakage Rate Test Program, the staff finds the response acceptable.
2.4.1.3  Conclusion The staff reviewed the LRA, UFSAR, and RAI and follow-up RAI responses to determine whether the applicant failed to identify any SCs within the scope of license renewal. The staff
 
found no omissions. In addition, the staff sought to determine if the applicant failed to identify
 
any SCs subject to an AMR. The staff found no omissions. On the basis of its review, the staff
 
concludes that the applicant has adequately identified the containment buildings SCs within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
 
====2.4.2 Water====
Control Structures 2.4.2.1  Summary of Technical Information in the Application LRA Section 2.4.2 describes the water control structures, which include: discharge canal and outfall structure  intake structure (IP1, IP2, IP3)  and intake structure enclosure building (IP3)  service water pipe chase (IP3)  service water valve pit (IP2 and IP3)
The discharge canal and outfall structure, located west of the IP2 and IP3 turbine buildings, extends from the IP1 turbine building and carries SW system discharge to the river. Three IP3
 
backup SW pumps, which provide cooling water from the discharge canal in the unlikely event
 
of damage to the SW intake structure, are supported on a slab spanning the walls of the canal.
 
The SW pipe chase, a concrete structure enclosing the SW line, spans across the discharge
 
canal. The discharge canal wall portion adjacent to the SW pipe chase is seismic Class I and
 
part of the ultimate heat sink. The outfall structure enhances mixing of cooling water and river
 
water to minimize thermal impact on the river. The discharge port gates can be adjusted
 
mechanically to control fluid discharge velocity. The outfall structure does not support a license
 
renewal function as defined by 10 CFR 54.4 and hence is not in the scope of license renewal.
The IP1 intake structure (also known as the screenwell house) is a seismic Class III structure located adjacent to the wharf and west of the station on the riverbank. It houses electrical
 
components required for the alternate safe shutdown system, which is credited in the
 
Appendix R safe shutdown analysis. The lower portion contains the IP1 intake, which houses
 
the river water pumps that support IP2 SW. The structure is a reinforced concrete frame
 
supported by a massive concrete substructure. Exterior walls of the intake structure are of
 
concrete brick construction. The north and south ends of the structure are covered by a
 
reinforced concrete roof slab.
The IP2 intake structure (also known as the screenwell structure) is west of the site, below grade at the Hudson River bank, and is open to the river on the west side. The IP3 intake
 
structure (also known as the screenwell structure) is west of the containment structure. Each 2-204 structure houses six CW pumps (each in a separate reinforced concrete compartment), six SW pumps (a SW bay enclosure protects the IP3 pumps), traveling and fixed screens, and screen
 
wash equipment. On the east side of each structure, the SW strainer pit houses SW strainers, screen wash piping, and the strainer control panel. Both the SW strainer pit and the SW bay
 
enclosure are seismic Class I.
The intake structure enclosure building located west of the containment structure provides an upper separate enclosure for the IP3 intake structure and protects CW and SW system components from the weather. Dampers located in the roof system release excess heat during
 
normal operations. The intake structure enclosure consists of a single story steel-framed
 
super-structure with exterior metal siding and ventilation panels.
The IP3 SW pipe chase, which protects SW lines that span the discharge canal and the SW valves and piping, is a reinforced concrete structure attached to the discharge canal wall. The
 
discharge canal wall portion adjacent to the SW pipe chase is seismic Class I.
SW valve pits at the west side of the IP2 and IP3 heater bay buildings protect SW components in IP2 and IP3 intake structures. IP3 has an additional SW valve pit on the north end of the IP3
 
heater bay building to back up the SW pumps. The SW valve pits are underground reinforced
 
concrete structures covered by structural steel plate welded to I-beams at ground level. The
 
additional SW valve pit for IP3 has a precast concrete roof.
The water control structures contain safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the water control structures
 
potentially could prevent the satisfactory accomplishment of a safety-related function. In
 
addition, the water control structures perform functions that support fire protection.
LRA Table 2.4-2 identifies water control structures component types, grouped by material (steel/other metals, concrete), within the scope of license renewal and subject to an AMR as
 
well as their intended functions.
2.4.2.2  Staff Evaluation The staff reviewed LRA Section 2.4.2 and UFSAR Section 8.3 for IP2 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 had not omitted from the scope of license renewal any
 
SCs with intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those SCs
 
that the applicant identified as within the scope of license renewal to verify that the applicant
 
had 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 Section 2.4.2, the staff identified areas in which additional information was necessary to complete the review of the applicants scoping and screening results. The
 
applicant responded to the staffs RAIs as discussed below.
In RAI 2.4.2-1, dated January 28, 2008, the staff noted that LRA Table 2.4-2 does not include the debris wall, fixed coarse screens, fine mesh traveling screens, and gates at the intake
 
structure. Further, the table does not include metal decking, metal siding, grating, and 2-205 ventilation panels for the intake structure enclosure; nor does it include manhole, ladder, and sump of the SW valve pit. The staff requested that the applicant confirm whether or not these
 
components should be included within the scope of license renewal and subject to an AMR and, if so, to provide scoping, screening and AMR results. If not, the staff requested the applicant to
 
justify their absence from LRA Table 2.4-2. The applicant also was requested to clarify whether
 
the "structural steel" component in LRA Table 2.4- 2 includes, among other items, beams, plates, and welded/bolted connections.
In its response, dated February 27, 2008, the applicant stated that the debris wall, fixed coarse screens, fine mesh traveling screens, and gates at the intake structure are not safety-related
 
and are not required to demonstrate compliance with 10 CFR 54.4(a)(3). The applicant stated
 
that the system design is such that failure of these components will not prevent satisfactory
 
accomplishment of a safety function. However, their support structures, being integral to the
 
intake structure in some cases (e.g., embedded guides and steel supports), are included in the
 
structural steel category listed in LRA Table 2.4.2. The applicant stated that metal siding for
 
the intake structure enclosure is not safety-related and is not required to demonstrate
 
compliance with 10 CFR 54.4(a)(3). The applicant added that failure of the metal siding component will not prevent satisfactory accomplishment of any safety function. The applicant
 
stated that in-scope grating, decking, and ladders are bulk commodities addressed in LRA
 
Table 2.4-4. The ventilation panels for the intake structure enclosure are addressed as "vents
 
and louvers" and listed in LRA Table 2.4-4. Furthermore, the applicant stated that manholes are
 
included in LRA Table 2.4-3. The sump of the SW valve pit is integral to the in-scope SW valve
 
pit; thus, it is not listed as a separate item. The applicant clarified that the structural steel
 
component type in LRA Table 2.4-2 includes columns, beams, plates, and their welded
 
connections. Structural bolting is included as a bulk commodity and listed in LRA Table 2.4-4.
In reviewing the response to RAI 2.4.2-1, the staff also reviewed the discussion on the Service Water System and Tornado Design Criteria in Sections 9.6.1 and 16.2, respectively, of the
 
IP3 UFSAR. Based on the description in these UFSAR sections, the SW supply is assured by
 
redundancy of two supply lines, four intakes and screens, and six pumps, of which only two
 
pumps, one intake and screen, and one supply line are required for prolonged shut-down.
 
Further, the backup SW system provides an additional source of service water independent of
 
the intake structure. The existence of these redundancies in the SW system confirms the
 
applicants statement, in the RAI response, that failure of the intake structure components noted
 
in the RAI, which are part of the SW system, will not prevent satisfactory accomplishment of the
 
safety function of the SW system. However, in the response, the applicant stated that in-scope
 
grating, decking, and ladders are bulk commodities addressed in LRA Table 2.4-4. Since this is
 
a generic statement, in a follow-up RAI, dated May 12, 2008, the staff requested the applicant to
 
clarify if the specific components in question that were identified in the RAI (i.e. metal decking
 
and grating of the intake structure enclosure and ladder of the service water valve pit) are
 
included in the scope of license renewal, and subject to AMR as bulk-commodities addressed in
 
LRA Table 2.4-4.
In its response, dated June 11, 2008, the applicant stated that metal decking and grating of the intake structure enclosure and ladder of the service water valve pit have license renewal
 
intended functions as defined by 10 CFR 54.4(a)(2) and, therefore, they are in scope of license
 
renewal and subject to an AMR. The applicant added that these structural components are
 
included in LRA Table 2.4-4, line item Stairway, handrail, platform, grating, decking, and
 
ladders. Since the applicant explicitly clarified that the specific structural components identified
 
in the RAI were subject to an AMR, the staff finds the response acceptable.
2-206 Based on the above response to RAI 2.4.2-1 and to the follow-up RAI, and the descriptions in Section 9.6.1 and Section 16.2 of the IP3 UFSAR, the staff finds that the applicant has
 
adequately addressed and/or clarified the scoping and screening of the specific structural
 
components identified in the RAI. Therefore, the applicants response to RAI 2.4.2-1 is
 
acceptable.
The staff also requested additional information in RAI 2.4.2-2, dated May 12, 2008, regarding other structural components. In Part (a) of RAI 2.4.2-2, the staff noted that LRA Table 2.2-3 and
 
LRA Section 2.4.2 include discharge canal and outfall structure as being within the scope of
 
license renewal. The description in LRA Section 2.4.2, in the second paragraph under the
 
subtitle Discharge Canal and Outfall Structure, states that the outfall structure does not
 
support a license renewal function and, therefore, is not in scope. The staff requested the
 
applicant to explain why the outfall structure was included in LRA Table 2.2-3 and LRA Section
 
2.4.2. The staff requested the applicant to discuss this inconsistency and take appropriate
 
action in scoping the outfall structure.
In Part (b) of RAI 2.4.2-2, because of a lack of clarity in the description in LRA Section 2.4.2 with regard to the discharge canal, the staff requested the applicant to confirm/clarify if (i) the
 
entire discharge canal is considered within the scope of license renewal and subject to AMR or (ii) only the portion adjacent to/supporting the service water pipe chase, and the portion
 
supporting and including the slab on which the Unit 3 service water backup pumps are
 
mounted, are within the scope of license renewal and subject to an AMR.
In its response to Part (a) of RAI 2.4.2-2, dated June 11, 2008, the applicant stated that the outfall structure is included in LRA Table 2.2-3and LRA Section 2.4.2 as part of line item
 
discharge canal and outfall structure because this line item is the name of one continuous
 
structure that includes the discharge canal and the outfall structure. The only portion that is
 
within the scope of license renewal is the discharge canal. The applicant reiterated that the
 
description in LRA Section 2.4.2, in the second paragraph under the subtitle Discharge Canal
 
and Outfall Structure, states that [t]he outfall structure does not support a license renewal
 
function as defined by 10 CFR 54.4 and, therefore, is not in scope. The applicant added that
 
this statement specifically addresses exclusion of the outfall structure portion of the structure
 
from the scope of license renewal and AMR. The staff finds the response acceptable because
 
the applicant clarified that only the discharge canal is within the scope of license renewal; the
 
outfall structure portion of the discharge canal and outfall structure is not within the scope of
 
license renewal.
In its response to Part (b) of RAI 2.4.2-2, dated June 11, 2008, the applicant stated that the entire discharge canal is within the scope of license renewal and subject to AMR. Since the
 
response clarified that the entire discharge canal is conservatively included as being in scope of
 
license renewal and subject to AMR, the staff finds the clarification provided by the applicant
 
acceptable.
2.4.2.3  Conclusion The staff reviewed the LRA, UFSAR, RAI and follow-up RAI responses, and description of related structural components to determine whether the applicant failed to identify any SCs
 
within the scope of license renewal. The staff found no omissions. In addition, the staff sought to
 
determine if the applicant failed to identify any SCs subject to an AMR. Again, the staff found no 2-207 omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the water control structures SCs within the scope of license renewal, as required by
 
10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.3  Turbine Buildings, Auxiliary Buildings, and Other Structures 2.4.3.1  Summary of Technical Information in the Application LRA Section 2.4.3 describes the turbine buildings, auxiliary buildings, and other structures: Appendix R diesel generator foundation, fuel oil tank vault, switchgear and enclosure (IP3) auxiliary feedwater pump building (IP2, IP3)  boric acid evaporator building (IP2)  city water storage tank foundation and meter house condensate storage tanks foundation (IP2, IP3)  containment access facility and annex (IP3)  control buildings (IP2, IP3)  diesel generator buildings (IP2, IP3)  electrical tunnels (IP2, IP3)  emergency lighting poles and foundations  fan houses (IP2, IP3)  fire pump house (IP2)/fire protection pump house (IP3)  fire water storage tank foundation (IP2, IP3)  fuel storage buildings (IP2, IP3)  gas turbine generator Nos. 1, 2, and 3 enclosure and fuel tank foundation (includes gas
 
turbine substation switchgear structures and foundation)  maintenance and outage building elevated passageway (IP2)  manholes and duct banks  new station security building  nuclear service building (IP1)  power conversion equipment building (IP3)  PABs (IP2, IP3)  primary water storage tanks foundation (IP2, IP3)  radiation monitoring enclosure (IP2)  refueling water storage tanks foundation (IP2, IP3)  security access and office building (IP3)  superheater building (IP1) 2-208 superheater stack (IP1)  transformer/switchyard support structures  transmission towers (SBO recovery path) and foundations  turbine building (IP1, IP2, IP3) and heater bay (IP2, IP3)  utility tunnel  waste holdup tank pit (IP2, IP3)
The Appendix R diesel generator, fuel oil tank vault, and switchgear are located in separate, adjacent enclosures in the yard area north of the AFW pump room. The Appendix R diesel
 
generator, fuel oil tank vault, and switchgear support a power supply sufficient to allow the plant
 
to be brought to cold shutdown in a loss of offsite power coincident with a fire causing the loss
 
of all three EDGs or their distribution systems.
The IP2 AFW pump building in the shield wall area between the shield wall and the IP2 containment building is a seismic Class I structure that protect the Class I AFW pumps. The MS
 
lines also located in this building are supported by the structural steel framing.
The IP3 AFW pump building in the shield wall area between the shield wall and the IP3 containment building also includes the shield wall area enclosure. It is a seismic Class I
 
structure that protects the Class I AFW pumps and MS lines located in this area.
The boric acid evaporator building is a seismic Class I reinforced concrete structure supported by the roof slab of the IP2 waste hold-up tank pit. The exterior walls are of concrete and
 
concrete block construction. Portions of the concrete walls are removable. Over the concrete
 
block portion is light-weight roofing over metal decking and over the concrete walls is a concrete
 
slab.The city water storage tank and meter house is a source of water for the AFW system for both IP2 and IP3 and of emergency water for SI, RHR, and charging pumps. The city water storage
 
tank foundation supports the storage tank safety function. The meter house shelters and
 
protects the storage tank components. A free-standing, 1,500,000-gallon vertically cylindrical
 
carbon steel city water storage tank is supported by a reinforced concrete spread footing
 
foundation on rock. The meter house is a single-story concrete brick and steel structure with a
 
concrete roof slab.
Two separate reinforced concrete slab foundations support the condensate storage tanks for IP2 and IP3.
The containment access facility and annex adjacent to the PAB is a handling area for contaminated material and a personnel access to containment. The containment access facility
 
and annex is Class III except for the seismic Class I structural steel portion interfacing with the
 
PAB. The containment access facility and annex has structural steel framing supported on the
 
PAB roof floor slab and insulated metal siding.
The control buildings house the central control room, cable spreading room, and other safety-related equipment and components. The IP2 control building adjacent to the IP2 turbine
 
building on the west and the superheater building on the south contains both the IP1 and IP2
 
control rooms. It is a multi-story Class I steel framed structure with north and east exterior walls 2-209 of insulated metal-sandwich panels. Floor slabs are composite-type construction, concrete over steel beam.The IP3 control building is a multi-story Class I concrete structure with concrete and
 
concrete brick exterior is adjacent to the IP3 turbine building on one end and the diesel
 
generator building on the south. Both structures are founded on bedrock.
The seismic Class I IP2 diesel generator building consists of a reinforced concrete foundation on bedrock, a prefabricated rigid steel superstructure with exterior insulated metal siding, and a
 
solid, corrugated metal roof. The diesel generators rest on reinforced concrete foundations
 
supported by the structure's main slab. A concrete shield wall on the west side serves as missile
 
protection between the control panel and diesels. The IP3 diesel generator building is a
 
single-story reinforced concrete structure on a concrete slab supported on bedrock. Each diesel
 
generator building houses three safety-related diesel generators. Each diesel has separate
 
underground storage vaults, integral to its building, for fuel oil tanks. Foundations for the fuel oil
 
tanks are the same as for the structure.
The electrical tunnels are partially below-grade, seismic Class I reinforced concrete structures that contain electrical cable, conduit, and cable trays that support plant operations.The IP2
 
electrical tunnel running eastward from the east side of the control building is attached to the
 
south side of an east-west retaining wall. The elevation of the lower slab of the tunnel slopes
 
from the control building up to the PAB. The tunnel then turns northward past the west side of
 
the PAB to the electrical penetration area adjacent to the IP2 containment building. The IP3
 
electrical tunnels run from the control building past the PAB to the containment penetration
 
vault. The electrical tunnels consist of two seismic Class I reinforced concrete conduits, one
 
above the other. Both the upper and lower tunnels are eight feet wide by eight feet high.
Pole-mounted security lighting around the perimeter of the plant site provides emergency lighting in an Appendix R fire and a loss of offsite power by illuminating ingress and egress.
 
Each emergency light pole is a single-pole steel structure supported by a reinforced concrete
 
foundation.
Each fan house is a seismic Class I structure containing the piping penetration area.
Safety-related valves in the piping penetration area may be used to achieve safe shutdown.
 
Each fan house building is a multi-story reinforced concrete and masonry block wall structure
 
founded on bedrock. A steel superstructure on top of each building supports the roof framing
 
system.The IP2 fan house southeast of the IP2 containment structure and between the IP2 containment, the IP2 PAB, and the IP2 fuel storage building is isolated from the containment
 
structure and the PAB. Its east wall is common with the west wall of the fuel storage building.
 
The IP3 fan house southeast of the IP3 containment structure and between the IP3
 
containment, the IP3 PAB, containment access facility, and the IP3 fuel storage building is
 
isolated from the containment structure and the PAB. Its east wall is common with the west wall
 
of the fuel storage building and its south wall is common to the containment access facility
 
annex.The IP2 fire protection pump house (also known as diesel fire pump house) houses the main diesel firewater pump and protects fire protection system components. The structure is of
 
structural steel framing with exterior insulated metal siding and a composite metal roof. The
 
foundation is a reinforced concrete slab on grade. The IP3 fire protection pump house contains
 
the electric motor-driven fire pump, the diesel-driven fire pump, and equipment for an adequate
 
source of fire water. The structure is a reinforced concrete and concrete block wall construction
 
with a concrete roof slab. The foundation is a reinforced concrete slab on bedrock.
2-210 The IP2 fire water storage tank (also known as suction tank) foundation is the main support for the 300,000-gallon fire water storage tank. Water for the dedicated diesel-driven fire pump for
 
normal operations comes from the tank. The IP3 fire water storage tank foundations are the
 
main supports for two 350,000-gallon fire water storage tanks. The tanks and their piping, electrical, and instrumentation systems are the source of fire protection system water and IP3 makeup water treatment.
For IP2 and IP3, the fuel storage building is designed to handle and store both spent and new fuel and supports the spent fuel crane and other fuel-handling equipment. In addition, the floor
 
of IP2 provides support for a single-failure-proof gantry crane. Each structure is located
 
adjacent to but separate from its containment building.
The gas turbine generator No. 1 enclosure and tank foundation are seismic Class III structures providing shelter and protection from the elements for gas turbine No. 1 and its associated
 
equipment. Gas turbine No. 1 is located adjacent to the Unit 1 turbine building and supports no
 
license renewal function; however, the associated switchgear components and fuel supply tank
 
provide support for the SBO/Appendix R diesel generator set. The gas turbine No. 1 enclosure
 
consists of structural steel framing with exterior metal siding on a reinforced concrete slab. The
 
fuel tank foundation is a reinforced concrete spread footing which supports the fuel tank
 
supplying the SBO/Appendix R diesel.
The gas turbine generators Nos. 2 and 3 enclosure is a seismic Class III structure that shelters and protects the equipment from the elements. The gas turbine Nos. 2 and 3 enclosure located
 
at the Buchanan substation houses gas turbine generators Nos. 2 and 3 and their switchgear
 
equipment. The switchgear and associated components within the structure support offsite
 
power recovery following station blackout. The gas turbine Nos. 2 and 3 fuel tank foundation
 
supports the fuel tank, an alternate source of EDG fuel. These fuel tanks shared by IP2 and IP3
 
are credited for minimum EDG fuel oil inventory. If the EDGs require the reserves in these
 
tanks, the contents can be transported by tanker truck.
The gas turbine substation switchgear structures and foundation support equipments required to support offsite power recovery following station blackout. It consists of a reinforced concrete
 
slab that supports the substation and switchgear support structures. Component equipment is
 
anchored by welding or bolting to embedments in the concrete slab.
The maintenance and outage building and elevated passageway are seismic Class II structures used by maintenance and outage personnel. The structures are southeast of the IP2
 
containment structure, across from the PAB, and adjacent to the fuel storage building. The
 
building has two major floors and an elevated passageway for access to the PAB. A
 
safety-related conduit routed through one end of the building near the bridge connects the
 
maintenance and outage building to the PAB.
Manholes and duct banks throughout the applicants yard allow underground routing of cables and piping. These structural components are of reinforced and non-reinforced concrete.
The new station security building east of the IP1 containment structure provides offices for personnel and contains the security generator credited as a source of backup power to the
 
station security lighting system. For IP2, this lighting illuminates exterior ingress and egress in
 
an Appendix R fire and a loss of offsite power.
2-211 The IP1 nuclear service building adjacent to but separated from the IP1 containment structure protects alternate safe shutdown system components in support of IP2. These components consist of cables in conduit for various systems: chemical and volume control, CCW, RHR, and
 
SI systems. The structure contains treatment and decontamination facilities and examination
 
rooms for site personnel.The IP3 power conversion equipment building houses power conversion system components.
The IP2 PAB is a seismic Class I structure housing safety injection pumps, component cooling pumps, heat exchangers, and RHR pumps. The IP3 PAB houses components required for
 
recirculation (e.g., component cooling pumps, heat exchangers, and SI and RHR pumps).
The IP2 and IP3 primary water storage tank foundations are the main supports for the 165,000-gallon primary water storage tank for each unit. The tanks supply demineralized water
 
for the primary water makeup systems.
The IP2 radiation monitoring enclosure houses radiation monitors R46, R49 and R53. Monitors R46 and R53 monitor the SW return from all containment fan cooler units.
For both IP2 and IP3, the RWST foundation is the main support for the 350,000-gallon RWST.
The tank supplies borated water to the refueling canal, SI pumps, RHR pumps, and the
 
containment spray pumps for a LOCA.
The IP3 security access and office building located west of the service admin complex provides offices for personnel and contains the security generator credited as a source of backup power
 
to the station security lighting system. For IP3, this lighting illuminates exterior ingress and
 
egress in an Appendix R fire or a loss of offsite power.
The IP1 superheater building is adjacent to but physically separated from the control building.
The superheater stack is located on top of the superheater building. The structure contains the
 
technical support center, provides office area for personnel, supports alternate safe shutdown
 
system components, and houses a safety-related battery room.
The IP1 superheater stack on top of the superheater building carries exhaust from the superheaters and also supports a ventilation duct carrying exhaust from the containment
 
structure. Failure of the stack could result in damage to the IP2 control building, the EDG
 
building, and in-scope IP3 structures. To minimize this risk, the applicant shortened the stack
 
and reinforced its support structure to satisfy IP3 tornado protection criteria.
The offsite power source required to support SBO recovery actions is fed through one of the station auxiliary transformers. Specifically, the path includes the 138kV and 345kV switchyard
 
circuit breakers feeding either station auxiliary transformers.
The transformer/switchyard support structures physically support the station auxiliary transformers and the other switchyard components in the SBO recovery path. These support
 
structures include the transformer foundations and support steel, transformer pothead
 
foundations and support steel, and switchyard breaker foundations.
Transmission towers (SBO recovery path) and foundations are parts of the path to restore offsite power.
2-212 The IP1 turbine building is an extension of the IP2 turbine building and is integrally attached to the superheater building and the IP2 turbine building. The structure is classified as seismic
 
Class III but was analyzed to ensure that there is no potential for gross structural collapse as a
 
result of a design basis event. Equipment and components on the IP1 operating floor have been
 
removed and the supporting systems for these components are not in service. The facility
 
houses the station blackout/Appendix R diesel and two fire water pumps, along with their
 
associated components relied upon in the site's safe shutdown analysis. The building is
 
constructed of heavy structural steel framing with steel supported reinforced concrete slabs
 
forming the floor area. Crane rails located within IP1 extending the entire length of the structure
 
also provide support for IP2. The building's exterior face is constructed of metal-sandwich
 
panels and concrete brick.
The IP2 turbine building and heater bay extension of the IP1 turbine building is similar to IP1 and is seismic Class III. Although the turbine building and heater bay are seismic Class III
 
structures, they were analyzed for potential gross structural collapse as a result of a
 
design-basis event. Attached to the superheater building and the IP1 turbine building, the
 
building houses the IP2 turbine generator, FW heaters, and their supporting systems as well as
 
cabling, switchgear, and other SBO/Appendix R diesel equipment.
The IP3 turbine building and heater bay is a seismic Class III structure that houses the turbine generator and its auxiliaries. The structure is designed not to affect Class I structures.
The utility tunnel is a seismic Class III structure. The tunnel shelters and protects the city water supply piping for AFW backup water and other miscellaneous functions. The utility tunnel is a
 
rectangular reinforced concrete structure founded on rock.
The IP2 waste holdup tank pit is adjacent to the refueling water tank and its top slab supports the boric acid evaporator building. The IP3 waste holdup tank pit, two structures joined to form a
 
single structure, is adjacent to the primary water storage tank and the radioactive machine
 
shop. The waste holdup tank pits house liquid waste holdup tanks which are the collection
 
points for liquid radwaste. A sump services the water tanks.
The turbine buildings, auxiliary buildings, and other structures contain safety-related components relied upon to remain functional during and following DBEs. The failure of
 
nonsafety-related SSCs in the turbine buildings, auxiliary buildings, and other structures
 
potentially could prevent the satisfactory accomplishment of a safety-related function. In
 
addition, the turbine buildings, auxiliary buildings, and other structures perform functions that
 
support fire protection and SBO.
LRA Table 2.4-3 identifies turbine buildings, auxiliary buildings, and other structure component types, grouped by material (steel/other metals, concrete), within the scope of license renewal
 
and subject to an AMR as well as their intended functions.
2.4.3.2  Staff Evaluation The staff reviewed LRA Section 2.4.3 and IP2 UFSAR Sections 1.3.8, 1.11.4.12, 1.11.6, 7.2.4.1.4, and 9.5.2, and IP3 UFSAR Sections 8.4, 9.6.2, 9.6.2.9, and 11.1.2.1, 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 2-213 and UFSAR to verify that the applicant had not omitted from the scope of license renewal any SCs with intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those SCs
 
that the applicant identified as within the scope of license renewal to verify that the applicant
 
had 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 Section 2.4.3, the staff identified areas in which additional information was necessary to complete the review of the applicants scoping and screening results. The
 
applicant responded to the staffs RAIs as discussed below.
In the second part of RAI 2.4-1, dated January 28, 2008 (the first part of RAI 2.4-1 is addressed in SER Section 2.4), the staff noted that the structure identified as Gas Turbine Substation
 
Switchgear Structures and Foundation in LRA Table 2.2-3 was not included in the structures
 
listed at the beginning of the subsection Description of LRA Section 2.4.3. The staff requested
 
that the applicant address the scoping and screening of these structures or clarify where they
 
were addressed in the LRA.
In the last paragraph of its response to RAI 2.4-1, dated February 27, 2008, the applicant stated that the Gas Turbine Substation Switchgear Structures and Foundation area is addressed in
 
LRA Section 2.4.3, subsection titled Description under Gas Turbine Generator No. 1, 2 and 3
 
Enclosure and Fuel Tank Foundation. The staff verified that a description of switchgear
 
structures and foundation was included in the subsection in Section 2.4.3 describing the gas
 
turbine generators No. 1, 2 and 3 enclosure and fuel tank foundations, as stated by the
 
applicant. The staff finds the applicants response acceptable subject to further clarification as
 
requested in the follow-up RAI, dated May 12, 2008.
Because of a lack of clarity in LRA Table 2.4-3, and the applicants response to RAI 2.4-1 with regard to switchgear structures and foundation, the staff sought clarification regarding which
 
specific structural components in Table 2.4-3 cover the switchgear structures and foundation.
 
The staff noted that the component line item foundations in LRA Table 2.4-3 does not list
 
switchgear structures in the structure list provided within parenthesis.
In its response, dated June 11, 2008, the applicant stated that the switchgear foundation is listed in LRA Table 2.4-4, as equipment pads/foundations. Since the applicant clarified that the
 
switchgear foundations are included as a concrete bulk commodity item as part of line item
 
equipment pads/foundation in LRA Table 2.4-4, and the embedments to which the switchgear
 
equipment is anchored are included as part of bulk commodity line item
 
anchorages/embedments in LRA Table 2.4-4, the staff finds the response acceptable.
In RAI 2.4.3-1, dated January 28, 2008, the staff noticed the following in the LRA with regard to the fuel storage buildings: (i) LRA Section 2.4.3 states that the fuel storage buildings have the following intended functions pursuant to 10 CFR 54.4(a)(1) and (a)(2):  Maintain integrity of
 
nonsafety-related components such that safety functions are not affected by maintaining
 
pool water inventory (Units 2 and 3).(ii) LRA Section 2.1.2.2, Screening of Structures, states that the screening of structural components and commodities was based primarily on whether they perform an intended
 
function.
2-214(iii) LRA Table 3.5.2-3, Turbine Building, Auxiliary Building, and Other Structures, Structural Components and Commodities (IP2 and IP3), identifies structural components subject
 
to aging management based on materials of construction and intended functions for
 
components of structures, including the fuel storage buildings. (iv) The intended functions listed in LRA Table 3.5.2-3 (e.g., pressure boundary, missile barrier, and shelter or protection) agree with the intended functions listed in LRA
 
Table 2.0-1, Intended Functions: Abbreviations and Definitions. However, the intended
 
functions for the fuel storage building listed in LRA Section 2.4.3 do not agree with the
 
listed intended functions in LRA Tables 2.0-1 and 3.5.2-3.
With reference to the above, the staff noted in the RAI that, pursuant to 10 CFR Part 54.21, the LRA must identify and list those SCs subject to an AMR. The staff requested that the applicant
 
clarify the LRA Section 2.4.3 description of the intended function(s) of the fuel storage building
 
components, using the list of intended functions from LRA Table 2.0-1. The staff added that, to
 
satisfy the requirements of 10 CFR Part 54.21, the clarification must be adequate to reasonably
 
identify the fuel storage building structural components subject to an AMR by the component or
 
commodity, material of construction, and intended functions listed in LRA Table 3.5.2-3.
In its response, dated February 27, 2008, as supplemented in LRA Amendment No. 3, dated March 24, 2008, the applicant stated that the intended functions listed in LRA Tables 2.0-1 and
 
3.5.2-3 are component intended functions, which are determined during the screening process.
 
The intended functions in LRA Section 2.4.3, in contrast, are the intended functions of the
 
structure in its entirety and are determined during the scoping process. The applicant explained
 
that the scoping process determines whether or not the structure has an intended function (i.e.,
providing containment or isolation to mitigate post-accident offsite doses, or providing support or
 
protection to safety-related equipment), whereas the screening process identifies those
 
components that support the structure intended function(s) via specific component intended
 
functions (i.e., providing shelter and protection or providing support for safety-related
 
equipment). The structure and system level functions that are assessed against the scoping
 
requirements of 10 CFR Part 54.4 are not intended to match the component level functions defined in LRA Table 2.0-1. While similarities exist between the terminology used for component
 
intended functions versus structure intended functions, a direct correlation between the
 
structure intended functions in LRA Section 2.4 and the component intended functions in the
 
tables in LRA Section 3.5 does not exist. The applicant clarified that the structure level intended
 
functions of the fuel storage buildings are to: (a) maintain integrity of nonsafety-related
 
components such that safety functions are not affected by maintaining pool water inventory, and (b) provide support and protection for safety-related equipment within the scope of license
 
renewal. The applicant also provided a tabulation of component level intended functions (as
 
defined in LRA Table 2.0-1) supporting each of the two structure level intended functions for the
 
fuel storage buildings.
In its response, the applicant used a broader structure level intended function concept in the scoping process and supplemented that by more detailed component level intended functions
 
for the structural components during the screening process. Because the applicant 1) has
 
clarified the structure level intended functions of the fuel storage buildings, and 2) provided a
 
tabulation of the structural component intended functions for each of the two structure level
 
intended functions (as defined in LRA Table 2.0-1), the staff finds the applicants response
 
acceptable. Therefore, the staffs concern described in RAI 2.4.3-1 is resolved.
2-215 In RAI 2.4.3-2, dated January 28, 2008, the staff noted that, in LRA Section 2.4.3, the top of the spent fuel pit wall forms the north wall of each unit's fuel building. The staff further noted that
 
UFSAR Figure 1.2-4 (IP2), Cross Section of Plant, indicates that at least part of the fuel
 
building exterior wall is below grade. LRA Table 2.4-3 lists pressure boundary as an intended
 
function for the concrete component exterior walls but does not list pressure boundary as an
 
intended function of the concrete component exterior walls-below grade, representing the fuel
 
building wall. The staff requested that the applicant update LRA Table 2.4-3 to include the
 
pressure boundary intended function for the spent fuel pit wall that is below grade or provide
 
justification for excluding this intended function.
In its response, dated February 27, 2008, the applicant stated that it agrees that the spent fuel pit wall below grade also performs a pressure boundary intended function. The applicant
 
revised LRA Tables 2.4-3 and 3.5.2-3 to include the pressure boundary intended function for
 
exterior walls below-grade which includes the spent fuel pit wall. The staff finds the applicants
 
response adequately addresses the staffs concerns raised in the RAI and, therefore, is
 
acceptable. The staffs concern described in RAI 2.4.3-2 is resolved.
In RAI 2.4.3-3, dated January 28, 2008, the staff noted that LRA Table 2.4-3 does not include the leak chase channel of the IP3 spent fuel pit as a component subject to an AMR. The staff
 
requested the applicant to include this as a component subject to an AMR or provide a
 
justification for its exclusion.
In its response, dated February 27, 2008, the applicant stated that the leak chase channel is an integral attachment to the liner plate, which is subject to AMR and included in line item Spent
 
fuel pool liner plate and gate in LRA Table 2.4-3. The staff agrees with the applicants position
 
that the leak chase channel, which is welded to the liner plate, can be considered an integral
 
attachment to the liner plate and included as part of the liner plate component. The staff finds
 
the applicants response adequately addresses the staffs concerns raised in the RAI and, therefore, is acceptable. The staffs concern described in RAI 2.4.3-3 is resolved.
In RAI 2.4.3-4, dated January 28, 2008, the staff noted that, although LRA Table 2.4-3 lists Crane rails and girders as a component type subject to an AMR, it is not clear whether this
 
component refers to just crane rails and girders or also refers to the cranes themselves. If it
 
includes the cranes, the applicant was requested to clarify whether all relevant subcomponents
 
(...including bridge and trolley, rails, and girders) of these in-scope crane systems have been
 
screened in as items requiring an AMR. The staff also requested that the applicant 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, with
 
technical bases. The applicant also was requested to confirm whether fasteners and rail
 
hardware associated with this component type are within the scope of license renewal and
 
subject to an AMR or provide the technical bases for their exclusion. The staff also requested
 
that the applicant confirm whether there are other hoists and lifting devices that should be
 
included within the scope of license renewal (and subject to an AMR) and, if so, provide their
 
scoping, screening, and AMR results, relevant to the LRA.
In its response, dated February 27, 2008, the applicant stated that the component type crane rails and girders in LRA Table 2.4-3 includes bridge and trolley and also refers to the cranes
 
themselves. The applicant further stated that there are no hoists or lifting devices that perform
 
an intended function that would place them in scope and subject to an AMR. The applicant
 
clarified that the specific cranes in scope and subject to an AMR are discussed in LRA Section 2-216 2.4-1 for containment buildings and in Section 2.4-3 for turbine building(s) and fuel storage building(s). The applicant confirmed that fasteners and rail hardware are in scope and subject to
 
an AMR. They are, however, considered bulk commodities and are included in LRA Table 2.4-4, line item structural bolting. Since the language of the line item as currently written could be
 
misleading, in a follow-up RAI, dated May 12, 2008, the staff requested the applicant to correct the line item crane rails and girders
" in LRA Table 2.4-3 to read cranes, rails and girders." In its response to the follow-up RAI, dated June 11, 2008, the applicant stated that the line item "crane rails and girders" LRA Table 2.4-3 and LRA Table 3.5.2-3 is corrected to read "cranes, rails and girders". Since the applicant corrected the line item, the staff finds the response
 
acceptable.
In RAI 2.4.3-5, dated January 28, 2008, the staff requested that the applicant confirm whether the component identified as "Structural Steel: beams, columns, plates" in LRA Table 2.4-3
 
includes bracings, welds, and bolted connections or indicate where they were included. The
 
staff also requested that the applicant include "Battery Racks" (e.g., for emergency diesels),
turbine generator pedestals and their structural bearing pads, and diesel generator pedestals
 
and the concrete curb around diesel generator foundations as components subject to an AMR.
In its response, dated February 27, 2008, the applicant clarified that the component identified as Structural Steel: beams, columns, plates, trusses in LRA Table 2.4-3 includes bracings and
 
welds associated with the component. The applicant added that bolted connections are
 
addressed in LRA Section 2.4.4 and LRA Table 2.4-4. The applicant further clarified that battery
 
racks (e.g., for emergency diesel) are within the scope of license renewal and subject to an
 
AMR and are included as bulk commodities within line item component and piping support in
 
LRA Table 2.4-4. The applicant further clarified that the turbine generator pedestals, diesel
 
generator pedestals, and the concrete curb around diesel generator foundations are included
 
within the LRA Table 2.4-3 as part of line item Floor slabs, interior walls and ceiling and line
 
item Foundations. The applicant stated that structural bearing pads associated with the turbine
 
generator pedestal are not within the scope of license renewal because they are not
 
safety-related and not required to demonstrate compliance with 10 CFR 54.4(a)(3). Failure of the bearing pads will not prevent satisfactory accomplishment of a safety function. Based on
 
this response, the staff finds that the applicant has adequately clarified the inclusion or justified
 
the exclusion, as applicable, of each of the structural components noted in the RAI. The staff
 
finds the applicants response adequately addresses the staffs concerns raised in the RAI and, therefore, is acceptable. The staffs concern described in RAI 2.4.3-5 is resolved.
2.4.3.3  Conclusion The staff reviewed the LRA, UFSAR, and RAI and follow-up RAI responses to determine whether the applicant failed to identify any SCs within the scope of license renewal. The staff
 
found no omissions. In addition, the staff sought to determine if the applicant failed to identify
 
any SCs subject to an AMR. Again, the staff found no omissions. On the basis of its review, the
 
staff concludes that the applicant has adequately identified the turbine buildings, auxiliary
 
buildings, and other structures SCs within the scope of license renewal, as required by
 
10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-217 2.4.4  Bulk Commodities 2.4.4.1  Summary of Technical Information in the Application LRA Section 2.4.4 describes bulk commodities, the structural components or commodities that perform or support intended functions of in-scope SSCs. Bulk commodities unique to a specific structure are included in the review for that structure (LRA Sections 2.4.1 through 2.4.3). Bulk
 
commodities common to Indian Point in-scope SSCs (e.g., anchors (including rock bolts), embedments, pipe and equipment supports, instrument panels and racks, cable trays, and
 
conduits) are addressed in this section.
Insulation may have the specific intended functions of (1) controlling the heat load during DBAs in areas with safety-related equipment, (insulation and Insulation jacket) or (2) maintaining
 
integrity such that falling insulation does not damage safety-related equipment (reflective
 
metallic-type reactor vessel insulation).
Bulk commodities have the following intended functions for 10 CFR 54.4(a)(1), (a)(2), and (a)(3):  Provide support, shelter, and protection for safety-related equipment and
 
nonsafety-related equipment within the scope of license renewal.
LRA Table 2.4-4 identifies bulk commodities component types, grouped by material (steel/other metals, concrete, other materials), within the scope of license renewal and subject to an AMR
 
as well as their intended functions.
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 had not omitted from the scope of license renewal any
 
SCs with intended functions, as required by 10 CFR 54.4(a). The staff then reviewed those SCs
 
that the applicant identified as within the scope of license renewal to verify that the applicant
 
had 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 Section 2.4.4, the staff identified areas in which additional information was necessary to complete the review of the applicants scoping and screening results. The
 
applicant responded to the staffs RAIs as discussed below.
In LRA Section 2.4.4 and LRA Table 2.4-4, the applicant discussed and listed the structural bulk commodities components common to in-scope structures that are subject to an AMR. Because
 
of a lack of clarity in LRA Table 2.4-4, in RAI 2.4.4-1, dated January 28, 2008, the staff
 
requested that the applicant confirm or clarify and appropriately address whether the following
 
bulk commodities have been screened in as components subject to an AMR, in LRA
 
Table 2.4-4: (i) expansion anchors (ii) vibration isolation elements (iii) flood curbs 2-218(iv) waterproofing membrane (v) sliding support bearings and sliding support surfaces The applicant also was requested to explicitly state the specific materials that are classified as "Other Materials" in LRA Table 2.4-4.
In its response, dated February 27, 2008, the applicant clarified the screening of each component identified in the RAI as follows: (i) Expansion Anchors are addressed in LRA Table 2.4-4 under line item anchorages/embedments.(ii) There are no vibration isolation elements identified as within the scope of license renewal and subject to AMR. (iii) Flood curbs are included in the review of structures. Considered integral to floor slabs, they are included in the review for those line items identified
 
in LRA Tables 2.4-1 as beams, columns, interior walls, slabs,
 
Table 2.4-2 as beams, columns, floor slabs and walls and Table 2.4-3
 
as floor slabs, interior walls, ceilings. (iv) Waterproofing membranes are not in-scope. Waterproofing membranes are not safety-related and are not required to demonstrate compliance
 
with 10 CFR 54.4(a)(3). Failure of these membranes will not prevent
 
satisfactory accomplishment of a safety function. (v) The sliding support bearings and sliding support surfaces identified as within the scope of license renewal are documented in LRA Table 2.4-1, line item Lubrite sliding surfaces.
The applicant also stated that materials classified as "Other Materials" in LRA Table 2.4-4 are those materials that were not captured by what is considered basic structural materials (i.e
., steel or concrete) and that the material make-up of these commodities is specifically identified in
 
LRA Section 3.5.2.1.4.
The staff finds that the applicant adequately clarified the issues related to the screening of the five specific structural components identified in the RAI. The staff also verified that, in LRA
 
Section 3.5.2.1.4, the applicant identified the bulk commodity component materials that make up
 
the line item Other Materials. These other materials, identified in LRA Section 3.5.2.1.4 are
 
aluminum, cera blanket, cerafiber, elastomer, fiberglass and/or calcium silicate, mineral wool, and pyrocrete. The staff finds that the applicants response adequately addresses the staffs
 
concerns raised in the RAI and, therefore, is acceptable. The staffs concern described in
 
RAI 2.4.4-1 is resolved.
In RAI 2.4.4-2, dated January 28, 2008, with regard to the components insulation and insulation jacket identified in LRA Table 2.4-4, the staff pointed out that it was unclear as to
 
which insulation (and material) and insulation jacket within the scope of license renewal were
 
included in these items. The applicant was requested to clarify whether the insulation and
 
jacketing on the containment liner, reactor vessel, RCS, MS and FW systems are included.
2-219 The applicant also was requested to provide the following information with regard to insulation that is used to control the maximum temperature of safety-related structural elements: (a) Identify the structures and structural components designated as 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 serve an intended
 
function in accordance with 10 CFR 54.4(a)(2) and describe the scoping and screening
 
results of thermal insulation, and provide the 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 AMP(s)
 
credited to manage their aging.
In its response, dated February 27, 2008, the applicant addressed each of the items in the RAI as follows: (a)  The applicant stated that structures and structural components within the scope of license renewal that have insulation and/or insulation jacketing that serves an
 
intended function pursuant to 10 CFR 54.4(a)(2) are the containment liner and
 
high-temperature piping at containment piping penetrations. The applicant stated
 
that the containment liner insulation is listed in LRA Table 2.4-1, and the
 
insulation associated with hot containment penetrations is addressed in LRA
 
Section 2.4.4 and in LRA Table 2.4-4. (b) The applicant clarified that insulation and insulation jacketing materials associated with item (a) do not require an AMP because these insulation
 
materials are exposed to indoor air environment and the containment liner
 
insulation is encapsulated in a stainless steel jacket and is not subject to external
 
environments. The applicant further stated that, in these environments, these
 
materials have no aging effects requiring management. The operating experiencereview specifically considered plant-specific information related to the
 
effects of aging on insulation materials, and that review confirmed that no aging
 
effects requiring management are applicable to the insulation materials that are
 
subject to an AMR at IP2 and IP3. (c) The applicant stated that aging management review results for insulation and insulation jacketing materials are shown in LRA Tables 3.5.2-1 and 3.5.2-4.
The applicant reiterated that, since there are no aging effects requiring management for insulation, no AMP is credited, noting that insulation materials in an indoor air environment are
 
not susceptible to degradation from the effects of aging.
In its response, and in the context of insulation that serves to limit the temperature of safety-related structural components, the applicant confirmed that the structures and structural
 
components, within the scope of license renewal and subject to an AMR, that have insulation 2-220 and/or insulation jacketing are the containment liner and high-temperature piping at the containment penetrations. The applicant concluded that none of the in-scope insulating material
 
used at IP2 and IP3 requires any management for aging effects because of its favorable
 
operating experience and the fact that it is only exposed to an indoor air environment and
 
encapsulated in metallic jacketing. The staff finds that this conclusion is consistent with the
 
GALL Report, Volume II. The staff further finds that the applicants response to RAI 2.4.4-2
 
adequately addressed the staffs question with regard to insulation and, therefore, is acceptable.
 
The staffs concern described in RAI 2.4.4-2 is resolved.
2.4.4.3  Conclusion The staff reviewed the LRA, UFSAR, and RAI responses to determine whether the applicant failed to identify any SCs within the scope of license renewal. The staff found no omissions. In addition, the staff sought to determine whether the applicant failed to identify any SCs subject to
 
an AMR. The staff found no omissions. On the basis of its review, the staff concludes 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).
 
===2.5 Scoping===
and Screening Results: Electrical and Instrumentation and Control Systems This section documents the staffs review of the applicants scoping and screening results for
 
electrical and I&C systems.
In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the
 
applicant properly implemented its methodology, the staff's review focused on the
 
implementation results. This focus allowed the staff to confirm that there were no omissions of
 
electrical and I&C system components that meet the scoping criteria and are subject to an AMR.
The staffs evaluation of the information in the LRA sought to determine whether the applicant had 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 applicants screening results to verify that all passive, long-lived
 
components were subject to an AMR in accordance with 10 CFR 54.21(a)(1).
In its scoping evaluation, the staff reviewed the applicable LRA sections, focusing on components that had not been identified as within the scope of license renewal. The staff
 
reviewed relevant licensing basis documents, including the UFSAR, for each electrical and I&C system to determine whether the applicant had omitted from the scope of license renewal
 
components with license renewal intended functions in accordance with 10 CFR 54.4(a). The
 
staff also reviewed the licensing basis documents to determine whether the LRA specified all
 
license renewal 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 applicants screening results. For those SCs with intended functions, the staff sought to determine whether (1) the functions are
 
performed with moving parts or a change in configuration or properties, or (2) the SCs are
 
subject to replacement after a qualified life or specified time period, as described in 2-221 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 Control Systems 2.5.1.1  Summary of Technical Information in the Application LRA Section 2.5 describes the electrical and instrumentation and control systems. As stated in LRA Section 2.1.1, plant electrical and instrument and control (I&C) systems are included in the
 
scope of license renewal as are electrical and I&C components in mechanical systems. The
 
default inclusion of plant electrical and I&C systems in the scope of license renewal reflects the
 
method for the integrated plant assessment (IPA) of electrical systems. This method is different
 
from the methods used for mechanical systems and structures.
The applicant stated that the basic philosophy of the electrical and I&C components IPA is that components are included in the review unless specifically screened out. In the plant spaces
 
approach, this method eliminates the need for unique identification of every component and its
 
specific location so components are not excluded improperly from an AMR. The electrical and
 
I&C IPA began by grouping all components into commodity groups of similar electrical and I&C
 
components with common characteristics and by determining component level intended
 
functions of the commodity groups.
The IPA eliminated commodity groups and specific plant systems from further review as the intended functions of commodity groups were examined. In addition to the plant electrical
 
systems, certain switchyard components required to restore offsite power following SBO were
 
included conservatively within the scope of license renewal even though those components are
 
not relied on in safety analyses or plant evaluations to perform a function that demonstrates
 
compliance with the Commission's regulations for SBO (10 CFR 50.63).
The applicant further stated that the offsite power system provides the electrical interconnection between IPEC and the offsite transmission network. The offsite power sources required to
 
support SBO recovery actions supply the station auxiliary transformers. Specifically, the offsite
 
power recovery path includes the station auxiliary transformers, the 138 kV and 13.8 kV
 
switchyard circuit breakers supplying the station auxiliary transformers, the circuit breaker-to-
 
transformer and transformer-to-onsite electrical distribution interconnections, control circuits, and structures.
The electrical and instrumentation and control systems perform functions that support SBO and EQ.LRA Table 2.5-1 identifies electrical and instrumentation and control systems component types within the scope of license renewal and subject to an AMR: cable connections (metallic parts)  electrical cables and connections not subject to 10 CFR 50.49 EQ requirements  electrical cables not subject to 10 CFR 50.49 EQ requirements used in instrumentation
 
circuits electrical connections not subject to 10 CFR 50.49 EQ requirements exposed to borated 2-222 water leakage  fuse holders (insulation material)  high-voltage insulators for SBO recovery  inaccessible medium-voltage (2kV to 35kV) cables not subject to 10 CFR 50.49 EQ requirements metal-enclosed bus (non-segregated) and connections for SBO recovery  metal-enclosed bus (non-segregated), insulation/insulators for SBO recovery  metal-enclosed bus (non-segregated) enclosure assemblies for SBO recovery  switchyard bus and connections for SBO recovery  transmission conductors and connections for SBO recovery  138 kV direct burial insulated transmission cables The intended functions of the electrical and instrumentation and control systems component types within the scope of license renewal include the following functions:  connect specified electrical circuit portions to deliver voltage, current, or signals insulate and support electrical conductors  structurally or functionally support equipment required for the 10 CFR 54.4(a)(3)
 
regulated events 2.5.1.2  Staff Evaluation The staff reviewed LRA Section 2.5 and the UFSAR using the evaluation methodology described in SER Section 2.5 and the guidance in SRP-LR Section 2.5, Scoping and Screening
 
Results: Electrical and Instrumentation and Controls Systems.
During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with
 
intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components
 
that the applicant had identified as within the scope of license renewal to verify that the
 
applicant had not omitted any passive and long-lived components subject to an AMR in
 
accordance with the requirements of 10 CFR 54.21(a)(1).
During its review of LRA Section 2.5, the staff identified several areas in which additional information was necessary to complete the review of the applicant's scoping and screening
 
results. The applicant responded to the staffs RAIs as discussed below.
The staff noted that, according to LRA Section 2.5, two independent paths from the safety-related buses to the first circuit breaker from the offsite transmission line were not included
 
within the scope of license renewal. General Design Criterion 17 of 10 CFR Part 50, Appendix
 
A, requires that electric power from the transmission network to the onsite electric 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 2-223 incorporated in SRP-LR Section 2.5.2.1.1, states:
For purposes of the license renewal rule, the staff has determined that the plant system portion of the offsite power system that is used to connect the plant to the
 
offsite power source should be included within the scope of the rule. This path typically includes switchyard circuit breakers that connect to the offsite system
 
power transformers (startup transformers), the transformers themselves, the
 
intervening overhead or underground circuits between circuit breaker and
 
transformer and transformer and onsite electrical system, and the associated
 
control circuits and structures. 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.
According to this guidance, the NRC staff position is that, for the purposes of license renewal, the specified offsite power recovery path elements should be included in the scope of license
 
renewal. In RAI 2.5-1, dated October 24, 2007, the staff conveyed its position that both paths
 
from the safety-related 480 V buses to the first circuit breaker from the offsite line used to
 
control the offsite circuits to the plant should be included within the scope of license renewal.
 
Therefore, the staff requested that the applicant provide a detailed explanation of which high
 
voltage breakers and other components in the switchyard will be connected from the startup
 
transformers up to the offsite power system for the purpose of SBO recovery.
In its response, dated November 16, 2007, the applicant stated that the Buchanan substation, which includes the 345 kV, 138 kV, and 13.8 kV sections, provides for the interconnection of
 
multiple sources of power and constitutes the offsite power source for IP2 and IP3.
In the LRA, Figure 2.5-2, IP2 Offsite Power Scoping Diagram, shows the IP2 primary offsite power source, the 6.9 kV source from the station auxiliary transformer which is connected to the
 
138 kV Buchanan substation through circuit breaker F2. The applicants November 16, 2007
 
response revised the scoping boundary for both offsite power sources for IP2. First, the station
 
auxiliary transformer is connected to the 138 kV Buchanan substation via switchyard bus, overhead transmission conductors, and underground transmission conductors through motor-
 
operated disconnect F3A (primary path). The staff determined that this change to a motor-
 
operated disconnect is not consistent with the staff guidance and, therefore, is unacceptable.
 
Secondly, the November 16, 2007 response delineated the secondary offsite power source (alternate path). The gas turbine (GT) autotransformer is connected to the 13.8 kV Buchanan
 
substation via underground medium voltage cable through 13.8 kV circuit breaker F2-3.
LRA Figure 2.5-3, IP3 Offsite Power Scoping Diagram, was modified in the applicants November 16, 2007, response to add the secondary offsite power feeder, indicating that the 6.9
 
kV buses receive power from two independent sources: the 138 kV/6.9 kV station auxiliary
 
transformer and the 13.8 kV/6.9 kV GT autotransformer. The station auxiliary transformer is
 
connected to the 138 kV Buchanan substation via switchyard bus and overhead transmission
 
conductors through circuit breaker BT2-6, and the GT autotransformer is connected to the 13.8
 
kV Buchanan substation via underground medium voltage cable through 13.8 kV circuit breaker
 
F3-1.During a telephone conference, documented in a conference call summary dated December 4, 2007, the staff requested that Entergy explain its response to RAI 2.5-1 with 2-224 regard to why the connection point for offsite power (for the purpose of station blackout recovery) changed from circuit breaker F2 to a motor-operated disconnect for IP2. The staff
 
informed the applicant that this change is not consistent with the staffs guidance and, therefore, is unacceptable.
In a letter dated March 24, 2008, the applicant modified its scoping boundary for the primary offsite power path for IP2, as shown in modified Figure 2.5-2, IP2 Offsite Power Scoping
 
Diagram. The station auxiliary transformer is connected to the 138 kV Buchanan substation via
 
switchyard bus, overhead transmission conductors, and underground transmission conductors
 
through switchyard breakers F2 and BT 3-4. The change from motor-operated disconnects to
 
138 kV circuit breakers addresses the staffs concern for the scoping boundary for the primary
 
offsite power path and provides closure for Open Item 2.5-1.
By letter dated May 20, 2009, the staff requested that the applicant explain why the secondary offsite circuit (the delayed access circuit) path, from the first inter-tie with the offsite distribution systems at the Buchanan substations to the safety buses, was not included in the scope of
 
license renewal.
By letter dated June 12, 2009, the applicant stated that the components up to and including either the 138 kV circuit breaker F1 or 345 kV circuit breaker F7 for IP2, and either the 138 kV
 
circuit breaker F3 or 345 kV circuit breaker F7 for IP3 were not included in the scope of license
 
renewal because they do not meet the scoping criteria specified in 10 CFR 54.4. The staff finds
 
the response acceptable as it is in accordance with the IP2 and IP3 current licensing basis and
 
applicable regulatory requirements. This closes Open Item 2.5-1.
The applicant did not specifically exclude the associated control circuits and structures for the circuit breakers and thus, it was unclear if these components are included in the scope of
 
license renewal. In RAI 2.5-5, the staff requested that the applicant confirm whether the
 
associated control cables and structures for the circuit breakers have been included in the
 
scope of license renewal. In letter dated August 14, 2008, the applicant clarified its response to
 
RAI 2.5-1 and confirmed that the associated control cables and structures for the circuit
 
breakers have been included in the scope of license renewal. Therefore, the staff finds the
 
response acceptable.
In RAI 2.5-2, dated October 24, 2007, the staff requested the applicant to clarify why elements such as resistance temperature detectors (RTDs), sensors, thermocouples, and transducers are
 
not included in the list of components and/or commodity groups subject to an AMR if a pressure
 
boundary is applicable. In its response, dated November 16, 2007, the applicant stated that
 
RTDs, sensors, thermocouples, and transducers associated with the pressure boundary are
 
evaluated in mechanical systems. Examples are thermowells and flow elements. LRA Section
 
2.1.2.3.1 states that the pressure boundary function that may be associated with some electrical
 
and I&C components was considered in the mechanical aging management reviews. The staff
 
verified through a sampling of mechanical systems that the applicant had scoped and screened
 
the passive mechanical components (e.g., thermowells and flow elements) associated with the
 
electrical elements in question. Therefore, the staff finds the response acceptable.
In RAI 2.5-3, dated October 24, 2007, the staff requested clarification as to why Section 2.5 of the LRA did not include splices, terminal blocks, control cables, and isolated-phase bus in the
 
commodity group of cables & connections, bus, electrical portions of electrical and I&C
 
penetration assemblies. In its response, dated November 16, 2007, the applicant stated that 2-225 electrical splices, terminal blocks, and control cables were included in the commodity group electrical cables and connections not subject to 10 CFR 50.49 EQ requirements. Thus, these
 
components are subject to an aging management review. The isolated-phase bus is not subject
 
to an AMR because it does not perform an intended function. Since the applicant clarified that
 
the electrical splices, terminal blocks, and control cables are subject to an AMR, the staff finds
 
the response acceptable.
2.5.1.3  Conclusion The staff reviewed the LRA, UFSAR, and RAI responses to determine whether the applicant failed to identify any SSCs within the scope of license renewal. In addition, the staff sought to
 
determine whether the applicant failed to identify any components subject to an AMR. The staff
 
found no such omissions. On the basis of its review, the staff concludes that the applicant has
 
adequately identified the electrical and I&C component commodity groups components within
 
the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
 
===2.6 Conclusion===
for Scoping and Screening The staff reviewed the information in LRA Section 2, Scoping and Screening Methodology for
 
Identifying Structures and Components Subject to Aging Management Review and
 
Implementation Results and determines that the applicant's scoping and screening
 
methodology is consistent with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a)(1),
except as noted above. Accordingly, the staff concludes that the applicant has adequately
 
identified those systems and components within the scope of license renewal, as required by
 
10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
With regard to these matters, the staff concludes that reasonable assurance exists that the activities authorized by the renewed licenses will continue to be conducted in accordance with
 
the CLB and that any changes made to the CLB, in order to comply with 10 CFR 54.29(a), are
 
in accordance with the Atomic Energy Act of 1954, as amended, and NRC regulations.
3-1 SECTION 3 AGING MANAGEMENT REVIEW RESULTS This section of the safety evaluation report (SER) evaluates aging management programs (AMPs) and aging management reviews (AMRs) for Indian Point Nuclear Generating Unit Nos.
 
2 and 3 (IP2 and IP3), by the staff of the U.S. Nuclear Regulatory Commission (NRC) (the staff).
 
In license renewal application (LRA), Appendix B, Entergy Nuclear Operations, Inc. (Entergy or
 
the applicant) described the 41 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 referenced NUREG-1801, Revision 1, Generic Aging
 
Lessons Learned (GALL) Report (the GALL Report), dated September 2005. The GALL Report
 
contains the staffs 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 structures and
 
components (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 is split into two volumes. Volume 1 summarizes the aging management reviews that are discussed in Volume 2. Volume 2 lists generic aging management reviews (AMRs) of SSC that may be in the scope of License Renewal Applications (LRAs) and identifies GALL AMPs that are acceptable to manage the listed aging effects. Revision 1 of the GALL Report incorporates changes based on experience gained from numerous NRC staff reviews of LRAs and other insights identified by stakeholders.
The GALL Report identifies: (1) systems, structures, and components (SSCs), (2) SC materials, (3) environments to which the SCs are exposed, (4) the aging effects of the materials and
 
environments, (5) the AMPs credited with managing or monitoring the aging effects, and (6) 3-2 recommendations for further applicant evaluations of aging management for certain component types.NUREG-1800, Revision 1, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants (SRP-LR), dated September 2005, was prepared based on both the
 
GALL Report model and lessons learned from the demonstration project.
If an LRA references the GALL Report as the approach used to manage aging effects, the NRC staff will use the GALL Report as a basis for the LRA assessment consistent with
 
guidance specified in the SRP-LR.
The staffs review was in accordance with Title 10, Part 54, of the Code of Federal Regulations (10 CFR Part 54), Requirements for Renewal of Operating Licenses for Nuclear Power Plants,
 
and the guidance of the SRP-LR and the GALL Report.
In addition to its review of the LRA, the staff conducted an onsite audit of selected AMPs and AMRs, during the weeks of August 26, 2007 and October 22, 2007, November 27 - 29, 2007, and February 19 - 22, 2008. The onsite audits and reviews are designed for maximum
 
efficiency of the staffs LRA review. The applicant can respond to questions, the staff can readily
 
evaluate the applicants responses, the need for formal correspondence between the staff and
 
the applicant is reduced, and the result is an improvement in review efficiency. 3.0.1  Format of the License Renewal Application The applicant submitted an application that follows the standard LRA format. This standard format was agreed to by the staff and the Nuclear Energy Institute (NEI) in a letter dated April 7, 2003. The revised LRA format incorporates lessons learned from the staffs reviews of the
 
previous five LRAs, which used a format developed from information gained during a staff-NEI
 
demonstration project conducted to evaluate the use of the GALL Report in the LRA review
 
process.The organization of LRA Section 3 parallels that of SRP-LR Chapter 3. LRA Section 3 presents AMR results information in the following two table types:    (1) Table 1s: Table 3.x.1 - where 3 indicates the LRA section number, x indicates the subsection number from the GALL Report, and 1 indicates that this table type is the
 
first in LRA Section 3.    (2) Table 2s: Table 3.x.2-y - where 3 indicates the LRA section number, x indicates the subsection number from the GALL Report, 2 indicates that this table type is the second
 
in LRA Section 3, and y indicates the system table number.
The content of the previous LRAs and of the Entergy application is essentially the same. The intent of the revised format of the Entergy LRA was to modify the tables in LRA Section 3 to
 
provide additional information that would assist in the staffs review. In its Table 1s, the
 
applicant summarized the portions of the application that it considered to be consistent with the
 
GALL Report. In its Table 2s, the applicant identified the linkage between the scoping and
 
screening results in LRA Section 2 and the AMRs in LRA Section 3.
3-3 3.0.1.1  Overview of Table 1's Each Table 1 compares in summary, how the facility aligns with the corresponding tables in the GALL Report. The tables are essentially the same as Tables 1 through 6 in the GALL Report, except that the Type column has been replaced by an Item Number column and the Item
 
Number in GALL column has been replaced by a Discussion column. The Item Number
 
column is a means for the staff reviewer to cross-reference Table 2s with Table 1s. In the Discussion column the applicant provided clarifying information. The following are examples of
 
information that might be contained within this column:  further evaluation recommended - information or reference to where that information is located the name of a plant-specific program  exceptions to GALL Report assumptions  discussion of how the line is consistent with the corresponding line item in the GALL
 
Report when the consistency may not be obvious  discussion of how the item is different from the corresponding line item in the GALL
 
Report (e.g., when an exception is taken to a GALL 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 2's 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 (RCS), engineered safety
 
features (ESF), auxiliary systems, etc.). For example, the ESF group has tables specific to the containment spray (CS) system, containment isolation (CI) system, and emergency core cooling
 
system (ECCS). 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 environments are indicated with a list of these
 
environments in LRA Tables 3.0-1, 3.0-2, and 3.0-3. Aging Effect Requiring Management - The fifth column lists aging effects requiring
 
management (AERMs). As part of the AMR process, the applicant determined any
 
AERMs for each combination of material and environment. Aging Management Programs - The sixth column lists the AMPs that the applicant uses
 
to manage the identified aging effects.
3-4 NUREG-1801 Vol. 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. 3.0.2  Staff's Review Process The staff conducted three types of evaluations of the AMRs and AMPs:    (1) For items that the applicant stated as consistent with the GALL Report, the staff conducted either an audit or a technical review to determine consistency.    (2) For items that the applicant stated as 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 applicants 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.
In some cases, an applicant may choose an existing plant program that does not meet all of the ten 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. 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 compliance with 10 CFR 54.21(a)(3).
Staff audits and technical reviews of the applicants AMPs and AMRs determine whether the effects of aging on SCs will be adequately managed so that the intended function will be
 
maintained consistent with the plants current licensing basis (CLB) for the period of extended
 
operation, as required by 10 CFR Part 54.21.
3-5 3.0.2.1  Review of Programs For programs for which the applicant claimed consistency with the GALL AMPs, the staff conducted either an audit or a technical review to verify the claim. For each program with one or
 
more deviations, the staff evaluated each deviation to determine whether the deviation was
 
acceptable and whether the modified program would adequately manage the aging effect(s) for
 
which it was credited. For programs not evaluated in the GALL Report, the staff performed a full
 
review to determine their adequacy. The staff evaluated the programs against the following 10
 
program elements defined in SRP-LR Appendix A. (1) Scope of the Program - Scope of the program should include the specific SCs subject to an AMR for license renewal. (2) Preventive Actions - Preventive actions should prevent or mitigate aging degradation.
(3) Parameters Monitored or Inspected - Parameters monitored or inspected should be linked to the degradation of the particular structure or component intended function(s). (4) Detection of Aging Effects - Detection of aging effects should occur before there is a loss of structure or component intended function(s). This includes aspects such as
 
method or technique (i.e., visual, volumetric, surface inspection), frequency, sample
 
size, data collection, and timing of new/one-time inspections to ensure timely detection
 
of aging effects. (5) Monitoring and Trending - Monitoring and trending should provide predictability of the extent of degradation, as well as timely corrective or mitigative actions. (6) Acceptance Criteria - Acceptance criteria, against which the need for corrective action will be evaluated, should ensure that the structure or component intended functions 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 experience of the AMP, including past corrective actions resulting in program enhancements or additional programs, should provide
 
objective evidence to support the conclusion that the effects of aging will be adequately
 
managed so that the SC intended functions will be maintained during the period of
 
extended operation.
Details of the staffs audit evaluation of program elements (1) through (6) are documented in SER Section 3.0.3.
The staff reviewed the applicants quality assurance (QA) program and documented its evaluations in SER Section 3.0.4. The staffs evaluation of the QA program included
 
assessment of program elements (7) corrective actions, (8) confirmation process, and (9)
 
administrative controls.
The staff reviewed the information on program element (10) operating experience, and 3-6 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 Vol. 2 Item,
 
correlate to an AMR combination as identified in the GALL Report. The staff also conducted
 
onsite audits to verify these correlations. A blank in column seven indicates that the applicant
 
was unable to identify an appropriate correlation in the GALL Report. The staff also conducted a
 
technical review of combinations not consistent with the GALL Report. The next column, Table 1 Item, refers to a number indicating the correlating row in Table 1.
3.0.2.3  UFSAR Supplement Consistent with the SRP-LR for the AMRs and AMPs that it reviewed, the staff also reviewed the UFSAR supplement, which summarizes the applicants programs and activities for
 
managing aging effects for the period of extended operation, as required by 10 CFR 54.21(d).
3.0.2.4  Documentation and Documents Reviewed In its review, the staff used the LRA, LRA supplements, the SRP-LR, and the GALL Report.
During the onsite audits, the staff also examined the applicants justifications to verify that the applicants activities and programs will adequately manage the effects of aging on SCs. The
 
staff also conducted detailed discussions and interviews with the applicants license renewal
 
project personnel and others with technical expertise relevant to aging management. The staff's
 
audit activities are documented in the Audit Report (ADAMS Accession No. ML083540662).
 
====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 systems or structures that credit the AMPs and the
 
GALL AMP with which the applicant claimed consistency and shows the section of this SER in
 
which the staffs evaluation of the program is documented.
3-7 Table 3.0.3-1  IP2 and IP3 Aging Management ProgramsAMP (LRA Section)New or Existing AMPGALL Report ComparisonGALL Report AMPsLRA Systems or Structures That Credit the AMP Staff's SER Section Aboveground Steel Tanks Program (B.1.1)Existing Consistent with enhancementsXI.M29 auxiliary systems / steam and power conversion systems 3.0.3.2.1Bolting Integrity Program (B.1.2)Existing Consistent with enhancementXI.M18 reactor vessel, internals and reactor coolant system / engineered safety features systems / auxiliary systems /
steam and power conversion systems  3.0.3.2.2 Boraflex Monitoring Program (B.1.3)Existing Consistent with exceptionsXI.M22 auxiliary systems  3.0.3.2.3 Boral Surveillance Program (B.1.4)Existing Plant-specific  auxiliary systems  3.0.3.3.1 Boric Acid Corrosion Prevention Program (B.1.5)Existing Consistent XI.M10 reactor vessel, internals and reactor coolant system / engineered safety features systems / auxiliary systems /
 
structures and component
 
supports / electrical and instrumentation and controls 3.0.3.1.1 Buried Piping and Tanks Inspection
 
Program (B.1.6)New Consistent XI.M34 engineered safety features systems / auxiliary systems / steam and power conversion systems  3.0.3.1.2 Containment Leak Rate Program (B.1.7)Existing Consistent XI.S4 structures and component supports 3.0.3.1.3 Containment Inservice Inspection Program (B.1.8)Existing Plant-specific  structures and component supports 3.0.3.3.2 Diesel Fuel Monitoring Program (B.1.9)Existing Consistent with exceptions and enhancementsXI.M30 auxiliary systems  3.0.3.2.4 Environmental Qualification of Electric Components Program (B.1.10)Existing Consistent X.E1 electrical and instrumentation and controls 3.0.3.1.4 3-8AMP (LRA Section)New or Existing AMPGALL Report ComparisonGALL Report AMPsLRA Systems or Structures That Credit the AMP Staff's SER Section External Surfaces Monitoring Program (B.1.11)Existing Consistent with enhancementXI.M36 reactor vessel, internals and reactor coolant system /
engineered safety features systems / auxiliary systems /
steam and power conversion systems  3.0.3.2.5 Fatigue Monitoring Program (B.1.12)Existing Consistent with exception and enhancementX.M1 reactor vessel, internals and reactor coolant system /
engineered safety features systems / auxiliary systems / steam and power conversion systems  3.0.3.2.6 Fire Protection Program (B.1.13)Existing Consistent with exception and enhancementsXI.M26 auxiliary systems / structures and component supports 3.0.3.2.7Fire Water System Program (B.1.14)Existing Consistent with exception and enhancementsXI.M27 auxiliary systems / structures and component supports 3.0.3.2.8Flow-Accelerated Corrosion Program (B.1.15)Existing Consistent with exceptionXI.M17 auxiliary systems / steam and power conversion systems 3.0.3.1.5Flux Thimble Tube Inspection Program (B.1.16)Existing Consistent with enhancementsXI.M37 reactor vessel, internals and reactor coolant system 3.0.3.2.9 Heat Exchanger Monitoring Program (B.1.17)Existing Plant-specific  engineered safety features systems / auxiliary systems 3.0.3.3.3 Inservice Inspection Program (B.1.18)Existing Plant-specific  reactor vessel, internals and reactor coolant system /
structures and component supports 3.0.3.3.4Masonry Wall Program (B.1.19)Existing Consistent with enhancementXI.S5 structures and component supports 3.0.3.2.10 Metal-Enclosed Bus Inspection Program (B.1.20)Existing Consistent with exceptions and enhancementsXI.E4 electrical and instrumentation and controls 3.0.3.2.11Nickel Alloy Inspection Program (B.1.21)Existing Plant-specific  reactor vessel, internals and reactor coolant system 3.0.3.3.5 Non-EQ Bolted Cable Connections Program (B.1.22)New Plant-specific  electrical and instrumentation and controls 3.0.3.3.6 3-9AMP (LRA Section)New or Existing AMPGALL Report ComparisonGALL Report AMPsLRA Systems or Structures That Credit the AMP Staff's SER Section Non-EQ Inaccessible Medium-Voltage Cable Program (B.1.23)New Consistent XI.E3 electrical and instrumentation and controls 3.0.3.1.6 Non-EQ InstrumentationCircuits Test Review Program (B.1.24)New Consistent XI.E2 electrical and instrumentation and controls 3.0.3.1.7 Non-EQ Insulated Cables and Connections Program (B.1.25)New Consistent XI.E1 electrical and instrumentation and controls 3.0.3.1.8Oil Analysis Program (B.1.26)Existing Consistent with exception and enhancementsXI.M39 engineered safety features systems / auxiliary systems / steam and power conversion systems  3.0.3.2.12One-Time Inspection Program (B.1.27)New Consistent XI.M32 engineered safety features systems / auxiliary systems / steam and power conversion systems  3.0.3.1.9One-Time Inspection - Small Bore Piping Program (B.1.28)New Consistent XI.M35 reactor vessel, internals and reactor coolant system 3.0.3.1.10 Periodic Surveillance and Preventive Maintenance Program (B.1.29)Existing Plant-specific  engineered safety features systems / auxiliary systems /
steam and power conversion systems / structures and component supports 3.0.3.3.7 Reactor Head Closure Studs Program (B.1.30)Existing Consistent XI.M3 reactor vessel, internals and reactor coolant system 3.0.3.1.11 Reactor Vessel Head Penetration Inspection Program (B.1.31)Existing Consistent XI.M11A reactor vessel, internals and reactor coolant system 3.0.3.1.12 Reactor Vessel Surveillance Program (B.1.32)Existing Consistent with enhancementXI.M31 reactor vessel, internals and reactor coolant system 3.0.3.2.13 Selective Leaching Program (B.1.33)New Consistent XI.M33 engineered safety features systems / auxiliary systems 3.0.3.1.13 Service Water Integrity Program (B.1.34)Existing Consistent XI.M20 auxiliary systems  3.0.3.1.14 3-10AMP (LRA Section)New or Existing AMPGALL Report ComparisonGALL Report AMPsLRA Systems or Structures That Credit the AMP Staff's SER Section Steam Generator Integrity Program (B.1.35)Existing Consistent with enhancementXI.M19 reactor vessel, internals and reactor coolant system 3.0.3.2.14 Structures Monitoring Program (B.1.36)Existing Consistent with enhancementsXI.S6 andXI.M23 structures and component supports 3.0.3.2.15Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program (B.1.37)New Consistent XI.M12 reactor vessel, internals and reactor coolant system 3.0.3.1.15Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless
 
Steel Program (B.1.38)New Consistent XI.M13 reactor vessel, internals and reactor coolant system 3.0.3.1.16Water Chemistry Control - Auxiliary Systems Program (B.1.39)Existing Plant-specific  engineered safety features systems / auxiliary systems 3.0.3.3.8Water Chemistry Control - Closed Cooling Water Program (B.1.40)Existing Consistent with exceptions and
 
enhancementsXI.M21 reactor vessel, internals and reactor coolant system /
engineered safety features systems / auxiliary systems 3.0.3.2.16Water Chemistry Control - Primary and Secondary Program (B.1.41)Existing Consistent with enhancementXI.M2 reactor vessel, internals and reactor coolant system / engineered safety features systems / auxiliary systems /
steam and power conversion systems / structures and component supports 3.0.3.2.17 3.0.3.1  Programs Consistent with the GALL Report In LRA Appendix B, the applicant described the following programs as consistent with the GALL Report: Boric Acid Corrosion Prevention Program  Buried Piping and Tanks Inspection Program  Containment Leak Rate Program  Environmental Qualification of Electric Components Program  Flow-Accelerated Corrosion Program  Non-EQ Inaccessible Medium-Voltage Cable Program  Non-EQ Instrumentation Circuits Test Review Program 3-11 Non-EQ Insulated Cables and Connections Program  One-Time Inspection Program  One-Time Inspection - Small Bore Piping Program  Reactor Head Closure Studs Program  Reactor Vessel Head Penetration Inspection Program  Selective Leaching Program  Service Water Integrity Program  Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program  Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program 3.0.3.1.1  Boric Acid Corrosion Prevention Program Summary of Technical Information in the Application. LRA Section B.1.5 describes the existing Boric Acid Corrosion Prevention Program as consistent with GALL AMP XI.M10, Boric Acid
 
Corrosion.
The Boric Acid Corrosion Prevention Program implements Generic Letter (GL) 88-05 recommendations to monitor the condition of components on which borated reactor water may
 
leak. The program detects boric acid leakage by periodic visual inspection of (a) systems
 
containing borated water for deposits of boric acid crystals and the presence of moisture and (b)
 
adjacent structures, components, and supports, for evidence of leakage. This program, which
 
manages loss of material and loss of circuit continuity, evaluates leakage discovered by other
 
activities. The applicant has made program improvements as suggested in NRC Regulatory
 
Issue Summary (RIS) 2003-013.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Boric Acid Corrosion Prevention Program and basis documents to verify consistency with GALL AMP XI.M10. Details of the staffs audit of the applicants AMP are
 
documented in the Audit Report (ADAMS Accession No. ML083540662). As documented in the
 
report, the staff found that elements (1) through (6) are consistent with the corresponding elements in GALL AMP XI.M10. Because these elements are consistent with the GALL Report
 
elements, the staff finds that they are acceptable.
Operating Experience. LRA Section B.1.5 states that inspections of the IP2 containment building in April 2005, November 2005, and May 2006 detected minor boron leakage. Also, a
 
March 2005 inspection detected boron leakage at IP3 reactor coolant boundary components
 
that may be subject to boric acid leakage and corrosion. The applicant stated that early
 
detection prevented boric acid wastage of affected components and adjacent structures and
 
components. It further stated that detection of degradation followed by corrective action prior to
 
loss of intended function has proven that the program effectively manages aging effects for
 
passive components.
LRA Section B.1.5 also states that the Boric Acid Corrosion Prevention Program was enhanced to include recommendations of the Westinghouse Owners Group Westinghouse Commercial
 
Atomic Power (WCAP)-15988-NP, Generic Guidance to Best Practice 88-05 Boric Acid
 
Inspection Program, Electric Power Research Institute (EPRI) Technical Report 1000975, Boric Acid Corrosion Guidebook, and NRC Bulletin 2003-02 Leakage from Reactor Coolant
 
Pressure Vessel Lower Head Penetrations and Reactor Coolant Pressure Boundary Integrity.
3-12 Ongoing program improvements, through incorporation of lessons learned from industry operating experience, assure continued effective management of aging effects for passive
 
components.
The applicant has reported leakage from Conoseals at both IP2 and IP3 but there was no measurable material degradation on the vessel head as a result of the boric acid leakage. The
 
applicant has stated that the most common cause of failure for bolts in the industry is boric acid
 
corrosion which is documented in EPRI Mechanical Tools (EPRI 1010639) and Non-Class 1
 
Mechanical Implementation guidelines.
During the audit and review of this AMP, the staff asked the applicant whether they had observed leakage from Conoseal flanges (Audit Item 109). By letter dated March 24, 2008, the
 
applicant stated that both IP2 and IP3 have experienced Conoseal leaks during the past few
 
operating cycles. At IP2, the most recent leak occurred at penetration #95, during the current
 
operating cycle. At IP3, the most recent leak was detected during the Spring 07 refueling
 
outage. The applicant stated that the Conoseals at IP2 and IP3 have been modified to minimize
 
the possibility of future leakage. All of the recent leaks have been eliminated with the exception
 
of the current leak at Penetration #95. The applicant stated that the boric acid was cleaned up
 
and the vessel head was examined for material degradation and that it did not detect any
 
degradation in the areas exposed to boric acid deposits.
The staff verified that the applicant had taken appropriate corrective actions to clean off the boric acid residues that developed on the IP2 and IP3 upper reactor vessel (RV) heads as a
 
result of Conoseal leakage. The staff also noted that applicants corrective actions included an
 
evaluation of the upper RV head wall thickness and that in the corrective actions documentation
 
the applicant had demonstrated that the Conoseal leakage did not result in any detectable boric
 
acid-induced wastage (i.e., loss of material degradation) in the upper RV closure heads. Based
 
on this review, the staff finds that the applicants program monitors for Conoseal leakage and
 
that the applicant takes appropriate corrective actions when Conoseal leakage is detected.
By letter dated May 7, 2008, in RAI RCS-1, the staff inquired about other operating experience (condition reports that had been issued on boric acid leakage of ASME Code Class 1
 
components). By letter dated June 5, 2008, the applicant stated, in part, that the routine
 
inspections of control rod drives, control rod drive mechanisms, resistance temperature devices, RV lower heads, RV bottom mounted instrumentation (BMI) nozzles, RV seal tables, RV fittings, and RV flux thimble tubes at IP2 and IP3 from 2001 - 2005 revealed indications of boric acid
 
leakage that could potentially lead to loss of material due to boric acid corrosion. The applicant
 
stated that it had taken appropriate corrective actions to correct the adverse conditions, including cleaning of the affected Class 1 areas to remove boric acid residues from the
 
components, replacing leaking gaskets, repair of leaking welds or components, and revisions to
 
the implementing procedures for foreign material (boric acid residue) control and for visual
 
inspections of the RVs. The applicant stated that the components, after boric acid residue
 
cleaning, were determined to be acceptable for further service.
The staff noted that the applicants response indicates that the applicants augmented Boric Acid Corrosion Prevention Program is achieving its function of monitoring and detecting
 
evidence of borated reactor coolant leakage from the applicants ASME Code Class 1 reactor
 
coolant pressure boundary components, and that the applicant is taking appropriate corrective
 
actions when borated reactor coolant leakage is detected as part of the applicants
 
implementation of the program.
3-13 Thus, the staff finds that the applicant has addressed relevant operating experience that is applicable to this AMP, and that, based on the applicants detection of boric acid residues and
 
corrective actions to correct adverse boric acid residue conditions, the applicant has
 
demonstrated that the program is effective and will be capable of detecting borated reactor
 
coolant leakage from ASME Code Class 1 reactor pressure boundary components and RV
 
Conoseals during the period of extended operation. RAI RCS-1 is resolved with respect to
 
operating experience that is relevant to this AMP.
Based on this review, the staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR
 
Section A.1.2.3.10. The staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.4 and A.3.1.4, the applicant provided the UFSAR supplement for the Boric Acid Corrosion Prevention Program. The staff reviewed these sections
 
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 applicants Boric Acid Corrosion Prevention Program, the staff finds that all program elements are consistent with the GALL
 
Report. The staff concludes that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended 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 program and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3.0.3.1.2  Buried Piping and Tanks Inspection Program
 
Summary of Technical Information in the Application. LRA Section B.1.6 describes the Buried Piping and Tanks Inspection Program as a new program that will be consistent with GALL AMP XI.M34, Buried Piping and Tanks Inspection.
The Buried Piping and Tanks Inspection Program includes (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining
 
capability of buried carbon steel, gray cast iron, and stainless steel components. Preventive
 
measures are in accordance with standard industry practice for maintaining external coatings
 
and wrappings. Buried components are inspected when excavated during maintenance. If
 
trending within the corrective action program finds susceptible locations, the areas with a history
 
of corrosion problems are evaluated for the need for additional inspection, alternate coating, or
 
replacement. The program applies to buried components in the following systems. safety injection  service water  fire protection  fuel oil  security generator  city water  plant drains  auxiliary feedwater  containment isolation support 3-14 Of these systems, only the safety injection system contains radioactive fluids during normal operations. Safety injection system buried components are stainless steel. This system uses
 
stainless steel for its corrosion resistance.
By letter dated July 27, 2009, as clarified by letter dated August 6, 2009, the applicant submitted an amendment to the LRA which modified the Buried Piping and Tanks Inspection Program.
 
This amendment was in response to recent operating history which involved a February 2009
 
leak on the return line to the condensate storage tank (CST) for Unit 2. As a result of this
 
operating experience, the applicant plans to include a risk assessment to classify in-scope
 
buried piping segments and buried tanks as high, medium, or low impact of leakage based on
 
the safety classification, the hazard posed by the fluids in the piping and tanks, and the impact
 
of leakage on reliable plant operation. The applicant will consider the piping or tank material of
 
construction, soil resistivity, drainage, the presence of cathodic protection, and the type of
 
coating for corrosion risk.
The applicants modification to the Buried Piping and Tanks Inspection Program significantly increases the number of inspections of buried piping and tanks. Rather than conduct one
 
inspection prior to entering the period of extended operation, consistent with the GALL Report
 
where site-specific operating experience is not a factor, the applicant will conduct 15 periodic
 
inspections for IP2 prior to entering the period of extended operation in 2013, and 30 periodic
 
inspections for IP3 prior to entering the period of extended operation in 2015. Also, because of
 
the recent leak in the CST return line, the applicant plans to conduct six additional inspections in
 
2009 at lower level elevations for the service water and auxiliary feedwater systems, based on a
 
determination that these locations have the highest risk of corrosion due to their proximity to the
 
water table.
The applicant stated that it will employ inspection methods with demonstrated effectiveness for detection of aging effects in buried components such as those currently being evaluated by the
 
Electric Power Research Institute. One example is guided wave ultrasonic testing (UT). The
 
applicant further stated that it is actively participating in the industry group established to
 
address issues with degradation of buried components.
With respect to inspections to be performed during the period of extended operation, the applicant stated that the number of inspections and inspection frequency will be based on the
 
results of the planned inspections prior to the period of extended operation, other applicable
 
industry and plant-specific operating experience, and its risk assessment.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements and basis documents of the Buried Piping and Tanks Inspection Program to verify consistency with GALL AMP XI.M34. Details of the staffs audit of the applicants AMP are
 
documented in the Audit Report. As documented in the report, the staff found that elements (1) through (6) are consistent with the corresponding elements in GALL AMP XI.M34. Because
 
these elements are consistent with the GALL Report elements, the staff finds that they are
 
acceptable.
During the audit, the staff asked the applicant if any buried tanks are in scope for license renewal (Audit Item 110). By letter dated March 24, 2008, the applicant stated that the following
 
tanks are buried and in scope for license renewal and are included in the Buried Piping and 3-15 Tanks Inspection Program:  IP2 Fuel Oil Storage Tanks (21/22/23 FOST)  GT1 Fuel Oil Storage North and South Storage Tanks  IP2 Security Diesel Fuel Tank  IP3 Appendix R Fuel Oil Storage Tank (EDG-33-FO-STNK)  IP3 Security Propane Fuel Tanks (2 of them)  IP3 Fuel Oil Storage tanks (EDG-31/32/33-FO-STNK).
The applicants discovery of a leak in the CST return line was documented in NRC Inspection Report 05000247/2009002, dated May 14, 2009. As a result of this leak, the applicant revised
 
its Buried Piping and Tanks Inspection Program, in a letter dated July 27, 2009, as clarified by
 
letter dated August 6, 2009. The staff reviewed the revised program to assure acceptability of
 
the revised inspection plans. The staff found that the applicants enhanced inspection plans
 
provide a significant increase in the number of locations to be examined prior to the period of
 
extended operation, from one per unit to a combined total of 51 inspections for the two units.
 
These inspections will focus on the buried piping and tanks that are within the scope of the
 
Buried Piping and Tanks Inspection Program. The applicant plans to prioritize the inspection
 
locations based on a risk assessment that identifies high, medium and low impact of leakage at
 
that location based on the safety classification, the hazard posed by the fluid, the potential
 
impact of leakage on reliable plant operation, and the corrosion risk of the location. As
 
described by the applicant, the corrosion risk appears to consider those parameters that will
 
reasonably characterize the corrosion likelihood for the location. Overall, the staff finds that this
 
approach for determining the specific locations for inspection and the large increase in the
 
number of locations to be inspected provide a significant enhancement in the program prior to
 
entering the period of extended operation, beyond that described in the GALL Report. The staff
 
finds that the scope of this enhancement is reasonable in light of the recent operating
 
experience at IP.
In its letter of July 27, 2009, as clarified by letter dated August 6, 2009, the applicant stated that additional periodic inspections will be conducted during the first 10 years of the period of
 
extended operation. The applicant further stated that the frequency and number of these
 
periodic inspections will be determined based on the results of the inspections that will be
 
conducted and completed prior to entering the period of extended operation, in addition to the
 
risk assessment of the piping segments and tanks. The staff finds that the applicants
 
commitment to consider the results of the inspections conducted prior to the period of extended
 
operation in its subsequent inspection program is reasonable.
The use of inspection methods with demonstrated effectiveness for detection of aging effects, as proposed by the applicant for inspections both prior to and during the period of extended
 
operation, provides reasonable assurance of the effectiveness of the technique. Specifically, the
 
technique is to be evaluated by a third party, the EPRI NDE Center, and would be demonstrated
 
to be capable of detecting degradation (e.g., cracks, corrosion) in samples that are similar to the
 
configuration and types of degradation that may be present at the IP site. The staff finds the use
 
of inspection methods with demonstrated effectiveness to be an acceptable and appropriate
 
aspect of this program.
The staff finds that with the numerous enhancements to the GALL Buried Piping and Tanks Inspection Program, the applicants program is acceptable. The applicant has significantly
 
increased the number of inspections of buried piping beyond that which is recommended in the 3-16 GALL Report AMP prior to entering the period of extended operation. In addition, the applicants commitment to perform additional periodic inspections using inspection methods with
 
demonstrated effectiveness during the first 10 years of the period of extended operation, with
 
the frequency and priority of inspections to be determined based on operating experience and
 
risk assessment of the piping segments and tanks, provides reasonable assurance that the
 
applicant will be able to adequately manage the effects of aging of its buried piping and tanks
 
during the period of extended operation.
Operating Experience. LRA Section B.1.6 states that the Buried Piping and Tanks Inspection Program is a new program. When implementing this new program the applicant will consider as
 
its basis industry operating experience in the operating experience element of the GALL Report
 
program description. IP plant-specific operating experience is consistent with the operating
 
experience in the GALL Report program description.
The applicant stated that the IP program is based on the GALL Report program description, which in turn is based on industry operating experience, assurance that the Buried Piping and
 
Tanks Inspection Program will manage the effects of aging so components continue to perform
 
intended functions consistent with the CLB through the period of extended operation. In Audit Item 110, the staff asked the applicant ifIP2 or IP3 had to replace any buried piping or had to replace or repair any sections of buried pipe. In its response, dated March 24, 2008, the
 
applicant stated that a review of site condition reports back to 2000 revealed that there have
 
been two underground piping leaks that occurred on the auxiliary steam supply cross connect
 
line between Unit 2 and Unit 3. This piping is nonsafety-related and is not within the scope of
 
license renewal. The first leak occurred in 2002 and a condition report was written for this leak.
 
The leak was repaired via the work control process. The applicant further stated that a second
 
leak occurred in April 2007 and was documented in a condition report. This line has been
 
excavated and replaced. The cause of the failure was determined to be advanced corrosion of
 
the pipe due to moisture intrusion. This was caused by the pipe coating breaking down and
 
insulation that was not sufficient for the task. After replacement, the pipe was reinsulated using
 
a special high temperature moisture resistant material that was designed to prevent this type of
 
corrosion in the future. The applicant stated that no other buried piping repair or replacement
 
was identified during its review of operating experience.
By letter dated July 27, 2009, as clarified by letter dated August 6, 2009, the applicant identified additional operating experience concerning coating degradation identified during the fall of
 
2008, and a February 2009 leak on the return line to the CST on Unit 2.
During the fall of 2008, the applicant performed inspections of three 10-foot sections of Unit 2 CST piping and found damaged coating and two locations with minor coating defects. The
 
damaged coating was repaired. Ultrasonic testing measurements confirmed that the pipe
 
thickness remained at nominal thickness, within the manufacturers tolerance.
In February 2009, the applicant identified a leak in the IP2 return line to the CST. The applicant stated that there was no safety significance to the leak because there was sufficient inventory
 
for the CST to perform its intended function. The applicant stated that the leak occurred as a
 
result of damage to the coating on the pipe, which it concluded occurred during original
 
construction. In particular, the applicant concluded that the damage occurred because the
 
construction installation specification did not specify the type of backfill for covering the pipe, permitting rocks in the backfill. The location of the leak was close to the water table, and 3-17 moisture in the soil may have contributed to the damage. The applicant replaced the section of pipe containing the leak and repaired several additional thinned areas on the pipe. The affected
 
areas were recoated and the applicant used improved backfill specifications to cover the pipe.
 
The staff at headquarters coordinated with NRC Region I inspectors who followed up on the
 
licensees corrective actions on site.
Based on its review, the staff concludes that the applicant has appropriately considered operating experience for the Buried Piping and Tanks Inspection Program. Further, the staff
 
concludes that the applicants 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 to be acceptable.
UFSAR Supplement. In LRA Sections A.2.1.5 and A.3.1.5, the applicant provided the UFSAR supplement for the Buried Piping and Tanks Inspection Program. The applicant committed to
 
implement the Buried Piping and Tanks Inspection Program prior to the period of extended
 
operation. The applicant further stated that this new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.M34, Buried Piping and
 
Tanks Inspection (Commitment 3). By letter dated July 27, 2009, as clarified by letter dated
 
August 6, 2009, the applicant modified Commitment 3 to include a risk assessment of in-scope
 
buried piping and tanks that includes consideration of the impacts of buried piping or tank
 
leakage and of conditions affecting the risk for corrosion. The applicant changed the inspections
 
from opportunistic to periodic, and committed to establish the inspection priority and frequency
 
based, in part, on the results from its planned inspections prior to entering the period of
 
extended operation and other applicable industry and plant-specific operating experience.
 
Further, the applicant committed to perform inspections using inspection methods with
 
demonstrated effectiveness. The applicant also modified LRA Sections A.2.1.5, A.3.1.5, and
 
B.1.6 to incorporate the changes to the Buried Piping and Tanks Inspection Program.
The staff reviewed these sections, as revised, and determines that the information provided in the UFSAR supplement is an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
By letter dated July 27, 2009, as clarified by letter dated August 6, 2009, the applicant added a new commitment (Commitment 40) that states that plant specific and appropriate industry
 
operating experience will be evaluated and lessons learned will be used to establish appropriate
 
monitoring and inspection frequencies to assess aging effects for the new aging management
 
programs.Conclusion. On the basis of its audit and review of the applicants Buried Piping and Tanks Inspection Program, the staff finds that all program elements are consistent with the GALL
 
Report. The staff concludes that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended 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 program and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3.0.3.1.3 Containment Leak Rate Program
 
Summary of Technical Information in the Application. LRA Section B.1.7 describes the existing Containment Leak Rate Program as consistent with GALL AMP XI.S4, 10 CFR 50, 3-18 Appendix J.
The applicant states that the Containment Leak Rate Program, as described in 10 CFR Part 50, Appendix J, requires containment leak rate tests to assure that (a) leakage through primary
 
reactor containment, and systems and components penetrating primary containment shall not
 
exceed allowable values specified in technical specifications or their bases and (b) periodic
 
surveillance of reactor containment penetrations and isolation valves is performed so that
 
proper maintenance and repairs are made during the service life of containment, and systems
 
and components penetrating containment. The applicant furthers states that the IP2 and IP3
 
program utilizes 10 CFR 50 Appendix J, Option B, and the guidance in RG 1.163, and the
 
recommendations in NEI 94-01.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Containment Leak Rate Program and basis documents to verify consistency with GALL AMP XI.S4. Details of the staffs audit of the applicants AMP are
 
documented in the Audit Report. As documented in the report, the staff found that elements (1) through (6) are consistent with the corresponding elements in GALL AMP XI.S4. Because these
 
elements are consistent with the GALL Report elements, the staff finds that they are acceptable.
Operating Experience. LRA Section B.1.7 states that in 2006 (Unit 2 refueling outage 17, 2R17), containment leak rate testing at IP2 was completed successfully. The applicant states that a QA
 
surveillance of the containment leak rate test found only administrative deficiencies in the
 
procedures for calculating total leakage. Results from the 2005 (Unit 3 refueling outage 13, 3R13) IP3 containment leak rate testing were satisfactory. Confirmation of containment integrity, along with detection and resolution of program discrepancies, assure effective program
 
management of loss of component material.
The applicant also states that an industry benchmarking for this program in 2004 found areas for improvement and implemented corrective actions. A 2003 self-assessment of the program
 
focused on differences between the IP2 and IP3 program procedures and took actions that led
 
to several improvements.
The applicant concluded that its program is consistent with the GALL Report, Option B program, stating that review of operating history, corrective actions, and self-assessments shows the
 
Containment Leak Rate Program is monitored and enhanced continually to incorporate
 
operating experience and is effective in ensuring the structural integrity and leak tightness of the
 
IP2 and IP3 containments.
During an onsite audit, the staff reviewed the program basis documents discussion of operating experience, which summarize the operating experience of the Containment Leakage Rate
 
Program, as well as the results of past leakage rate tests of the containment at IP2 and IP3. In
 
addition, the documents describe other industry benchmarking and focused self-assessment of
 
the Containment Leakage Rate Program.
The staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable.
3-19 UFSAR Supplement. In LRA Sections A.2.1.6 and A.3.1.6, the applicant provided the UFSAR supplement for the Containment Leak Rate Program. The staff reviewed these sections 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 applicants Containment Leak Rate Program, the staff finds that all program elements are consistent with the GALL Report. The
 
staff concludes that the applicant has demonstrated that the effects of aging will be adequately
 
managed so that the intended 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 program and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.1.4  Environmental Qualification of Electric Components Program
 
Summary of Technical Information in the Application. LRA Section B.1.10 describes the existing Environmental Qualification of Electric Components Program as consistent with the GALL Report AMP X.E1, Environmental Qualification (EQ) of Electric Components.
The applicant stated that the Environmental Qualification of Electric Component Program is an existing program. The NRC has established nuclear station EQ requirements in 10 CFR Part 50, Appendix A, Criterion 4, and 10 CFR 50.49. 10 CFR 50.49 specifically requires that an EQ
 
program be established to demonstrate that certain electric components located in harsh
 
environments (that is, those areas of plant that could be subject to the harsh environmental
 
effects of a loss of coolant accident (LOCA), high energy line breaks (HELBs) or high radiation)
 
are qualified to perform their safety function in those harsh environments. 10 CFR 50.49
 
requires that the effects of significant aging mechanisms be addressed as part of EQ. The
 
applicant further stated that the IP EQ program manages the effects of thermal, radiation, and
 
cyclic aging through the use of aging evaluations based on 10 CFR 50.49(f) qualification
 
methods. As required by 10 CFR 50.49, EQ components are refurbished, replaced, or their
 
qualification is extended prior to reaching the aging limits established in the evaluation. Aging
 
evaluations for EQ components are TLAAs for license renewal.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Environmental Qualification of Electric Components Program and basis documents to verify consistency with the GALL Report AMP X.E1. Details of the staffs
 
audit of the applicants AMP are documented in the Audit Report. As documented in the report, the staff found that elements (1) through (6) are consistent with the corresponding elements in the GALL Report AMP X.E1. Because these elements are consistent with the GALL Report
 
elements, the staff finds that they are acceptable.
Operating Experience. LRA Section B.1.10 states that in August 2001, the applicant identified incorrect inputs in the EQ analyses. As part of its corrective actions, the applicant stated that it
 
updated calculations and evaluated other program documents and environmental conditions.
 
The applicant also stated that, in July 2002, a QA audit of the program found differences
 
between the analytical tools for high-energy line break analyses at IP2 and IP3. As part of
 
corrective actions, the applicant developed revised pressure-temperature (P-T) profiles and
 
thermal lag evaluations for specific equipment and revised the EQ program plan and supporting
 
calculations. The applicant further stated that a focused self-assessment in 2002 found that 3-20 program procurement and work control processes complied with 10 CFR 50.49 and that in February 2003, the EQ program was reviewed to determine the impact of the IP2 power uprate.
 
Those EQ files which required update were revised. In 2003-2004, an EQ master list validation
 
project led to wiring diagram reviews and master list updates.
The staff interviewed the applicant's technical staff and reviewed the program basis documents.
During the discussion of the EQ program with the applicant, the staff requested the applicant to
 
provide additional operating experience (OE) associated with the EQ program (Audit Item 160).
 
In a letter dated March 24, 2008, the applicant stated that in January 2006, during an EQ
 
program enhancement project, it discovered that an EQ file did not identify or address
 
qualification of pigtail extension cables. A condition report (CR) was initiated to capture EQ
 
documentation deficiency. The EQ program enhancement project was initiated to correct this
 
type of discrepancy and test reports were obtained and evaluated. The applicable test report
 
met the applicants environmental parameter requirements; therefore, these cables were
 
considered qualified.
The applicant further stated that it participates in several industry-based working and assessment groups, to ensure that the IP2 and IP3 EQ program stays current with the industry
 
and that the industry OE is addressed. The industry groups are comprised of utility operators
 
worldwide, the majority of which are in the US and Canada. Participation in these organizations
 
also provides a source of regulatory and reference documents, component information, engineering analyses, and material data from many different manufacturers and utilities.
The staff finds that the operating experiences identified above and those identified in program basis documents demonstrate that identification of program weakness and timely corrective
 
actions as part of the EQ program provide assurance that program will remain effective in
 
assuring that equipment is maintained within its qualification basis and qualified life.
The staff confirmed that the operating experience program element meets the recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.9 and A.3.1.9, the applicant provided the UFSAR supplement for the Environmental Qualification of Electric Components Program. The staff
 
reviewed these sections 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 applicants Environmental Qualification of Electric Components Program, the staff finds that all program elements are consistent with the GALL Report AMP X.E1. 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 program and
 
concludes that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3-21 3.0.3.1.5  Flow-Accelerated Corrosion Program Summary of Technical Information in the Application. LRA Section B.1.15 describes the existing Flow-Accelerated Corrosion (FAC) Program as consistent with GALL AMP XI.M17, Flow-
 
Accelerated Corrosion.
The Flow-Accelerated Corrosion Program applies to safety-related and nonsafety-related carbon and low-alloy steel components in systems containing high-energy fluids which carry
 
two-phase or single-phase high-energy fluid for more than 2 percent of plant operating time. The
 
program, based on EPRI guidelines in Nuclear Safety Analysis Center (NSAC)-202L-R2,Recommendations for an Effective Flow-Accelerated Corrosion Program, (April 1999) for an effective Flow-Accelerated Corrosion program, predicts, detects, and
 
monitors flow-accelerated corrosion in plant piping and other pressure-retaining components.
 
This program includes (a) an evaluation to determine critical locations, (b) initial operational
 
inspections to determine the extent of thinning at these locations, and (c) follow-up inspections
 
to confirm predictions or to repair or replace components as necessary.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Flow-Accelerated Corrosion Program and basis documents to verify consistency with the GALL Report AMP XI.M17. Details of the staffs audit of the applicants
 
AMP are documented in the Audit Report. As documented in the report, the staff found that
 
elements (1) through (6) are consistent with the corresponding elements in the GALL Report AMP XI.M17. Because these elements are consistent with the GALL Report elements, the staff
 
finds that they are acceptable.
The staff reviewed the corrective actions program element for this AMP with respect to verifying whether repair/replacement activities for in-scope components involved replacement
 
with components using FAC-resistant materials. The staff reviews this aspect of the corrective
 
actions program element later in the evaluation of the applicant response to Part 2 of RAI
 
B.1.15-2.However, during its review of the applicants program, the staff identified the following aspects that needed additional clarification: (1) the scope of the applicants program, (2)
 
evaluation of the exception in the program to use EPRI Report NSAC-202L-R3, Recommendations for an Effective Flow-Accelerated Corrosion Program, (May 2006) as the implementation guideline document for the applicants program, (3) resolution of RAI B.1.15-1
 
on whether the AMRs in the LRA credit this program to manage loss of material due to flow-
 
accelerated corrosion for the carbon steel components in the steam generator (SG) blowdown
 
system, and (4) resolution of RAI B.1.15-2, Parts 1, 2, and 3, on how CHECWORKS modeling is
 
performed, how power uprate conditions are incorporated into this modeling, and on which in-
 
scope systems at IP2 and IP3 are considered as being the most susceptible to flow-accelerated
 
corrosion. The staff evaluates these aspects of the applicants program in the italicized
 
subsections that follow.
Clarification on the Scope of Program The NRC discussed the establishment and implementation of Flow-Accelerated Corrosion Programs in NRC Bulletin 87-01, Thinning of Pipe Walls in Nuclear Power Plants (July 9, 1987) and in Generic Letter (GL) 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning (May 3-22 2, 1989). The staff verified that the applicant responded to Bulletin 87-01 for IP2 in a letter dated September 11, 1987 (NRC Microfiche Address 42741, Pages 199-233) and for IP3 in a letter
 
dated September 15, 1987 (NRC Microfiche Address 42739, Pages 131-146). The staff verified
 
that the applicant responded to GL 89-08 for IP2 in a letter dated July 20, 1989 (NRC Microfiche
 
Address 50726, Pages 331-332) and for IP3 in a letter dated July 21, 1989 (NRC Microfiche
 
Address 50737, Pages 100-102). The staff verified that these responses were the docketed
 
documents that initially defined the systems that are within the scope of the applicants Flow
 
Accelerated Corrosion Programs for IP2 and IP3, and defined how the programs would be
 
implemented. The staff verified that the scope of the applicants Flow-Accelerated Corrosion
 
Program includes these generic communication responses. In the operating experience program element in GALL AMP XI.M17, Flow Accelerated Corrosion, the staff clearly identified that single-phase feedwater and condensate systems and
 
two-phase extraction steam, moisture separator reheater drain, and feedwater heater drain
 
systems are among the PWR plant systems that are the most susceptible to loss of material (erosion) by flow-accelerated corrosion. From its review of the applicants responses to Bulletin
 
87-01 and GL 89-08 for IP2 and IP3, the staff verified that the scope of the programs for IP2 and
 
IP3 includes those systems that contain carbon steel or alloy steel components that are exposed to high velocity, single-phase water-based flow environment or high velocity, two-
 
phase water-steam environments, and, as a minimum, the feedwater, condensate, extraction
 
steam, moisture separator reheater drain, and feedwater heater drain systems, as
 
recommended for inclusion in the AMP according to the operating experience and reference sections of GALL AMP XI.M17, Flow-Accelerated Corrosion. The staff also noted from the
 
applicants responses to these generic communications, that the programs developed in
 
response to Bulletin 87-01 and GL 89-08 includes the following additional systems:  Auxiliary feedwater systems (as indicated in the Bulletin 87-01 response for IP2 and the GL 89-08 response for IP3)  Steam generator (SG) blowdown systems (as indicated in the Bulletin 87-01 response
 
for IP2 and the GL 89-08 response for IP3)  Turbine generator cross-under piping, including pre-separators (as indicated in the
 
Bulletin 87-01 response for IP2)  Heater drain pump discharge piping (as indicated in the Bulletin 87-01 response for IP2)  Main steam system (as indicated in the GL 89-08 response for IP3)  Reheater drain system (as indicated in the GL 89-08 response for IP3)  Auxiliary Steam System (as indicated in the GL 89-08 response for IP3)
The staff finds that the inclusion of these additional systems within the scope of the applicants program is acceptable because it represents an additional scoping conservatism in the program
 
beyond the feedwater, condensate, extraction steam, moisture separator reheater drain, and
 
feedwater heater drain systems that were included in the program in response to the NRCs
 
safety-significant FAC-related generic communications that have been identified in operating experience program element of GALL AMP XI.M17.
Based on this review, the staff finds that the scope of program element for the Flow-Accelerated Corrosion Program is acceptable because: (1) the scope of the program includes the applicants
 
responses to Bulletin 87-01 and GL 89-08, (2) the scope of the program includes the feedwater, 3-23 condensate, extraction steam, moisture separator reheater drain, and feedwater heater drain systems, which are the plant systems that the staff has identified as being highly susceptible to
 
loss of material by flow-accelerated corrosion, (3) the scope of the program includes additional
 
plant systems that the applicant has also identified as being potentially susceptible to flow-
 
accelerated corrosion, and (4) the scope of the program is consistent with NRC-identified, industry-identified, IP2-specific, and IP3-specific operating experience.
Exception to use EPRI Report NSAC-202L-R3 The staff noted that in the scope of program and detection of aging effects program elements of GALL AMP XI.M17, Flow-Accelerated Corrosion, the staff recognizes EPRI Report NSAC-
 
202L-R2 as a suitable guidance document for implementing flow-accelerated corrosion
 
programs. The staff also noted that the applicant indicated that, instead of using Revision 2, Entergy is implementing Revision 3 for implementation of the applicants program, and that the
 
applicant did not identify this inconsistency as an exception to the scope of program and detection of aging effects program elements of GALL AMP XI.M17.
In Audit Item 156, the staff asked the applicant to justify its use of Revision 3, and why the use of the later version of the report was not indentified as an exception to the aging management
 
criteria that are given in the scope of program and detection of aging effects program elements of GALL AMP XI.M17. By letter dated December 18, 2007, the applicant stated that
 
the changes made from NSAC-202L-R2 to NSAC-202L-R3 basically accomplished the following
 
improvements in the report that made for better FAC-management guidance on the scope of
 
program and detection of aging effects program elements for the AMP: 1. scope of program - (1) administrative relocation of the guidance for system selection within the scope of the program, (2) reorganization of the guidance for selecting
 
components for inspection for those systems that are within the scope of the program, (3) enhancement of the guidance for component sample selection to provide clarification
 
and details on sample selection for both modeled piping lines and non-modeled piping
 
lines that are within the scope of the program, (4) addition of enhanced guidance for
 
using plant-specific and industry-generic operating experience as an additional basis for
 
selecting components for inspection, and (5) improved, enhanced guidance for sample
 
expansion upon detection of relevant FAC-induced indications. 2. detection of aging effects  - (1) additional clarification on the use of volumetric inspection techniques, including UT and radiographic testing (RT) for the detection of
 
loss of material as a result of FAC, (2) additional guidance for the inspection of in-scope
 
vessels and tanks, (3) enhancement of the inspection guidance for turbine cross-around
 
piping, valves, orifices and flow elements, and (4) additional guidance of the basis for
 
the use of RT as an volumetric technique for large bore piping.
The staff verified that the updated guidance in NSAC-202L-R3 did not change: (1) the guidelines basis for excluding components from examination based on their materials of
 
fabrication and material alloying contents, operational characteristics (for components not in
 
service or infrequently in service), the dissolved oxygen contents of the single-phase or two-
 
phase environments that the components are subjected to, or the flow velocities for the single-
 
phase or two-phase environments that the components are subjected to, (2) the UT inspection
 
criteria in NSAC-202L-R2 that components to be inspected around their girths and over a
 
distance equivalent to least +/- two pipe diameters of the subject welds or components scheduled 3-24 for inspection, (3) the minimum wall thickness acceptance criteria for in-scope components, and (4) the repair/replacement criteria for components that do not meet the acceptance criteria of
 
the report.
The staff also noted that the stated changes to the EPRI NSAC report provide for better programmatic guidance because they: (1) provide for enhanced guidance on how to apply
 
relevant industry experience and plant-specific experience as an additional basis for selecting
 
and scheduling additional components for UT or RT inspection, (2) provide for enhanced
 
guidance on sample expansion if relevant indications of loss of material by flow-accelerated
 
corrosion or other loss of material mechanisms are detected, (3) provide for enhanced guidance
 
for inspection of in-scope tanks, cross-around piping, and small bore piping, and (4) provide
 
addition clarifications on how to apply UT and RT as a volumetric inspection techniques for
 
these programs.
The staff verified that, in the applicants letter of December 18, 2007, the applicant amended the scope of program and detection of aging effects program elements in AMP B.1.15, Flow-
 
Accelerated Corrosion Program, to identify use of EPRI Report NSAC-202L-R3 as an exception
 
to the implementation guidance document that is recommended in the scope of program and detection of aging effects program elements of GALL AMP XI.M17, Flow-Accelerated
 
Corrosion. Thus, based on this review, the staff finds that EPRI Report NSAC-202L-R3 is an
 
acceptable alternative and updated version of the EPRI NSAC guidelines for managing loss of
 
material due to flow-accelerated corrosion at IP2 and IP3 because: (1) the updated version of
 
the report in EPRI Report NSAC-202L-R3 has not led to any non conservatisms in the reports
 
core guidance recommendations for inspecting of in-scope carbon steel or low-chromium
 
content alloy steel components, for establishing the acceptance criteria for these components, or for repairing or replacing components if unacceptable indications of loss of material are
 
detected in the components, and (2) the staff has verified that the applicant has amended the
 
LRA to identify the use of EPRI Report NSAC-202L-R3 as an exception to the scope of program and detection of aging effects program elements in GALL AMP XI.M17. NRC Audit
 
Item 156 is resolved.
Resolution of RAI B.1.15-1 The staff also noted that in the AMR items for the LRA, the applicant credited only its Water Chemistry Control-Primary and Secondary Program for managing loss of material in the steam
 
generator blowdown nozzle carbon steel interior surface. In RAI B.1.15-1, dated December 7, 2007, the staff questioned whether degradation of these nozzles would be more appropriately
 
managed by the Flow-Accelerated Corrosion Program.
In its response, dated January 4, 2008, the applicant stated that [t]he blowdown system piping external to the steam generators is susceptible to loss of material due to flow accelerated
 
corrosion and is managed by the Flow Accelerated Corrosion Program. The steam generator
 
blowdown nozzles are part of the blowdown system piping and are included in the FAC
 
program.In addition, the applicant stated that the corresponding AMR entries to LRA Tables 3.1.2-4-IP2 and 3.1.2-4-IP3 would be revised to include a statement in Table 3.1.1 AMR Item 3.1.1-59 that
 
will state that the carbon steel steam generator (SG) blowdown pipe connection is susceptible
 
to FAC and that the Flow-Accelerated Corrosion Program is credited to manage loss of material
 
due in these components.
3-25 The staff verified that the applicant amended the LRA by letter dated January 4, 2008, to: (1) amend the applicable AMRs for carbon steel SG blowdown piping to identify loss of material
 
due to flow-accelerated corrosion as an applicable aging effect requiring management (AERM)
 
for the interior piping surfaces that are exposed to treated water, (2) amend the applicable
 
AMRs to credit the Flow-Accelerated Corrosion Program for management of this aging effect, and (3) amend AMP B.1.15, Flow-Accelerated Corrosion Program to bring the SG blowdown
 
piping system within the scope of the AMP. Based on the applicants explicit inclusion of the
 
above components in the Flow-Accelerated Corrosion Program, the staff finds the applicants
 
response to RAI B.1.15-1 to be acceptable because the applicant has amended the scope of
 
the Flow-Accelerated Corrosion program to include the SG blowdown piping system, and
 
because the applicant has amended its AMRs to include AMRs on loss of material due to flow-
 
accelerated of the carbon steel or alloy steel SG blowdown system piping, piping components, and pipe fittings that credit this program for aging management. The staffs concern described in
 
RAI B1.15-1 is resolved.
Based on this review, the staff finds that the scope of program program element for the Flow-Accelerated Corrosion Program is acceptable because: (1) the applicant has identified
 
components within the scope of the program are those carbon steel/low chromium-content alloy
 
steel plant components that are in systems within the scope of license renewal and are subject
 
to high-velocity/high energy single-phase or two-phase aqueous environments, (2) the program, as amended, is consistent with the program element criteria in GALL AMP XI.M17.
Resolution of RAI B.1.15-2, Parts 1, 2, and 3 The staff noted that IP2 and IP3 have implemented stretch power uprates (SPU) within the last three years. To assess the impact that these SPUs would have on the modeling and predictions
 
of the CHECWORKS TM program, the staff issued RAI B.1.15-2 on December 7, 2007 to the applicant. In this three part RAI, the staff asked the applicant to: (1) provide details on any
 
changes made to the Flow Accelerated Corrosion Program in order to account for changes that
 
would need to be made to the process variables in CHECWORKS TM as a result of implementing these SPUs, (2) identify those in-scope piping systems and components that are currently most
 
susceptible to loss of materials by flow-accelerated corrosion, and (3) clarify how accurately the
 
CHECWORKS TM model has predicted changes in FAC wear rates for the top four most susceptible systems/components in each unit since the time the SPUs were implemented.
The applicant responded to RAI B.1.15-2 in a letter dated January 4, 2008. With respect to the applicant response to Part 1 of the RAI, the applicant stated that inputs to the IP2 and IP3 Flow-
 
Accelerated Corrosion Programs were updated to include SPU operating parameter changes
 
(e.g., flow rates and operating temperatures), in addition to incorporating the results of previous wall thickness measurements into the CHECWORKS TM modeling to allow for updated FAC-induced wear rate predictions. The staff verified that the applicants revised program used
 
the CHECWORKS TM program as one of several bases for establishing which in-scope piping component locations should be scheduled for inspection at the next outage. The staff also
 
verified that the applicant uses IP2-specific and IP3-specific operating experience, operating
 
experience discussed in NRC generic communications, industry operating experience records
 
or reports, and engineering judgment as additional bases for selecting in-scope piping
 
components for inspection. The staff also verified that the applicants use of the
 
CHECWORKS TM program uses the most recent updated power-uprated operating parameters and the most current inspection results obtained from past inspections performed on 3-26 components as the basis for establishing the program wear predictions for ferritic steel components that are within the scope of the program. Thus, the staff finds that the applicant has
 
provided an acceptable basis for using CHECWORKS TM as one of several means for identifying components for inspection and for scheduling components for inspection at the next unit
 
refueling outage because the current predictions from the computer model are based on the
 
power uprated conditions and the most current inspection results for systems and components
 
that are within the scope of and have been modeled by CHECWORKS TM. Part 1 of RAI B.1.15-2 is resolved.
With respect to the applicants response to Part 2 of RAI B.1.15-2, the applicant stated that the extraction steam system lines at IP2 and IP3 are the most susceptible plant systems for flow-
 
accelerated corrosion, with the 3 rd point extract steam lines between the high pressure turbines and the #23 feedwater heater being the most susceptible lines for IP2, and the 5 th point extraction steam lines between the pre-separators and the #35 feedwater heater being the most
 
susceptible lines for IP3. The staff finds that this is acceptable because it is consistent with the
 
staffs operating experience discussions in NRC Information Notices (INs) 89-53 and 97-84 that
 
FAC-induced full ruptures of extraction steam systems have occurred in the industry and that
 
these systems are among plant systems most susceptible to FAC-induced erosion (i.e. loss of
 
material due to FAC).
The applicant also clarified the majority of the most susceptible plant locations at IP2 and IP3 have been replaced with FAC-resistant materials. The staff verified that the applicant identifies (in the operating experience program element for this AMP) that the FAC-resistant materials are chromium-molybdenum (Cr-Mo) alloy steels. The staff noted that in EPRI Report No.
NSAC-202L-R2 (which is endorsed in GALL AMP XI.M17) and in EPRI Report No.
 
NSAC-202L-R3.(which is the version of the report currently being used by the applicant, and
 
found to be an acceptable alternative by the staff), EPRI identifies that austenitic stainless
 
steels or chromium-molybdenum (Cr-Mo) alloy steels with chromium alloying contents in excess
 
of 0.75% Cr by weight are steel materials that have enhanced resistance to FAC-induced
 
erosion (i.e. loss of material due to FAC). The staff finds that the applicants basis for replacing
 
susceptible components with Cr-Mo alloy steels is acceptable because, in the staffs
 
endorsement of EPRI Report NSAC-202L-R2, the staff concurred that Cr-Mo alloy steels
 
provide for added corrosion resistance to FAC. Thus, based on this review, the staff finds that
 
the applicant has resolved Part 2 of RAI B.1.15-2 because: (1) the applicants statement that the
 
extraction steam systems are the plant systems most susceptible to flow-accelerated corrosion
 
is consistent with the staffs discussions in INs 89-53 and 97-84 that extraction steam systems
 
are among the plant systems that are most susceptible to FAC-induced erosion, and (2) the
 
applicant has provide an acceptable basis for replacing susceptible components (including any
 
components that have been identified to have an unacceptable amount of FAC-induced aging in
 
them) with Cr-Mo alloy steel in-kind components. Part 2 to RAI B.1.15-2 is resolved.
With respect to the applicants response to Part 3 of RAI B.1.15-2, the applicant provided the following clarification on how the CHECWORKS TM modeling accounted for SPU conditions and why prolonged benchmarking of the models predictive analytical modeling was not necessary:
The input to the CHECWORKS modeling program includes plant operating parameters such as flow rates, operating temperatures and piping configuration, as well as measured wall thicknesses from FAC program components. This
 
input, in conjunction with the CHECWORKS predictive algorithm, is used to
 
predict the rate of wall thinning and remaining service life on a component-by-3-27 component basis. The value of the model lies in its ability to predict wear rates based on changing parameters, such as flow rate, without having to have actual
 
measured wall thickness values. The predictive algorithms built into
 
CHECWORKS are based on available laboratory data and FAC data from many
 
plants. CHECWORKS was designed, and has been shown, to handle large
 
changes in chemistry, flow rate and or other operating conditions. In its use
 
throughout the industry, the CHECWORKS model has been benchmarked
 
against measurements of wall thinning for components operating over a wide
 
range of flow rates. Consequently, the validity of the model does not depend on
 
benchmarking against plant-specific measured wear rates of components
 
operating under SPU conditions. In addition, by the time IPEC enters the period
 
of extended operation (in the year 2013), inspection data under SPU conditions
 
will have been obtained. These additional data sets, when added to the
 
CHECWORKS database, will result in more refined wear rate predictions. Since
 
the previously most susceptible locations have been replaced, wear rates are
 
low. Due to the low wear rates, the small changes in operating parameters due to
 
SPU, and the relatively short time since SPU, changes to wear rates since SPU
 
will be very small. The accuracy of the model is not expected to change
 
significantly due to the SPU.
The staff noted that the applicants response to RAI B.1.15-2 clearly explains how the CHECWORKS TM computer code is used as an analytical model for predicting which plant system and components should be inspected during scheduled outages in which the applicant
 
can perform UT examinations of the components. With respect to the use of CHECWORKS TM as a predictive model, the staff noted that the CHECWORKS TM analytical model uses the actual configured plant design, plant operating characteristics and parameters (such as system
 
operating temperature flow rates, pressure, and water chemistry values), and actual UT
 
inspection results to establish a susceptibility ranking of the plant's steel components to wall
 
thinning by flow-accelerated corrosion.
The staff also noted the modeling includes a feature to incorporate actual inspection wall thickness results back into the computer modeling, and that this feature is used to accomplish
 
two important aspects of CHECWORKS TM predictive modeling capability: (1) it permits the user to compare that actual as-found wall component thickness measurements of an inspected
 
component to the wall thickness for the component that was predicted by CHECWORKS TM in the previous modeling results, thus providing a method for confirming the degree of accuracy of
 
the models previous component wear rate predictions and component wall thickness
 
predictions, and (2) it permits the user to perform re-baselined component wear rate predictions
 
and component wall thickness predictions based on the incorporation of the compiled inspection
 
data for components that are modeled by the computer code and are inspected as part of the
 
applicants Flow-Accelerated Corrosion Program. The staff considers this feature to be a self-
 
benchmarking capability of the CHECWORKS TM model. The staff also verified that the applicant's implementation of the CHECWORKS TM computer code applies all of these features and that the modeling has incorporated the operating conditions and parameters from the IP2
 
and IP3 stretch power uprates.
The staff noted that CHECWORKS TM is endorsed in EPRI Report Nos. NSAC-202L-R2 and EPRI Report No. NSAC-202L-R3 only as one of a number of methods that should be used to
 
predict which plant components are susceptible to FAC and which components should be
 
inspected at scheduled refueling outages or replaced with in-kind components using 3-28 FAC-resistant materials. The staff noted that these reports also state the relevant operating experience and engineering judgment are both invaluable additional tools that should used in
 
establishing which components should be scheduled and inspected for wall thickness
 
measurements. The staff verified that, in addition to use of CHECWORKS TM , the applicant also uses IP2-specific and IP3-specific operating experience, industry-wide operating experience, operating experience identified in NRC-issued INs, GLs, and Bulletins, and engineering
 
judgment as additional bases for selecting the steel piping, piping components, and piping
 
elements for inspection. The staff also verified that the Flow-Accelerated Corrosion Program
 
includes applicable acceptance criteria for evaluating in-scope components and applicable
 
corrective actions (repair, replacement, or re-evaluation) for components that are projected to
 
exhibit an unacceptable amount of FAC-induced wall thinning.
Since the applicants program includes the incorporation of actual wall thickness measurement data into the CHECWORKS TM modeling, since the staff considers CHECWORKS TM to be a self-benchmarking compute code, and since the applicant does not limit CHECWORKS TM as being the only programmatic basis for selecting and scheduling components for inspection, the
 
staff finds that it is unnecessary to require prolonged benchmarking of the CHECWORKS TM computer code in order to justify its use in the selection and scheduling of in-scope components
 
for inspection. In addition, the staff has verified that the applicants implementation of
 
CHECWORKS TM as part of the applicants program is consistent with the staffs recommendation in the monitoring and trending program element in GALL AMP XI.M17 that
 
CHECWORKS TM be used as one of the bases for selecting and scheduling in-scope components for inspection. Based on this review, the staff finds that this approach for aging
 
management of loss of material due to flow-accelerated corrosion is acceptable because it
 
provides an adequate basis why prolonged benchmarking of CHECWORKS TM is unnecessary and because the applicants implementation of CHECWORKS TM is in conformance with the staffs monitoring and trending program element criteria for aging management that are recommended in GALL AMP XI.M17, Flow-Accelerated Corrosion. RAI B.1.15-2, Part 3 is
 
resolved.Based on this review, the staff concludes that the program elements for the applicant's Flow-Accelerated Corrosion Program, as amended, provide an adequate basis to manage
 
flow-accelerated corrosion because: (1) CHECWORKS TM code is considered to be a self-benchmarking code that is capable of modeling, predicting, and tracking the results of the
 
ultrasonic inspections that are performed in accordance with the applicant's Flow-Accelerated
 
Corrosion Program, (2) the self-benchmarking feature of CHECWORKS TM makes prolonged benchmarking of CHECWORKS TM is unnecessary, (3) the applicant uses the actual UT inspection results to confirm the predictive modeling of the CHECWORKS TM analyses and to perform re-baselined CHECWORKS TM predictive analyses, (4) the applicant does not limit the use of the CHECWORKS TM computer code as the sole basis for establishing which steel piping, piping components, or piping elements at IP2 and IP3 will be inspected, and (5) the program
 
includes acceptable program elements for managing flow-accelerated corrosion that are consistent with the program element criteria in GALL AMP XI.M17 or with the acceptable
 
alternative to use EPRI Report NSAC-202L-R3 as the implementation guideline for this
 
program.Operating Experience. LRA Section B.1.15 states that the most recent updates of the respective CHECWORKS FAC models account for IP2 and IP3 operating experience, including inspection
 
data from the outage inspections as well as the changes to FAC wear rates, due to the recent
 
power uprates. These updates further calibrate the model; and, therefore, improve the accuracy 3-29 of the wear predictions.
The applicant stated that the IP2 Flow-Accelerated Corrosion Program was audited in 2004.
The audit team found this program effective and in compliance with NRC regulations, ASME
 
code, EPRI standards, and Institute of Nuclear Power Operations (INPO) guidelines. Program
 
compliance with industry standards and guidelines assures continued effective management of
 
aging effects for passive components.
In the LRA, the applicant stated that in February 2006, it performed a self-assessment of the Flow-Accelerated Corrosion Program to evaluate its overall health and effectiveness. The
 
assessment team concluded that the applicant has a well-organized and effective Flow-
 
Accelerated Corrosion Program, consistent with the primary industry standards, and with no
 
weaknesses or deficiencies that would indicate any negative impact on long-term monitoring of
 
flow-accelerated corrosion.
Further, the applicant stated that in March 2005, during the 3R13 refueling outage, it detected wall thinning on vent chamber drain and high-pressure turbine drain components, which were
 
replaced during that outage. The applicant stated that these systems are susceptible to flow-
 
accelerated corrosion and are closely monitored. Susceptible sections of these systems are
 
replaced with FAC-resistant chrome-moly material. All remaining inspected components were
 
found acceptable for continued service. In May 2006, during the 2R17 refueling outage, the
 
applicant detected wall thinning in a steam trap pipe, which was then replaced during that
 
outage. The applicant concluded that detection of degradation and corrective action prior to loss
 
of intended function assure effective program management of aging effects due to flow-
 
accelerated corrosion.
As part of the development of a fleet-wide program procedure, Entergy performed a review of best practices for the Flow-Accelerated Corrosion Program at all Entergy sites. Guidance from
 
the EPRI CHECWORKS TM Users Group was applied to this procedure. Program compliance with industry standards and use of fleet-wide best practices in the development of procedures
 
assure continued effective management of aging effects for passive components.
The staff noted that relevant FAC-related operating experience for PWR facilities has been provided in the NRC INs, Bulletins, and GLs that are given in the operating experience and reference sections in GALL AMP XI.M17, Flow-Accelerated Corrosion. The staff verified, through its review of the applicants responses to Bulletin 87-01 and GL 89-08, that the
 
applicants program includes those plant systems that are addressed in these NRC generic
 
communications. Based on this determination, the staff finds that this provides evidence that the
 
applicant adjusts its program to account for relevant operating experience.
The staff also noted that one of the requests made in Bulletin 87-01 was for applicants to summarize the FAC-based inspections that they had performed prior to issuance of the bulletin
 
on May 2, 1987. The staff verified that in the applicants responses to Bulletin 87-01, the
 
applicant provided a summary of the UT inspections that had been performed at IP2 and IP3
 
prior to issuance of the bulletin. The staff noted that in the applicants summary of its inspection
 
results, the applicant had provided both the nominal wall thicknesses and the as-found wall
 
thicknesses of the components that had been inspected prior to Bulletin 87-01. The staff also
 
noted that in the applicants bulletin responses, the applicant had indicated those components
 
that were scheduled for repair or replacement as a result of detection of an unacceptable
 
degree of FAC-induced degradation in the components or because the existing amount of 3-30 degradation in the components was projected to grow to an unacceptable level prior to the next outage in which re-inspections would be performed. Based on this information, the staff finds
 
that the inspection results in the bulletin responses demonstrate that the applicant is
 
appropriately performing UT inspections of the systems that include carbon steel or alloy steel
 
components which are potentially susceptible to flow-accelerated corrosion and that the
 
applicant takes appropriate corrective action to repair or replace those components based on
 
relevant IP2 and IP3 FAC-related operating experience.
Based on its review of the applicant responses to Bulletin 87-01 and GL 89-08, and of relevant IP2-specific and IP3-specific operating experience and operating experience discussed in
 
applicable FAC-related NRC generic communications, the staff concludes that the applicant
 
appropriately assesses and adjusts its Flow-Accelerated Corrosion Program to account for
 
relevant FAC-related operating experience and to adjust the scope of program and remaining
 
program elements for the AMP in accordance with lessons learned from this operating
 
experience.
Based on this review, the staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR
 
Section A.1.2.3.10. The staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.14 and A.3.1.14, the applicant provided the UFSAR supplements for the Flow-Accelerated Corrosion Program. By letter dated December 18, 2007, the applicant revised LRA Sections A.2.1.14, A.3.1.14, and B.1.15 to change the reference from
 
NSAC-202L-R2 to NSAC-202L-R3. The staff reviewed these sections, as revised, 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 applicants Flow-Accelerated Corrosion Program, the staff finds that all program elements are consistent with the GALL Report. The
 
staff concludes that the applicant has demonstrated that the effects of aging will be adequately
 
managed so that the intended 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 program and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3.0.3.1.6  Non-EQ Inaccessible Medium-Voltage Cable Program
 
Summary of Technical Information in the Application. LRA Section B.1.23 describes the Non-EQ Inaccessible Medium-Voltage Cable Program as a new program that will be consistent with the GALL Report AMP XI.E3, Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49
 
Environmental Qualification Requirements.
The applicant stated that the Non-EQ Inaccessible Medium-Voltage Cable Program includes periodic inspections for water collection in cable manholes and tests cables. In-scope medium-
 
voltage cables (i.e., cables with operating voltage from 2kV to 35kV) exposed to significant moisture and voltage are tested at least every ten years for an indication of the condition of the
 
conductor insulation. The program inspects for water accumulation in manholes at least every
 
two years.
3-31 Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Non-EQ Inaccessible Medium-Voltage Cable Program and basis documents to verify consistency with the GALL Report AMP XI.E3. Details of the staffs audit of
 
the applicants AMP are documented in the Audit Report. As documented in the report, the staff
 
found that the Non-EQ Inaccessible Medium-Voltage Cable Program elements (1) through (6) are consistent with the corresponding elements in the GALL Report AMP XI.E3. Because these
 
elements are consistent with the GALL Report elements, the staff finds that they are acceptable.
Operating Experience:
In LRA Section B.1.23, the applicant states that the Non-EQ Inaccessible Medium-Voltage Cable Program is a new program. When implementing, the applicant will
 
consider as its basis, industry operating experience in the operating experience element of the
 
GALL Report program description. IP plant-specific operating experience is consistent with the
 
operating experience in the GALL Report program description.
The applicant also stated that the IP program is based on the GALL Report program description, which in turn is based on industry operating experience. The applicant also stated that plant-
 
specific operating experience is not inconsistent with that in the GALL Report. The applicant will consider industry and plant-specific operating experience when implementing the Non-EQ
 
Inaccessible Medium-Voltage Cable Program to confirm the new program effectiveness. The
 
applicant further stated that such operating experience assures program management of the
 
effects of aging so components continue to perform intended functions consistent with the CLB
 
through the period of extended operation.
SRP-LR Section A.1.2.3.10 provides guidance for staff review of operating experience. It states that an applicant may have to commit to providing operating experience in the future for new
 
program to confirm their effectiveness. As stated above, the applicant stated that it will consider
 
industry and plant-specific operating experience when implementing this program.
The NRC conducted its license renewal inspections in accordance with Inspection Procedure IP-71002 during the weeks of January 28 th , February 11 th , March 31 st , and June 2 nd of 2008.
During the June 2008 inspection, the staff observed a scheduled quarterly preventive
 
maintenance (PM) activity to open and inspect the IP3 manhole 36. The staff observed standing
 
water with several cable splices submerged. These included two 6.9 kV cables, both associated
 
with the station blackout/Appendix R diesel generator, and are within the scope of license
 
renewal. The applicant pumped the water out of the manhole, and assessed the condition of the
 
cable jackets and splices as acceptable. The staff reviewed the results of previous PM activities, and noted that water was typically found in the manhole at a depth sufficient to submerge at
 
least the lower cable splices. In GALL Report AMP XI.E3, under the detection of aging effects element, it recommends that the inspection for water collection should be performed based on actual plant experience with water accumulation in the manhole. However, the inspection frequency should be at least once every two years.
The applicant currently performs quarterly PM activities to open the manholes and look for water accumulation. If water is found, as indicated by the applicant, the water is pumped out of the manhole. The applicant has considered and will continue to
 
factor in plant operating experience when determining the frequency of inspection.
The staff has identified water in manholes as a generic, current operating plant issue in Information Notice 2002-12, Submerged Safety-Related Electrical Cables, dated March 21, 3-32 2002, and in Generic Letter 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 the manholes, for the current period of operation, through the reactor
 
oversight process in accordance with the requirements of 10 CFR Part 50.
During review of the LRA, the staff determined that the Non-EQ Inaccessible Medium-Voltage Cable Program when implemented as described will ensure that the aging effects on
 
inaccessible medium-voltage cables, due to exposure to significant moisture, will be adequately
 
managed during the period of extended operation in accordance with the guidance in GALL Report, Section XI.E3. The Non-EQ Inaccessible Medium-Voltage Cable Program is a new
 
program which recommends the applicant to test the cables and to evaluate plant-specific and
 
industry-wide operating experience to determine if 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 operation.
The staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.22 and A.3.1.22, the applicant provided the UFSAR supplement for the Non-EQ Inaccessible Medium-Voltage Cable Program. The staff reviewed
 
these sections and determines that the information in the UFSAR supplement is an adequate
 
summary description of the program, as required by 10 CFR 54.21(d). The applicant committed
 
to implement the Non-EQ Inaccessible Medium-Voltage Cable Program prior to the period of
 
extended operation. The applicant further stated that this new program will be implemented consistent with the corresponding program described in NUREG-1801, Section XI.E3, Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification
 
Requirements (Commitment 15).
By letter dated July 27, 2009, the applicant added a new commitment (Commitment 40) that states that plant specific and appropriate industry operating experience will be evaluated and
 
lessons learned will be used to establish appropriate monitoring and inspection frequencies to
 
assess aging effects for the new aging management programs.
Conclusion. On the basis of its audit and review of the applicants Non-EQ Inaccessible Medium-Voltage Cable Program, the staff finds that all program elements are consistent with the GALL Report AMP XI.E3. 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 program and
 
concludes that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.1.7  Non-EQ Instrumentation Circuits Test Review Program
 
Summary of Technical Information in the Application:
LRA Section B.1.24 describes the Non-EQ Instrumentation Circuits Test Review Program as a new program that will be consistent with the GALL Report AMP XI.E2, Electrical Cables and Connections Not Subject to 10 CFR 50.49
 
Environmental Qualification Requirements Used in Instrumentation Circuits.
3-33 The applicant stated that the Non-EQ Instrumentation Circuits Test Review Program is a new program that assures the intended functions of sensitive, high-voltage, low-signal cables
 
exposed to adverse localized environments caused by heat, radiation, and moisture (i.e.,
neutron flux monitoring instrumentation) can be maintain consistent with the CLB through the
 
period of extended operation. Most neutron flux monitoring system cables and connections are
 
included in the instrumentation loop calibration at the normal calibration frequency, which
 
provide sufficient indication of the need for corrective actions based on acceptance criteria
 
related to instrumentation loop performance. The applicant further stated that for neutron
 
monitoring system cables that are disconnected during instrumentation calibrations, testing
 
using a proven method for detecting deterioration for the insulation system (such as insulation
 
resistance tests or time domain reflectometry) will occur at least every ten years, with the first
 
test occurring before the period of extended operation. Engineering evaluation will be performed
 
when test acceptance criteria are not met and corrective actions, including modified inspection
 
frequency, will be implemented to ensure that the intended functions of the cables can be
 
maintained consistent with the CLB through the period of extended operation.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff reviewed the
 
program elements of the Non-EQ Instrumentation Circuits Test Review Program and basis documents to verify consistency with the GALL Report AMP XI.E2. Details of the staffs audit of
 
the applicants AMP are documented in the Audit Report. As documented in the report, the staff
 
found that the Non-EQ Instrumentation Circuits Test Review Program elements (1) through (6) are consistent with the corresponding elements in the GALL Report AMP XI.E2 except for the
 
following area. Because these elements are consistent with the GALL Report elements, the staff
 
finds that they are acceptable. Under the program element 1 (scope of the program), the GALL Report AMP XI.E2 states that this program applies to high-range-radiation and neutron flux monitoring instrumentation cables
 
in addition to other cables used in high voltage, low level signal applications that are sensitive to
 
reduction in insulation resistance. In its Non-EQ Instrumentation Circuits Test Review Program, the applicant only included neutron monitoring system cables in the scope of the program. The
 
staff requested the applicant to explain why high-range-radiation monitoring cables were not
 
included in the program (Audit Item 64). The staff also requested the applicant to identify any
 
other high voltage, low level signal cables and explain why these cables are not in scope under
 
the Non-EQ Instrumentation Circuits Test Review Program. In a letter dated March 24, 2008, the applicant stated that although not explicitly listed, the high-range radiation monitoring cables
 
were included in AMP B.1.24. The AMR included neutron monitoring circuits and high-range
 
radiation monitoring circuits. The program description for AMP B.1.24 uses the phrase (i.e.,
neutron monitoring instrumentation). Since this was meant to be an example, the term e.g.
 
would have been a more appropriate choice than i.e. The applicant also stated that:
During the integrated plant assessment (IPA), the only high instrument voltage circuits with low signal values that were not subject to AMR were the incore
 
detectors and the area radiation monitors. The nonsafety-related incore detectors
 
and the area radiation monitors do not perform a license renewal intended
 
function per 10 CFR 54.4(a)(1), (2), or (3). Therefore, the incore detectors and the area radiation monitors are not included in the scope of the B.1.24 (XI.E2)
 
AMP.
3-34 A change will be made to LRA Section B.1.24 for clarification. The recommended change is as follows.
The Non-EQ Instrumentation Circuits Test Review Program is a new program that assures the intended functions of sensitive, high-voltage, low-signal cables
 
exposed to adverse localized environments caused by heat, radiation and
 
moisture (i.e., neutron flux monitoring instrumentation and high range radiation
 
monitors); can be maintained consistent with the current license basis through
 
the period of extended operation. Most sensitive instrumentation circuit cables
 
and connections are included in the instrumentation loop calibration at the normal
 
calibration frequency, which provide sufficient indication of the need for corrective
 
actions based on acceptance criteria related to instrumentation loop
 
performance. The review of calibration results will be performed once every ten
 
years, with the first review occurring before the period of extended operation.
For sensitive instrumentation circuit cables that are disconnected during instrument calibration, testing using a proven method for detecting deterioration
 
for the insulation system (such as insulation resistance tests or time domain
 
reflectometry) will occur at least every ten years, with the first test occurs before
 
the period of extended operation. In accordance with corrective action program, an engineering evaluation will be performed when test acceptance criteria are not
 
met and corrective actions, including modified inspection frequency, will be
 
implemented to ensure that the intended functions of the cables can be
 
maintained consistent with the current licensing basis through the period of
 
extended operation. This program will consider the technical information and
 
guidance provided in NUREG/CR-5643, IEEE Std. P1205, SAND96-0344, and
 
EPRI TR-109619.
The staff found the applicants response acceptable because with the proposed LRA amendment and clarification described above, the scope of the Non-EQ Instrumentation Circuits Test Review Program is consistent with that in the GALL Report AMP XI.E2. The staff agreed
 
with the applicant that incore detectors and area radiation monitors do not perform an intended
 
function per 10 CFR 54.4(a)(1), (2), or (3) because they are non safety-related, their failure will
 
not affect safety-function of safety-related components, and they are not credited in any
 
regulated events under 10 CFR 54.4(a)(3). Therefore, they are not in the scope of the Non-EQ
 
Instrumentation Circuits Test Review Program. The staff verified that in a letter dated December
 
18, 2007, the applicant amended LRA Section B.1.24 as described above.
Operating Experience. LRA Section B.1.24 states that the Non-EQ Instrumentation Circuits Test Review Program is a new program. When implementing this new program, the applicant will consider industry operating and plant-specific operating experience. Plant-specific operating
 
experience is not inconsistent with the operating experience in the GALL Report program
 
description.
The applicant also stated that the Non-EQ Instrumentation Circuits Test Review program is based on the GALL Report program description, which in turn is based on industry operating
 
experience. The applicant further stated that such operating experience assures management
 
of the effects of aging so components continue to perform their intended functions consistent
 
with the CLB through the period of extended operation.
3-35 SRP-LR Section A.1.2.3.10 provides guidance for staff review of operating experience. It states that an applicant may have to commit to providing operating experience in the future for new
 
program to confirm their effectiveness. As stated above, the applicant stated that it will consider
 
industry and plant-specific operating experience when implementing this program.
The staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.23 and A.3.1.23, the applicant provided the UFSAR supplement for the Non-EQ Instrumentation Circuits Test Review Program. The staff reviewed
 
these sections and determines that the information in the UFSAR supplement is an adequate
 
summary description of the program, as required by 10 CFR 54.21(d). The applicant committed
 
to implement the Non-EQ Instrumentation Circuits Test Review Program prior to the period of
 
extended operation. The applicant further stated that this new program will be implemented consistent with the corresponding program described in NUREG-1801, Section XI.E2, Electrical
 
Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification
 
Requirements Used in Instrumentation Circuits (Commitment 16).
By letter dated July 27, 2009, the applicant added a new commitment (Commitment 40) that states that plant specific and appropriate industry operating experience will be evaluated and
 
lessons learned will be used to establish appropriate monitoring and inspection frequencies to
 
assess aging effects for the new aging management programs.
Conclusion. On the basis of its audit and review of the applicants Non-EQ Instrumentation Circuits Test Review Program, the staff finds that all program elements are consistent with the GALL Report AMP XI.E2 program elements. 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
 
program and concludes that it provides an adequate summary description of the program, as
 
required by 10 CFR 54.21(d).
3.0.3.1.8  Non-EQ Insulated Cables and Connections Program
 
Summary of Technical Information in the Application. LRA Section B.1.25 describes the Non-EQ Insulated Cables and Connections Program as a new program that will be consistent with the GALL Report AMP XI.E1, Electrical Cables and Connections Not Subject to 10 CFR 50.49
 
Environmental Qualification Requirements.
The applicant stated that the Non-EQ Insulated Cables and Connections Program assures maintenance of the intended functions of insulated cables and connections exposed to adverse
 
environments of heat, radiation, and moisture consistent with the CLB through the period of
 
extended operation. An adverse environment is significantly more severe than the specified
 
service condition for the insulated cable or connection. The applicant further stated that a
 
representative sample of accessible insulated cables and connections within the scope of
 
license renewal will be inspected visually for cable and connection jacket surface anomalies
 
(e.g., embrittlement, discoloration, cracking or surface contamination). The technical basis for sampling will be determined from EPRI TR-109619, Guideline for the Management of Adverse
 
Localized Equipment Environments.
3-36 Staff Evaluation. During its audit and review, the staff reviewed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Non-EQ Insulated Cables and Connections Program and basis documents to verify consistency with the GALL Report AMP XI.E1. Details of the staffs audit of
 
the applicants AMP are documented in the Audit Report. As documented in the report, the staff
 
found that the Non-EQ Insulated Cables and Connections Program elements (1) through (6) are consistent with the corresponding elements in the GALL Report AMP XI.E1 except for the
 
following area. Because these elements are consistent with the GALL Report elements, the staff
 
finds that they are acceptable.
Under the program description for this AMP, the GALL Report states that this program can be thought as a sampling program. Selected cables and connections from accessible areas (the
 
inspection sample) are inspected and represent, with reasonable assurance, all cables and
 
connection in the adverse localized environments. If an unacceptable condition or situation is
 
identified for a cable or connection in the inspection sample, a determination is made as to
 
whether the same condition or situation is applicable to other accessible or inaccessible cables
 
or connections. In the program description of Non-EQ Insulated Cables and Connections
 
Program, the applicant stated that a representative sample of accessible insulated cables and
 
connections within the scope of license renewal will be visually inspected. The staff requested
 
the applicant to describe the technical basis for sampling and action taken if degradation was
 
found on a representative sample (Audit Item 65). In a letter dated March 24, 2008, the
 
applicant stated that this program addresses cables and connections under the premise that a
 
large portion of cables and connections are accessible. This program sample consists of all
 
accessible cables and connections in localized adverse environments. If an unacceptable
 
condition or situation for cable or connection during this visual inspection, the corrective action
 
process will be used for resolution. As part of the corrective action process, a determination will
 
be made as to whether the same condition or situation is applicable to other cables and
 
connections. The applicant will revise the LRA Sections B.1.25, A.2.1.24, and A.3.1.24, second
 
paragraph as described below:
A representative sample of accessible insulated cables and connections within the scope of license renewal will be visually inspected for cable and connection
 
jacket surface anomalies such as embrittlement, discoloration, cracking or
 
surface contamination. The program sample consists of all accessible cables
 
and connections in localized adverse environment.
The staff finds the applicants response acceptable because the program will address cable and connections whose configuration is such that most (if not all) cables and connections installed in
 
adverse localized environments are accessible. This program is a sampling program. Selected
 
cables and connections from accessible areas (the inspection sample) are inspected and
 
represent all cables and connections in the adverse localized environment. If an unacceptable
 
condition or situation is identified for a cable or connection in the inspection sample, a
 
determination is made to whether the same condition or situation is applicable to other cable or connections. The sample inspection is consistent with those in GALL AMP XI.E1. In a letter
 
dated December 18, 2007, the applicant revised LRA Sections B.1.25, A.2.1.24, and A.3.1.24
 
as described above.
Operating Experience.
LRA Section B.1.25 states that the Non-EQ Insulated Cables and Connections Program is a new program. When implementing this new program, the applicant 3-37 will consider plant-specific and industrial operating experience as its basis. Plant-specific operating experience is not inconsistent with the operating experience in the GALL Report
 
program description.
The applicant also stated that the Non-EQ Insulated Cables and Connections Program is based on the GALL Report program description, which in turn is based on industry operating
 
experience. The applicant further stated that such operating experience assures management
 
of the effects of aging so components continue to perform their intended functions consistent
 
with the CLB through the period of extended operation.
SRP-LR Section A.1.2.3.10 provides guidance for staff review of operating experience. It states that an applicant may have to commit to providing operating experience in the future for new
 
program to confirm their effectiveness. As stated above, the applicant stated that it will consider
 
industry and plant-specific operating experience when implementing this program.
The staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.24 and A.3.1.24, the applicant provided the UFSAR supplement for the Non-EQ Insulated Cables and Connections Program. The staff reviewed
 
these sections and the amendments as described above and determines that the information in
 
the UFSAR supplement is an adequate summary description of the program, as required by
 
10 CFR 54.21(d). The applicant committed to implement the Non-EQ Insulated Cables and
 
Connections Program prior to the period of extended operation. The applicant further stated that
 
this new program will be implemented consistent with the corresponding program described in NUREG-1801, Section XI.E1, Electrical Cables and Connections Not Subject to 10 CFR 50.49
 
Environmental Qualification Requirements (Commitment 17).
By letter dated July 27, 2009, the applicant added a new commitment (Commitment 40) that states that plant specific and appropriate industry operating experience will be evaluated and
 
lessons learned will be used to establish appropriate monitoring and inspection frequencies to
 
assess aging effects for the new aging management programs.
Conclusion
: On the basis of its audit and review of the applicants Non-EQ Insulated Cables and Connections Program, the staff finds all program elements consistent with the GALL Report
 
program elements. 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 program and concludes that it provides an
 
adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.1.9  One-Time Inspection Program
 
Summary of Technical Information in the Application. LRA Section B.1.27 describes the One-Time Inspection Program as a new program that will be consistent with GALL AMP XI.M32, One-Time Inspection.
The One-Time Inspection Program confirms AMP effectiveness and the absence of aging effects. For structures and components that rely on AMPs, this program confirms that 3-38 unacceptable degradation has not occurred and that component intended functions will be maintained during the period of extended operation. One-time inspections may be needed to
 
address concerns about potentially long incubation periods for certain aging effects on
 
structures and components. There are cases where either (a) an aging effect is not expected to
 
occur but there is insufficient data to rule it out completely or (b) an aging effect is expected to
 
progress very slowly. For these cases, there will be confirmation that either the aging effect
 
indeed has not occurred or the aging effect occurs so slowly as not to affect the components or
 
structures intended function. A one-time inspection of the subject component or structure is
 
appropriate for this confirmation.
The elements of the program include (a) determination of the sample size based on an assessment of fabrication materials, environment, plausible aging effects, and operating
 
experience, (b) determination of the system or component inspection locations for the aging
 
effect, (c) determination of the examination technique, including acceptance criteria effective for
 
managing the aging effect for which the component is examined; and (d) evaluation of the need
 
for follow-up examinations to monitor the progression of any aging effect. The program will
 
confirm the absence of aging effects as described:
A one-time inspection activity confirms the effectiveness of:  water chemistry control programs by confirming that unacceptable cracking, loss of material, and fouling have not occurred on system components managed by the
 
programs the Oil Analysis Program by confirming that unacceptable cracking, loss of material, and
 
fouling have not occurred on system components managed by the program  the Diesel Fuel Monitoring Program by confirming that unacceptable loss of material and
 
fouling have not occurred on system components managed by the program When a one-time inspection reveals evidence of an aging effect, routine evaluation of the inspection results develops appropriate corrective actions.
Staff Evaluation. During its audit and review, the staff reviewed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the One-Time Inspection Program and basis documents to verify consistency with the GALL Report AMP XI.M32. Details of the staffs audit of the applicants
 
AMP are documented in the Audit Report. As documented in the report, the staff found that the
 
One-Time Inspection Program elements (1) through (6) are consistent with the corresponding elements in the GALL Report AMP XI.M32. Because these elements are consistent with the
 
GALL Report elements, the staff finds that they are acceptable.
The applicant stated in the LRA that the sample size will provide 90 percent confidence that 90 percent of the population will not display degradation (90/90). The staff asked the applicant
 
to justify the use of 90/90 for the sample size (Audit Item 71). By letter dated March 24, 2008, the applicant stated that it is following the guidelines in EPRI TR-107514, Age Related
 
Degradation Inspection Method and Demonstration, which describes methods used to inspect
 
for age related degradation during the period of extended operation. This report recommends
 
using the 90 percent confidence that 90 percent of the population will not display degradation.
 
The justification for the 90/90 is that the locations selected for inspection are either the oldest
 
components or are the locations most likely to be susceptible to degradation, so the true 3-39 confidence is higher that 90 percent. The staff found this approach to be acceptable because biased sampling of the most susceptible locations should provide higher confidence than a
 
90/90 random sampling approach.
Operating Experience. LRA Section B.1.27 states that the One-Time Inspection Program is a new program. The applicant will consider industry operating experience when implementing this
 
new program. The scopes of the inspections and inspection techniques are consistent with
 
proven industry practices for managing the effects of aging. Plant-specific operating experience
 
is consistent with the operating experience in the GALL Report program description.
The applicant also stated that the One-Time Inspection Program is based on the GALL Report program description, which in turn is based on industry operating experience. The applicant
 
further stated that such operating experience assures management of the effects of aging so
 
components continue to perform intended functions consistent with the CLB through the period
 
of extended operation.
The staff confirmed that the operating experience program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.26 and A.3.1.26, the applicant provided the UFSAR supplement for the One-Time Inspection Program. By letter dated December 18, 2007, the
 
applicant revised LRA Sections A.2.1.26, A.3.1.26, and B.1.27 to clarify that the "inspections will
 
be nondestructive examinations (including visual, ultrasonic, or surface techniques)."
Additionally, the applicant revised these sections for several one-time inspection activities that
 
used the term "components" to replace the term "components" with the term "tanks, pump
 
casings, piping, piping elements and components, as appropriate. By letter dated June 12, 2009, the applicant revised LRA Section A.2.1.26 to add one-time inspection activities for the
 
internal surfaces of stainless steel piping, tubing, strainers, and valve bodies in the IP1 station
 
air system exposed to condensation. The staff reviewed these sections, as revised, and
 
determines that the information in the UFSAR supplement, as clarified, is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d). The applicant stated in the LRA
 
that this program will be implemented prior to the period of extended operation. In addition, the
 
applicant stated that this new program will be implemented consistent with the corresponding program described in NUREG-1801, Section XI.M32, One-Time Inspection (Commitment 19).
By letter dated July 27, 2009, the applicant added a new commitment (Commitment 40) that states that plant specific and appropriate industry operating experience will be evaluated and
 
lessons learned will be used to establish appropriate monitoring and inspection frequencies to
 
assess aging effects for the new aging management programs.
Conclusion. On the basis of its audit and review of the applicants One-Time Inspection 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 program and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3-40 3.0.3.1.10  One-Time Inspection - Small Bore Piping Program Summary of Technical Information in the Application. LRA Section B.1.28 describes the One-Time Inspection - Small Bore Piping Program as a new program that will be consistent with GALL AMP XI.M35, One-Time Inspection of ASME Code Class 1 Small-Bore Piping.
LRA Section B.1.28 states that the One-Time Inspection - Small Bore Piping Program applies to small-bore ASME Code Class 1 piping less than 4 inches nominal pipe size (NPS), including
 
pipe, fittings, and branch connections. The ASME Code does not require volumetric
 
examination of Class 1 small-bore piping. The One-Time - Small Bore Piping Program will
 
identify cracking by volumetric examinations.
The program will select a sample based on susceptibility, inspectability, dose considerations, operating experience, and limiting locations of the total population of ASME Code Class 1 small
 
bore piping locations. When a one-time inspection reveals evidence of an aging effect, evaluation of the inspection results will develop appropriate corrective actions.In the GALL Report program description, GALL AMP XI.M35 includes piping less than or equal to NPS 4" with a reference to ASME Section XI, Table IWB-2500-1, Examination Category BJ;
 
however, according to the ASME Code, a volumetric examination already is required for piping
 
equal to 4-inch NPS. Consistent with the Code, GALL Report Item IV.C2-1 applies the One-Time Inspection of ASME Code Class 1 Small Bore Piping Program (XI.M35) only to Class 1
 
piping less than 4-inch NPS. On this basis, the applicant concludes that the intent of GALL Program XI.M35 is not to include 4-inc NPS pipe. Therefore, the One-Time Inspection - Small
 
Bore Piping Program includes only small-bore Class 1 piping less than 4-inch NPS and as
 
consistent with the GALL AMP.
Staff Evaluation. During its audit and review, the staff reviewed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the One-Time Inspection - Small Bore Piping Program and basis documents to verify consistency with the GALL Report AMP XI.M35. Details of the staffs audit
 
of the applicants AMP are documented in the Audit Report. As documented in the report, the
 
staff found that the One-Time Inspection - Small Bore Piping Program elements (1) through (6) are consistent with the corresponding elements in the GALL Report AMP XI.M35. Because
 
these elements are consistent with the GALL Report elements, the staff finds that they are
 
acceptable.
During its review, the staff identified the following aspects of the applicants program that needed additional clarification: (1) whether inspections performed on ASME Code Class 1 small
 
bore piping to date have indicated any indications of cracking in the components, (2) the basis
 
that will be used for selecting ASME Code Class 1 small bore piping for inspection during the
 
period of extended operation, (3) whether ASME Code Class 1 piping that is 4-inch in diameter
 
NPS is within the scope of the program, and (4) the acceptance criteria that will be used to
 
evaluate relevant indication of cracking in these components.
During an onsite audit, the staff asked the applicant if the applicant had experienced cracking of ASME Class 1 small bore piping as a result of stress corrosion cracking or thermal and
 
mechanical loading (Audit Item 73). By letter dated December 18, 2007, the applicant clarified
 
that inspections to date at IP 2 and IP 3 have not revealed any indications of cracking in the
 
ASME Code Class 1 small-bore piping components for the units. Based on this review, the staff 3-41 finds that the applicant has provided an acceptable basis for concluding that the One-Time Inspection - Small Bore Piping Program is an acceptable AMP to credit for managing cracking in
 
the ASME Code Class 1 small bore piping because: (1) the AMP is an acceptable AMP to credit
 
for cases where no indications of cracking have been detected in the ASME Code Class 1 small
 
bore piping components and (2) the applicant has not detected any indications of cracking in its
 
ASME Code Class 1 piping as a result of the inspections that have been performed on these
 
components. The staffs concern on this matter is resolved.
During the audit the staff asked the applicant if they were going to follow the guidance in Materials Reliability Program (MRP) -24 for identifying susceptible locations for inspection (Audit
 
Item 74). By letter dated December 18, 2007, the applicant clarified that the program elements
 
for the One-Time Inspection - Small Bore Piping program will be consistent with the corresponding program element recommendations in GALL AMP XI.M35. The applicant clarified
 
that the program will include a sample selected based on susceptibility, inspectability, dose
 
considerations, operating experience, and limiting locations of the total population of ASME
 
Code Class 1 small bore piping locations, and that MRP-24 (January 2001) or subsequent
 
revisions of this industry guidance, will be followed for identifying susceptible locations for
 
inspection. The staff noted that the applicants response to Audit Item 74 was in conformance
 
with the recommendation in the monitoring and trending program element in GALL AMP XI.M35, recommends that the sample size for the small bore piping inspections be based on a
 
assessment of the susceptibility, inspectability, dose considerations, operating experience, and
 
limiting locations of the total population of ASME Code Class 1 small-bore piping locations. The
 
staff also noted that the applicants response to Audit Item 74 was also in conformance with the recommendation in the scope of program program element in GALL AMP XI.M35 that EPRI
 
Report 1000701, "Interim Thermal Fatigue Management Guideline (MRP-24)," January 2001
 
provides an acceptable basis for identifying those ASME Code Class 1 small bore piping
 
locations that are most susceptible to cracking as a result of thermal stratification or turbulence.
Based on this review, the staff finds that the applicant has provided an acceptable basis for selecting those AMSE Code Class 1 small bore piping component for inspection because the
 
applicants basis is in conformance with the staffs recommendations for selecting susceptible
 
components for inspection, as given in the scope of program program element in GALL AMP XI.M35. The staff also finds that the applicant has provided an acceptable basis for establishing
 
the sample size of its AMSE Code Class 1 small bore piping component inspections because
 
the applicants basis is in conformance with the staffs recommendations for sample size, as given in the monitoring and trending program element in GALL AMP XI.M35. The staffs
 
concern in Audit Item 74 is resolved.
During the audit, the staff asked the applicant if it intends to exclude 4" size from AMP B.1.28 from the scope of the applicants One-Time Inspection - Small Bore Piping Program, and if so, whether this should be treated as an exception to GALL and a justification included in the LRA
 
to establish exception to the GALL report (Audit Item 174). By letter dated December 18, 2007, the applicant clarified that the staffs AMR in GALL AMR Item IV.C2-1 identifies that the program
 
is credited only for ASME Code Class 1 piping less than 4-inches NPS and that the Examination Categories B-F and B-J in Table IWB-2500-1 of the ASME Code, Section XI already require
 
volumetric examinations for ASME Code Class 1 piping greater than or equal to 4-inches in
 
diameter NPS. Thus, the applicant clarified that AMSE Code Class 1 piping equal to 4-inches
 
NPS is not within the scope of the One-Time Inspection - Small Bore Piping Program. The staff
 
verified that the requirements for volumetric examinations for ASME Code Class 1 piping
 
greater than or equal to 4-inches in diameter NPS is already included within the scope of the 3-42 applicants Inservice Inspection Program (LRA AMP B.1.18). Based on this review, the staff finds that the applicant has provided an acceptable basis for excluding AMSE Code Class 1
 
piping equal to 4-inches NPS from the scope of the One-Time Inspection - Small Bore Piping
 
Program because volumetric examinations of this ASME Code Class 1 pipe size is already
 
included within the scope of the applicants Inservice Inspection Program. The staffs concern in
 
Audit Item 174 is resolved.
During the audit, the staff asked the applicant whether the applicant follows the applicable ASME Code, Section XI corrective action criteria in Paragraph IWB-3131 for flaw evaluation and
 
supplemental examinations in Paragraph IWB-2430 for flaw indications exceeding their
 
applicable flaw standard in Subarticle IWB-3400 (Audit Item 283). By letter dated December 18, 2007, the applicant confirmed that it follows the applicable ASME Code, Section XI corrective
 
action criteria in Paragraph IWB-3131 for flaw evaluation and supplemental examinations in
 
Paragraph IWB-2430 for any flaw indication in a small bore Class 1 piping components that
 
exceeds its applicable flaw standard in Subarticle IWB-3400. The staff noted that the volumetric examinations recommended in GALL AMP XI.M35 for small bore Class 1 piping components are not ASME Code, Section XI mandated examinations, and therefore, go beyond the current
 
10 CFR 50.55a mandated inservice inspection (ISI) requirements for these types of components in ASME Code, Section XI Table IWB-2500-1. As such, the applicant is not obligated to using the stated ASME Code, Section XI-based correction actions for its non-mandatory, LRA-recommended one-time volumetric examinations. The staff noted, however, that the applicant credited these ASME Code, Section XI-based corrective action provisions for any flaw
 
indication in a small bore Class 1 piping components that exceeds its applicable flaw standard
 
in Subarticle IWB-3400. Thus, the staff finds that the applicant has provided an acceptable
 
basis for corrective actions of any non-conforming indications because the applicant is applying
 
the conservative Code-based corrective actions to any non-conforming indication that is
 
detected as a result of the non-mandatory, LRA-recommended one-time volumetric
 
examinations that will be performed on these small bore ASME Code Class 1 piping
 
components. The staffs concern in Audit Item 283 is resolved.
Based on the review of this AMP and the applicants responses to the audit questions, the staff finds this program acceptable because the staff has verified that the program elements for the
 
applicants One-Time Inspection - Small Bore Piping Program are in conformance with the
 
staffs aging management criteria that are provided in the program elements of GALL AMP XI.M35, and because the applicant will implement this program consistent with GALL AMP XI.M35 recommendations.
Operating Experience. LRA Section B.1.28 states that the One-Time Inspection - Small Bore Piping Program is a new program. When implementing this new program the applicant will
 
consider as its basis industry operating experience in the GALL Report program description, which in turn is based on industry operating experience. Such operating experience assures
 
program management of the effects of aging so components continue to perform intended
 
functions consistent with the CLB through the period of extended operation.
In its response to Audit Item 73, the applicant indicated that previous non-volumetric inservice inspections performed on the small bore ASME Code Class 1 piping components did not reveal
 
any indication of cracking in the piping components. In addition, the staff noted that the
 
applicant indicated that there are not any small bore ASME Code Class 1 socket welds at IP2
 
and IP3 that have been identified as critical welds from a risk-informed inservice inspection (RI-
 
ISI) program perspective. Therefore, small bore ASME Code Class 1 socket welds are not 3-43 included within the scope of the applicants One-Time Inspection - Small Bore Piping Program.
The staff has confirmed that the applicant instead credits the surface examination requirements
 
and visual examination requirements in the applicants Inservice Inspection Program as the
 
basis for inspecting the applicants small bore ASME Code Class 1 socket welds. Based on this
 
review, the staff finds that the applicant has provided an acceptable basis for concluding that
 
the One-Time Inspection - Small Bore Piping Program may be used to verify whether cracking is
 
occurring in the applicants ASME Code Class 1 piping components during the period of
 
extended operation because the applicant has not detected any indications of cracking as a
 
result of the non-volumetric examinations that were performed on these components through
 
implementation of the applicants Inservice Inspection Program, and because the IP2 and IP3
 
designs do not include any critical small bore ASME Code Class 1 socket weld locations that
 
are considered to be critical risk-informed locations under the applicants RI-ISI program. Based
 
on this review, the staff confirmed that the operating experience program element satisfies the
 
recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.27 and A.3.1.27, the applicant provided the UFSAR supplement for the One-Time Inspection - Small Bore Piping Program. The staff reviewed these
 
sections and determines that the information in the UFSAR supplement is an adequate
 
summary description of the program, as required by 10 CFR 54.21(d). The applicant stated in
 
the LRA that this program will be implemented prior to the period of extended operation. In
 
addition, the applicant stated that this new program will be implemented consistent with the corresponding program described in NUREG-1801, Section XI.M35, One-Time Inspection -
 
Small Bore Piping (Commitment 20).
By letter dated July 27, 2009, the applicant added a new commitment (Commitment 40) that states that plant specific and appropriate industry operating experience will be evaluated and
 
lessons learned will be used to establish appropriate monitoring and inspection frequencies to
 
assess aging effects for the new aging management programs.
Conclusion. On the basis of its audit and review of the applicants One-Time Inspection - Small Bore Piping Program, the staff finds that all program elements are consistent with the GALL
 
Report. The staff concludes that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended 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 program and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3.0.3.1.11  Reactor Head Closure Studs Program
 
Summary of Technical Information in the Application. LRA Section B.1.30 describes the existing Reactor Head Closure Studs Program as consistent with GALL AMP XI.M3, Reactor Head
 
Closure Studs.
The Reactor Head Closure Studs Program includes inservice inspection (ISI) in compliance with the requirements of ASME Section XI, Subsection IWB, and preventive measures (e.g., rust
 
inhibitors, stable lubricants, appropriate materials) to mitigate cracking and loss of material of
 
reactor head closure studs, nuts, washers, and bushings.
3-44The GALL Report program, Section XI.M3, Reactor Head Closure Studs, is based on ASME Code 2001 Edition including the 2002 and 2003 Addenda. The ISI program is based on ASME
 
Code 1989 Edition, no addenda, with inspection of reactor head closure studs based on the
 
1998 Edition through the 2000 Addenda. The 1998 Edition through the 2000 Addenda allow
 
surface or volumetric examination when closure studs are removed. This is consistent with the requirements of GALL Report, Section XI.M3. Therefore, use of different ASME Code editions
 
for this program is not an exception to the GALL Report.
Staff Evaluation. During its audit and review, the staff reviewed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Reactor Head Closure Studs Program and basis documents to verify consistency with the GALL Report AMP XI.M3. Details of the staffs audit of the applicants AMP
 
are documented in the Audit Report. As documented in the report, the staff found that the
 
Reactor Head Closure Studs Program elements (1) through (6) are consistent with the corresponding elements in the GALL Report AMP XI.M3. Because these elements are
 
consistent with the GALL Report elements, the staff finds that they are acceptable.
The staff confirmed that the existing Reactor Head Closure Studs Program at IP is part of the applicants ISI program under ASME Code, Section XI, Subsection IWB, Examination Category
 
B-G-1. The staff also confirmed that the program includes the preventive measures (e.g., rust
 
inhibitors, stable lubricants, appropriate materials) that are recommended in NRC RG 1.65 to
 
mitigate cracking and loss of material of reactor head closure studs, nuts, washers, and
 
bushings, and that these activities are performed under several plant-specific programs or
 
activities. The staff verified that these programs and activities include measures to ensure
 
conformance with closure stud material specifications during procurement, metal plating
 
activities to prevent corrosion or hydrogen embrittlement, use of manganese phosphate or other
 
acceptable surface treatment and stable lubricant during service, and implementation of the ISI examinations, which mandated by the ASME Code, Section XI, Examination B-G-1
 
requirements. The staff found this to be acceptable because it is in compliance with the requirements for reactor vessel closure stud components in the ASME Code, Section XI and because it is in conformance with the program element recommendations in GALL AMP XI.M3. The staff notes that this program is based on the ASME Section XI Code Edition 1998, up to 2000 addenda, although the applicants Inservice Inspection Program is based on 1989 Edition
 
of the Code. According to the 1998 Code Edition (Code Item B6.30), the program allows surface
 
or volumetric examination when closure studs are removed, which is not consistent with the requirements of GALL Report, Section XI.M3. The GALL Report program element detection of
 
aging effects states that the Code requires both surface and volumetric examination of studs
 
when removed. During an onsite audit, the staff asked Entergy to clarify why this is not an
 
exception to the GALL recommendations (Audit Item 82). By letter dated March 24, 2008, the applicant stated that GALL AMP XI.M3 also references ASME Section XI 2001 edition including the 2002 and 2003 Addenda, which allows surface or
 
volumetric examination when closure studs are removed. The applicant also clarified that the inservice inspection requirements in the 1998 Edition of the ASME Code, Section XI, inclusive
 
of the 2000 Addenda require either a surface examination or volumetric examination of the
 
closure studs when they are removed. This is the same examination requirement for these studs that is provided in the 2001 Edition of ASME Code, Section XI, inclusive of the 2003 Addenda referenced in GALL AMP XI.M3. The staff reviewed the two Code editions and verified
 
that the examination requirements for reactor vessel closure studs in the 1998 Edition of the 3-45ASME Code, Section XI (inclusive of the 2000 Addenda) is the same as that required for the studs in the 2001 Edition of the ASME Code, Section XI (inclusive of the 2003 Addenda). The
 
staff also noted that, in the applicants letter of June 11, 2008, the applicant clarified that the updated Code of Record for IP2 is the 2001 Edition of the ASME Code, Section XI, inclusive of
 
the 2003 Addenda, and that the Code of Record for IP3 is the 1989 Edition of the ASME Code, Section XI. The staff verified that the use of the 2001 Edition of the ASME Code, Section XI, inclusive of the 2003 Addenda is consistent with the Code editions referenced for use in GALL AMP XI.M3. The staff also confirmed that the inservice inspection bases for the reactor vessel closure studs in the 1998 Edition of the ASME Code, Section XI, inclusive of the 2000 Addenda, are the same as, and are consistent with, the inservice inspection bases for the closure studs in
 
the 2001 Edition of the ASME Code, inclusive of the 2003 Addenda, as referenced for use in GALL AMP XI.M3. Therefore, based on this review the staff finds that the inspection bases for
 
the reactor vessel closure studs at IP2 and IP3 are consistent with the Code requirements referenced in GALL AMP XI.M3 and are acceptable.
During an onsite audit, the staff reviewed the following four aspects of the RG 1.65 recommendations: material specification during procurement, avoiding the use of metal-plated
 
stud bolting to prevent corrosion or hydrogen embrittlement, use of manganese phosphate or
 
other acceptable surface treatments and stable lubricants during service, and ISI examination.
 
During the audit, Entergy provided access to plant documents that addressed the RG 1.65
 
recommendations. The staff determined that the procurement and material specifications
 
aspects of the RG 1.65 recommendations are followed as evidenced in purchase order
 
documents. The staff determined that the preventive measures recommended in the RG with
 
respect to lubricants, rust inhibitors, etc., are not applicable to IP since all bolts are plasma
 
bonded and since this fabrication method does not involve the use of lubricants. The staff noted
 
that the applicant implements the inspections of its reactor vessel closure studs in accordance
 
with the applicants Inservice Inspection Program (refer to AMP B.1.18) and the ASME Code, Section XI Examination Category B-G-1 requirements for reactor vessel closure assembly
 
components. The staff finds this to be acceptable because it is in compliance with the requirements of 10 CFR 50.55a and the ASME Code, Section XI and because it is in
 
conformance with the inspection recommendations for reactor vessel closure studs in GALL AMP XI.M3.
The staff also notes that this AMP, as recommended in RG 1.65, is applicable to closure studs and nuts constructed from materials with a maximum tensile strength limited to less than 170 ksi
 
(1,170 MPa). During discussions with the applicant during the audit, Entergy stated that, for IP2, results of testing from available test reports for the original and refurbished reactor head closure
 
stud and nut material showed a maximum tensile strength value < 170 ksi (1,170 MPa).
 
However, for IP3, the original and refurbished reactor head closure stud and nut materials
 
showed a maximum tensile strength value of 174 ksi (1,200 MPa), which was above the value in
 
RG 1.65. The applicant also stated that the slight deviation above 170 ksi (1,170 MPa) shown in
 
the test results does not significantly increase the materials potential for embrittlement and
 
stress corrosion cracking. After reviewing the tensile testing data on bolt materials for IP3, the
 
staff determined that the test results relating to several tests both for original and replaced studs
 
are made out of ASME SA-540 B23/24 materials with an average tensile strength less than 170
 
ksi (1,170 MPa). The staff determined that, for IP3, only a few of the test results for the original
 
bolt materials exceeded the 170 ksi (1,170 MPa) limit, with a maximum of 174 ksi (1,200 MPa).
 
The staff verified that, in order to address the issue with high tensile strength RV studs, the
 
applicant has appropriately identified cracking as an applicable aging effect requiring
 
management for the IP2 and IP3 reactor vessel closure assembly studs, nuts and washers, and 3-46 that the applicant credits the inservice inspections that are within the scope of this AMP and are implemented in accordance with the applicants Inservice Inspection Program, Examination
 
Category B-G-1 requirements as the basis for managing cracking in these components. The
 
staff finds this to be acceptable because it is in accordance with the parameters monitored or inspected and detection of aging effects program elements in GALL AMP XI.M3.
Since the program basis documents for the Reactor Head Closure Studs Program is based on the ASME Code, Section XI, Table IWB-2500-1, Examination Category B-G-1 requirements and
 
the recommendations in NRC RG 1.65, the staff finds that the applicants Reactor Vessel Closure Studs Program is consistent with recommended program element criteria in GALL AMP XI.M3 and is acceptable.
Operating Experience. LRA Section B.1.30 states that ISI-IWB examinations were conducted at IP2 and IP3 during 2004 and 2005. Results found to be outside of acceptable limits were repaired, replaced, or evaluated in accordance with ASME Section XI requirements. Detection
 
of degradation and corrective action prior to loss of intended function assure program
 
effectiveness in managing aging effects.
The applicant also stated that an ISI program self-assessment was completed in October 2004.
Review of the scope for refueling outage 2R16 (2004) and refueling outage 3R13 (2005) verified
 
that the proper inspection percentages had been planned for both outages. A follow-up
 
assessment for IP2 in March 2006 ensured that all inspection activities required to close out the
 
third 10-year ISI interval were scheduled for refueling outage 2R17. The applicant concluded
 
that confirmation of compliance with program requirements assures continued effective
 
management of loss of component material. QA surveillances in 2005 and 2006 revealed no
 
issues or findings that could impact program effectiveness.
The staff reviewed the QA self-assessment documents for the applicants Inservice Inspection Program for IP2 and IP3 and found that QA self-assessments reported that the applicants
 
Inservice Inspection Program appropriately identified and took corrective measures on the
 
inspection findings. The staff noted that there are several deficiencies identified in these reports
 
and verified that the applicant has taken appropriate corrective actions to address the
 
deficiencies that were identified in these reports. Based on this aspect of the applicants
 
program, the staff did not identify any issues with the applicants program that would impact the
 
effectiveness of the Reactor Head Closure Studs Program in managing the aging effects that
 
are applicable to the RV closure stud assembly components.
Therefore, based on this review, the staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR
 
Section A.1.2.3.10. The staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.29 and A.3.1.29, the applicant provided the UFSAR supplement for the Reactor Head Closure Studs Program. The staff reviewed these sections
 
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 applicants Reactor Head Closure Studs Program, the staff finds that all program elements are consistent with the GALL Report. The
 
staff concludes that the applicant has demonstrated that the effects of aging will be adequately
 
managed so that the intended functions will be maintained consistent with the CLB for the 3-47 period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this program and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3.0.3.1.12  Reactor Vessel Head Penetration Inspection Program
 
Summary of Technical Information in the Application. LRA Section B.1.31 describes the existing Reactor Vessel Head Penetration Inspection Program as consistent with GALL AMP XI.M11A, Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of
 
Pressurized Water Reactors.
LRA Section B.1.31 states that the Reactor Vessel Head Penetration Inspection Program manages primary water stress corrosion cracking (PWSCC) of nickel-based alloy reactor vessel
 
head penetrations exposed to borated water to maintain pressure boundary function. This
 
program was developed in response to NRC Order EA-03-009. The applicant uses the ASME Section XI, Subsection IWB Inservice Inspection and Water Chemistry Control Programs with
 
this program to manage cracking of the reactor vessel head penetrations. A combination of bare
 
metal visual examination (external surface of head) and non-visual examination (underside of
 
head) techniques detects cracking. Procedures are developed for reactor vessel head bare
 
metal inspections and calculations of plant susceptibility ranking. Entergy will continue to
 
implement commitments to (1) NRC orders, bulletins, and GLs on nickel alloys and (2)
 
staff-accepted industry guidelines.
Staff Evaluation. During its audit and review, the staff reviewed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Reactor Vessel Head Penetration Inspection Program and basis documents to verify consistency with the GALL Report AMP XI.M11A. Details of the staffs audit
 
of the applicants AMP are documented in the Audit Report. As documented in the report, the
 
staff found that the Reactor Vessel Head Penetration Inspection Program elements (1) through (6) are consistent with the corresponding elements in the GALL Report AMP XI.M11A. Because
 
these elements are consistent with the GALL Report elements, the staff finds that they are
 
acceptable.
During audit, the staff confirmed that all 97 penetrations at IP2 and all 78 penetrations at IP3 reactor vessel heads and associated J-groove welds, and the adjoining upper RV closure heads
 
are within the scope of this program.
The staff noted that this program was developed based on the commitments that the applicant made in response to the staffs augmented inspection and flaw evaluation requirements that
 
were issued in NRC Order EA-03-009, as amended in the applicants response to the staffs
 
augmented inspection and flaw evaluation requirements that were issued in First Revised Order
 
EA-03-009 (henceforth referred to the Order as Amended). The staff verified the applicants
 
commitments made in the applicants responses to the Order as Amended are within the scope
 
of the program, as provided in the following Entergy Letters:  Entergy Letter No. NL-03-037, dated March 3, 2003 (ADAMS Accession number ML030650884) Entergy Letter No. NL-04-026, dated March 11, 2004 (ADAMS Accession number
 
ML041610278) 3-48 The staff noted that the applicant credits its Water Chemistry Control Program - Primary and Secondary in conjunction with this program to manage cracking of the reactor vessel head
 
penetration nozzles and their associated nickel alloy nozzle-to-vessel penetration welds. The
 
staff finds this to be acceptable because it is consistent with the AMRs that invoke this program
 
for aging management, and because this in accordance with the preventive actions program element criteria that are recommended in GALL Report AMP XI.M11A.
The staff noted that the program uses a combination of bare metal visual examination (external surface of head) and non-visual examination (underside of head) techniques as the bases for
 
managing cracking that is postulated to occur in these nozzle components. The staff finds this
 
to be acceptable because it is in conformance with the detection of aging effects program element in GALL Report AMP XI.M11-A.
The staff noted and verified that the applicant has established plant procedures that govern the applicants augmented bare metal visual inservice inspection activities for the IP2 and IP3 upper reactor vessel RV closure heads and the non-visual non-destructive examination (non-visual
 
NDE) methods (i.e., either ultrasonic testing (UT) or eddy current testing (ECT)) for the nickel
 
alloy upper RV closure head penetration nozzles and their associated nickel alloy penetration
 
welds. The staff also noted that the applicant has established plant procedures for calculating
 
the susceptibility rankings of the IP2 and IP3 upper RV closure head penetration nozzles in
 
accordance with susceptibility ranking calculation requirements of the Order as Amended.
By letter dated March 24, 2008, in response to an audit question (Audit Item 83), the applicant clarified that, as of the last refueling outage for IP2 (Spring 2006), the upper RV closure head
 
penetration nozzles at IP2 are categorized as a moderate susceptibility category penetration
 
nozzles, as calculated using the staffs required susceptibility calculation equations that are
 
given in the Order as Amended, and as of the last refueling outage for IP3 (Spring 2007), the
 
upper RV closure head penetration nozzles at IP3 are categorized as a high susceptibility
 
category penetration nozzles, as calculated using the same required susceptibility calculation
 
equations. The staff finds this to be acceptable because it is in compliance with the
 
requirements in the Order as amended, and because this is consistent with the detection of aging effects and monitoring and trending program elements in GALL Report AMP XI.M11A.
The staff verified that the applicant has established an augmented inspection program plan for these Class 1 penetration nozzles that addresses all of the bare metal visual and non-visual
 
NDE inspection requirements in the Order as amended for the upper RV closure head
 
penetrations, as ranked for the moderate susceptibility ranking for IP2 and the high
 
susceptibility ranking for IP3, and approved for relaxation from the requirements of the Order as
 
Amended in the following NRC safety evaluations:  Safety evaluation for IP2 dated February 27, 2006, granting a reduced vertical inspection
 
coverage for the RV closure head penetration nozzles based on the inaccessibility of the
 
threaded non-pressure boundary portions of the nozzles Safety evaluation for IP2 dated October 15, 2004, granting a reduced inspection
 
coverage (to 95% coverage) for bare metal examinations required to be performed on
 
the IP2 upper RV closure head  Safety evaluation for IP3 dated April 4, 2005, granting a reduced vertical inspection
 
coverage for the RV closure head penetration nozzles based on the inaccessibility of the
 
threaded non-pressure boundary portions of the nozzles 3-49 Safety evaluation for IP3 dated March 18, 2005, granting a reduced inspection coverage (to 95% coverage) for bare metal examinations required to be performed on the IP3
 
upper RV closure head The staff finds that the inspection bases granted in these safety evaluations are acceptable because they are in conformance with the required inspection bases that are defined in the
 
detection of aging effects and monitoring and trending program elements in GALL Report AMP XI.M11A.
In the same response (Audit Item 83), Entergy also stated that the Boric Acid Corrosion Prevention Program (B.1.5) complements the Reactor Vessel Head Penetration Inspection
 
Program by performing visual inspection of the reactor vessel head at locations specified by
 
IP2-specific and IP3-specific plant procedures. The staff noted that these procedures provide
 
general guidance for performing the system walkdowns and bare metal visual examinations of
 
both the IP2 and IP3 upper RV closure heads and other ASME Code Class 1 components for
 
evidence of boric acid leakage, boric acid residues, or signs of corrosion.
The staff verified that the applicant coordinates the activities with reactor vessel disassembly and the inspections that are required by Order as Amended, in accordance with the applicants
 
implementing procedures and outage scheduling.
Based on its review of the applicants augmented inspection program plan for upper RV closure heads and its associated penetrations nozzles, the staff verified that the applicant credits the
 
programs UT and ECT examination methods for the detection of cracking of nozzle
 
penetrations and their nickel alloy penetration welds. The staff also verified that the applicant
 
credits its bare metal visual inspections of the upper RV heads with the detection of evidence of
 
reactor coolant leakage from the upper RV closure head penetration nozzles, boric acid
 
residues that precipitate out on the upper RV head or adjacent components, or corrosion
 
products that result from rusting of the low-alloy steel materials used to fabricate the RV heads
 
or shells. The staff finds that this is acceptable because the inspection methods that are
 
credited for examination and the parameters that these inspections methods are credited for are
 
consistent with the staffs recommended criteria that are provided in the parameters
 
monitored/inspected and detection of aging effects program elements in GALL Report AMP XI.M11A. Based on this review, the staff finds that the applicant Reactor Vessel Head Penetration Inspection Program is acceptable because the program is designed to be in compliance with the
 
requirements of the Order as Amended and because the staff has verified that the program
 
elements for the program are in conformance with the program element criteria that are recommended in GALL Report AMP XI.M11A.
Operating Experience. LRA Section B.1.31 states that bare metal visual examination of no less than 95 percent of the IP2 reactor vessel head surface and 360 degrees around each head
 
penetration nozzle completed in November 2004 (refueling outage 2R16) consistently with the
 
requirements of NRC Order EA-03-009 and approved relaxation request found no indications of
 
reactor vessel head degradation or leakage due to cracking.
The applicant also stated that bare metal visual examination of no less than 95 percent of the IP3 reactor vessel head surface and 360 degrees around each head penetration nozzle
 
completed during March 2005 (refueling outage 3R13), consistent with the requirements of NRC 3-50 Order EA-03-009 and approved relaxation requests, found no indications of reactor vessel head degradation or leakage due to cracking. A QA surveillance of these inspections found all
 
regulatory requirements met.
Further, the applicant stated that the most recent inspection of the IP2 reactor vessel head penetrations completed in May 2006 (refueling outage 2R17) used a procedure written from
 
lessons learned during the refueling outage 2R16 and refueling outage 3R13 inspections. The
 
results of this refueling outage 2R17 inspection were satisfactory. This inspection noted that
 
bare metal areas reviewed had significant improvement in the cleanliness in the base metal and
 
annulus around the penetrations. A QA surveillance of these inspections found all regulatory
 
requirements met. A self-assessment of the inspection process noted improvements that should
 
be made before future use of the process. Corrective actions implemented these process
 
improvements. Absence of cracking with continuous improvement of material condition assures
 
program effectiveness in managing aging effects. Use of recent operating experience and
 
industry guidance in the development of site-wide procedures with site QA oversight and
 
continuous process improvement assures continued program effectiveness in managing aging
 
effects for passive components.
The staff verified that the applicants Reactor Vessel Head Penetration Inspection Program was developed and is being implemented to address the cracking and boric acid leakage events that
 
have been identified and discussed in the Order as Amended, and in NRC Bulletins 2002-01
 
and 2002-02, that were issued prior to the Order as Amended.
The staff verified that the latest augmented inspection reports for the IP2 and IP3 upper RV closure head and its penetration nozzles are given in the following inspection reports that were
 
required to be reported in accordance with the requirements of the Order as Amended:  Entergy Letter No. NL-05-001 for IP2, dated January 17, 2005 (ML050340067) -
 
reporting bare metal visual examination inspection results performed on the IP2 head. Entergy Letter No. NL-06-064 for IP2, dated July 12, 2006 (ML062140076) - reporting
 
non-visual NDE inspections on all 97 upper RV closure head penetration nozzles using
 
UT and ECT. Entergy Letter No. NL-05-044 for IP3, dated May 31, 2005 (ML051590104) - reporting
 
bare metal visual examination inspection results performed on the IP3 head. Entergy Letter No. NL-06-064 for IP3, dated July 12, 2006 (ML062140076) - reporting
 
non-visual NDE inspections on all 97 upper RV closure head penetration nozzles using
 
both UT and ECT).
The staff verified that in the letters, Entergy reported that the inspections did not identify any indications of reactor coolant pressure boundary leakage from the IP2 and IP3 upper RV
 
closure head penetration nozzles or evidence of cracking in these nozzles or their structural
 
nickel-alloy welds. By letter dated January 17, 2005, the applicant did report some Conoseal
 
leakage at IP2 and IP3. The staffs evaluation on the applicants steps to correct Conoseal
 
leakage is given in SER Section 3.0.3.1.1. Based on this review, the staff also finds that the
 
applicant has been taking appropriate steps to determine whether there is any site-specific
 
operating experience on cracking of the IP2 and IP3 upper RV closure head penetration nozzles
 
or on reactor coolant leakage from the nozzles onto the upper RV closure head or adjacent
 
Class 1 components.
3-51 Based on this review, the staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR
 
Section A.1.2.3.10 because the staff has verified that applicant is currently performing the
 
mandatory examinations of the IP2 and IP3 upper RV closure heads and their penetration
 
nozzles in order to address the generic operating experience discussed in the Order as
 
Amended. Based on this review, the staff finds this program element to be acceptable.
UFSAR Supplement. In LRA Sections A.2.1.30 and A.3.1.30, the applicant provided the UFSAR supplement for the Reactor Vessel Head Penetration Inspection Program. The staff reviewed
 
these sections 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 applicants Reactor Vessel Head Penetration Inspection Program, the staff finds that all program elements are consistent with the
 
GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging
 
will be adequately managed so that the intended 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 program and concludes that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.1.13  Selective Leaching Program
 
Summary of Technical Information in the Application. LRA Section B.1.33 describes the Selective Leaching Program as a new program that will be consistent with GALL AMP XI.M33, Selective Leaching of Materials.
In the LRA, the applicant stated that the Selective Leaching Program will ensure the integrity of components made of gray cast iron, bronze, brass, and other alloys exposed to raw water, treated water, or groundwater that may lead to selective leaching. The program will include a
 
one-time visual inspection, hardness measurement (where feasible based on form and
 
configuration) or other industry-accepted mechanical inspection techniques of selected
 
components that may be susceptible to selective leaching to determine whether loss of material
 
due to selective leaching has occurred and whether the process will affect component ability to
 
perform intended functions through the period of extended operation.
By letter dated March 24, 2008, the applicant amended the program description to add the following:
The selected set or representative sample size will be based on Chapter 4 of EPRI document 107514, Age Related Degradation Inspection Method and
 
Demonstration, which outlines a method to determine the number of inspections
 
required for 90% confidence that 90% of the population does not experience
 
degradation (90/90). Each group of components with the same material-
 
environment combination is considered a separate population.
Staff Evaluation. During its audit and review, the staff reviewed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Selective Leaching Program to verify consistency with GALL AMP XI.M33. Details of the staffs audit of the applicants AMP are documented in the Audit Report.
 
As documented in the report, the staff found that the Selective Leaching Program elements (1) 3-52through (6) are consistent with the corresponding elements in GALL AMP XI.M33. Because these elements are consistent with the GALL Report elements, the staff finds that they are
 
acceptable.
During the audit, the staff reviewed the applicants program evaluation document and confirmed that the program scope includes all systems that could be susceptible to selective leaching.
 
These include cast iron, brass, bronze, or aluminum-bronze and exposed to raw water, treated
 
water, or groundwater environments. Systems that have this combination of material and
 
environment include susceptible components that include piping, valve bodies and bonnets, pump casings, and heat exchanger (HX) components.
Operating Experience. LRA Section B.1.33 states that the Selective Leaching Program is a new program. When implementing this new program, the applicant will consider as its basis industry
 
operating experience in the operating experience element of the GALL Report program
 
description. Plant-specific operating experience is not inconsistent with the operating
 
experience in the GALL Report program description.
The program is based on the GALL Report program description, which in turn is based on industry operating experience. Such operating experience assures program management of
 
aging effects so components continue to perform intended functions consistent with the CLB
 
through the period of extend operation.
The staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.32 and A.3.1.32, the applicant provided the UFSAR supplement for the Selective Leaching Program. The staff reviewed these sections and
 
determines that the information in the UFSAR supplement is an adequate summary description
 
of the program, as required by 10 CFR 54.21(d). The applicant stated in the LRA that this
 
program will be implemented prior to the period of extended operation. In addition, the applicant
 
stated that this new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.M33, Selective Leaching of Materials (Commitment 23).
By letter dated July 27, 2009, the applicant added a new commitment (Commitment 40) that states that plant specific and appropriate industry operating experience will be evaluated and
 
lessons learned will be used to establish appropriate monitoring and inspection frequencies to
 
assess aging effects for the new aging management programs.
Conclusion. On the basis of its audit and review of the applicants Selective Leaching Program, the staff finds that all program elements are consistent with the GALL Report. The staff
 
concludes that the applicant has demonstrated that the effects of aging will be adequately
 
managed so that the intended 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 program and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3-53 3.0.3.1.14  Service Water Integrity Program Summary of Technical Information in the Application. LRA Section B.1.34 describes the existing Service Water Integrity Program as consistent with GALL AMP XI.M20, Open-Cycle Cooling
 
Water System.
The Service Water Integrity Program implements the recommendations of GL 89-13 for managing the effects of aging on the service water (SW) system, through the period of extended
 
operation. The program inspects components for erosion, corrosion, and biofouling to confirm
 
the heat transfer capability of safety-related heat exchangers cooled by SW. Chemical treatment
 
with biocides and sodium hypochlorite and periodic cleaning and flushing of loops infrequently
 
used are methods for controlling fouling within the heat exchangers and managing loss of
 
material in SW components.
Staff Evaluation. During its audit and review, the staff reviewed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff reviewed the
 
program elements of the Service Water Integrity Program to verify consistency with GALL AMP XI.M20. Details of the staffs audit of the applicants AMP are documented in the Audit Report.
 
As documented in the report, the staff found that the Service Water Integrity Program elements (1) through (6) are consistent with the corresponding elements in GALL AMP XI.M20. Because
 
these elements are consistent with the GALL Report elements, the staff finds that they are
 
acceptable.
Operating Experience. LRA Section B.1.34 states that in July 2003 a peer assessment of the IP3 SW program conducted by EPRI found some areas for improvement. Corrective actions
 
included changes to chlorination practices and evaluation of new software tools for heat
 
exchanger performance analysis. Assessment of practices by offsite review groups and
 
appropriate corrective action assure continued program effectiveness in managing aging effects
 
for passive components.
The applicant stated that self-assessments of the IP2 and IP3 ultimate heat sink (GL 89-13 Program) in April 2004 and June 2005 focused on adequate maintenance of ultimate heat sink
 
subcomponents and their operation within the plant design basis. The applicant concluded that
 
detection of program weaknesses and subsequent corrective actions assure continued program
 
effectiveness in managing loss of component material.
In the LRA, the applicant noted that in December 2005, the staff completed an ultimate heat sink performance review at IP2 to verify that Entergy continually monitored performance of the
 
instrument air closed cooling water heat exchangers and to detect potential deficiencies which
 
could mask degraded performance. The staff reviewed the design basis documents and final
 
safety analysis report for whether testing acceptance criteria were appropriate. The staff also
 
reviewed the latest inspection reports for the heat exchangers and evaluated the results of eddy
 
current testing for use of appropriate tube plugging criteria. In addition, the staff verified whether
 
Entergy had maintained its commitments to GL 89-13 on heat exchanger inspection and testing
 
and made no findings. Confirmation of program compliance with established standards and
 
regulations assures continued program effectiveness in managing loss of component material.
As part of the ultimate heat sink performance review at IP3 in 2005, the staff observed the condition of a component cooling water (CCW) heat exchanger after it had been opened for
 
periodic inspection and cleaning and reviewed preventive maintenance of this safety-related 3-54 heat exchanger for adequacy in minimizing the effects of biofouling on its performance. The staff visually examined the heat exchanger when it was first opened to assess the adequacy of
 
Entergys periodic cleaning to avoid excessive fouling, compared the as-found eddy current
 
testing results to previous testing data, and made no significant findings. Reviews of program
 
specifics prove program effectiveness in managing loss of component material.
The applicant also noted that in June 2006, the staff completed an ultimate heat sink performance review at IP3 for whether Entergy had used the periodic maintenance method
 
outlined in EPRI NP-7552, Heat Exchanger Performance Monitoring Guidelines, for the IP3
 
emergency diesel generator (EDG) lube oil coolers. The staff reviewed the results of the last
 
inspections and eddy current tests for each of the lube oil coolers and made no significant
 
findings. Confirmation of program compliance with established standards and regulations
 
assures continued program effectiveness in managing loss of component material.
Further, the applicant stated, in June 2006, the staff completed at IP2 an ultimate heat sink performance review which included the CCW heat exchangers and the EDG jacket water and
 
lube oil heat exchangers. The staff reviewed documents for whether Entergy had detected and
 
corrected common cause heat sink performance problems with the potential to increase risk.
 
The staff also reviewed records for whether Entergy had examined potential macro fouling (silt, debris, etc.) and biofouling issues closely. To ensure adequate implementation of Generic Letter
 
89-13, the staff reviewed Entergys inspection, cleaning, and eddy current testing methods and
 
frequency with the responsible system engineers. The staff compared surveillance test and
 
inspection data, including as-found conditions and eddy current summary sheets, to the
 
established acceptance criteria to verify whether the results were acceptable and the system
 
heat exchanger operation was consistent with design. The staff reviewed heat exchanger
 
design-basis values and assumptions, plugging limit calculations, and vendor information to
 
verify whether they were incorporated into the heat exchanger inspection and maintenance
 
procedures. The staff reviewed a sample of condition reports for the CCW and EDG heat
 
exchangers and the SWS for whether Entergy had detected, characterized, and corrected
 
problems related to these systems and components appropriately and made no significant
 
findings. Confirmation of program compliance with established standards and regulations
 
assures continued program effectiveness in managing loss of component material.
The staffs review of Appendix B of the LRA and of the applicants basis document found them to conclude that the Service Water Integrity Program has been effective in managing those
 
aging effects for which it is credited. The staff noted, however, that this conclusion is based on
 
the results of one peer assessment, one self-assessment and five NRC inspections of the GL
 
89-13 program. Since the guidelines of GL 89-13 are directed at ensuring the performance of safety-related systems and components exposed to SW, it is not clear how the results of
 
inspections performed under the GL 89-13 program could be used to confirm the absence of
 
aging effects in nonsafety-related components within scope for license renewal. In addition, NRC inspections of the GL 89-13 program are based on a limited sample of safety-related
 
components. For example, NRC Inspection Procedure IP 93810 (Service Water System
 
Operational Performance Inspection) specifically states that the selection of SW system
 
components and systems should consider those that have been dominant contributors to the
 
SW system operational risk at the plant or similar plants. In RAI AUX-2, dated May 7, 2008, the staff requested the applicant to clarify whether the Service Water Integrity Program is credited for aging management of the nonsafety-related
 
components of the SW system that are within scope for license renewal, and if so, to provide 3-55 evidence for the conclusion presented in the LRA, that this AMP is effective in managing age-related degradation. If this AMP is not credited, the staff requested the applicant to identify the
 
AMP(s) that are credited for aging management of the nonsafety-related components of the SW
 
system that are within scope for license renewal and to provide the basis for concluding that these programs have been or will be effective for managing aging during the license renewal
 
period.By letter dated June 5, 2008, the applicant provided the following response:
The Service Water Integrity Program is credited for managing the effects of aging on components as listed in LRA Section 3 tables regardless of safety
 
classification.
The materials of construction and operating environment for components and piping in nonsafety-related and safety-related portions of the SWS are identical.
Therefore, the aging effects managed by the Service Water Integrity Program are
 
identical.
As stated in LRA Section B.1.34, the Service Water Integrity Program is consistent with NUREG-1801, Section XI.M20, Open Cycle Cooling Water
 
System and includes activities that apply to both safety-related and nonsafety-
 
related components described below. 1. Component inspections for erosion, corrosion, and biofouling. Results of these inspections have been used to determine the corrective actions
 
required to preclude recurrence of unacceptable conditions, as described
 
in LRA Section B.0.3. All components in the SWS [service water system]
 
flowpath are within the scope of such corrective actions regardless of
 
safety classification. 2. Safety-related heat exchangers in the program are tested to verify heat transfer capabilities. Nonsafety-related heat exchangers cooled by
 
service water are periodically inspected. These inspections are sufficient
 
to manage aging effects since there is no license renewal component
 
intended function of heat transfer. 3. Chemical treatment using biocides and sodium hypochlorite and periodic cleaning and flushing of infrequently used loops are applied to all
 
components in the SWS flowpath regardless of safety classification. In
 
this manner, the program remains effective for managing aging effects for
 
all components in the SWS. 4. GL 89-13 inspections are performed on nonsafety-related piping. For example, during [refueling outage] 2R18 in March and April 2008, approximately 10% of the scheduled GL 89-13 program volumetric weld
 
examinations were conducted on nonsafety-related SWS piping welds, and approximately 25% of the scheduled GL 89-13 program visual
 
inspections were conducted on nonsafety-related SWS piping. Scope
 
expansion for indications found by GL 89-13 inspections of nonsafety-
 
related piping is based on consideration of location, severity, materials, 3-56 previous inspection history, and other relevant factors. 5. System walkdowns apply to both SWS safety-related and nonsafety-related components.
Considering that activities under the Service Water Integrity Program apply to both safety-related and nonsafety-related components, the program
 
effectiveness conclusions of recent peer and self assessments as well as NRC
 
inspections described in the operating experience section are applicable to all
 
components crediting the program for aging management. The staff noted that the scope of GALL AMP XI.M20, Open-Cycle Cooling Water System, is applicable to safety-related service water system components that are tied to the ultimate heat
 
sink for the facility. The applicants response clarifies that it is conservatively applying its
 
Service Water Integrity Program to both the safety-related and nonsafety-related components
 
that are exposed to the service water environment. Thus, based on the staffs review of the Service Water Integrity Program, as amended in the applicants response to RAI AUX-2, the
 
staff finds the applicants has provided an acceptable basis for managing aging effects in the
 
nonsafety-related service water system components consistent with the program elements in GALL AMP XI.M20. The staffs concern in RAI AUX-2 is resolved.
UFSAR Supplement. In LRA Sections A.2.1.33 and A.3.1.33, the applicant provided the UFSAR supplement for the Service Water Integrity Program. The staff reviewed these sections 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 applicants Service Water Integrity Program, the staff finds all program elements consistent with the GALL Report. The staff
 
concludes that the applicant has demonstrated that the effects of aging will be adequately
 
managed so that the intended 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 program and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3.0.3.1.15  Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program
 
Summary of Technical Information in the Application. LRA Section B.1.37 describes the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program as a new program that will be consistent with GALL AMP XI.M12, Thermal Aging Embrittlement of Cast Austenitic
 
Stainless Steel (CASS).
LRA Section B.1.37 states that the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program augments the inspection of reactor coolant system components in accordance
 
with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section XI. The augmented inspection detects the effects of loss of fracture toughness due to
 
thermal aging embrittlement of CASS components. This AMP determines the susceptibility of
 
CASS components to thermal aging embrittlement based on casting method, molybdenum
 
content, and percent ferrite. The program manages aging through either enhanced volumetric
 
examination or flaw tolerance evaluation. Additional inspections or evaluations to demonstrate
 
adequate material fracture toughness are not required for components that are not susceptible 3-57 to thermal aging embrittlement. In the staffs letter from Christopher Grimes, NRC, to Douglas Walters, NEI, the staff provided its basis for establishing that CASS pump casings and valve
 
bodies do not need to be screened for thermal aging embrittlement. The existing ASME Section XI inspection requirements, including the alternative requirements of ASME Code Case
 
N-481 for pump casings, are adequate for all pump casings and valve bodies.
Staff Evaluation. During its audit and review, the staff reviewed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff reviewed the
 
program elements of the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program to verify consistency with GALL AMP XI.M12. Details of the staffs audit of the
 
applicants AMP are documented in the Audit Report. As documented in the report, the staff
 
found that the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program elements (1) through (6) are consistent with the corresponding elements in GALL AMP XI.M12.
 
Because these elements are consistent with the GALL Report elements, the staff finds that they
 
are acceptable.
Operating Experience. LRA Section B.1.37 states that the Thermal Aging Embrittlement of CASS Program is a new program. When implementing this new program the applicant will
 
consider as its basis industry operating experience in the operating experience element of the
 
GALL Report program description. Plant-specific operating experience is not inconsistent with
 
the operating experience in the GALL Report program description.
The Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program is based on the GALL Report program description, which in turn is based on industry operating experience.
 
Such operating experience assures program management of the effects of aging so
 
components continue to perform intended functions consistent with the CLB through the period
 
of extended operation.
The staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.36 and A.3.1.36, the applicant provided the UFSAR supplement for the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program.
 
The staff reviewed these sections and determines that the information in the UFSAR
 
supplement is an adequate summary description of the program, as required by
 
10 CFR 54.21(d). The applicant stated in the LRA that this program will be implemented prior to
 
the period of extended operation. In addition, the applicant stated that this new program will be
 
implemented consistent with the corresponding program described in NUREG-1801 Section XI.M12, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) (Commitment
 
26).By letter dated July 27, 2009, the applicant added a new commitment (Commitment 40) that states that plant specific and appropriate industry operating experience will be evaluated and
 
lessons learned will be used to establish appropriate monitoring and inspection frequencies to
 
assess aging effects for the new aging management programs.
Conclusion. On the basis of its audit and review of the applicants Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program, the staff finds that all program elements presented
 
in the program basis documents are consistent with the GALL report. The staff concludes that 3-58 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 program and concludes that it provides an adequate summary description of the
 
program, as required by 10 CFR 54.21(d).
3.0.3.1.16  Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program Summary of Technical Information in the Application. LRA Section B.1.38 describes the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program as a new program that will be consistent with GALL AMP XI.M13, Thermal Aging and Neutron
 
Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS).
The Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program augments the reactor vessel internals visual inspection in accordance with the ASME Code, Section XI, Subsection IWB. This augmented inspection manages the effects of loss of
 
fracture toughness due to thermal aging and neutron embrittlement of CASS components. This
 
AMP determines the susceptibility of CASS components to thermal aging or neutron irradiation (neutron fluence) embrittlement based on casting method, molybdenum content, operating
 
temperature, and percent ferrite. For each potentially susceptible component, aging management is through either a component-specific evaluation or a supplemental examination
 
of the affected component as part of the ISI program during the license renewal term.
Staff Evaluation. During its audit and review, the staff reviewed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program to verify consistency with GALL AMP XI.M13. Details of the
 
staffs audit of the applicants AMP are documented in the Audit Report. As documented in the
 
report, the staff found that the Thermal Aging and Neutron Irradiation Embrittlement of Cast
 
Austenitic Stainless Steel Program elements (1) through (6) are consistent with the corresponding elements in GALL AMP XI.M13. Because these elements are consistent with the
 
GALL Report elements, the staff finds that they are acceptable.
Operating Experience. LRA Section B.1.38 states that the Thermal Aging and Neutron Irradiation Embrittlement of CASS Program is a new program. When implementing this new
 
program the applicant will consider as its basis industry operating experience in the operating
 
experience element of the GALL Report program description. Plant-specific operating
 
experience is not inconsistent with the operating experience in the GALL Report program
 
description.
The Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program is based on the GALL Report program description, which in turn is based on industry
 
operating experience. Such operating experience assures program management of the effects
 
of aging so components continue to perform intended functions consistent with the CLB through
 
the period of extended operation.
The staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable.
3-59 UFSAR Supplement. In LRA Sections A.2.1.37 and A.3.1.37, the applicant provided the UFSAR supplement for the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic
 
Stainless Steel Program. The staff reviewed these sections and determines that the information
 
in the UFSAR supplement is an adequate summary description of the program, as required by
 
10 CFR 54.21(d). The applicant stated in the LRA that this program will be implemented prior to
 
the period of extended operation. In addition, the applicant stated that this new program will be
 
implemented consistent with the corresponding program described in NUREG-1801 Section XI.M13, Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless
 
Steel (CASS) (Commitment 27).
By letter dated July 27, 2009, the applicant added a new commitment (Commitment 40) that states that plant specific and appropriate industry operating experience will be evaluated and
 
lessons learned will be used to establish appropriate monitoring and inspection frequencies to
 
assess aging effects for the new aging management programs.
Conclusion. On the basis of its audit and review of the applicants Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel 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
 
program and concludes that it provides an adequate summary description of the program, as
 
required by 10 CFR 54.21(d).
3.0.3.2  Programs Consistent with the GALL Report with Exceptions or Enhancements In LRA Appendix B, the applicant stated that the following programs are, or will be, consistent with the GALL Report, with exceptions or enhancements:      Aboveground Steel Tanks Program      Bolting Integrity Program      Boraflex Monitoring Program      Diesel Fuel Monitoring Program      External Surfaces Monitoring Program      Fatigue Monitoring Program      Fire Protection Program      Fire Water System Program      Flux Thimble Tube Inspection Program      Masonry Wall Program      Metal-Enclosed Bus Inspection Program      Oil Analysis Program      Reactor Vessel Surveillance Program      Steam Generator Integrity Program      Structures Monitoring Program      Water Chemistry Control - Closed Cooling Water Program      Water Chemistry Control - Primary and Secondary Program For programs that the applicant claimed are consistent with the GALL Report, with exception(s) and/or enhancement(s), the staff performed an audit and review to confirm that those attributes 3-60 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
 
staffs audits and reviews are documented in the following sections.
3.0.3.2.1  Aboveground Steel Tanks Program
 
Summary of Technical Information in the Application. LRA Section B.1.1 describes the existing Aboveground Steel Tanks Program as consistent with GALL AMP XI.M29, Aboveground Steel
 
Tanks, with enhancements.
The Aboveground Steel Tanks Program manages loss of material from external surfaces of aboveground carbon steel tanks by periodic visual inspection of external surfaces and thickness
 
measurement of locations inaccessible for visual inspection.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the program elements of the Aboveground Steel Tanks Program to verify consistency with GALL AMP XI.M29. Details of the staffs audit of the applicants AMP are documented in the Audit
 
Report. As documented in the report, the staff found that the Aboveground Steel Tanks Program
 
elements scope of program, preventive actions, and parameters monitored or inspected, are consistent with the corresponding elements in GALL AMP XI.M29. Because these elements
 
are consistent with the GALL Report elements, the staff finds that they are acceptable.
The staff reviewed the enhancements to determine whether the program will be adequate to manage the aging effects for which it is credited. Enhancement 1. In the LRA, the applicant committed to implement the following enhancement to program elements detection of aging effects, and acceptance
 
criteria, prior to the period of extended operation:  Revise applicable procedures to
 
perform thickness measurements of the bottom surfaces of the condensate storage
 
tanks, city water tank (IP2), and the fire water tanks once during the first ten years of the
 
period of extended operation.
The staff finds this enhancement acceptable because it establishes the thickness measurements for the bottom surfaces of these tanks as recommended in the GALL Report. Enhancement 2. In the LRA, the applicant committed to implement the following enhancement to program element monitoring and trending prior to the period of extended operation:  Revise
 
applicable procedures to require trending of thickness measurements when material loss is
 
detected.
The staff finds this enhancement acceptable because it establishes the practice of trending of thickness measurements as recommended in the GALL Report.
Operating Experience. LRA Section B.1.1 states that visual inspections detected corrosion on the top of the IP3 condensate storage tank in 2003 and 2005 and on the IP2 condensate
 
storage tank in 2004. Corrective actions cleaned and repainted the surfaces to prevent
 
recurrence. Visual inspections of the external surfaces of the gas turbine fuel storage tanks in
 
December 2006 detected no loss of material due to corrosion.
3-61 Thickness measurements of the gas turbine fuel storage tanks in April 2002 found pitting up to 60 percent through-wall with no loss of intended function. This pitting was repaired with a weld
 
overlay. Internal inspections of the IP2 fire water and the training center fire water storage tanks
 
in 2003 detected failure of the coating in several places but no appreciable metal loss, Corrective actions repaired the coating.
The staff confirmed detection of degradation and corrective action prior to loss of intended function assures program effectiveness in managing the aging effects for these passive
 
components.
Furthermore, the staff confirmed that the operating experience program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this
 
program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.1 and A.3.1.1, the applicant provided the UFSAR supplement for the Aboveground Steel Tanks Program. The staff reviewed these sections and
 
determines that the information in the UFSAR supplement is an adequate summary description
 
of the program, as required by 10 CFR 54.21(d).
The applicant has committed to implement the noted enhancements prior to entering the period of extended operation (Commitment 1).
Conclusion. On the basis of its audit and review of the applicants Aboveground Steel Tanks Program, the staff determines that those program elements, for which the applicant claimed
 
consistency with the GALL Report, are consistent. Also, the staff reviewed the enhancements to
 
the program elements and confirmed that their implementation prior to the period of extended
 
operation would make the existing program consistent with the GALL Report AMP to which it
 
was compared. The staff concludes that the applicant has demonstrated that the effects of
 
aging will be adequately managed so that the intended functions will be maintained consistent
 
with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff
 
also reviewed the UFSAR supplement for this program and concludes that it provides an
 
adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.2  Bolting Integrity Program
 
Summary of Technical Information in the Application. LRA Section B.1.2 describes the existing Bolting Integrity Program as consistent with GALL AMP XI.M18, Bolting Integrity, with
 
enhancement.
The Bolting Integrity Program relies on NUREG-1339, Resolution of Generic Safety Issue 29:
Bolting Degradation or Failure in Nuclear Power Plants, recommendations, industry recommendations, and EPRI NP-5769, Degradation and Failure of Bolting in Nuclear Power Plants, Volumes 1 and 2, for a comprehensive bolting integrity program with the exceptions noted in NUREG-1339 for safety-related bolting. The program relies on industry recommendations for comprehensive bolting maintenance as in EPRI TR-104213, Bolted Joint Maintenance & Application Guide, for pressure-retaining and structural bolting. The program applies bolting and torquing practices of safety- and nonsafety-related bolting for pressure-retaining components, NSSS component supports, and structural joints. The program
 
addresses all bolting regardless of size except reactor head closure studs, which are addressed 3-62 by the Reactor Head Closure Studs Program. The program periodically inspects closure bolting for signs of leakage that may be due to crack initiation, loss of preload, or loss of material due to
 
corrosion. The program also includes preventive measures to preclude or minimize loss of
 
preload and cracking.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the program elements of the Bolting Integrity Program to verify consistency with GALL AMP XI.M18.
 
Details of the staffs audit of the applicants AMP are documented in the Audit Report. As
 
documented in the report, the staff found that the Bolting Integrity Program elements scope of
 
program, parameters monitored or inspected, detection of aging effects, monitoring and trending, and acceptance criteria, are consistent with the corresponding elements in GALL AMP XI.M18. Because these elements are consistent with the GALL Report elements, the staff
 
finds that they are acceptable.
The staff reviewed the enhancement to determine whether the program will be adequate to manage the aging effects for which it is credited.Enhancement.
In the LRA, the applicant committed to implement the following enhancement to program element, preventive actions, specifically, [r]evise applicable procedures to clarify that
 
actual yield strength is used in selecting materials for low susceptibility to SCC and to clarify the
 
prohibition on use of lubricants containing MoS 2 for bolting.
This enhancement is based on EPRI guidance and staff recommendations in NUREG-1339 and is therefore acceptable.
In Audit Item 109, the staff asked the applicant if they have a bolting expert for IP2 and IP3 as recommended in the EPRI guidance. By letter dated March 24, 2008, the applicant stated that
 
the Maintenance Department provides the functions of the expert for bolting in accordance with
 
the EPRI guidance. The staff found this to be acceptable because it is consistent with the EPRI
 
guidance.In Audit Items 241 and 270, the staff asked the applicant why loss of preload was not an aging effect requiring management. The applicant stated that EPRI Mechanical Tools, EPRI 1010639 (which is an industry guidance document), does not list loss of preload as an aging effect
 
requiring management. The staff stated that other plants have listed loss of preload as an aging
 
effect requiring management and the Bolting Integrity Program used to manage the aging. In
 
addition, the GALL Report lists loss of preload as an aging effect requiring management and
 
lists the Bolting Integrity Program as the appropriate program to manage this aging effect. The
 
applicant stated that the Bolting Integrity Program includes provisions to manage loss of
 
preload. By letter dated December 18, 2007, the applicant revised its commitment and amended
 
the LRA to explicitly state that the Bolting Integrity Program manages the aging effect of loss of
 
preload. The staff finds the applicants response acceptable because it amended the LRA to
 
manage loss of preload which is consistent with the guidance in the GALL Report.
Operating Experience. LRA Section B.1.2 stated that visual inspections of bolted connections were documented during 2001 through 2005. Although corrosion products were found on some
 
bolting materials, the applicant did not identify any situations where loss of material had
 
precluded the bolted connection from performing its intended function. The applicant completed
 
corrective actions to ensure future integrity of the bolted connection. The applicant concluded 3-63 that identification of degradation and performance of corrective action prior to loss of intended function provide assurance that the program is effective for managing aging effects for passive
 
components.
The staff notes that the applicant uses plant procedures that address material and lubricant selection, design standards, and good bolting maintenance practices consistent with EPRI
 
guidance that results in few problems with bolting. By controlling the material (i.e., the maximum
 
yield strength), the applicant has not experienced SCC of pressure boundary bolting.
The staff confirmed that the operating experience program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.2 and A.3.1.2, the applicant provided the UFSAR supplement for the Bolting Integrity Program. The staff reviewed these sections and determines
 
that the information in the UFSAR supplement is an adequate summary description of the
 
program, as required by 10 CFR 54.21(d).
The applicant has committed to implement the noted enhancement prior to entering the period of extended operation (Commitment 2). The applicant has also committed to use the Bolting
 
Integrity Program to manage the loss of preload (Commitment 2).
Conclusion. On the basis of its audit and review of the applicants Bolting Integrity Program, the staff determines that those program elements, for which the applicant claimed consistency with
 
the GALL Report, are consistent. Also, the staff reviewed the enhancement to the program
 
element and confirmed that their implementation prior to the period of extended operation would
 
make the existing AMP consistent with the GALL Report AMP to which it was compared. The
 
staff concludes that the applicant has demonstrated that the effects of aging will be adequately
 
managed so that the intended 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 program and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.3  Boraflex Monitoring Program
 
Summary of Technical Information in the Application. LRA Section B.1.3 describes the existing Boraflex Monitoring Program as consistent with GALL AMP XI.M22, Boraflex Monitoring, with
 
exceptions.
The Boraflex Monitoring Program prevents degradation of the Boraflex panels in the spent fuel racks from compromising the criticality analysis supporting the design of the spent fuel storage
 
racks. The program relies on 1) areal density testing, 2) a predictive computer code, and 3)
 
determination of boron loss through correlation of silica levels in spent fuel water samples to
 
maintain the required five percent subcriticality margin. Corrective actions follow if test results
 
find that the five percent subcriticality margin cannot be maintained because of current or
 
projected Boraflex degradation. This program applies to IP2 only as no Boraflex is used for
 
criticality control of IP3 spent fuel.
Staff Evaluation. During its review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff reviewed the program 3-64elements of the Boraflex Monitoring Program to verify consistency with GALL AMP XI.M22.
Based on the staffs review, the staff determined that Boraflex Monitoring Program elements
 
scope of program, parameters monitored or inspected, monitoring and trending, and acceptance criteria, are consistent with the corresponding elements in GALL AMP XI.M22.
 
Because these elements are consistent with the GALL Report elements, the staff finds that they
 
are acceptable.
The staff reviewed the exceptions to determine whether the program is adequate to manage the aging effects for which it is credited.
Exception 1.
In the LRA, the applicant took the following exception to program element preventive actions:  NUREG-1801 specifies measuring gap formation by blackness testing.
 
The IPEC program specifies areal density measurements for boraflex degradation.
Exception 2.
In the LRA, the applicant took the following exception to program element detection of aging effects:  NUREG-1801 recommends blackness testing as a supplement to
 
areal density measurements for determining gap formations. The IPEC program specifies areal
 
density testing only.
For both exceptions, the applicant provided a footnote which read:
The NRC Staff, as documented in the SER for Oyster Creek, has accepted the position that areal density measurement in lieu of blackness testing is
 
acceptable. Areal density testing provides a direct measurement of in-rack
 
performance of Boraflex panels through measurement of gaps, erosion, and
 
general thinning. Blackness testing provides only an indication of neutron
 
absorber presence and does not quantitatively measure the Boron-10 areal
 
density of neutron absorber in each rack. Therefore, areal density along with the
 
monitoring of silica levels in the spent fuel pool provides adequate detection of
 
boraflex degradation.
The exceptions to the GALL Report relate to one of the types of periodic tests performed to monitor and detect Boraflex degradation. The GALL Report specifies neutron
 
attenuation/blackness testing be performed to determine gap formation in the Boraflex panels.
 
In response to Audit Item 21, by letter dated December 18, 2007, the applicant stated that areal density measurement (BADGER testing) provides a direct measurement of in-rack performance
 
of the boraflex panels through measurement of gaps, erosion and general thinning and
 
quantitatively measures the Boron-10 areal density. Blackness testing provides an indication of
 
neutron absorber presence only, and does not provide quantitative measurements of the
 
Boron-10 areal density. Therefore, the blackness testing is not required.
The staff reviewed the exceptions and concluded that since the areal density test is more quantitative than the blackness test, these exceptions are acceptable.
In RAI 3.0.3.3.3-1, dated April 18, 2008, the staff noted that the UFSAR, Revision 20, dated 2006, Section 14.2.1 states in part that, Northeast Technology Corporation report NET-173-01
 
and NET-171-02 are based on conservative projections of amount of boraflex absorber panel
 
degradation assumed in each sub-region. These projections are valid through the end of the
 
year 2006. The staff requested that the applicant confirm that the Boraflex neutron absorber panels in the IP2 spent fuel pool have been re-evaluated for service through the end of the 3-65 current licensing period, and that the applicant provides information on their plans for updating the Boraflex analysis during the period of extended operation.
In its response, dated May 16, 2008, the applicant provided the following information. BADGER testing was performed in February 2000, July 2003, and July 2006. The latest test data and
 
RACKLIFE [a computer-generated value of boron loss] predictive code indicate that the Boraflex
 
neutron absorbing panels will meet the TS requirements through the end of the current licensing
 
period. The next BADGER test will be performed prior to the end of calendar year 2009.
 
Periodic BADGER testing and RACKLIFE projections will continue through the period of
 
extended operation to confirm acceptable Boraflex condition. The appropriate UFSAR section
 
will be updated in the next revision to reflect this.
By letter dated October 20, 2008, the applicant transmitted the most recent UFSAR which included the following statement:
Based upon BADGER testing in calendar years 2003 and 2006 and RACKLIFE code projections, the validity of the criticality and boron dilution analysis
 
documented in NET-173-01 and NET-173-02 can be extended through the end
 
of the current license (September 30, 2013), provided BADGER testing is
 
performed during calendar year 2009 and again in 2012 to confirm the
 
progression of localized Boraflex dissolution.
Because the applicant updated its UFSAR to reflect that the analysis will be valid through the end of the current license, the staffs concern is resolved.
Operating Experience. LRA Section B.1.3 states that panels of Boraflex maintain adequate subcriticality of the fuel in the spent fuel racks. As Boraflex is susceptible to in-service
 
degradation, the applicant developed a RACKLIFE model of the IP2 spent fuel pool. Results of
 
Boron-10 areal density gage for evaluating racks (BADGER) testing in February 2000, July
 
2003, and again in July 2006, confirmed the predictions of the RACKLIFE computer model and
 
proved that the program effectively manages change in material properties (reduction in
 
neutron-absorbing capacity) for Boraflex neutron absorber panels.
The staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.10.The GALL Report, Section XI.M22 in Operating Experience, states:  The experience with Boraflex panels indicates that coupon surveillance programs are not reliable. Therefore, during the period of extended operation, the measurement of boron areal density correlated, through a predictive code, with silica levels in the pool water is verified. These monitoring programs provide assurance that degradation of Boraflex sheets is
 
monitored, so that appropriate actions can be taken in a timely manner if
 
significant loss of neutron-absorbing capability is occurring. These monitoring programs ensure that the Boraflex sheets will maintain their integrity and will be effective in performing its intended function.
3-66The applicant has provided information in a response to an Audit Item, and has updated its UFSAR to reflect the performance of BADGER testing. Therefore, the staff finds that the applicant has considered the appropriate plant-specific and industry operating experience.
UFSAR Supplement. In LRA Section A.2.1.3, the applicant provided the UFSAR supplement for the Boraflex 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 its review of the applicants Boraflex 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 exceptions and their
 
justifications and determines that the program  is adequate to manage the aging effects for
 
which it is credited. The staff concludes that the applicant has demonstrated that the effects of
 
aging will be adequately managed so that the intended 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 program and concludes that it provides an
 
adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.4  Diesel Fuel Monitoring Program
 
Summary of Technical Information in the Application. LRA Section B.1.9 describes the existing Diesel Fuel Monitoring Program as consistent with GALL AMP XI.M30, Fuel Oil Chemistry,
 
with exceptions and enhancements.
The Diesel Fuel Monitoring Program entails sampling for whether adequate diesel fuel quality is maintained to prevent loss of material and fouling in fuel systems. Periodic draining and
 
cleaning of tanks and verification of new oil quality before its introduction into the storage tanks
 
minimize exposure to fuel oil contaminants (e.g., water, microbiological organisms). Sampling
 
and analysis are in accordance with the IP2 and IP3 fuel oil purity technical specifications and
 
ASTM Standards D4057-95 and D975-95 (or later revisions of these standards). Thickness
 
measurements of storage tank bottom surfaces verify whether degradation has occurred. The
 
One-Time Inspection Program describes inspections planned to verify the effectiveness of the
 
Diesel Fuel Monitoring Program.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Diesel Fuel Monitoring Program to verify consistency with GALL AMP XI.M30. Details of the staffs audit of the applicants AMP are documented in the Audit Report.
 
As documented in the report, the staff found that the Diesel Fuel Monitoring Program element corrective actions is consistent with the corresponding element in GALL AMP XI.M30.
 
Because this element is consistent with the GALL Report element, the staff finds that it is
 
acceptable.
As documented in the Audit Report, the staff verified the sampling frequencies for the EDGs, gas turbine generators, diesel fire pump, Appendix R diesel generators, and security diesel
 
generator fuel oil storage tanks. Enhancements to the Diesel Fuel Monitoring Program, discussed below, include draining, cleaning, and inspection and bottom thickness measurement
 
once every ten years for the gas turbine generators fuel oil storage tanks, the EDGs fuel oil
 
storage and day tanks, and the Appendix R diesel generators fuel oil storage and day tanks. In 3-67 addition, an enhancement to the Diesel Fuel Monitoring Program provides for periodic sampling, near the bottom, once per month to determine water content in the gas turbine generators fuel
 
oil storage tanks, the EDGs fuel oil storage and day tanks, the diesel fire pumps storage tanks, the security diesel generator storage tank, and the Appendix R diesel generators fuel oil storage
 
tanks. The staff determined that the sampling frequencies are consistent with current industry
 
standards, and are consistent with the plant technical specifications. The sampling frequencies
 
will provide for timely detection of fuel oil contamination, and will allow corrective actions to be
 
taken, as needed, prior to the loss of intended function. On this basis, the staff finds these
 
sampling frequencies acceptable.
The staff reviewed the exceptions and enhancements to determine whether the program will be adequate to manage the aging effects for which it is credited.
Exception 1. In the LRA, the applicant took the following exception to the GALL Report program element scope of program:  NUREG-1801 recommends use of ASTM Standards D2276 and
 
D6217. Particulate testing is performed using the guidelines of ASTM Standard D2276.
The staff noted that the discussion of this exception in LRA Section B.1.9 includes a footnote, which states the following: ASTM Standard D6217 (particulate by filtration) is not used for
 
determination of particulate. Particulate testing is performed using standard D2276. The
 
guidelines of D2276 are appropriate for determination of particulates and the plant technical
 
specifications specify this standard. The staff noted that GALL Report, Section XI.M30 recommends ASTM D2276 and D6217 for the measurement of particulates in diesel fuel. The staff reviewed both standards and
 
determined that the guidelines of D2276 are appropriate for determination of particulates and
 
the plant technical specifications specify this standard. Therefore, the staff concludes that this
 
exception is acceptable.
Exception 2. In the LRA, the applicant took the following exception to the GALL Report program elements scope of program, parameters monitored or inspected, and acceptance criteria:
 
NUREG-1801 recommends use of ASTM Standards D1796 and D2709. Only ASTM Standard
 
D1796 is used for testing water and sediment.
The staff noted that the discussion of this exception in LRA Section B.1.9 includes a footnote, which states the following: The guidelines of ASTM Standard D1796 are used rather than those
 
of ASTM Standard D2709 (water and sediment by centrifuge for lower viscosities) for
 
determination of water and sediment. The two standards are applicable to oils of different
 
viscosities. Standard D1796 is applicable to the fuel oil used at IPEC.
ASTM Standard D1796 and 2709 are applicable to oils of different viscosities. Although the GALL Report specifies the use of ASTM Standard D2709, ASTM Standard D1796 is applicable
 
to the fuel oil used at IP. Determination of water and sediment are established in site
 
procedures. The staff also confirmed that the guidance presented in ASTM standard D1796
 
applies to fuel oils with the viscosity of that used at IP2 and IP3. Therefore, the staff concludes
 
that this exception is acceptable.
Exception 3.
In the LRA, the applicant took the following exception to the GALL Report program element preventive actions:  NUREG-1801 specifies fuel oil is maintained by addition of
 
biocides. IPEC does not add biocide to diesel fuel oil storage tanks.
3-68 The staff noted that the discussion of this exception in the Diesel Fuel Monitoring Program includes a footnote, which states the following:
IPEC does not add biocides to diesel fuel oil storage tanks. Since water contamination in the diesel fuel oil storage tanks is minimized, the potential for
 
MIC [microbiologically-influenced corrosion] is limited. The IPEC process for
 
review of site and industry operating experience ensures that if MIC is discovered
 
during future analyses, appropriate corrective actions will be taken, including
 
modification of program attributes, if appropriate.
The IP2 and IP3 program does not add biocides to diesel fuel oil storage tanks on a routine basis to prevent biological breakdown of the diesel fuel (i.e., microbiologically-influenced
 
corrosion). Rather, the program is focused on limiting the potential for microbiologically-
 
influenced corrosion by minimizing the water concentration of the fuel. If the results of routine
 
samples indicate evidence of MIC activity, the need for biocides is evaluated under the
 
corrective action program. If the evaluation deems them necessary to correct the condition, biocides will be used. This practice is consistent with guidance contained in ASTM Special
 
Technical Publication 1005, Distillate Fuel: Contamination, Storage and Handling. Based on
 
operating history and FO management activities, the addition of biocides, biological stabilizers, and corrosion inhibitors into stored fuel is not necessary; however, the option is retained on an
 
as-needed basis.
Since water contamination in the diesel fuel storage tanks is minimized, the potential for microbiologically-influenced corrosion is limited. The staff confirmed that the applicants process
 
for review of site and industry operating experience ensures that if microbiologically-influenced
 
corrosion is discovered during future analyses, appropriate corrective actions will be taken, including modification of program attributes, if appropriate. Therefore, the staff finds that this
 
exception is acceptable.
Exception 4.
In the LRA, the applicant took the following exceptions to the GALL Report program elements parameters monitored or inspected and acceptance criteria, which were
 
revised by Amendment 1 to the LRA, Attachment 1, Audit Item 131, dated December 18, 2007.
 
Specifically, the exception stated, [f]or determination of particulates, NUREG-1801
 
recommends use of modified ASTM Standard D2276 Method A and D6217. Determination of
 
particulates is according to ASTM Standard D2276.
The staff noted that the discussion of this exception in Section B.1.9 of the LRA includes a footnote. The footnote to this exception was revised by Amendment 1 to the LRA, Attachment 1, Audit Item 131, dated December 18, 2007. The revised footnote states the following:
Determination of particulates is according to ASTM Standard D2276 which conducts particulate analysis using a 0.8 micron filter, rather than the 3.0 micron
 
filter specified in NUREG-1801. Use of a filter with a smaller pore size results in a
 
larger sample of particulates since smaller particles are retained. Thus, use of a
 
===0.8 micron===
filter is more conservative than use of the 3.0 micron filter specified in
 
NUREG-1801. ASTM D6217 applies to middle distillate fuel using a smaller
 
volume of sample passing over the 0.8 micron filter. Since ASTM D2276
 
determines particulates with a larger volume passing through the filter for a
 
longer time than the D6217 method, use of D2276 only is more conservative.
3-69The staff noted that GALL Report Section XI.M30 recommends modified ASTM D2276, Method A, and ASTM D6217 for the measurement of particulates in diesel fuel. The modification to
 
D2276 consists of using a filter with a pore size of 3.0 micron, instead of 0.8 micron. The staff
 
reviewed both standards and determined that the guidelines of D2276 are appropriate for
 
determination of particulates at IP and the use of a 0.8 micron filter is more conservative than
 
use of the 3.0 micron filter since ASTM D2276 determines particulates with a larger volume
 
passing through the filter for a longer time than the D6217 method. Therefore, the staff
 
concluded that this exception is acceptable. Enhancement 1.
In the LRA, the applicant committed to implement the following enhancement to program elements preventive actions and detection of aging effects:
IP2:  Revise applicable procedures to include cleaning and inspection of the GT1 gas turbine fuel oil storage tanks, EDG fuel oil day tanks, and SBO/Appendix R
 
diesel generator fuel oil day tank once every ten years.
IP3:  Revise applicable procedures to include cleaning and inspection of the EDG fuel oil day tanks, Appendix R fuel oil storage tank, and Appendix R fuel oil day
 
tank once every ten years.
As discussed in the applicants procedures, the EDG and GT2/3 gas turbine fuel storage tanks are cleaned and inspected every ten years to remove sludge, debris, and water. Program
 
enhancements are needed to include the GT1 storage tank, EDG fuel oil day tanks, Appendix R
 
fuel oil storage tank and the SBO/Appendix R diesel generator fuel oil day tanks.
The GT1 tanks are monitored in accordance with technical specifications on fuel oil purity and the guidelines of ASTM Standards D1796 (water and sediment by centrifuge), D2276 (particulate gravimetrically), and D4057 (sampling). In addition the GT1 gas turbine fuel oil
 
storage tanks, EDG fuel oil day tanks, and SBO/Appendix R diesel generator fuel oil day tank
 
are periodically sampled, near the bottom, to determine water content. The frequencies and
 
acceptance criteria are documented in the applicants procedures.
In Audit Item 36, the staff asked the applicant to provide a technical basis for the 10-year inspection frequency. In its response, dated March 24, 2008, the applicant stated that the basis
 
for the 10-year wall thickness inspection frequency is to perform the inspections in conjunction
 
with other 10-year inspections and cleanings. This inspection frequency is consistent with the
 
recommended frequency in RG 1.137 and meets New York State regulations for fuel oil storage
 
tanks. Past visual inspections of fuel oil storage tanks have not detected significant degradation
 
that would lead to a need for an increased inspection frequency.
The staff determined that the applicants enhancement will add routine draining, cleaning, and visual inspections, and ultrasonic measurement of the bottom surfaces of the diesel generators
 
fuel oil storage tanks and day tanks and gas turbine generators fuel oil storage tanks, which are
 
consistent with the recommendations in the GALL Report. The frequency for draining, cleaning
 
and inspecting the tanks will be based on past experience, which has been demonstrated to
 
provide acceptable performance for the diesel fuel storage tanks. The enhancement to the
 
diesel fuel oil monitoring program ensures that significant degradation is not occurring. On this
 
basis, the staff found this enhancement acceptable.
3-70Enhancement 2.
In the LRA, the applicant committed to implement the following enhancement to program elements preventive actions, detection of aging effects, and monitoring and
 
trending:
IP2:  Revise applicable procedures to include quarterly sampling and analysis of the SBO/Appendix R diesel generator fuel oil day tank and security diesel fuel oil
 
day tank. Particulates (filterable solids), water and sediment checks will be
 
performed on the samples. Filterable solids acceptance criterion will be < 10mg/l.
 
Water and sediment acceptance criterion will be < 0.05%.
IP3:  Revise applicable procedures to include quarterly sampling and analysis of the Appendix R fuel oil storage tank. Particulates (filterable solids), water and
 
sediment checks will be performed on the samples. Filterable solids acceptance
 
criterion will be < 10mg/l. Water and sediment acceptance criterion will be <
 
0.05%.As described in the applicants procedures, IP2 and IP3 perform periodic multi-level sampling to provide assurance that fuel oil contaminants are within acceptable limits. Water and particulate
 
concentrations are monitored and trended at least quarterly or in accordance with technical
 
specifications. This enhancement expands scope of existing procedures to include quarterly
 
sampling and analysis of all tanks within the scope of license renewal.
During the regional inspection conducted in February 2008, the inspectors identified that the IP2 security diesel fuel oil storage tank was not included in the program enhancement to perform
 
fuel oil chemistry sampling. By letter dated March 24, 2008, the applicant amended the above
 
enhancement to include quarterly sampling of the IP2 security diesel fuel oil storage tank.
The staff determined that the applicants enhancement will add routine diesel fuel oil sampling and analysis for the SBO/Appendix R diesel generator fuel oil day tank (IP2), the Appendix R
 
fuel oil storage tank (IP3), and the security diesel fuel oil storage and day tanks (IP2), which is
 
consistent with the recommendations in the GALL Report. The frequency for sampling and analysis is consistent with the technical specifications where applicable. The enhancement to
 
the diesel fuel oil monitoring program ensures that fuel oil quality is maintained. On this basis, the staff finds this enhancement acceptable. Enhancement 3.
In the LRA, the applicant committed to implement the following enhancement to program element detection of aging effects:
IP2:  Revise applicable procedures to include thickness measurement of the bottom surface of the EDG fuel oil storage tanks, EDG fuel oil day tanks, SBO/
 
Appendix R diesel generator fuel day tank, GT1 gas turbine fuel oil storage
 
tanks, and diesel fire pump fuel oil storage tank once every ten years.
IP3:  Revise applicable procedures to include thickness measurement of the bottom surface of the EDG fuel oil day tanks, Appendix R fuel oil storage tank, and diesel fire pump fuel oil storage tank once every ten years.
The enhancement is necessary to provide periodic thickness measurement monitoring for all tanks within scope of license renewal. Presently, the only diesel fuel oil tanks with procedures or
 
tasks requiring NDE of the tank bottom are the IP3 EDG storage tanks and the GT2/3 storage 3-71 tank. These inspections are described in the applicants procedures. The minimum acceptable thickness for each tank bottom when inspected is based upon a component-specific
 
engineering evaluation. Wall thickness will be acceptable if greater than the minimum wall
 
thickness for the specific component. As described in the applicants procedure, thickness measurements are performed once every ten years on the IP3 EDG fuel oil storage tanks to verify that significant degradation is not
 
occurring. The Aboveground Steel Tanks Program includes thickness measurement of the
 
GT2/3 fuel oil storage tank once every ten years. Enhancement is also needed to specify
 
acceptance criteria for thickness measurements of the fuel oil storage tanks within the scope of
 
the program (see Enhancement 5, below).
The staff determined that the applicants enhancement will add routine draining, cleaning, visual inspections, and ultrasonic measurement of the bottom surfaces of the diesel fuel tanks, which
 
are consistent with the recommendations in the GALL Report. The frequency for draining, cleaning and inspecting the tanks will be based on past experience, which has been
 
demonstrated to provide acceptable performance for the diesel fuel storage tanks. Ultrasonic
 
measurement of the tank bottoms will provide objective evidence that degradation of the tanks
 
is not occurring. The staff finds that the selection of the tank bottoms for ultrasonic inspection is
 
appropriate since any moisture in the oil will tend to settle to the bottom of the tanks, making
 
this the most susceptible location for degradation. On this basis, the staff found this
 
enhancement acceptable. Enhancement 4.
In the LRA, the applicant committed to implement the following enhancement to program element monitoring and trending:
IP2:  Revise appropriate procedures to change the GT1 gas turbine fuel oil storage tanks and diesel fire pump fuel oil storage tank analysis for water and
 
particulates to a quarterly frequency.
IP3:  Revise appropriate procedures to change the Appendix R fuel oil day tank and diesel fire pump fuel oil storage tank analysis for water and particulates to a
 
quarterly frequency.
The enhancement is necessary to address all tanks within scope of license renewal. The diesel fuel oil sampling and analysis frequencies for water and particulates are included in the
 
applicants procedures and the technical specifications, as applicable.
The staff determined that the applicants enhancement will add routine quarterly frequency diesel fuel oil sampling and analysis from the GT1 gas turbine generator and diesel fuel oil
 
storage tanks at IP2 and the Appendix R diesel generator fuel oil day tank and the diesel fire
 
pump storage tank at IP3, which are consistent with the recommendations in the GALL Report.
The frequency for sampling and analysis is consistent with the technical specifications where
 
applicable. The enhancement to the diesel fuel oil monitoring program ensures that fuel oil
 
quality is maintained. On this basis, the staff found this enhancement acceptable. Enhancement 5.
In the LRA, the applicant committed to implement the following enhancement to program element acceptance criteria:  [r]evise applicable procedures to specify acceptance
 
criteria for thickness measurements of the fuel oil storage tanks within the scope of the
 
program.
3-72 The enhancement is necessary to specify acceptance criteria for thickness measurements for all tanks within scope of license renewal. See Enhancement 3, above.
Presently, the only diesel fuel oil tanks with procedures or tasks requiring NDE of the tank bottom are the IP3 EDG storage tanks and the GT2/3 storage tank. These inspections are
 
described in plant procedures. The minimum acceptable thickness for each tank bottom when
 
inspected is based upon a component-specific engineering evaluation. Wall thickness will be
 
acceptable if greater than the minimum wall thickness for the specific component.
The staff determined that the applicants enhancement will specify acceptance criteria for thickness measurements of diesel generator fuel storage tanks within the scope of this program, which is consistent with the recommendations in the GALL Report. The acceptance criteria will
 
provide a measure to determine whether corrective actions are required based upon inspection
 
results. On this basis, the staff finds this enhancement acceptable. Enhancement 6.
In Amendment 1 to the LRA, dated December 18, 2007, in response to Audit Item 128, the applicant committed to implement the following enhancement to program element
 
preventive actions:  [r]evise applicable procedures to direct samples to be taken near the tank
 
bottom and include direction to remove water when detected.
The enhancement is necessary to ensure that applicable fuel oil sampling procedures include specific direction to obtain samples near the bottom of all tanks within scope of this program in
 
order to more accurately determine the water content. If large amounts of water are
 
encountered the applicable fuel oil sampling procedures will provide direction to remove water
 
from the bottom of the tank. This commitment was included in Amendment 1 to the LRA, dated
 
December 18, 2007.
By letter dated December 18, 2007, in response to the staffs inquiries about how water content of fuel oil tanks was to be determined and how removal of water from the bottoms of fuel oil
 
tanks was to be implemented, the applicant stated that procedure 0-CY-1810, which covers the
 
monitoring of all diesel fuel oil on the site, will be enhanced to include direction to take samples
 
near the tank bottom for water detection and to remove water from the tank bottom if detected (Audit Item 128).
The staff determined that the applicants program and procedure enhancement will adequately detect the water near the bottom of fuel oil tanks within scope of this program and provide
 
direction to remove water from the tanks when it is detected, which is consistent with the
 
recommendations in the GALL Report. The preventive actions will provide administrative
 
controls to detect water near the bottom of fuel oil tanks and provide direction to remove water
 
from the tanks when it is detected. On this basis, the staff finds this enhancement acceptable. Enhancement 7.
In Amendment 1 to the LRA, dated December 18, 2007, in response toAudit Item 132, the applicant committed to implement the following enhancement to program element preventive actions:  [r]evise applicable procedures to direct the addition of chemicals
 
including biocide when the presence of biological activity is confirmed.
The enhancement is necessary to ensure that applicable administrative controls are in place to direct the addition of biocides to control biological activity when it is detected in fuel oil tanks
 
within scope of this program as recommended in the GALL Report to prevent biological 3-73 breakdown of the diesel fuel. This commitment was included in Amendment 1 to the LRA, dated December 18, 2007.
By letter dated December 18, 2007, in response to the staffs inquiries about the addition of biocides to control biological activity in diesel fuel oil, the applicant stated that the corrective
 
actions program is used to evaluate microbiological activity and determine the need for the use
 
of biocides (Audit Item 132). The applicant follows the guidelines of ASTM Special Technical
 
Publication 1005, Distillate Fuel: Contamination, Storage, and Handling, with regard to the
 
addition of biocides to diesel fuel oil. In order to make the procedures regarding the addition of
 
biocides to diesel fuel oil consistent between IP2 and IP3, the applicant stated that an
 
enhancement will be added to combine the directions from unit procedures into series
 
procedure for the addition of chemicals, including biocide, on both units when the presence of
 
biological activity is confirmed.
The staff determined that the applicants program and procedure enhancement will adequately provide direction for the addition of chemicals, including biocide, to the diesel fuel oil storage
 
tanks within the scope of this program on both units when the presence of biological activity is
 
confirmed. The preventive actions will provide administrative controls to direct the addition
 
chemicals, including biocide, to the diesel fuel oil storage tanks when the presence of biological
 
activity is confirmed. On this basis, the staff finds this enhancement acceptable. Enhancement 8.
During the regional inspection, the inspectors identified that the existing procedure for fuel oil transfer using the emergency fuel oil transfer trailer did not specify a that
 
chemistry oil sample be taken at the tank bottom, and did not provide specific acceptance
 
criteria as to when tank flushing would be required. In Amendment 3 to the LRA, dated March 24, 2008
, the applicant committed to implement the following enhancement to program element preventive actions:  [r]evise applicable procedures to direct sampling of the onsite portable fuel oil tanker contents prior to transferring the contents to the storage tanks.
The staff determined that the applicants program and procedure enhancement will provide direction for sampling the portable fuel oil tanker contents prior to transfer to the storage tanks.
 
The preventive actions will provide administrative controls to ensure that possible contaminants
 
will not be transferred into the emergency diesel fuel oil supply system. On this basis, the staff
 
finds this enhancement acceptable.
Operating Experience. LRA Section B.1.9 states that results of a vendor microorganism study of a sample taken from an EDG underground diesel fuel tank reported heavy bacteria growth. The
 
source of the bacteria was water intrusion through an overfill line spool piece incorrectly
 
reassembled following maintenance. After removal of the water from the tank, testing found no
 
bacteria. Detection of out-of-specification fuel conditions demonstrates the programs ability to
 
detect potentially detrimental diesel fuel conditions. Subsequent corrective actions enhance the
 
programs ability to remain effective in managing loss of component material.
A QA surveillance in 2004 found the overall program effective. One deficiency found and corrected was a missed surveillance. Detection of program deficiencies and subsequent
 
corrective actions add assurance that the program will continue to manage loss of component
 
material effectively.
Other than the noted instances, fuel oil sampling results from 2001 through 2005 reveal that fuel oil quality is maintained in compliance with acceptance criteria. Continuing acceptable diesel 3-74 fuel quality assures program effectiveness in managing loss of fuel system component material.
Visual inspection of an IP3 EDG fuel oil storage tank in 2001, visual and ultrasonic testing inspections of the two other EDG fuel oil storage tanks in 2001, and visual inspection of the IP2
 
fuel oil storage tanks in 2003 found no significant degradation.
The staffs review of the operating experience presented by the applicant indicates diesel fuel oil qualify has been maintained and that out-of-specification or deteriorating condition have been
 
detected and corrected. The staff determined that the applicants program, with the
 
implementation of the proposed procedure enhancements, will adequately maintain diesel fuel
 
oil quality for the tanks within the scope of the program.
The staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.8 and A.3.1.8, the applicant provided the UFSAR supplement for the Diesel Fuel Monitoring Program. In response to Audit Items 128 and 132, in
 
Amendment 1 to the LRA, dated December 18, 2007, the applicant revised LRA Sections
 
A.2.1.8 and A.3.1.8 to include the following (Commitment 4):
Revise applicable procedures to direct samples taken near the tank bottom and include direction to remove water when detected.
Revise applicable procedures to direct the addition of chemicals including biocides when the presence of biological activity is confirmed.
In Amendment 3 to the LRA, Attachment 1, dated March 24, 2008, the applicant added the following enhancement and committed to implementing it prior to the period of extended
 
operation (Commitment 4):
Revise applicable procedures to direct sampling of the onsite portable fuel oil tanker contents prior to transferring the contents to the storage tanks.
The staff reviewed these sections and determines that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicants Diesel Fuel 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 exceptions
 
and their justifications and determines that the program is adequate to manage the aging effects
 
for which it is credited. Also, the staff reviewed the enhancements to the program elements and
 
confirmed that their implementation prior to the period of extended operation would make the
 
existing program consistent with the GALL Report AMP to which it was compared. The staff
 
concludes that the applicant has demonstrated that the effects of aging will be adequately
 
managed so that the intended functions will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the
 
UFSAR supplement for this program and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3-75 3.0.3.2.5  External Surfaces Monitoring Program Summary of Technical Information in the Application. LRA Section B.1.11 describes the existing External Surfaces Monitoring Program as consistent with GALL AMP XI.M36, External
 
Surfaces Monitoring, with enhancement.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the External Surfaces Monitoring Program to verify consistency with GALL AMP XI.M36. Details of the staffs audit of the applicants AMP are documented in the Audit
 
Report. As documented in the report, the staff found that the External Surfaces Monitoring
 
Program elements preventive actions, parameters monitored or inspected, detection of
 
aging effects, monitoring and trending, and acceptance criteria, are consistent with the corresponding elements in GALL AMP XI.M36. Because these elements are consistent with the
 
GALL Report elements, the staff finds that they are acceptable.
The staff reviewed the enhancement to determine whether the program will be adequate to manage the aging effects for which it is credited. Enhancement.
In the LRA, the applicant committed to implement the following enhancement to the program element scope of program:
External Surfaces Monitoring Program guidance documents will be revised to require periodic inspections of systems in scope and subject to aging
 
management review for license renewal in accordance with 10 CFR 54.4 (a)(1)
 
and (a)(3). Inspections shall include areas surrounding the subject systems to
 
identify hazards to those systems. Inspections of nearby systems that could
 
impact the subject systems will include SSCs that are in scope and subject to
 
aging management review for license renewal in accordance with 10 CFR 54.4 (a)(2).The staff reviewed the proposed enhancement and finds it acceptable because implementation of the enhancement will result in the periodic inspection of those systems identified by the
 
applicant as within the scope of license renewal in accordance with 10 CFR 54.4(a), which is
 
consistent with the GALL Report.
Operating Experience. In LRA Section B.1.11, the applicant summarizes the operating experience review it performed for the External Surfaces Monitoring program. The applicant
 
reviewed operating experience for the five-year period covering 2001 through 2005, for both IP2
 
and IP3. The review was documented in a report that was reviewed by the staff during an onsite
 
review. As stated in LRA Section B.0.4, for monitoring programs, such as the External Surfaces
 
Monitoring program, the applicant reviewed sample results to determine if parameters are being
 
maintained as required by the program. During an audit, the staff reviewed the sample results
 
produced by the applicant, and in addition, independently reviewed additional reports that
 
contained keywords such as rust/rusted/rusting, residue, corroded, encrustation, paint, flakes/flaking, etc. Such keywords would likely be included in condition reports to describe a
 
degraded exterior surface of a component. Based on the review of the applicant-identified
 
operating experience, and the independent review of additional condition reports, the staff has
 
confirmed that the applicant has addressed operating experience related to this program, and 3-76 has identified the applicable aging effects, i.e., loss of material, which is the aging effect identified by the GALL Report for this AMP. Therefore, the staff determines that the applicant
 
has adequately addressed this program element.
UFSAR Supplement. In LRA Sections A.2.1.10 and A.3.1.10, the applicant provided the UFSAR supplement for the External Surfaces Monitoring Program. The staff reviewed these sections
 
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).
As documented in LRA Sections A.2.1.10 and A.3.1.10, the applicant has committed to enhance this program prior to entering the period of extended operation (Commitment 5).
Conclusion. On the basis of its review of the applicants External Surfaces Monitoring Program, the staff determines that those program elements, for which the applicant claimed consistency
 
with the GALL Report are consistent. Also, the staff reviewed the enhancement to the program
 
element and confirmed that its implementation prior to the period of extended operation would
 
make the existing program consistent with the GALL Report AMP to which it was compared.
 
Lastly, the staff confirmed that the applicant addressed operating experience related to this
 
program, and identified the applicable aging effects. Therefore, 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 program and concludes that it provides an adequate summary description of the
 
program, as required by 10 CFR 54.21(d).
3.0.3.2.6  Fatigue Monitoring Program
 
Summary of Technical Information in the Application. LRA Section B.1.12 describes the existing Fatigue Monitoring Program as consistent with GALL AMP X.M1, Metal Fatigue of Reactor
 
Coolant Pressure Boundary, with exception and enhancement.
The Fatigue Monitoring Program tracks the number of critical thermal and pressure transients for selected reactor coolant system components to validate the analyses of fatigue transients by
 
assuring that the actual effective number does not exceed the analyzed number of transients.
In a letter dated January 22, 2008, the applicant amended LRA Section B.1.12, Fatigue Monitoring, to provide detailed information on the cycles counting and the methodology that will
 
be used for the determination of stresses and fatigue usage, including the environmental
 
effects.Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Fatigue Monitoring Program to verify consistency with GALL AMP X.M1. Details of the staffs audit of the applicants AMP are documented in the Audit Report. As
 
documented in the report, the staff found that the Fatigue Monitoring Program elements scope
 
of program, preventive actions, monitoring and trending, and acceptance criteria, are consistent with the corresponding elements in GALL AMP X.M1. Because these elements are
 
consistent with the GALL Report elements, the staff finds that they are acceptable.
3-77 The staff reviewed the exception and enhancement to determine whether the program will be adequate to manage the aging effects for which it is credited.
During the audit, the staff asked the applicant to provide more information regarding the actions or alarm limits that will trigger the corrective action for the applicant to update fatigue usage
 
calculations (Audit Item 40). In a letter dated March 24, 2008, the applicant stated that, in
 
accordance with their procedure, alert levels will be calculated by adding twice the number of
 
cycles from the last fuel cycle to the total number of cycles to date. The applicant stated that
 
they will take corrective actions if this alert level is greater than the analyzed transients.
In a letter dated April 18, 2008, in RAI 4.3.1.8-2, the staff also asked the applicant to explain the corrective actions and the frequency of such actions if the alert level is approached. In the
 
applicants response, dated May 16, 2008, the applicant explained that the frequency of
 
updates for the counting of plant transients is at least once each operating cycle, and these
 
updates determine if design transients may be exceeded before the next update. The applicant
 
also stated that corrective actions will be taken prior to exceeding the analyzed transient cycles.
The staff finds the applicants response acceptable because the applicant will perform periodic updates on the counting of plant transients, which ensures that design transients will not be
 
exceeded and will allow adequate time for corrective actions to be initiated based on the alert
 
level from the applicants procedure on cycle counting and tracking. These corrective actions
 
include further re-analysis or repair or replacement of the affected components. The staff also
 
finds the applicants response acceptable because the applicant will appropriately include the
 
new or updated CUF calculations for all NUREG/CR-6260 locations identified in LRA Tables
 
4.3-12 and 4.3-13 to be a part of the Fatigue Monitoring Program and the incurred cycles will be
 
monitored and the applicant will ensure that they do not exceed the analyzed number of cycles.
 
Based on the staffs conclusions this issue is resolved.
Exception. The staff noted that the applicant originally took exception to the detection of aging effects program element of the GALL AMP X.M1 recommendation. The applicant stated that
 
updates of fatigue usage calculations are not necessary unless the number of accumulated
 
fatigue cycles approaches the number of analyzed design cycles. In a letter dated January 22, 2008, the applicant amended the LRA with respect to its basis for its environmentally-assisted
 
fatigue analysis. In this letter, the applicant provided clarification regarding the relationship
 
between Commitment 33 and the FMP. The applicant stated that as part of Commitment 33, refined CUF calculations will be provided to the NRC. The applicant amended the LRA so that
 
Commitment 33 is within the scope of the applicants Fatigue Monitoring Program and to credit
 
this AMP as the basis for accepting this TLAA and other TLAAs described in LRA Section
 
4.3.1.1 through 4.3.1.8 in accordance with 10 CFR 54.21(c)(1)(iii).
During a teleconference with the applicant on April 3, 2008, the staff asked the applicant if the exception to the detection of aging effects program element in GALL AMP X.M1 will still be
 
taken based on the applicants changes made in LRA Amendment 2, dated January 22, 2008.
 
The applicants proposed change to have refined CUF calculations is consistent with the NRCs
 
recommendations for the periodic CUF updates in the detection of aging effects program element of GALL AMP X.M1. Also the applicant stated in Commitment No.33 that the actions to
 
replace or repair components before exceeding a CUF of 1.0 are consistent with the corrective
 
actions recommended in the program element, corrective action program element of GALL AMP X.M1.
3-78 The staff verified that, in a letter dated June 11, 2008, the applicant amended the LRA and removed the exception to the detection of aging effects program element in GALL AMP X.M1.
 
Based on this assessment and the applicants removal of the exception taken to GALL AMP X.M1 and clarification on the corrective actions for the program, the staff concludes that the
 
detection of aging effects and corrective actions program elements for the Fatigue Monitoring
 
Program are consistent with and conform to the staffs detection of aging effects and corrective actions program element criteria that are recommended in GALL AMP X.M1 without
 
exception, and that these program elements are, therefore, acceptable. The staffs question on the exception taken to GALL AMP X.M1 is resolved. Enhancement
. In the LRA, the applicant committed to implement the following enhancement to the program element parameters monitored or inspected:
IP2: Perform an evaluation to confirm that monitoring steady state cycles is not required or revise appropriate procedures to monitor steady state cycles. Review
 
the number of allowed events and resolve discrepancies between reference
 
documents and monitoring procedures.
IP3 Enhancements: Revise appropriate procedures to include all the transients identified. Assure all fatigue analysis transients are included with the lowest
 
limiting numbers. Update the number of design transients accumulated to date.
During the audit, the staff noted that in the LRA the IP2 enhancement included monitoring steady state cycles, but the program basis document discussed both steady state cycles and
 
feedwater cycles. The staff asked the applicant to clarify the discrepancy (Audit Item 164).
In a letter dated March 24, 2008, the applicant submitted an amendment to the LRA, and stated that feedwater cycles are included in the enhancement. The staff reviewed these changes and
 
noted that the revised statement is in agreement with the Commitment 6. Therefore, the staff
 
finds the applicants response acceptable.
The staff finds that after implementation of these enhancements, the parameters monitored or inspected program element will be consistent with the staffs parameters monitored or inspected program element criteria that are recommended in GALL AMP X.M1. On this basis, the staff finds these enhancements acceptable.
The staff reviewed those portions of the Metal Fatigue of Reactor Coolant Pressure Boundary Program for which the applicant claims consistency with GALL AMP X.M1 and finds that they
 
are consistent with the GALL Report AMP. The staff finds the applicants Metal Fatigue of
 
Reactor Coolant Pressure Boundary Program acceptable because it conforms to the
 
recommended AMP, as subject to the enhancements that have been discussed and evaluated
 
in the previous paragraphs and that have been incorporated into Commitment 6.
Operating Experience. LRA Section B.1.12 states that the program re-evaluates usage factors as appropriate (e.g., certain auxiliary transients related to charging and letdown approaching
 
typical design cycle limits for the IP2 charging nozzles during the current period of operation).
 
The assessment of impact of thermal transient cycles on the IP2 nozzles compared plant-
 
specific against previously-assumed moment loads and reconciled the cycle counts to design
 
cycles in previous analysis. The reevaluation concluded that the fatigue impact of transient
 
cycles accumulated on the IP2 charging nozzles is within expectations based on pro-rated 3-79 typical operation of the charging system and projected allowable cycles during the current period of operation.
The staff noted, from the applicants license renewal plant operating experience review report for this AMP, that the applicant has factored in industry experience, which includes the thermal
 
and operating stresses that were not considered during the original plant design related to NRC
 
Bulletins 88-08 and 88-11, and will continue to factor in industry experience in the IP Fatigue
 
Monitoring Program. During the audit, the staff reviewed implementing procedures and problem
 
identification reports related to the applicants Metal Fatigue Program. The staff noted that the
 
applicant demonstrated that the program monitors transients and tracks their accumulation
 
based on the applicants implementing procedure. The staff noted that the applicant tracked and
 
monitored reactor shutdowns and startups and their cycle limitations did not indicate that the
 
allowable number of cycles would be exceeded. The staff also interviewed the applicants
 
technical staff who have specialized knowledge of the program. The staff reviewed instances
 
previously documented by the applicant that identified issues with the Metal Fatigue Program
 
and where the applicant had implemented corrective actions. The staffs review demonstrated
 
that the operating experience shows that this program effectively manages aging effects;
 
therefore, continued implementation of the program assures management of the effects of aging
 
so components crediting this program will perform intended functions consistent with the CLB
 
during the period of extended operation Based on this review, the staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR
 
Section A.1.2.3.10. The staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.11 and A.3.1.11, the applicant provided the UFSAR supplement for the Fatigue Monitoring Program. By letter dated March 24, 2008, the applicant
 
revised LRA Section A.2.1.11 to include feedwater cycles (in response to Audit Item 164). The
 
staff reviewed these LRA sections, as revised, and the amendments made to Commitments 6
 
and 33. The staff verified that LRA Sections A.2.1.11 and A.3.1.11 include Commitment 6. The
 
staff also verified that the applicant amended the Fatigue Monitoring Program to incorporate the
 
corrective actions for the applicants TLAA on metal fatigue, as defined in Commitment 33.
 
Based on this review, the staff finds that the UFSAR Supplement Sections A.2.11 and A.3.1.11, as amended by letter dated January 22, 2008, and as revised by letter dated March 24, 2008, provide 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 applicants Fatigue 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 enhancement to the
 
program element and confirmed that its implementation prior to the period of extended operation
 
would make the existing program consistent with the GALL Report AMP to which it was
 
compared. The staff concludes that the applicant has demonstrated that the effects of aging will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this program and concludes that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3-80 3.0.3.2.7  Fire Protection Program Summary of Technical Information in the Application. LRA Section B.1.13 describes the existing Fire Protection Program as consistent with GALL AMP XI.M26, Fire Protection, with exception
 
and enhancements.
The Fire Protection Program includes fire barrier, reactor coolant pump oil collection system, and diesel-driven fire pump inspections. The fire barrier inspection requires periodic visual
 
inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors and periodic
 
visual inspection and functional tests of fire rated-doors to maintain their operability. The diesel-
 
driven fire pump inspection requires periodic testing and inspection of the pump and its driver so
 
diesel engine subsystems, including the fuel supply line, can perform intended functions. The
 
program periodically inspects and tests the Halon fire protection system (IP2) and the carbon
 
dioxide fire protection system (IP3).
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the program elements of the Fire Protection Program to verify consistency with GALL AMP XI.M26.
 
Details of the staffs audit of the applicants AMP are documented in the Audit Report. As
 
documented in the report, the staff found that the Fire Protection Program elements preventive
 
actions, and monitoring and trending, are consistent with the corresponding elements in GALL AMP XI.M26. Because these elements are consistent with the GALL Report elements, the staff finds that they are acceptable.
The staff reviewed the exception and enhancements to determine whether the program will be adequate to manage the aging effects for which it is credited.
The GALL Report recommends that visual inspection of approximately 10 percent of each type of fire barrier penetration seal be performed during walkdowns carried out at least once every
 
refueling outage. These inspections examine any sign of degradation such as cracking, seal
 
separation from wall and components, separation of layers of material, rupture and puncture of
 
seals, which are directly caused by increased hardness, and shrinkage of seal material due to
 
weathering.
In RAI 3.0.3.2.7-1, dated February 13, 2008, the staff noted that LRA Table 2.4-4 lists fire stops and fire wrap as bulk commodities that perform an intended function as fire barriers. LRA Table
 
3.5.2-4, Bulk Commodities, identifies the material, environment and aging effect requiring
 
aging management for these two commodities. The Fire Protection Program is identified in the
 
AMR, along with Note J, which indicates that neither the component nor the material and
 
environment combination is evaluated in the GALL Report. However, in LRA Section B.1.13, Fire Protection, there is no indication that fire stops and fire wraps are included as
 
commodities whose aging effects will be managed by the AMP. The staff requested that the
 
applicant describe how the aging effects of cracking/delamination, separation (for fire stops),
and loss of material (for fire wrap) will be managed under the Fire Protection AMP.
In its response, dated March 12, 2008, the applicant stated that in LRA Section B.1.13, the fire protection program is an existing program that includes fire barrier inspections. The
 
commodities fire stops and fire wraps are considered to be fire barriers which are included in
 
the scope of the Fire Protection Program. Each fire stop (penetration seal) is visually inspected
 
for cracking, delaminating, separation, and change in material properties at least once every 3-81seven operating cycles (15 percent every 24 months). Fire wraps are visually inspected at least once every 24 months for loss of material and any other indications of degradation or damage.
The GALL Report program states that approximately 10% of each type of penetration seal should be visually inspected at least once every refueling outage. The applicant indicated that
 
the inspection program also requires that fire wraps be visually inspected at least once every 24
 
months for loss of material and any other indications of degradation or damage. The staff
 
evaluated the applicant's program and determined that overall it meets or exceeds the
 
penetration seal inspection frequency recommended in the GALL Report. The staff finds the fire
 
stop and fire wrap inspection program acceptable, because it monitors material cracking, delaminating, separation, and change in fire stop and fire wrap properties.
Based on the applicants response to RAI 3.0.3.2.7-1, dated March 12, 2008, the staff issued a follow up RAI 3.0.3.2.7-2 concerning inspection of inaccessible fire barrier penetration seals.
During an audit, the staff reviewed bases documents (for IP3) associated with the fire protection AMP. One of the bases documents states that 15 percent of the fire seals located in fire barriers
 
are demonstrated to be operable by visual inspection on a frequency of 24 months. However, for those penetration seals that are inaccessible, the frequency of inspection is given as not
 
required. By letter dated April 29, 2008, the staff requested that the applicant justify the lack of
 
visual inspections of inaccessible penetration seals.
In its response, dated May 28, 2008, the applicant stated that as provided in response to RAI 3.0.3.2.7-1, penetration seals are inspected at least once every seven operating cycles.
 
However, IP3 site surveillance procedure provides provisions for cases where a penetration
 
seal may become inaccessible for periodic inspection as result of plant configuration changes (i.e., installation of new plant equipment, walls, barriers, or other obstacles). In such cases, the
 
IP3 site procedure includes guidance for the cessation of periodic surveillance of such
 
penetration seals, subject to preparation of a formal fire protection engineering evaluation
 
justifying the discontinuance of periodic visual surveillance.
As stated in the IP3 bases document, the visual inspection of inaccessible penetration seals is not required if justified by a supporting fire protection engineering evaluation, developed in
 
accordance with the guidance of GL 86-10. On a case-by-case basis, the inaccessibility of any
 
such penetration seal must be justified, and the fire protection adequacy of the configuration
 
must be demonstrated. The evaluation, as stated in the bases document, must include
 
assessment of proximate combustible loading, mitigating features, and the consequences of
 
potential failure of the affected seal.
The applicant further stated that if the formal fire protection engineering evaluation (prepared in accordance with guidance of GL 86-10) demonstrates that the penetration seal is inaccessible
 
for inspection, that the fire challenge to the barrier is insubstantial, and the consequences of
 
failure of the seal would not compromise fire safety or nuclear safety, then periodic surveillance
 
of that specific seal is not required.
The applicant clarified in the above response that the IP3 fire barrier penetration seal surveillance procedure includes inspection provisions for inaccessible fire barrier penetration
 
seals based on a change in plant fire area configuration. The applicant stated that, for a plant 3-82 change, an engineering evaluation based on guidance provided in GL 86-10 5 must be conducted to evaluate fire area configuration and to declare if a fire barrier penetration seal is
 
inaccessible for periodic inspection.
The staff reviewed the applicant's response and found that it did not address the fact that GL 86-10 evaluations exist for all inaccessible fire barrier penetration seals; the response only
 
indicated that it is a part of the fire protection program to perform such analysis. The staff
 
requested the applicant to confirm that these analyses do exist and are periodically
 
reviewed/updated to ensure their continued applicability. This was identified as Open
 
Item 3.0.3.2.7-1.
By the letter dated January 27, 2009, the applicant stated that there are no IP3 fire barrier penetration seals excluded from periodic inspection due to inaccessibility. Therefore, there are
 
no corresponding engineering evaluations.
The applicant clarified the IP3 fire barrier penetration seal program does not exclude periodic inspection of any inaccessible seal. The staff concludes that the concerns identified in Open
 
Item 3.0.3.2.7-1 have been resolved. Therefore, Open Item 3.0.3.2.7-1 is closed.
Exception. In the LRA, the applicant took the following exception to the GALL Report program element detection of aging effects:
The NUREG-1801 program recommends that testing and inspection of the Halon (IP2) and CO 2 (IP3) fire suppression systems occur at least once every six months. However, IPEC performs inspection every six months, functional testing
 
is performed every 18 months for Halon 1301 and 24 months for CO 2.During the audit and review, the staff asked the applicant to provide technical justification why the proposed testing frequency is acceptable to detect degradation of the Halon 1301 and CO 2 fire suppression systems before the loss of the components intended function (Audit Item 150).
In its response, dated March 24, 2008, the applicant stated that a review of past performance functional testing of Halon 1301 and CO 2 fire suppression systems has indicated no adverse material degradation that requires adjustment of the testing frequencies reported in the
 
condition reporting database. This condition reporting database was similarly reviewed and
 
revealed no indication of adverse material degradation.
The 18-month functional test frequency for the Halon 1301 and 24 months for CO 2 fire suppression systems is part of the current licensing basis documented in NRC IP2 SER dated
 
October 31, 1980, and NRC IP3 SER dated April 20, 1994. The review of IP2 and IP3 operating
 
experience indicated that these frequencies are reasonable to manage the aging effects. The
 
functional testing frequencies are considered sufficient to ensure system availability and
 
operability based on the plant operating history, and that there has been no aging-related event
 
that has adversely affected system operation. Because these aging effects occur over a
 
considerable period of time, the staff concluded that the 18-month and 24-month intervals will 5 GL 86-10is the means by which a licensee may make changes to the approved fire protection program without prior approval of the Commission in accordance with the standard license condition provided that the changes do not adversely affect the plants ability to achieve and maintain post-fire safe-shutdown.
3-83 be sufficient to detect aging of the Halon 1301 and CO 2 fire suppression systems.
The Halon 1301 and CO 2 fire suppression systems and associated components (bolting, coil, nozzles, piping and supports, tubing, fittings, valves, and tanks) are in an inside air (external)
 
environment. The staff found that the applicant has demonstrated that the effects of aging on
 
the Halon 1301 and CO 2 fire suppression systems will be adequately managed so that the intended functions will be maintained consistent with the current licensing basis for the period of
 
extended operation, as required by 10 CFR 54.21(a)(3).
In addition, the staff noted that the applicant currently performs fire damper operational tests once per 12 months to detect degradation of the fire dampers before loss of the intended function. IP2 and IP3 maintenance procedures also include visual inspections of component
 
external surfaces for signs of corrosion and mechanical damage every 6 months. The
 
applicants review of station operating experience identified no aging-related degradation adversely affecting the operation of the Halon 1301 and CO 2 fire suppression systems.
Although the Halon 1301 and CO 2 fire suppression system frequencies of functional testing exceed that recommended in GALL AMP XI.M26, the staff determined that it is sufficient to
 
ensure system availability and operability with the existing surveillance which includes visual
 
inspections of component external surfaces for signs of corrosion and mechanical damage, and
 
verification of Halon 1301 and CO 2 storage tank weight, level, and pressure. In addition, the staffs review of the station operating history indicates no aging-related events adversely affecting system operation exist at IP2 and IP3. Based on its review of the applicants program
 
and plant-specific operating experience, the staff finds that the 18- and 24-month
 
testing/surveillance frequencies for the Halon and CO 2 fire suppression systems are adequate for aging management considerations. On this basis, the staff finds this exception acceptable.
 
The staff is adequately assured that the aging effects on the Halon 1301 and CO 2 fire suppression systems will be considered appropriately during plant aging management activities
 
and that they will continue to perform their applicable intended functions consistent with the
 
current licensing basis for the period of extended operation. Enhancement 1
. In the LRA, the applicant committed to implement the following enhancement to program elements, scope of program, parameters monitored or inspected, detection of
 
aging effects, and acceptance criteria:  IP3: Revise appropriate procedures to inspect
 
external surfaces of the RCP oil collection system for loss of material each refueling outage.
The staff determined that this enhancement is acceptable because, when the enhancement is implemented in Fire Protection Program elements scope of program, parameters monitored or
 
inspected, detection of aging effects, and acceptance criteria, will be consistent with the GALL AMP XI.M26 program. This enhancement will enable the monitoring of the RCP oil
 
collection system and components through inspection, providing a detailed look at system
 
material condition to ensure external surfaces are not experiencing loss of material. This will
 
provide additional assurance that the effects of aging are adequately managed. Enhancement 2
. In the LRA, the applicant committed to implement the following enhancement to program elements, parameters monitored or inspected, detection of aging effects, and
 
acceptance criteria:
Revise appropriate procedures to explicitly state that the diesel fire pump engine sub-systems (including the fuel supply line) shall be observed while the pump is 3-84 running. Acceptance criteria will be revised to verify that the diesel engine does not exhibit signs of degradation that could involve items such as fuel oil, lube oil, coolant, or exhaust while running.
The staff determined that this enhancement is acceptable because, when the enhancement is implemented in Fire protection program elements parameters monitored or inspected, detection of aging effects, and acceptance criteria will be consistent with the GALL AMP XI.M26 program. GALL AMP XI.M26, Element 3, states that the diesel fire pump is observed
 
during performance tests for detection of any fuel supply line degradation. This enhancement is also acceptable for making the program consistent with GALL AMP XI.M26, element 6, which
 
states that no corrosion is acceptable in the diesel-driven fire pump fuel supply line. The staff
 
reviewed the applicants program procedures and confirmed that these elements are consistent
 
with the GALL Report. Enhancement 3
. In the LRA, the applicant committed to implement the following enhancement to program elements, parameters monitored or inspected, detection of aging effects, and acceptance criteria:  [r]evise appropriate procedures to specify that diesel fire pump engine
 
carbon steel exhaust components are inspected for evidence of corrosion or cracking at least
 
once each operating cycle.
The staff determined that this enhancement is acceptable because, when the enhancement is implemented in Fire protection program element parameters monitored or inspected, detection of aging effects, and acceptance criteria, will be consistent with the GALL AMP XI.M26. GALL AMP XI.M26, Element 3, states that periodic tests are performed at least once
 
every refueling outage, such as  sequential starting capability tests. This enhancement is also acceptable for making the program consistent with GALL AMP XI.M26, Element 6, which states
 
that no corrosion is acceptable. The staff reviewed the applicants program procedures and
 
confirmed that these elements are consistent with the GALL Report. Enhancement 4
. In the LRA, the applicant committed to implement the following enhancement to program elements,detection of aging effects, and acceptance criteria:  IP3: Revise
 
appropriate procedures to visually inspect the cable spreading room, 480V switchgear room, and EDG room CO 2 fire suppression system for signs of degradation, such as corrosion and mechanical damage, at least once every 6 months.
The staff determined that this enhancement is acceptable because, when the enhancement is implemented in Fire protection program element Detection of Aging Effects, Acceptance Criteria will be consistent with the GALL AMP XI.M26 program. GALL AMP XI.M26, Element 4, states that the visual inspections of the Halon/CO 2 fire suppression system detect any sign of added degradation, such as corrosion, mechanical damage, or damage to dampers. This enhancement is also acceptable for making the program consistent with GALL AMP XI.M26, Element 6, which states that no corrosion is acceptable in the Halon/CO 2 fire suppression system. The staff reviewed the applicants program procedures and confirmed that these
 
elements are consistent with the GALL Report.
Operating Experience. LRA Section B.1.13 states that inspections of fire stops, fire barrier penetration seals, fire barrier walls, ceilings, and floors from 2001 through 2005 revealed signs
 
of degradation: cracks, gaps, voids, holes, or missing material. Periodic surveillances in 2001
 
and 2004 detected discrepancies in fire barrier wrappings. Immediate actions repaired these fire
 
barriers. Detection of deficiencies and timely corrective actions provide confidence that the 3-85 program will continue to be managed to effectively identify and minimize any loss of component material.LRA Section B.1.13 states that a program self-assessment in 2003 found deficiencies in the fire barrier inspection list at IP2. Corrective actions reviewed the Type I fire barrier drawing against
 
the inspection list in the procedure and changed the procedure and drawing. Detection of
 
program weaknesses and subsequent corrective actions assure continued program
 
effectiveness in managing loss of component material.
LRA Section B.1.13 states that quality assurance audits in 2003, 2005, and 2006 revealed that the material condition of system equipment was good. The audits revealed no issues or findings
 
that could impact program effectiveness in managing aging effects for fire protection
 
components.
LRA Section B.1.13 states that a November 2005 inspection of the reactor coolant pump oil collection system within the IP2 containment building found no indications of loss of system
 
component material.
Additionally, in November 2006, observations of the IP2 and IP3 diesel-driven fire pumps while they were running noted no leaks or degradation of diesel engine sub-systems, including the
 
fuel supply line. The applicant stated that continuing monitoring provides confidence that the program effectively manages aging of diesel-driven fire pump subsystem components.
LRA Section B.1.13 states that in August 2004, the NRC completed a triennial fire protection team inspection at IP2 to assess whether the plant had implemented an adequate fire protection
 
program and whether post-fire safe shutdown capabilities had been established and maintained
 
properly. The inspection team also evaluated the material condition of fire area boundaries, fire
 
doors, and fire dampers and reviewed the surveillance and functional test procedures for the
 
diesel fire pump and other components. Additionally, the team reviewed the surveillance
 
procedures for structural fire barriers, penetration seals, and structural steel and made no
 
significant findings. Confirmation of program compliance with established standards and
 
regulations assures continued program effectiveness in managing loss of component material.
LRA Section B.1.13 states that on May 17, 2007, the NRC completed a triennial fire protection team inspection at IP2 to assess whether the plant had implemented an adequate fire protection
 
program and whether post-fire safe-shutdown capabilities had been established and maintained
 
properly. The team walked down accessible portions of selected fire areas to observe material
 
condition and the adequacy of design of fire area boundaries (including walls, fire doors and fire
 
dampers) to ensure they were appropriate for the fire hazards in the area. The inspection team
 
reviewed electric and diesel fire pump flow and pressure test results to ensure that the pumps
 
were meeting their design requirements. The team reviewed the fire main loop flow test results
 
to ensure that the flow distribution circuits were able to meet the design requirements. The team
 
also performed a walkdown of accessible portions of the detection and suppressions systems in
 
the selected areas as well as a walkdown of major system support equipment in other areas (e.g., fire protection pumps, Halon storage tanks and supply system) to assess the material
 
condition of the systems and components. No findings of significance were identified.
LRA Section B.1.13 states that in January 2005, the NRC completed a triennial fire protection team inspection at IP3 to assess whether the plant had implemented an adequate fire protection
 
program and whether post-fire safe-shutdown capabilities had been established and maintained 3-86 properly. The inspection team evaluated the material condition of fire area boundaries, fire doors, and fire dampers, and reviewed the surveillance and functional test procedures for the
 
diesel fire pump and other components. The staff also reviewed for adequacy of selected total
 
flooding CO 2 systems and surveillance procedures for periodic system testing and the adequacy of structural fire barriers and penetration seals. The team made no significant findings.
 
Confirmation of program compliance with established standards and regulations assures
 
continued program effectiveness in managing aging effects.
The staff reviewed the above operating experience and also condition reports made available during the audit, and interviewed the applicants technical staff. The staff confirmed that the plant-specific operating experience did not reveal any degradation not already bounded by
 
industry experience. The staff also reviewed the IP2 and IP3 operating experience reports, condition reports, and maintenance work orders associated with the corrective actions taken for
 
the identification of signs of degradation of fire protection components. The staff confirmed that
 
the condition reports were closed out by repairs to the degraded fire barriers or by performing
 
adequate engineering evaluations for their acceptability. The staff noted that the applicant
 
performs periodic inspections and places identified deficiencies into their corrective action
 
program to ensure appropriate corrective actions are performed in a timely manner.
The staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.12 and A.3.1.12, the applicant provided the UFSAR supplement for the Fire Protection Program. The staff reviewed these sections 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).
As documented in LRA Sections A.2.1.12 and A.3.1.12, the applicant has committed to enhance this program prior to entering the period of extended operation (Commitment 7).
Conclusion. On the basis of its audit and review of the applicants Fire Protection Program, the staff determines that those program elements, for which the applicant claimed consistency with
 
the GALL Report, are consistent. In addition, the staff reviewed the exception and its
 
justifications and determined that the program is adequate to manage the aging effects for
 
which it is credited. Also, the staff reviewed the enhancements and confirmed that their
 
implementation prior to the period of extended operation would make the existing program
 
consistent with the GALL Report AMP to which it was compared. The staff concludes that the
 
applicant has demonstrated that the effects of aging will be adequately managed so that the
 
intended functions will be maintained consistent with the current licensing basis for the period of
 
extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR
 
supplement for this program and concludes that it provides an adequate summary description of
 
the program, as required by 10 CFR 54.21(d).
3.0.3.2.8  Fire Water System Program
 
Summary of Technical Information in the Application. LRA Section B.1.14 describes the existing Fire Water System Program as consistent with GALL AMP XI.M27, Fire Water System, with
 
exception and enhancements.
3-87 The Fire Water System Program manages water-based fire protection systems consisting of sprinklers, nozzles, fittings, valves, hydrants, hose stations, standpipes, piping, and components
 
tested in accordance with National Fire Protection Association (NFPA) codes and standards to
 
assure system functionality. Periodic flushing, system performance testing, and inspections
 
determine whether significant corrosion has occurred in water-based fire protection systems.
 
Many of these systems normally are maintained at required operating pressure and monitored
 
to detect leakage resulting in loss of system pressure immediately for corrective actions. In
 
addition, periodic wall thickness evaluations of fire protection piping on system components by
 
nonintrusive techniques (e.g., volumetric testing) detect loss of material due to corrosion.
 
Inspection of a sample of sprinkler heads required by 10 CFR 50.48 will be guided by NFPA 25
 
(2002 edition), Section 5.3.1.1.1. NFPA 25 states, Where sprinklers have been in place for
 
50 years, they shall be replaced or representative samples from one or more sample areas shall
 
be submitted to a recognized testing laboratory for field service testing. This sampling will be
 
repeated every 10 years after initial field service testing.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Fire Water System Program to verify consistency with GALL AMP XI.M27. Details of the staffs audit of the applicants AMP are documented in the Audit Report.
 
As documented in the report, the staff found that the Fire Water System Program elements
 
scope of program, preventive actions, and monitoring and trending, are consistent with the corresponding elements in GALL AMP XI.M27. Because these elements are consistent with the
 
GALL Report elements, the staff finds that they are acceptable.
The staff reviewed the exception and enhancements to determine whether the program will be adequate to manage the aging effects for which it is credited.
The staff asked the applicant to clarify why jockey pumps were excluded from the scope of the Fire Water System Program (Audit Item 152). By letter dated March 24, 2008, the applicant
 
stated that the fire water jockey pumps support standby operation of the fire water system and
 
are conservatively included in the scope of the license renewal and subject to an AMR. The Fire
 
Water System Program manages component aging effects. However, the applicant stated that
 
the jockey pumps are not required for operation of the fire water system to comply with 10 CFR
 
50.48 and Appendix R. The applicant also stated that testing of the jockey pumps is not
 
required.The staff reviewed the applicants response and finds it contrary to the IP3 fire protection SER dated March 6, 1979, which is part of the current licensing basis. That SER reflects the
 
applicants commitment to implement modifications that conform to the provisions of Appendix A
 
to BTP APCSB 9.5-1. Sections 3.1.5 and 4.3.1.2 of the SER dated March 6, 1979, state in part,
[t]wo 2500 gpm fire pumps, one electric motor driven and one diesel engine driven, will be
 
provided along with two jockey pumps.  . . . [t]wo electric jockey pumps [are] provided to
 
maintain pressure on the fire water system . . . The applicant indicated in the audit question
 
response that the jockey pumps in question are within the scope of license renewal and subject
 
to an AMR but are not required for operation of the fire water system to comply with 10 CFR
 
50.48 and Appendix R. The applicants current licensing basis demonstrates that this
 
component was credited to meet the guidance of Appendix A to BTP APCSB 9.5-1. Therefore, the staff considers that the jockey pumps in question should be included within the scope of
 
license renewal pursuant to 10 CFR 54.4(a)(3) because they are required for compliance with
 
10 CFR 50.48 . The staff agrees that testing is not required for the jockey pump. The staff notes 3-88 that NFPA Fire Pump Handbook, 1 st Edition, Section 2-19, Page 136, states that pressure maintenance devices are not required to be tested for fire protection service. Although the
 
applicant disagrees with the staffs view that the jockey pumps are required for compliance with
 
10 CFR 50.48, the applicant has included the jockey pumps within the scope of license renewal, and they are subject to an AMR.
During its review, the staff noted that a "cross-connect" of the high pressure fire water system exists between Units 1, 2, and 3 individual fire water supply systems, and asked the applicant if
 
credit has been taken for the use of this capability per the CLB (Audit Item 153). By letter dated
 
March 24, 2008, the applicant clarified that IP2 and IP3 maintain independent fire protection
 
systems and the cross-connect is not considered for compliance with IP2 and IP3 fire
 
protection requirements. The IP3 UFSAR states that the IP3 fire protection system was originally designed as an extension of the IP1 fire protection system. After a series of
 
modifications, the IP3 fire protection was made to be independent from the IP1 fire protection
 
system. The staff finds the applicants response acceptable because it clarified that the cross-
 
connection between units is not credited for compliance with fire protection requirements, and
 
thus, is not subject to an AMR.
Exception. In the LRA, the applicant took the following exception to the GALL Report program element detection of aging effects:
NUREG-1801 specifies annual fire hose hydrostatic and gasket inspections. Fire hoses and hose station gaskets are not subject to an AMR and not included in
 
the program.
1 1 Fire hoses are periodically inspected, hydrostatically tested, and replaced as required in accordance with plant procedures. Gaskets in couplings are replaced
 
during hose station inspections.
As stated in the footnote, the applicant periodically inspects and replaces hoses and hose gaskets; therefore, they are not subject to an AMR. The applicant treats these
 
components as consumables. The staff determined that, since hose gaskets are
 
replaced on a periodic basis, this meets the guidance in SRP-LR Section 2.1.3.2.2.
The staff recognizes that the applicants interpretation of these items as consumables (short-lived components) will result in more vigorous oversight of the condition and performance of the
 
component. Therefore, the staff is adequately assured that fire hoses and hose station gaskets
 
used for the fire suppression will be considered appropriately during the period of extended
 
operation.Enhancement 1
. In the LRA, the applicant committed to implement the following enhancement to program elements parameters monitored or inspected and acceptance criteria:  [r]evise
 
applicable procedures to include inspection of hose reels for corrosion. Acceptance criteria will
 
be revised to verify no unacceptable sign of degradation.
The staff determined that this enhancement is acceptable because, when the enhancement is implemented in Fire Water System Program element parameters monitored or inspected and acceptance criteria, will be consistent with the GALL AMP XI.M27 program. The staff reviewed
 
the applicants program procedures to confirm that these elements are consistent with the GALL
 
Report. The staff is adequately assured that this enhancement will adequately manage the 3-89 effects of aging. Enhancement 2.In the LRA, the applicant committed to implement the following enhancement to program elements parameters monitored or inspected, detection of aging effects, and
 
acceptance criteria:
"IP3: Revise applicable procedures to inspect the internal surface of the foam-based fire suppression tanks. Acceptance criteria will be enhanced to verify no significant
 
corrosion. By letter dated January 17, 2008, the applicant revised this enhancement to remove
 
the reference to IP3. This enhancement now applies to both IP2 and IP3.
The staff determined that this enhancement is acceptable because, when the enhancement is implemented in Fire Water System Program elements parameters monitored or inspected,
 
detection of aging effects, and acceptance criteria, will be consistent with the GALL AMP XI.M27 program. The staff reviewed the applicants program procedures to confirm that these
 
elements are consistent with the GALL Report. The staff is adequately assured that this
 
enhancement will adequately manage the effects of aging. Enhancement 3
. In the LRA, the applicant committed to implement the following enhancement to program element detection of aging effects:
A sample of sprinkler heads for fire water systems required for 10 CFR 50.48 will be inspected using guidance of NFPA 25 (2002 Edition), Section 5.3.1.1.1, before the end of the 50-year sprinkler head service life and at 10-year intervals
 
thereafter during the extended period of operation to ensure that signs of
 
degradation, such as corrosion are detected in a timely manner.
The staff determined that this enhancement is acceptable because, when the enhancement is implemented, Fire Water System Program element detection of aging effects, will be consistent with GALL AMP XI.M27 which states that the sprinkler heads are inspected before
 
the end of the 50-year sprinkler head service life and at 10-year intervals thereafter during the
 
extended period of operation to ensure that signs of degradation, such as corrosion, are
 
detected in a timely manner.Enhancement 4
. In the LRA, the applicant committed to implement the following enhancement to program element detection of aging effects:
Wall thickness evaluations of fire protection piping will be performed on system components using non-intrusive techniques (e.g., volumetric testing) to identify
 
loss of material due to corrosion. These inspections will be performed before the
 
end of the current operating term and at intervals thereafter during the period of
 
extended operation. Results of the initial evaluations will be used to determine
 
the appropriate inspection interval to ensure aging effects are identified prior to
 
loss of intended function.
The staff determined that this enhancement is acceptable because, when the enhancement is implemented, Fire Water System Program element detection of aging effects, will be consistent with GALL AMP XI.M27 which states that wall thickness evaluations of fire protection
 
piping are performed on system components using non-intrusive techniques (e.g., volumetric
 
testing) to identify evidence of loss of material due to corrosion. These inspections are
 
performed before the end of the current operating term and at plant-specific intervals thereafter
 
during the period of extended operation. As an alternative to non-intrusive testing, the plant 3-90 maintenance process may include a visual inspection of the internal surface of the fire protection piping upon each entry into the system for routine or corrective maintenance, as long
 
as it can be demonstrated that inspections are performed (based on past maintenance history)
 
on a representative number of locations on a reasonable basis.
Operating Experience. In addition to the operating experience cited in LRA Section B.1.13, LRA Section B.1.14 stated that visual inspections of fire hose station equipment in September 2005
 
at IP3 and in November 2006 at IP2 revealed no loss of material on hose station steel parts.
 
One broken sprinkler nozzle was replaced as a result of the IP2 inspection. Detection of
 
degradation followed by corrective action prior to loss of intended function provides confidence
 
that the program will continue to effectively manages aging effects for steel fire water system components.
Further, LRA Section B.1.14 states that flow tests of fire main segments and hydrant inspections during 2006 found no evidence of obstruction or loss of material. Spray and sprinkler system functional tests and visual inspections of piping and nozzles in 2006 found no evidence of
 
blockage or loss of material. Confirmed absence of degradation provides confidence that the
 
program will continue to effectively manage loss of material for fire water system components.
The staff reviewed the above operating experience and also operating experience reports and interviewed the applicants technical staff and confirmed that the plant-specific operating
 
experience did not reveal any degradation not already bounded by industry experience. The
 
staff also reviewed the IP2 and IP3 operating experience reports, condition reports, and
 
maintenance work orders associated with the corrective actions taken for the identification of
 
signs of degradation of fire protection components. The staff confirmed that the condition
 
reports were closed out by repairs to the degraded fire barriers or performed engineering
 
evaluations for their acceptability. The staff noted that the applicant performs periodic
 
inspections and places identified deficiencies into their corrective action program to ensure
 
appropriate corrective actions are performed in a timely manner.
The staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.13 and A.3.1.13, the applicant provided the UFSAR supplement for the Fire Water System Program. By letter dated December 18, 2007, the
 
applicant revised LRA Section A.2.1.13 to state that "sprinkler heads required for 10 CFR 50.48
 
will be replaced or a sample tested using guidance of NFPA 25 (2002 edition)." By letter dated
 
January 17, 2008, the applicant revised LRA Section A.2.1.13 to add the following "revise
 
applicable procedures to inspect the internal surface of the foam-based fire suppression tanks."
The staff reviewed these sections, as revised, 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).
As documented in LRA Sections A.2.1.13 and A.3.1.13, the applicant has committed to implement the enhancements prior to entering the period of extended operation (Commitment
 
8).Conclusion. On the basis of its audit and review of the applicants Fire Water System Program, the staff determines that those program elements for which the applicant claimed consistency 3-91 with the GALL Report are consistent. In addition, the staff reviewed the exception and its justifications and determined that the program s adequate to manage the aging effects for which
 
it is credited. Also, the staff reviewed the enhancements and confirmed that their
 
implementation prior to the period of extended operation would make the existing program
 
consistent with the GALL Report AMP to which it was compared. The staff concludes that the
 
applicant has demonstrated that the effects of aging will be adequately managed so that the
 
intended functions will be maintained consistent with the current licensing basis for the period of
 
extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR
 
supplement for this program 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  Flux Thimble Tube Inspection Program
 
Summary of Technical Information in the Application. LRA Section B.1.16 describes the existing Flux Thimble Tube Inspection Program as consistent with GALL AMP XI.M37, Flux Thimble
 
Tube Inspection, with enhancements.
LRA Section B.1.16 states that the Flux Thimble Tube Inspection Program monitors thinning of the flux thimble tube wall, a path for the in-core neutron flux monitoring system detectors and
 
part of the reactor coolant system pressure boundary. Flux thimble tubes are subject to loss of
 
material at certain locations in the reactor vessel where flow-induced fretting causes wear at
 
discontinuities in the path from the reactor vessel instrument nozzle to the fuel assembly
 
instrument guide tube. A nondestructive examination (NDE) methodology, eddy current testing
 
or other similar inspection method, monitors for wear of the flux thimble tubes. This program
 
implements the recommendations of NRC Bulletin 88-09, Thimble Tube Thinning in
 
Westinghouse Reactors.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the program elements of the Flux Thimble Tube Inspection Program to verify consistency with GALL AMP XI.M37. Details of the staffs audit of the applicants AMP are documented in the Audit
 
Report. As documented in the report, the staff found that the Flux Thimble Tube Inspection
 
Program elements scope of program, preventive actions, parameters monitored or
 
inspected, and detection of aging effects, are consistent with the corresponding elements in GALL AMP XI.M37. Because these elements are consistent with the GALL Report elements, the staff finds that they are acceptable.
The staff reviewed the enhancements to determine whether the program will be adequate to manage the aging effects for which it is credited. Enhancement 1.
In the LRA, the applicant committed to implement the following enhancement to program element monitoring and trending:
[r]evise appropriate procedures to implement comparisons to wear rates identified in WCAP-12866. Include provisions to compare data to the previous performances and perform evaluations
 
regarding change to test frequency and scope.
The staff verified that the applicant included this enhancement in Commitment 9. The monitoring and trending program element in GALL AMP XI.M37 recommends that the wear
 
rate projections for flux thimble tubes be based on plant-specific wear data. The staff finds that
 
this enhancement will make the monitoring and trending program element in the Flux Thimble 3-92Tube Program consistent with the corresponding program element in GALL AMP XI.M37. The staff finds that this is acceptable because the applicant will use the plant-specific wear data to
 
adjust the projected wear values and inspection frequencies if it is determined that the wear
 
rates from the plant specific data are more conservative than the generic wear rate that is
 
recommended in WCAP-12866, Bottom-Mounted Instrumentation Flux Thimble Wear, January
 
1991. Thus, the applicant will only use the generic wear rate value if it remains conservative
 
relative to wear rates that are established from the plant-specific data.Enhancement 2.
In the LRA, the applicant committed to implement the following enhancement to program element acceptance criteria:  [r]evise appropriate procedures to
 
specify the acceptance criteria as outlined in WCAP-12866 or other plant-specific values
 
based on evaluation of previous test results.
The staff verified that the applicant included this enhancement in Commitment 9. In the acceptance criteria program element in GALL AMP XI.M37, the staff established the following recommended criteria for acceptance criteria that are used to evaluate flux thimble tube to wear:
Appropriate acceptance criteria such as percent through-wall wear will be established. The acceptance criteria will be technically justified to provide an
 
adequate margin of safety to ensure that the integrity of the reactor coolant
 
system pressure boundary is maintained. The acceptance criteria will include
 
allowances for factors such as instrument uncertainty, uncertainties in wear scar
 
geometry, and other potential inaccuracies, as applicable, to the inspection
 
methodology chosen for use in the program. Acceptance criteria different from
 
those previously documented in NRC acceptance letters for the applicants
 
response to Bulletin 88-09 and amendments thereto should be justified.
In response to the NRC Bulletin 88-09 in April 1989, the staff verified that Entergy originally committed to an acceptance criterion of 50 percent allowable throughwall wear in wall thickness
 
of the thimble tubes at IP2 and 60 percent allowable throughwall wear for the corresponding
 
thimble tubes at IP3. However, WCAP-12866 6 , established that a thimble tube can safely operate with up to 80 percent through wall loss, even with considerations of all uncertainties that
 
may occur during an ECT. The staff noted, however, that since 1991, Entergy has used
 
Westinghouses 80 percent allowable throughwall wear (i.e., a 20 percent minimum wall
 
thickness criterion) as its basis for accepting wear projections prior to the next scheduled
 
outage for the thimble tube examinations.
The staff also noted that Entergys current program calls for Entergy to perform the ECT examinations of the IP2 and IP3 thimble tubes at scheduled inspection intervals and to record 6Westinghouse WCAP-12866 is a Class 2 Proprietary Westinghouse Report. In NRC Bulletin 88-09, the staff specifically stated, in part, that each addressee is requested to establish an inspection program to monitor thimble tube performance that includes the establishment, with technical justification, of an appropriate thimble tube wear acceptance criterion. The 80 percent allowable through-wall wear acceptance criterion established in the report is not considered by the NRC to be proprietary in content because the staff did not intend this type of information to be withheld from the public when it issued NRC Bulletin 88-09. Further, this type of information has been divulged to the general public in the past in other industry correspondence, NRC correspondence, NRC audit reports, and safety evaluations.
However, the remaining specific data, equations, and information are considered to be proprietary in content and are withheld from the public, in accordance 10 CFR 2.390. Therefore, only a general basis on the acceptability of Westinghouses 80 percent through-wall wear acceptance criterion will be given in this SER.
3-93 the wall thickness measurements for the thimble. The staff also noted that the applicants program then calls for Entergy to: (1) use its plant specific wear rate data to project the
 
remaining thimble wall thickness at the next schedule outage in which thimble tube
 
examinations are performed, and (2) compare the projected wall thicknesses to the 20 percent
 
allowable minimum wall thickness criterion that is being relied upon for programmatic
 
acceptance on allowable wear.
The staff has previously accepted the 80 percent allowable throughwall wear acceptance value in the WCAP-12866 because the acceptance criterion was based on conservative burst tests on
 
Westinghouse thimble tube designs that supported this acceptance criterion for the thimble
 
tubes in Westinghouse designed nuclear plants, including IP2 and IP3. The staff also accepted
 
this value because the acceptance criterion includes an additional safety margin on allowable
 
wear in Westinghouse-designed thimble tubes.
6 The applicants enhancement of the program will ensure that the acceptance criteria used for
 
the program is proceduralized and justified. The staff has approved the 80 percent allowable
 
throughwall wear acceptance criterion in WCAP-12866 for use because the applicant may
 
justify an acceptance criterion different from this value based on the results of IP2 or IP3
 
specific wear rate data. Based on this review, the staff finds that this enhancement will make the
 
acceptance criteria program element in the Flux Thimble Tube Program consistent with the corresponding program element in GALL AMP XI.M37 and that the enhancement is acceptable. Enhancement 3.
In the LRA, the applicant committed to implement the following enhancement to program element acceptance criteria:
Revise appropriate procedures to direct evaluation and performance of corrective actions based on tubes that exceed or are projected to exceed the acceptance
 
criteria. Also stipulate in procedures that flux thimble tubes that cannot be
 
inspected over the tube length and can not be shown by analysis to be
 
satisfactory for continued service, must be removed from service to ensure the
 
integrity of the reactor coolant system pressure boundary.
The staff verified that the applicant included this enhancement Commitment 9. In the corrective actions program element in GALL AMP XI.M37, the staff established its recommendation that
 
flux thimble tubes out of conformance with the established minimum thimble tube wall thickness
 
acceptable criterion must be either isolated, capped, plugged, withdrawn, replaced, or
 
otherwise removed from service in a manner that ensures the integrity of the reactor coolant
 
system pressure boundary, and that thimble tubes approaching this acceptance criterion may
 
be repositioned. The staff also established that flux thimble tubes that cannot be inspected
 
over the tube length, that ... [are] ... subject to wear due to restriction or other defect, and that
 
can not be shown by analysis to be satisfactory for continued service, must be removed from
 
service to ensure the integrity of the reactor coolant system pressure boundary.
The staff noted that based on the applicants use of appropriate Westinghouse documents, the applicant isolates, caps, plugs, withdraws, repositions, or replaces thimble tubes whose wall
 
thicknesses are projected to be less than the minimum wall thickness of 20 percent at the next
 
inspection outage. The staff also noted that the applicants enhancement of the corrective actions program element will incorporate these corrective action criteria. Thus, based on this
 
review, the staff finds that this enhancement will make the corrective actions program element
 
in the Flux Thimble Tube Program consistent with the corresponding program element in GALL 3-94AMP XI.M37 and that the enhancement is acceptable.
Based on this review, the staff finds that the Flux Thimble Tube Inspection Program, as enhanced by the applicant, is either in conformance with the recommended criteria in GALL AMP XI.M37, or that the enhancements will ensure that use of the generic wear rate and
 
acceptance criterion in WCAP-12866 will be conservative and justified.
Operating Experience. LRA Section B.1.16 states that after flux thimble tube inspections at IP2 in March 1989, an inspection plan used the inspection results and WCAP-12866 methodology.
The applicants operating experience discussion states that, after flux thimble tube inspections at IP3 in May 1997 and May 2001, a comparison of 1997 to 2001 results for each tube
 
indicating wall loss revealed, in general, that tubes had either no significant increase in wall loss
 
or an increase of 20 percent or less over four years. The applicants operating experience
 
discussion also indicated that all 2001 recorded wall losses were below the maximum allowed
 
by the WCAP-12866 vendor guidelines and that detection of degradation prior to loss of function
 
indicates that the program is effective in managing loss of material due to wear in these
 
components.
The staff reviewed the operating experience program element in the applicants license renewal basis document for this program but did not find any additional summary details beyond
 
what was originally included and discussed in LRA AMP B.1.16. However, the staff reviewed
 
one ECT test report each for IP2 and IP3 and verified that the ECT test reports confirmed
 
Entergys claim that it was already periodically performing eddy current inspections of both IP2
 
and IP3 flux thimble tubes in accordance with the Bulletin 88-09 recommendations.
The staff also verified that, in the spring 2006 IP2 outage, Entergy repositioned all flux thimbles as part of a seal table modification, except for nine thimble tubes that the applicant capped as a
 
more conservative corrective action. The staff verified that Entergy has capped two IP3 thimble
 
tubes based on plant-specific IP3 calculations.
In RAI RCS-2, the staff asked the applicant, in part, to clarify how it performed a condition report review for relevant operating experience related to implementation of this program. The
 
applicant provided its response to RAI RCS-2 in Entergy letter dated June 5, 2008. In this
 
response, the applicant clarified that, with respect to operating experience that is applicable to
 
the Flux Thimble Tube Inspection Program, the applicant took the following two-tiered approach
 
to determine whether there was any applicable operating experience related to the reactor
 
vessel flux thimble tubes at IP2 and IP3: (1) The applicant conducted interviews of the applicable site program owners at IP2 and IP3 to discuss: (1) program effectiveness, (2) site-specific of generic bases for making any
 
programmatic changes to the program elements of the program, (3) aspects of the program that would demonstrate successful implementation and performance of the
 
program, (4) aspects of the programs that would demonstrate programmatic strengths
 
and weaknesses in the program, and (5) the results of any QA audits, self assessments, or peer review evaluations that were performed on the program (2) The applicant conducted searches to locate and review applicable inspections, test, and examinations reports for the thimble tubes in order to determine whether the inspections, examinations, or tests had indicated any evidence of aging effects in the thimble tubes.
3-95 The applicant also conducted applicable keyword searches of its condition report (CR) database in order to locate any IP2 and IP3 flux thimble tubes issues and to ensure that
 
any CRs generated as a result of this search were evaluated and retained for further
 
evaluation of the program.
The applicant stated that inspection results for these components were located in applicable thimble inspection reports, QA surveillance records, and assessment findings. The applicant
 
also stated that the results of these program owner interviews and document searches were
 
documented in the IP Operating Experience Review Report. The staff noted that the
 
applicants response to RAI RCS-2 indicated that the applicant had performed an extensive
 
enough review to search for and locate reports or documentation that would provide evidence of
 
age-related aging effects in the IP2 or IP3 flux thimble tubes. Thus, based on the response to
 
RAI RCS-2, as made relative to the Flux Thimble Program, and on the applicants corrective
 
actions of capping or repositioning to address adverse conditions of thimble tube wear, the staff
 
concludes that the applicant has performed a sufficient review for relative operating experience
 
related to flux thimble tube degradation and that the applicant has provided acceptable
 
evidence that appropriate corrective actions are taken when adverse aging related to thimble
 
tube wear is detected in the components. RAI RCS-2 is resolved with respect to the adequacy
 
of operating experience reviews and corrective actions for flux thimble tubes at IP2 and IP3.
Based on this review, the staff finds that the applicant has been performing its ECT examinations of the IP2 and IP3 thimble tubes to address the experience discussed in NRC
 
Bulletin 88-09 and that Entergy has been taking appropriate corrective action prior to the time
 
when the thimble tube wear is projected to exceeding the applicant acceptance criterion for the
 
program.Based on this review, the staff confirms that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR
 
Section A.1.2.3.10. The staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.15 and A.3.1.15, the applicant provided the UFSAR supplement for the Flux Thimble Tube Inspection Program. The staff reviewed these UFSAR
 
Supplement sections and Commitment No. 9 on the LRA. The staff verified that the UFSAR
 
Supplement summary descriptions in LRA Section A.2.1.15 and A.3.1.15 incorporated the type
 
of elements that are provided in the staffs recommended summary report description for these
 
type of programs, as given in Table 3.1-2 of the SRP-LR. The staff also verified that
 
Commitment 9 of the LRA references that the commitment is applicable to these UFSAR
 
Supplement sections. Based on the review, the staff finds that the information in the UFSAR
 
supplement provides an adequate summary description of the program and meets the
 
requirement in 10 CFR 54.21(d) because the summary descriptions have incorporated the type
 
of element descriptions that are recommended for these type of programs in the SRP-LR and
 
because the UFSAR Supplement summary descriptions appropriately reflect Commitment 9 on
 
the LRA. Conclusion. On the basis of its audit and review of the applicants Flux Thimble Tube Inspection Program, the staff determines that those program elements, for which the applicant claimed
 
consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements
 
and confirmed that their implementation prior to the period of extended operation would make
 
the existing program 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 3-96 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 program 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  Masonry Wall Program
 
Summary of Technical Information in the Application. LRA Section B.1.19 describes the existing Masonry Wall Program as consistent with GALL AMP XI.S5, Masonry Wall Program, with
 
enhancement.
The Masonry Wall Program manages aging effects so the evaluation basis established for each masonry wall within the scope of license renewal remains valid through the period of extended
 
operation. The program visually inspects all masonry walls with 10 CFR 54.4 intended functions.
 
Included components are 10 CFR 50.48-required masonry walls, radiation shielding masonry
 
walls, and masonry walls with the potential to affect safety-related components. Structural steel
 
components of masonry walls are managed by the Structures Monitoring Program. Visual
 
examinations of masonry walls are at a frequency to ensure no loss of intended function
 
between inspections.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the program elements of the Masonry Wall Program to verify consistency with GALL AMP XI.S5.
 
Details of the staffs audit of the applicants AMP are documented in the Audit Report. As
 
documented in the report, the staff found that the Masonry Wall Program elements preventive
 
actions, parameters monitored or inspected, detection of aging effects, monitoring and
 
trending, and acceptance criteria, are consistent with the corresponding elements in GALL AMP XI.S5. Because these elements are consistent with the GALL Report elements, the staff
 
finds that they are acceptable.
As documented in the Audit Report, the staff reviewed the program basis documents and confirmed that the Masonry Wall Program is an existing program that manages aging effects for
 
all masonry walls identified as performing intended functions in accordance with 10 CFR 54.4.
 
The existing program is the Condition Monitoring of Maintenance Rule Structures which is a
 
program that establishes the requirements for monitoring the various structures at IP2 and IP3
 
in accordance with 10 CFR 50.65.
The staff reviewed the enhancement to determine whether the program will be adequate to manage the aging effects for which it is credited. Enhancement.
In the LRA, the applicant committed to implement the following enhancement to the program element scope of program:  [r]evise applicable procedures to specify that the IP1
 
intake structure is included in the program.
During an audit, the staff asked the applicant if a documented seismic qualification basis, in accordance with IE Bulletin 80-11, has been developed for the masonry components of the 1P1
 
intake structure (Audit Item 62). By letter dated March 24, 2008, the applicant stated that there
 
are no masonry walls in the IP1 intake structure which meet the criteria for inclusion in the site-
 
specific IE Bulletin 80-11 program. Therefore, no seismic qualification basis in accordance with
 
IE Bulletin 80-11 has been developed for masonry walls of the IP1 intake structure. The 3-97 masonry walls in the IP1 intake structure were included in the Masonry Wall AMP because the IP1 intake structure houses components required for the alternate safe shutdown system, which
 
is credited in the Appendix R safe shutdown analysis. The staff finds that including the masonry
 
walls, located within the IP1 intake structure, in the Masonry Wall Program is acceptable since it
 
provides support for equipment that perform a function that demonstrates compliance with the
 
Commissions regulations for fire protection (10 CFR 50.48).
The staff reviewed the proposed enhancement and finds it acceptable because implementation of the enhancement will result in the inclusion of the IP1 intake structure identified by the
 
applicant as within the scope of license renewal in accordance with 10 CFR 54.4(a), which is
 
consistent with the GALL Report.
Operating Experience. LRA Section B.1.19 identifies the following inspection results for masonry walls:
Inspections of the IP2 fan house in 2001 detected cracking and spalling in some walls. These conditions did not affect their structural integrity and were repaired. Slight corrosion of column-
 
to-wall connections did not affect their structural integrity, and was listed for future monitoring.
Inspections of the IP2 fuel storage building in 2003 detected some hairline cracks and loose blocks which were listed for future monitoring.
Inspections of the IP2 control building in 2003 found evidence of water intrusion only in efflorescence on the concrete floor. This condition did not affect the structural integrity of the
 
walls.Inspections of the IP3 primary auxiliary building, fuel storage building, fan house, and turbine building in 2003 through 2005 noted minor cracking in some walls unchanged from the baseline
 
condition and some leaking seals, which were repaired. A crack in the joint between the fuel
 
storage building and the fan house was noted as acceptable with future monitoring.
Inspections of the city water metering house in 2004 detected some hairline cracks and loose blocks found acceptable but listed for future monitoring.
Inspections of the IP2 turbine building in 2004 detected minor cracks and spalling, which did not affect structural integrity, and were listed for future monitoring.
Inspections of the IP3 control building in 2005 revealed hairline cracks in the battery room walls found acceptable with no effect on structural integrity. These cracks did not require future
 
monitoring.
Inspections of the IP3 fan house in 2006 detected hairline cracks which did not affect the structural integrity of the walls and were listed for future monitoring.
Inspections of the IP3 fuel storage building in 2006 detected minor shrinkage cracking along the mortar joints on the outside of the south wall with no observable change in width since the
 
baseline inspection. These conditions did not affect the structural integrity of the walls.
The applicant concluded that detection of degradation followed by corrective action prior to loss of intended function prove that the program effectively manages cracking of masonry walls and 3-98 masonry wall joints.
The staff reviewed the program basis document discussion of operating experience. This report discussed the results of past visual examinations of masonry walls at IP2 and IP3. It cites
 
examples of degradation of some masonry walls that occurred in the past and how they were
 
disposition. In some cases hairline cracks were identified and found not to affect structural
 
integrity and in other cases cracks and loose blocks were identified and found not to affect
 
structural integrity, however, they were repaired.
The staff confirmed that the operating experience program element satisfies the guidance in SRP-LR Section A.1.2.3.10. The staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.18 and A.3.1.18, the applicant provided the UFSAR supplement for the Masonry Wall Program. The staff reviewed these sections and determines
 
that the information in the UFSAR supplement is an adequate summary description of the
 
program, as required by 10 CFR 54.21(d).
The applicant has committed to implement the enhancement prior to entering the period of extended operation (Commitment 12).
Conclusion. On the basis of its audit and review of the applicants Masonry Wall Program, the staff determines that those program elements, for which the applicant claimed consistency with
 
the GALL Report, are consistent. Also, the staff reviewed the enhancement regarding the scope
 
of program element and confirmed that its implementation prior to the period of extended
 
operation would make the existing program consistent with the GALL Report AMP to which it
 
was compared. The staff concludes that the applicant has demonstrated that the effects of
 
aging will be adequately managed so that the intended functions will be maintained consistent
 
with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff
 
also reviewed the UFSAR supplement for this program 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  Metal-Enclosed Bus Inspection Program
 
Summary of Technical Information in the Application. LRA Section B.1.20 describes the existing Metal-Enclosed Bus (MEB) Inspection Program as consistent with the GALL Report AMP XI.E4, Metal Enclosed Bus, with exceptions and enhancements.
The existing Metal-Enclosed Bus Inspection Program inspects the following non-segregated phase buses:  IP2/IP3 - 6.9kV bus between station aux transformers and switchgear buses 1/2/3/4/5/6  IP3 - 6.9kV bus for the gas turbine substation  IP2 - 480V bus for substation A  IP2/IP3 - 480V bus between EDGs and switchgear buses 2A/3A/5A/6A The applicant stated that inspections are for cracks, corrosion, foreign debris, excessive dust buildup, and evidence of water intrusion. Inspection of bus insulation is for signs of
 
embrittlement, cracking, melting, swelling, or discoloration which may indicate overheating or
 
aging degradation. The applicant further stated that inspection of internal bus supports is for
 
structural integrity and signs of cracks. Bolted connections are covered with heat-shrink tape or 3-99 insulating boots per manufacturer recommendations, so a sample of accessible bolted connections is inspected visually for insulation material surface anomalies. Enclosure
 
assemblies are inspected visually for evidence of loss of material.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Metal Enclosed Bus Inspection Program and basis documents for consistency with GALL AMP XI.E4. Details of the staffs audit of this AMP are documented in
 
the Audit Report. As documented in the report, the staff found that the Metal Enclosed Bus
 
Program elements preventive actions, and monitoring and trending are consistent with respective elements in GALL AMP XI.E4. Because these elements are consistent with the GALL
 
Report elements, the staff finds that they are acceptable.
The staff reviewed the exceptions and their justifications to determine whether the program will be adequate to manage the aging effects for which it is credited. The staff also reviewed the
 
enhancements to determine whether the program will be consistent with the GALL Report AMP XI.E4. Exception 1
. In the LRA, the applicant took the following exception to the GALL Report element parameters monitored or inspected:  NUREG-1801 specifies this program provides for the
 
inspection of the internal portion of the MEBs. The IPEC program specifies visual inspection of
 
the external surfaces of the MEB enclosure assemblies in addition to internal portions.
Exception 2
. In the LRA, the applicant took the following exception to the GALL Report element, detection of aging effects:  NUREG-1801 specifies this program provides for the inspection of
 
the internal portion of the MEBs. IPEC inspects the MEB enclosure assemblies externally in
 
addition to internal surfaces.
For both exceptions, the applicant stated under Note 1, that Inspection of the external portion of MEB enclosure assemblies under the Metal-Enclosed Bus Inspection Program assures that
 
effects of aging will be identified prior to loss of intended function. Visual inspections have been
 
proven effective in detecting indications of loss of material.
The GALL Report, Items VI.A-12 and VI-13, refer to the Structure Monitoring Program for inspecting the external of MEB for loss of material due to general corrosion and inspecting the
 
enclosure seals for hardening and loss of strength due to elastomer degradation. In LRA
 
Section B.1.20, the applicant stated that the program attribute of MEB inspection program would be consistent with the program attribute in the GALL Report, Section XI.E4 with an exception.
 
The exception is to inspect MEB enclosure assemblies in addition to internal surfaces using the
 
MEB inspection program. The staff found the exception acceptable because the external of
 
MEBs will be inspected in the MEB Inspection program instead of a separate GALL Structure
 
Monitoring Program. These inspections are the same as those in GALL Structure Monitoring
 
Program.Enhancement 1
. In the LRA, the applicant committed to implement the following enhancement to program element, scope of program:  [r]evise appropriate procedures to add IP2 480 V bus
 
associated with substation A to the scope of bus inspected. Enhancement 2
. In the LRA, the applicant committed to implement the following enhancement to program elements parameters monitored or inspected, detection of aging effects, and 3-100acceptance criteria:  [r]evise appropriate procedures to visually inspect the external surface of MEB external enclosure assemblies for loss of material at least once per every 10 years. The
 
acceptance criterion will be no significant loss of material. Enhancement 3
. In the LRA, the applicant committed to implement the following enhancement to program element, detection of aging effects:  [r]evise appropriate procedures to inspect bolted connections visually at least once every five years or at least once every ten years using
 
thermography.
During the audit and review, the staff noted that the Metal Enclosed Bus Inspection Program, under program description, only discusses visual inspection, but the enhancements to the
 
existing plant program discussed visual inspection as well as thermography. The staff also
 
noted that the site document for the AMP evaluation, Item 3(b), 4(b), and 6(b) discusses visual
 
inspections. However, the existing plant implementing procedures (etc., 480 V metal enclosed
 
buses) discuss micro-ohm checks. The staff requested the applicant to address the
 
inconsistency among site documents and the LRA. The staff also requested the applicant to provide inspection methods as described in GALL Report AMP XI.E4, or provide a basis for not
 
including these methods in the Metal Enclosed Bus Inspection Program (Audit Item 124). In a
 
letter dated March 24, 2008, the applicant stated that as indicated in LRA Section B.1.20, the
 
Metal Enclosed Bus Inspection Program is consistent with the inspection methods described
 
in the GALL Report. The program description in LRA Section B.1.20 will be clarified to describe the alternate tests and inspections discussed in the GALL Report, Section XI.E4. Visual
 
inspections will continue to be used for bolted connections as appropriate. The applicant also
 
stated that the site AMP evaluation report will also be clarified as discussed for LRA B.1.20. The
 
program description, and Items 4(b), and 6(b) will be modified to address the inspection methods besides visual that are discussed in the GALL Report AMP XI.E4. Item 3(b) does not
 
require a change, since this item is consistent with the GALL Report. The inspection methods
 
used in the existing site procedure will be reflected in the site AMP evaluation report.
In LRA Amendment 1, dated December 18, 2007, the applicant revised LRA Section B.1.20, Metal Enclosed Bus Inspection, Program Description, second paragraph, and the
 
enhancements as follows:
Program Description Inspections of the metal enclosed bus (MEB) include the bus and bus
 
connections, the bus enclosure assemblies, and the bus insulation and
 
insulators. A sample of the accessible bolted connections will be inspected for
 
loose connections. The bus enclosure assemblies will be inspected for loss of
 
material and elastomer degradation. This program will be used instead of the
 
Structures Monitoring Program for external surfaces of the bus enclosure
 
assemblies. The internal portions of the MEB will be inspected for foreign debris, excessive dust buildup, and evidence of moisture intrusion. The bus insulation or
 
insulators are inspected for degradation leading to reduced insulation resistance (IR). The bus insulation will be inspected for signs of embrittlement, cracking, melting, swelling, or discoloration, which may indicate overheating or aging
 
degradation. The internal bus supports or insulators will be inspected for
 
structural integrity and signs of cracks and corrosion. These inspections include
 
visual inspections, as well as quantitative measurements, such as thermography
 
or connection resistance measurements, as required.
3-101 Enhancements Attributes Affected: 3. Parameters Monitored or Inspected; 4. Detection of Aging
 
Effects; 6. Acceptance Criteria
 
Revise appropriate procedures to visually inspect the external surface of MEB
 
enclosure assemblies for loss of material at least once every 10 years. The first
 
inspection will occur prior to the period of extended operation and the acceptance
 
criterion will be no significant loss of material.
Attributes Affected: 4. Detection of Aging Effects Revise appropriate procedures to inspect bolted connections at least once every
 
five years if only performed visually or at least once every ten years using
 
quantitative measurements such as thermography or contact resistance
 
measurements. The first inspection will occur prior to the period of extended
 
operation.
The applicant also revised LRA Sections A.2.1.19 and A.3.1.19, Metal Enclosed Bus Inspection Program, second paragraph, as follows:
Inspections of the metal enclosed bus (MEB) include the bus and bus connections, the bus enclosure assemblies, and the bus insulation and
 
insulators. A sample of the accessible bolted connections will be inspected for
 
loose connections. The bus enclosure assemblies will be inspected for loss of
 
material and elastomer degradation. This program will be used instead of the
 
Structures Monitoring Program for external surfaces of the bus enclosure
 
assemblies. The internal portions of the MEB will be inspected for foreign debris, excessive dust buildup, and evidence of moisture intrusion. The bus insulation or
 
insulators are inspected for degradation leading to reduced insulation resistance (IR). These inspections include visual inspections, as well as quantitative
 
measurements, such as thermography or connection resistance measurements, as required.
In addition, LRA Sections A.2.1.19 and A.3.1.19, Metal Enclosed Bus Inspection Program, third paragraph, second bullet was revised as follows.
Revise appropriate procedures to inspect bolted connections at least once every five years if only performed visually or at least once every ten years using
 
quantitative measurements such as thermography or contact resistance
 
measurements.
During the license renewal regional inspection, the staff questioned the completeness of acceptance criteria for the internal inspection portion of the program procedures. The applicant
 
agreed to revise the inspection procedures to include more complete acceptance criteria and
 
amended the LRA.
In LRA Amendment 3, dated March 24, 2008, the applicant revised LRA Section A.2.1.19, Metal-Enclosed Bus Inspection Program, third paragraph to add the following enhancement:
Revise acceptance criteria of appropriate procedures for MEB internal visual inspection inspections to include the absence of indication of dust accumulation
 
on the bus bar, on the insulators, and in the duct, in addition to the absence of 3-102 indications of moisture intrusion into the duct.
The applicant also revised LRA Section A.3.1.19, Metal-Enclosed Bus Inspection Program, third paragraph to the following enhancement.
Revise acceptance criteria of appropriate procedures for MEB internal visual inspection inspections to include the absence of indication of dust accumulation
 
on the bus bar, on the insulators, and in the duct, in addition to the absence of
 
indications of moisture intrusion into the duct.
In addition, the applicant revised LRA Section B.1.20, Metal Enclosed Bus Inspection Program, Enhancements, as follows.
: 6. Acceptance Criteria
 
Revise the acceptance criteria for MEB internal visual inspections to include the absence of indication of dust accumulation on the bus bar, on the insulators, and
 
in the duct, in addition to the absence of indication of moisture intrusion into the
 
duct.The staff finds the applicants response acceptable. With the revisions described above, the applicants LRA Section B.1.20, FSAR supplements, program basis documents, and
 
plant implementation procedures are consistent with each other. The staff also finds the
 
enhancement acceptable because after enhancements the applicants MEB program are consistent with the GALL Report XI.E4. The inspection methods as described are consistent with those in the GALL Report AMP XI.E4. The acceptance criteria have been
 
revised to be more complete as agreed to during the regional inspection. The staff
 
verified in letters dated December 18, 2007, and March 24, 2008, that the applicant
 
revised LRA and UFSAR supplement as described above.
Operating Experience. LRA Section B.1.20 states that a comparison of techniques for the cleaning and inspection of metal-enclosed buses at IP2 and IP3 was performed to develop a
 
site-wide program procedure with input from NRC Information Notice 2000-014. The applicant
 
also stated that comparison of program techniques and use of industry findings in the
 
development of site-wide procedures assure continued program effectiveness in managing
 
aging effects for passive components.
The staff noted that the applicant developed a site-wide program based on lessons learned from industry findings and the staff generic communications. The staff finds this information provide
 
evidence to support the conclusion that aging will be managed adequately so that structure and
 
component intended functions will be maintained during the period of extended operation.
The staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.19 and A.3.1.19, the applicant provided the UFSAR supplement for the Metal-Enclosed Bus Inspection Program. The staff reviewed these sections
 
and the amendments as described above, and determines that the information in the UFSAR
 
supplement is an adequate summary description of the program, as required by 3-103 10 CFR 54.21(d).
As documented in LRA Sections A.2.1.19 and A.3.1.19, the applicant has committed to enhance the program prior to entering the period of extended operation (Commitment 19).
Conclusion. On the basis of its audit and review of the applicants Metal-Enclosed Bus 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 determines that the program is adequate to manage the
 
aging effects for which it is credited. Also, the staff reviewed the enhancements and confirmed
 
that their implementation prior to the period of extended operation would make the existing program consistent with the GALL Report AMP to which it was compared. The staff concludes
 
that the applicant has demonstrated that the effects of aging will be adequately managed so
 
that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this program 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  Oil Analysis Program
 
Summary of Technical Information in the Application. LRA Section B.1.26 describes the existing Oil Analysis Program as consistent with GALL AMP XI.M39, Lubricating Oil Analysis, with
 
exception and enhancements.
The Oil Analysis Program maintains oil systems free of contaminants (primarily water and particulates) to preserve an environment that is not conducive to loss of material, cracking, or
 
fouling. Activities include sampling and analysis of lubricating oil in accordance with industry
 
standards such as ISO 4406, ASTM D445, ASTM D4951, and ASTM D96. Water, particle
 
concentration and viscosity acceptance criteria are based on industry standards supplemented
 
by manufacturers' recommendations.
Oil analysis frequencies for IP2 and IP3 equipment are based on Entergy templates with technical basis justifications. These templates are based on EPRI preventive maintenance (PM)
 
bases documents TR-106857 Volumes 1 through 39 and TR-103147. Each template contains
 
sections describing failure location and cause, progression of degradation to failure, fault
 
discovery and intervention, task content and task objective. From information in these sections, frequencies are selected for the components managed by the Oil Analysis Program to mitigate
 
failure. The One-Time Inspection Program includes inspections planned to verify the
 
effectiveness of the Oil Analysis Program.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Oil Analysis Program and basis documents for consistency with GALL AMP XI.M39. Details of the staffs audit of this AMP are documented in the Audit Report. As
 
documented in the report, the staff found that the Oil Analysis Program element scope of program, is consistent with the respective element in GALL AMP XI.E4. Because this element
 
is consistent with the GALL Report element, the staff finds that it is acceptable.
The staff reviewed the exception and enhancements to determine whether the program will be adequate to manage the aging effects for which it is credited.
3-104 In the LRA the applicant states that the Oil Analysis Program includes sampling and analysis of lubricating oil for components within the scope of license renewal and subject to aging
 
management review, that are exposed to lubricating oil, for which pressure boundary integrity or
 
heat transfer is required for the component to perform its intended function. The staff confirmed
 
that the specific components for which the oil analysis program manages aging are identified
 
and the lubricating oil to which these components are exposed is included in the oil analysis
 
program.In the program basis document, the applicant states that oil systems within the scope of the program are monitored to detect and control abnormal levels of contaminants (primarily water
 
and particulates), thereby preserving an environment that is not conducive to loss of material, cracking, or fouling. In response to staffs inquiries regarding detection of out-of-specification
 
conditions, the applicant stated that the results of lube oil analyses are reviewed by the
 
predictive maintenance group to determine if oil is suitable for continued use until the next
 
scheduled sampling or scheduled oil change. Oil analysis data sheets are provided by an offsite
 
vendor with current and historical analysis results. The data are reviewed to evaluate unusual
 
trends. When degraded conditions are indicated, the predictive maintenance group will take
 
appropriate actions to check the validity of the data and issue a condition report with
 
recommended corrective actions.
The staff confirmed that preventive sampling and analysis activities were included in the implementing procedures.
In Amendment 1 to the LRA, dated December 18, 2007, the applicant revised LRA Sections B.1.26, A.2.1.25 and A.3.1.23 regarding determination of oil sampling frequencies. The
 
applicant stated that oil analysis frequencies for IP2 and IP3 equipment are based on Entergy
 
templates with technical basis justifications. The templates are based on EPRI PM bases
 
documents TR-106857 Volumes 1 through 39 and TR-103147. Each template contains sections
 
describing failure location and cause, progression of degradation to failure, fault discovery and
 
intervention, task content and task objective. From information in these sections, frequencies
 
are selected for the components managed by the Oil Analysis Program to mitigate failure. The
 
staff determined that the sampling frequencies are consistent with current industry standards, and are consistent with the plant technical specifications, where applicable. The sampling
 
frequencies will provide for timely detection of lubricating oil contamination, and will allow
 
corrective actions to be taken, as needed, prior to the loss of intended function. On this basis, the staff finds these sampling frequencies acceptable.
Exception. In the LRA, the applicant took the following exception to the GALL Report program element parameters monitored or inspected:  NUREG-1801 requires determination of flash
 
point for components that do not have regular oil changes to verify the oil is suitable for
 
continued use. IP does not determine flash point for systems that are not potentially exposed to
 
hydrocarbons. For lubricating oil systems potentially exposed to hydrocarbons, fuel dilution
 
testing is performed in lieu of flash point testing.
The staff noted that the discussion of this exception in LRA Section B.1.26 includes a footnote, which states the following:
While it is important from an industrial safety perspective to monitor flash point, it has little significance with respect to the effects of aging. Analyses of filter 3-105 residue or particle count, viscosity, total acid/base (neutralization number), water content, fuel dilution, and metals content provide sufficient information to verify
 
the oil is suitable for continued use. IPEC performs a fuel dilution test in lieu of
 
flash point testing on emergency diesel generators and IP3 Appendix R diesel
 
generator lubricating oils. This test accomplishes the same goal as the flash
 
point test but is more prescriptive. The fuel dilution test determines the percent
 
by volume of fuel and water. The analysis can determine the cause of the change
 
in flash point without having to conduct additional tests. Corrective actions, if
 
required, could be implemented on a timelier basis. For oil systems not
 
associated with internal combustion engines, lubricating oil flash point change is
 
unlikely.The staff noted that the GALL Report AMP XI.M39, states that for components with periodic oil changes in accordance with manufacturers recommendations, a particle count and check for
 
water are performed to detect evidence of abnormal wear rates, contamination by moisture, or excessive corrosion. Section XI.M39, further states that for components that do not have regular
 
oil changes, viscosity, neutralization number, and flash point are also determined to verify the oil
 
is suitable for continued use.
During an audit, the staff asked the applicant to provide a technical justification for this exception (Audit Item 69). By letter dated March 24, 2008, the applicant referred to the technical
 
basis provided in LRA section B.1.26, exception footnote 1, which states that fuel dilution testing
 
is performed in lieu of flash point testing for lubricating oil systems potentially exposed to
 
hydrocarbons. IP2 and IP3 perform a fuel dilution test in lieu of flash point testing on emergency
 
diesel generators and IP3 Appendix R diesel generator lubricating oils.
The applicant further stated that there are two factors that affect the flash point of the oil: the addition of fuel that would lower the flash point or the addition of water that would raise the flash
 
point. The fuel dilution test determines the percent by volume of fuel and the water content test
 
determines the percent by volume of water. By determining the percent by volume of both fuel
 
and water, the analysis can determine the expected change in flashpoint. While it is important
 
from an industrial safety perspective to monitor flash point, it has little significance with respect
 
to the effects of aging. Analyses of filter residue or particle count, viscosity, total acid/base (neutralization number), water content, fuel dilution, and metals content provide sufficient
 
information to verify the oil is suitable for continued use. For oil systems not associated with
 
internal combustion engines, lubricating oil flash point change is unlikely. The staff noted that the GALL Report AMP XI.M39 recommends determination of flash point for components that do not have regular oil changes to verify that the oil is suitable for continued
 
use. The applicant performs fuel dilution testing in lieu of flash point determination on lubricating
 
oil systems, such as the emergency diesel generators and the Appendix R diesel, that are
 
potentially exposed to hydrocarbons. The staff reviewed the applicants responses and
 
determined that the performance of fuel dilution testing on lubricating oil systems that are
 
potentially exposed to hydrocarbons will provide for timely detection of lubricating oil
 
degradation or contamination, and will allow corrective actions to be taken, as needed, prior to
 
the loss of intended function. Therefore, the staff concluded that this exception is consistent with
 
the recommendations in the GALL Report and is acceptable. Enhancement 1
. In the LRA, and in Amendment 1 to the LRA, dated December 18, 2007, the applicant committed to implement the following enhancement to program elements preventive 3-106 actions, parameters monitored or inspected, detection of aging effects, acceptance criteria, and corrective actions:  [f]ormalize preliminary oil screening for water and particulates and
 
laboratory analyses including defined acceptance criteria for all components included in the
 
scope of the program. The program will specify corrective actions in the event acceptance
 
criteria are not met.
The enhancement is necessary to ensure that administrative controls for preliminary oil screening for water and particulates and laboratory analyses including defined acceptance
 
criteria are in place for all components included in the scope of the oil analysis program.
The staff determined that the applicants enhancement will add routine preliminary oil screening for water and particulates and laboratory analyses including defined acceptance criteria for all
 
components included in the scope of the oil analysis program. The screening process is
 
supplemented with detailed analysis in accordance with industry standards such as ISO 4406, ASTM D445, ASTM D4951, and ASTM D96. Water, particle concentration, and viscosity
 
acceptance criteria are based on industry standards supplemented by manufacturers
 
recommendations. The preliminary oil screening process is, therefore, consistent with the
 
recommendations in the GALL Report. On this basis, the staff finds this enhancement
 
acceptable.Enhancement 2
. In the LRA, the applicant committed to implement the following enhancement to program element  parameters monitored or inspected:  IP2: Revise appropriate procedures
 
to sample and analyze lubricating oil used in the SBO/Appendix R diesel generator consistent
 
with oil analysis for other site diesel generators.
The enhancement is necessary to ensure that administrative controls for sampling and analysis of lubricating oil are in place for all components included in the scope of the oil analysis
 
program. Program activities for sampling and analysis of lubricating oil will be consistent for all
 
diesel generators on the site. The enhancement will ensure that lubricating oil sampling and
 
analysis is included for all components included in the scope of the oil analysis program.
The staff determined that the applicants enhancement will add routine sampling and analysis of lubricating oil for all diesel generators on the site which is consistent with the recommendations
 
in the GALL Report. On this basis, the staff finds this enhancement acceptable. Enhancement 3
. In the LRA, the applicant committed to implement the following enhancement to program element parameters monitored or inspected:  [r]evise appropriate procedures to
 
sample and analyze generator seal oil and turbine hydraulic control oil (electrohydraulic fluid).
The enhancement is necessary to ensure that administrative controls for sampling and analysis of generator seal oil and turbine hydraulic control oil (electrohydraulic fluid). The enhancement
 
will ensure that lubricating oil sampling and analysis is included for all components included in
 
the scope of the oil analysis program.
The staff determined that the applicants enhancement will add routine sampling and analysis of generator seal oil and turbine hydraulic control oil (electrohydraulic fluid). The enhancement will
 
ensure that lubricating oil is sampled and analyzed for all components on the site within the
 
scope of the oil analysis program which is consistent with the recommendations in the GALL
 
Report. On this basis, the staff finds this enhancement acceptable.
3-107Enhancement 4
. In the LRA and in Amendment 1 to the LRA, dated December 18, 2007, the applicant committed to implement the following enhancement to program element monitoring
 
and trending:  [f]ormalize trending of preliminary oil screening results as well as data provided
 
from independent laboratories.
The enhancement is necessary to ensure that administrative controls for monitoring and trending of preliminary oil screening results and data from independent laboratory analyses are
 
in place for all components included in the scope of the oil analysis program.
The staff determined that the applicants enhancement will add formalized routine monitoring and screening of preliminary oil screening results and data from independent laboratory
 
analyses for all components included in the scope of the oil analysis program. The screening
 
process is supplemented with detailed analysis in accordance with industry standards such as
 
ISO 4406, ASTM D445, ASTM D4951, and ASTM D96. Water, particle concentration, and
 
viscosity acceptance criteria are based on industry standards supplemented by manufacturers
 
recommendations. The formalized monitoring and trending of the results of the preliminary oil
 
screening process is, therefore, consistent with the recommendations in the GALL Report. On
 
this basis, the staff finds this enhancement acceptable.
Operating Experience. LRA Section B.1.26 states that analysis of oil samples taken in 1999 through 2006 from the containment spray pump motors showed lube oil in these motors within
 
normal tolerances and satisfactory for continued use. Absence of particulates in a routine
 
sampling program indicates a lack of corrosion, thus proving that the program effectively
 
manages aging effects. Absence of contaminants indicates that the program effectively
 
preserves an environment not conducive to loss of material, cracking, or fouling.
Analysis of an oil sample from a safety injection pump in April 2001 revealed moderate amounts of particulate and contaminates. Analysis of an oil sample from a reactor coolant pump lower
 
bearing in November 2002 indicated a high particulate level. In each case, the lube oil for these
 
pumps was replaced as a priority. Use of warning level indicators to direct corrective actions
 
prior to equipment degradation proves that the program effectively manages aging effects.
Oil analysis results for EDG samples in April and May 2002 indicated increasing metal wear concentrations. IP3 diesel fire pump engine crankcase oil analysis results in June 2003
 
indicated a trend of elevated metal wear. In each case, the lube oil was replaced and
 
appropriate corrective actions taken. Total acid numbers and viscosity levels from oil samples
 
from service water pump motors in 2006 met warning levels. A 2006 sample of lube oil from a
 
safety injection pump motor also indicated a high total acid number. Because of these data, the
 
motor lube oil was replaced prior to component degradation. Use of warning level indicators to
 
initiate corrective actions prior to equipment degradation assures program effectiveness in
 
managing aging effects.
In June 2006, the applicant compared practices for oil analysis among all Entergy Nuclear Northeast sites and developed an action plan to establish common oil sampling frequencies and
 
analysis techniques based on best practices among the sites. Comparison of program
 
techniques and development of fleet-standard practices assures continued program
 
effectiveness in managing aging effects for passive components.
The staffs review of operating experience documented in the program basis document indicates that this program has been effective in managing aging effects.
3-108 The staff confirmed that the operating experience program element satisfies the criterion in SRP-LR Section A.1.2.3.10. The staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.25 and A.3.1.25, the applicant provided the UFSAR supplement for the Oil Analysis Program.
In Amendment 1 to the LRA, Attachment 1, Audit Item 166, dated 18 December 2007, the applicant revised the first paragraph of Section A.2.1.25 and the first paragraph of Section
 
A.3.1.25 as follows:
The Oil Analysis Program is an existing program that maintains oil systems free of contaminants (primarily water and particulates) thereby preserving an
 
environment that is not conducive to loss of material, cracking, or fouling.
 
Activities include sampling and analysis of lubricating oil in accordance with
 
industry standards such as ISO 4406, ASTM D445, ASTM D4951 and ASTM
 
D96. Water, particle concentration and viscosity acceptance criteria are based on
 
industry standards supplemented by manufacturer's recommendations.
In Amendment 1 to the LRA, dated December 18, 2007, the applicant revised the second paragraph of Sections A.2.1.25 and A.3.1.25 as follows:
Oil analysis frequencies for IP2 and IP3 equipment are based on Entergy templates with technical basis justifications. Procedure EN-DC-335, "PM Bases
 
Template", is based on EPRI PM bases documents TR-106857 volumes 1 thru
 
39 and TR-103147. Each template contains sections describing failure location
 
and cause, progression of degradation to failure, fault discovery and intervention, task content and task objective. From information in these sections, frequencies
 
are selected for the components managed by the Oil Analysis Program to
 
mitigate failure.
In Amendment 1 to the LRA, dated December 18, 2007, the applicant revised the fourth paragraph of Section A.2.1.25 as follows:
The Oil Analysis Program will be enhanced to include the following. Revise appropriate procedures to sample and analyze lubricating oil used in the SBO/Appendix R diesel generator consistent with oil analysis for
 
other site diesel generators. Revise appropriate procedures to sample and analyze generator seal oil
 
and turbine hydraulic control oil (electrohydraulic fluid). Formalize preliminary oil screening for water and particulates and
 
laboratory analyses including defined acceptance criteria for all
 
components included in the scope of the program. The program will
 
specify corrective actions in the event acceptance criteria are not met. Formalize trending of preliminary oil screening results as well as data
 
provided from independent laboratories.
3-109 In Amendment 1 to the LRA, dated December 18, 2007, the applicant revised the fourth paragraph of Section A.3.1.25 as follows:
The Oil Analysis Program will be enhanced to include the following. Revise appropriate procedures to sample and analyze generator seal oil and turbine hydraulic control oil (electrohydraulic fluid). Formalize preliminary oil screening for water and particulates and
 
laboratory analyses including defined acceptance criteria for all
 
components included in the scope of the program. The program will specify corrective actions in the event acceptance criteria are not met. Formalize trending of preliminary oil screening results as well as data
 
provided from independent laboratories.
The staff reviewed these sections and determines that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
As documented in LRA Sections A.2.1.25 and A.3.1.25, the applicant has committed to enhance the program prior to entering the period of extended operation (Commitment 18).
Conclusion. On the basis of its audit and review of the applicants Oil Analysis Program, the staff determines that those program elements, for which the applicant claimed consistency with
 
the GALL Report, are consistent. In addition, the staff reviewed the exception and its technical
 
justification and determines that the program is adequate to manage the aging effects for which
 
it is credited. Also, the staff reviewed the enhancements and confirmed that their
 
implementation prior to the period of extended operation would make the existing program
 
consistent with the GALL Report AMP to which it was compared. The staff concludes that the
 
applicant has demonstrated that the effects of aging will be adequately managed so that the
 
intended functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement
 
for this program 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  Reactor Vessel Surveillance Program
 
Summary of Technical Information in the Application. LRA Section B.1.32 describes the existing Reactor Vessel Surveillance Program as consistent with GALL AMP XI.M31, Reactor Vessel
 
Surveillance, with enhancement.
The Reactor Vessel Surveillance Program manages reduction in fracture toughness of reactor vessel beltline materials to maintain the pressure boundary function of the reactor pressure
 
vessel through the period of extended operation. The program, based on ASTM E-185, Recommended Practice for Surveillance Tests for Nuclear Reactor Vessels, as required by 10 CFR Part50
, Appendix H, evaluates radiation damage shown by pre- and post-irradiation testing of Charpy V-notch and tensile specimens. The rate at which these specimens accumulate radiation damagewill be higher than that of the vessel because the specimens are 3-110 closer to the core than the vessel itself.
Under the Reactor Vessel Integrity Program, reports submitted as required by 10 CFR Part 50
, Appendix H include a capsule withdrawal schedule, a summary report of capsule withdrawal and test results, and, if needed, a technical specification change for pressure-temperature limit
 
curves. The program, which meets ASTM E-185 recommendations and complies with
 
10 CFR Part 50, Appendix H, evaluates radiation damage shown by pre- and post-irradiation
 
testing of Charpy V-notch and tensile specimens from the most limiting plate in the core region
 
of the reactor vessel (RV).
Staff Evaluation. During its review, the staff confirmed the applicants claim of consistency with the GALL Report. The staff reviewed the enhancements to determine whether the AMP, with the
 
enhancements, remained adequate to manage the aging effects for which it is credited.
The Reactor Vessel Surveillance Program is identified as consistent with the program described in GALL Report, Section XI.M31, "Reactor Vessel Surveillance," with enhancements. The
 
enhancements are: (1) to withdraw and test a standby capsule to cover the peak reactor vessel
 
fluence that is expected through the end of the period of extended operation; and (2) to revise
 
procedures to require that tested and untested specimens from all capsules pulled from the
 
reactor vessel be maintained in storage.
The staff reviewed the enhancement to determine whether the program will be adequate to manage the aging effects for which it is credited. Enhancement
. In the LRA, the applicant committed to implement the following enhancement:
The specimen capsule withdrawal schedules will be revised to draw and test a standby capsule to cover the peak reactor vessel fluence expected through the
 
end of the period of extended operation.
Appropriate procedures will be revised to require that tested and untested specimens from all capsules pulled from the reactor vessel are maintained in
 
storage.In Commitment 22, the applicant stated that it will revise the specimen capsule withdrawal schedules for IP2 and IP3 to withdraw and test a standby capsule to cover the peak RV neutron
 
fluence expected through the end of the period of extended operation.
The withdrawal schedules will be submitted as required by 10 CFR Part 50, Appendix H, Section III.B.3.
In response to the staffs RAI B.1.1.32-1, the applicant provided the lead factors for each standby capsule, the materials available to be tested in each capsule, and the date for capsule
 
withdrawal to ensure that the neutron fluence of the surveillance capsule will be equal or greater
 
than the peak RV neutron fluence through the end of the period of extended operation. The
 
response by the applicant is contained in their letter dated November 28, 2007.
Indian Point Nuclear Generating Unit No. 2 has three remaining capsules with lead factors of 1.2. The capsules contain surveillance test specimens from plates B2002-1, B2002-2 and
 
B2002-3 and correlation monitor material. The lead factor is the ratio of the neutron fluence of 3-111 the capsule to the neutron fluence of the reactor vessel. Therefore, the IP2 capsules will receive 20 percent more neutron fluence than the IP2 RV.
To ensure that the neutron fluence of the surveillance capsule will be equal to or greater than the peak RV neutron fluence through the end of the period of extended operation, at least one
 
capsule will remain in the RV until approximately 40 effective full power years (EFPY). This
 
burnup should be attained approximately 8 years prior to the end of the period of extended
 
operation or around 2025.
Indian Point Nuclear Generating Unit No. 3 has three remaining capsules with lead factors of 1.52. Capsules W and U have surveillance test specimens from plates B2803-3 and B2802-1
 
and weld metal. Capsule V has surveillance test specimens from plate B2803-3 material, weld
 
metal, ASTM reference material and weld heat affected zone material. Since the lead factor is
 
1.52, the IP3 capsules will receive 52 percent more neutron fluence than the IP3 RV.
To ensure that the neutron fluence of the surveillance capsule will be equal to or greater than the peak RV neutron fluence through the end of the period of extended operation, a capsule
 
must remain in the RV until approximately 32 EFPY. This burnup should be attained
 
approximately 16 years prior to the end of the period of extended operation or around 2019.
The staff finds that the testing of the surveillance capsules in accordance with the proposed schedule provides reasonable assurance that the neutron-induced embrittlement in low alloy
 
steel RV base metals and their associated welds will be adequately monitored during the
 
extended period of operation. Additionally, the staff finds that the applicants Reactor Vessel
 
Surveillance Program complies with the requirements of the 10 CFR Part 50, Appendix H.
Operating Experience. LRA Section B.1.32 states that an updated RV surveillance capsule withdrawal schedule for IP2 was submitted to the staff in November 2004. Information from the
 
surveillance program throughout the IP2 operating history was included in this request to
 
change the previous schedule. The staff determined that the new withdrawal schedule met the 1982 Edition of ASTM E-185 criteria and complied with 10 CFR Part50
, Appendix H. Review of the surveillance requirements against industry standards, confirmed through staff oversight, assures continued program effectiveness in managing reduction in fracture toughness for RV
 
beltline materials.
A summary of IP3 surveillance capsule exposure was prepared in a November 2003 neutron fluence evaluation for the units power uprate. This evaluation will be used to project the neutron
 
exposure of the reactor vessel for future operating periods at the uprated power level. The surveillance capsule lead factors in this calculation will be the basisfor development of future capsule withdrawal schedules. Review of the surveillance program due tochanges from the
 
power uprate assures continued program effectiveness in managing reduction in fracture
 
toughness for reactor vessel beltline materials.
The staff confirmed that the operating experience program element satisfies the guidance in SRP-LR Section A.1.2.3.10. The staff findsthis program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.31 and A.3.1.31, the applicant provided the UFSAR supplement for the Reactor Vessel Surveillance Program. The staff reviewed these sections and determines that the information in the UFSAR supplement isan adequate summary description
 
of the program, as required by 10 CFR 54.21(d).
3-112 As documented in LRA Sections A.2.1.31 and A.3.1.31, the applicant has committed to enhance the program prior to entering the period of extended operation (Commitment 22).
Conclusion. On the basis of its review of the applicants Reactor Vessel Surveillance Program
, the staff determined that those program elements, for which the applicant claimed consistency
 
with the GALL Report, are consistent. Also, the staff reviewed the enhancement and confirmed that itsimplementation would make the existing program consistent with the GALL Report AMP
 
to which it was compared. The staff concluded 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 program and
 
concluded that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.2.14  Steam Generator Integrity Program
 
Summary of Technical Information in the Application. LRA Section B.1.35 describes the existing Steam Generator Integrity Program as consistent with GALL AMP XI.M19, Steam Generator
 
Tube Integrity, with enhancement.
In the industry, steam generator (SG) tubes have experienced degradation from corrosion phenomena (e.g., PWSCC, outside diameter SCC, intergranular attack, pitting, and wastage)
 
with other mechanically-induced phenomena (e.g., denting, wear, impingement damage, and
 
fatigue). NDE techniques detect defective tubes that must be removed from service or repaired
 
in accordance with plant technical specifications. The Steam Generator Integrity Program
 
monitors and maintains secondary side component integrity. The program defines inspection
 
and maintenance schedules, scope of work, and methods. The Steam Generator Integrity
 
Program is consistent with NEI 97-06, Steam Generator Program Guidelines.
Staff Evaluation. During its review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff reviewed the program
 
elements of the Steam Generator Integrity Program to verify consistency with GALL AMP XI.M19. Based on the staffs review, the staff determined that Steam Generator Integrity
 
elements scope of program, preventive actions, parameters monitored or inspected,
 
detection of aging effects, and acceptance criteria, are consistent with the corresponding elements in GALL AMP XI.M19. Because these elements are consistent with the GALL Report
 
elements, the staff finds that they are acceptable.
The staff reviewed the enhancement to determine whether the program will be adequate to manage the aging effects for which it is credited. Enhancement
. In the LRA, the applicant committed to implement the following enhancement program element monitoring and trending:  [r]evise appropriate procedures to require that the
 
results of the condition monitoring assessment are compared to the operational assessment
 
performed for the prior operating cycle with differences evaluated.
The applicant has committed to enhancing the program by requiring that the results of the condition monitoring assessment be compared to the operational assessment performed for the
 
prior cycle with the differences evaluated. The operational assessment is performed at the 3-113 completion of an inspection to demonstrate that SG tube integrity will be maintained during the up-coming operating cycle. It predicts what tube degradation will occur during operation, until
 
the next planned inspection, and evaluates SG tube structural integrity and leakage integrity for
 
that predicted level of degradation. The condition monitoring assessment is performed with as-
 
found tube degradation data on a defect-specific basis, to demonstrate compliance with integrity
 
criteria by the comparing the NDE measurements with calculated burst and leakage integrity
 
limits. Calculated integrity limits, including consideration for appropriate uncertainties, burst and leak analytical correlations, material properties, NDE technique, and analyst uncertainties are
 
provided in the degradation assessment report.
The staff agrees that this comparison and evaluation is an important attribute of an acceptable Steam Generator Integrity Program that should be performed and will result, long term, in a
 
more robust program. The enhancement will be consistent with the guidance in NEI 97-06, Steam Generator Program Guidelines, which endorses the EPRI Steam Generator Integrity
 
Assessment Guideline, (EPRI TR 107621). The EPRI guidelines state that condition monitoring
 
results are to be evaluated with respect to the previous operational assessment and if the
 
operational assessment did not bound the condition monitoring, then an analysis, in accordance
 
with the plant corrective action program, shall be performed. Since these guidelines are
 
consistent with the GALL Report, the staff finds that this enhancement is acceptable.
In RAI 3.1.2.2.14-1, dated December 7, 2007, the staff requested that the applicant provide additional details on the SG secondary side inspections performed on the feedwater inlet rings
 
for each unit, to monitor for wear and loss of material due to flow accelerated corrosion.
In its response, by letter dated January 4, 2008, the applicant provided the following information. The IP2 SGs were replaced in 2000. The feedwater rings in the replacement SGs
 
are not scheduled to be inspected until 2010. This planned inspection will be for two of the four
 
SGs. The acceptance criteria for the inspection are the absence of any unusual conditions. Any
 
conditions that do not meet this criterion will require further evaluation. This inspection
 
frequency and criteria are acceptable based on the relatively short operating time of the new
 
SGs and that the Steam Generator Integrity Program is implemented in accordance with NEI
 
97-06, Steam Generator Program Guidelines, which includes inspections to assure secondary
 
side component integrity.
The IP3 SGs were replaced in 1989. Since that time there have been 5 different inspections of all or some of the feedwater rings: in 1992 all 4 SGs were inspected, in 1997 SG 34, in 1999 SG
 
33, in 2001 SG 32, and in 2007 SGs 31 & 32. The scope of the inspections performed in 1997
 
through 2007 consisted of a visual exam of the outer diameter of the ring and a fiberscope
 
inspection of the inner diameter of 5 selected J-nozzles (out of 36 total) and the feedwater ring
 
tee. The next feedwater ring inspection for IP3 is planned for 2 SGs in 2013. No anomalies were
 
noted in the prior inspections other than the appearance of minor washed out areas on the
 
exterior of the feedwater ring beneath the outlets of the J-nozzles. The feedwater entering the
 
steam generators exits the J-nozzles welded to the feedwater ring such that the discharge is
 
directed downward towards the exterior of the feedwater ring. The feedwater ring is a carbon
 
steel pipe that has a thin oxide film on the exterior surface. The flow from the J-nozzles prevents
 
this oxide buildup giving the appearance of washed out areas where this feedwater impact
 
occurs. Visual inspections of these washed out areas did not identify any loss of material on the
 
feedwater ring.
3-114 Based on the applicants response to the RAI describing the secondary side inspections performed to detect feedwater ring degradation, the staff finds the applicants response to the
 
RAI 3.1.2.2.14-1 acceptable. The staffs concern in RAI 3.1.2.2.14-1 is resolved.
Operating Experience. LRA Section B.1.35 states that IP2 SGs replaced in December 2000 began operating at uprated power levels in November 2004. IP3 SGs replaced in 1989 began
 
operating at uprated power levels in April 2005.
A March 2003 IP3 SG degradation assessment per NEI 97-06 Revision 1 and the EPRI PWR Steam Generator Examination Guidelines Revision 5 (EPRI TR-107569) summarized the
 
inspection results of IP3 replacement SGs since their installation in refueling outage 3R7
 
(1989), compared them to industry operating experience, and described a refueling outage
 
3R12 (2003) inspection plan based on this input. Use of plant-specific and industry operating
 
experience and industry guidance in the development of an inspection plan assures program
 
effectiveness in managing aging effects for passive components.
All indications from inspections of the IP3 SGs in March 2003 (refueling outage 3R12) were below calculated integrity limits in the pre-outage degradation assessment. During these
 
refueling outage inspections, the staff evaluated the SG integrity assessment program and
 
compared it to the staff-accepted guidance of EPRI PWR Steam Generator Examination
 
Guidelines, Revision 5 (EPRI TR-107569). To evaluate implementation of the SG assessment
 
program, the staff witnessed SG tube testing and secondary side inspection processes and
 
made no significant findings. Confirmation of program compliance with established standards
 
and regulations assures effective program management of passive component aging.
The applicant revised the IP2 program procedure in June 2005 to incorporate the results of the September 2004 INPO Steam Generator Review Visit and the IP3 program procedure in July
 
2005 to incorporate the latest EPRI guidelines. Review of existing practices by industry groups, implementation of process improvements, and incorporation of industry guidelines assure
 
continued program effectiveness in managing aging effects for passive components.
An INPO-assisted self-assessment of the IP2 and IP3 SG programs in September 2004 generated actions that led to program improvement in several key areas. Detection of program
 
weaknesses and subsequent corrective actions assure continued program effectiveness in
 
managing loss of component material.
An IP2 SG degradation assessment in April 2006 per NEI 97-06 Revision 1 and the EPRI TR-107569 summarized the inspection results of IP2 replacement SGs since their installation in
 
December 2000, compared the results to industry operating experience, and listed a refueling
 
outage 2R17 (2006) inspection plan based on this input. Use of plant-specific operating
 
experience, industry operating experience, and industry guidance in the development of an
 
inspection plan assures continued program effectiveness in managing aging effects for passive
 
components.
All indications from inspections of the IP2 SGs in April 2006 were below calculated integrity limits in the pre-outage degradations assessment.
In April 2006, the regional inspection staff reviewed portions of the SG management plan, degradation assessment, and the final operational assessment to evaluate the SG inspection
 
and management program. The staff reviewed plant-specific SG information, tube inspection 3-115 criteria, integrity assessments, degradation modes, and tube plugging criteria. Entergy conducted eddy current testing of tubes in all SGs to detect and quantify tube degradation
 
mechanisms and to confirm tube integrity following the completion of two fuel cycles of
 
operation. The staff observed a sample of tubes from each generator to verify Entergys
 
examination of the entire length and made no significant findings. Confirmation of program
 
compliance with established standards and regulations assures effective program management
 
of passive component aging. The staff evaluated the SG tube inspection report for the
 
inspections performed during 2006, 2R17 refueling outage and concluded the applicant
 
provided the information required by the technical specifications and that the applicants
 
inspection program appears to be consistent with the objective of detecting potential tube
 
degradation and with industry operating experience at similarly designed units.
The staff confirmed that the operating experience program element satisfies the recommendations in the GALL Report and the guidance in SRP-LR Section A.1.2.3.10. The
 
staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.34 and A.3.1.34, the applicant provided the UFSAR supplement for the Steam Generator Integrity Program. The staff reviewed these sections 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).
As documented in LRA Sections A.2.1.34 and A.3.1.34, the applicant has committed to enhance the program prior to entering the period of extended operation (Commitment 24).
Conclusion. On the basis of its review of the applicants Steam Generator Integrity Program, the staff determines that those program elements, for which the applicant claimed consistency with
 
the GALL Report, are consistent. Also, the staff reviewed the cited enhancement and confirmed
 
that its implementation prior to the period of extended operation would make the existing AMP
 
consistent with the GALL Report AMP to which it was compared. The staff concludes that the
 
applicant has demonstrated that the effects of aging will be adequately managed so that the
 
intended 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 program 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 Structures Monitoring Program
 
Summary of Technical Information in the Application. LRA Section B.1.36 describes the existing Structures Monitoring Program as consistent with GALL AMP XI.S6, Structures Monitoring
 
Program, with enhancements.
The applicant states that Structures Monitoring Program inspections are in accordance with 10 CFR 50.65 (Maintenance Rule) as addressed in Regulatory Guide 1.160 and NUMARC
 
93-01. Periodic inspections monitor the condition of structures and structural components for
 
loss of intended function. As protective coatings are not relied upon to manage the effects of
 
aging for structures in the Structures Monitoring Program, the program does not address
 
protective coating monitoring and maintenance.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the 3-116 program elements of the Structures Monitoring Program to verify consistency with GALL AMP XI.S6. Details of the staffs audit of this AMP are documented in the Audit Report. As
 
documented in the report, the staff found that the Structures Monitoring Program elements
 
preventive actions, parameters monitored or inspected, monitoring and trending, and acceptance criteria, are consistent with the corresponding elements in GALL AMP XI.S6.
 
Because these elements are consistent with the GALL Report elements, the staff finds that they
 
are acceptable.
The staff reviewed the enhancements to determine whether the program will be adequate to manage the aging effects for which it is credited. Enhancement 1
. In the LRA, the applicant committed to implement the following enhancement to program element of scope of program:
Appropriate procedures will be revised to explicitly specify that the following structures are included in the program.
* Appendix R emergency diesel generator foundation (IP3)
* Appendix R emergency diesel generator fuel oil tank vault (IP3)
* Appendix R emergency diesel generator switchgear and enclosure (IP3)
* city water storage tank foundation
* condensate storage tanks foundation (IP3)
* containment access facility and annex (IP3)
* discharge canal (IP2/3)
* emergency lighting poles and foundations (IP2/3)
* fire pumphouse (IP2)
* fire protection pumphouse (IP3)
* fire water storage tank foundation (IP2/3)
* gas turbine 1 fuel storage tank foundation
* maintenance and outage building-elevated passageway (IP2)
* new station security building (IP2)
* nuclear service building (IP1)
* primary water storage tank foundation (IP3)
* refueling water storage tank foundation (IP3)
* security access and office building (IP3)
* service water pipe chase (IP2/3)
* service water valve pit (IP3)
* superheater stack
* transformer/switchyard support structures (IP2)
* waste holdup tank pit (IP2/3)
From the applicant
=s description, the staff could not identify the complete scope of the program.
Very significant enhancements to the A scope of program
@ are identified, but there is no description of the scope of the existing program, and there is no explanation why such major enhancements to the program scope are needed for license renewal. While most of the added
 
structures serve a license renewal intended function for 10 CFR 54.4(a)(3), about half of these
 
structures also serve license renewal intended functions for 10 CFR 54.4(a)(1) or 10 CFR
 
54.4(a)(2). In accordance with RG 1.160 and NUMARC 93-01 these structures would be
 
expected to be included in the current existing program.
3-117 In an audit question, the staff asked Entergy to (1) describe the structures and structural components inspected as part of the existing structures monitoring program; and (2) explain
 
why 11 structures listed in the scope of program
@ enhancement have intended functions for 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(2) (Audit Item 85).
By letter dated December 18, 2007, the applicant responded to the audit item. In its response to (1), Entergy provided a list of the structures and structural components which are inspected as
 
part of the existing Structures Monitoring Program. The staff reviewed this list and confirmed
 
that it matched the list of existing structures presented in the program basis documents (PBDs).
In its response to (2), for each of the structures listed in the enhancement to the scope of program that have intended functions for 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(2), Entergy
 
described its function and its specific intended function for license renewal. The staff reviewed
 
this information and finds the response acceptable.Enhancement 2
. In the LRA, the applicant committed to implement the following enhancement to program element scope of program:
Appropriate procedures will be revised to clarify that in addition to structural steel and concrete, the following commodities are inspected for each structure as part
 
of the Structures Monitoring Program:
* cable trays and supports
* concrete portion of reactor vessel supports
* conduits and supports
* cranes, rails, and girders
* equipment pads and foundations
* fire proofing (pyrocrete)
* HVAC duct supports
* jib cranes
* manholes and duct banks
* manways, hatches, and hatch covers
* monorails
* new fuel storage racks
* sumps, sump screens, strainers and flow barriers The staff notes that the specific commodities listed would be expected to be included in the current existing program if they are safety-related or important to safety. In an audit question, the staff asked Entergy to (1) describe the structural commodities inspected as part of the
 
existing structures monitoring program; and (2) explain why the 13 commodities are identified as
 
an enhancement to the scope of program (Audit Item 86).
By letter dated December 18, 2007, the applicant responded to the audit item. In its response to (1), Entergy explained that the structural commodities inspected as part of the existing program
 
include structural steel beams, columns, and end connections; support steel (e.g., instrument racks, base plates); and concrete surfaces. Individual inspection checklists are provided in the
 
program procedures for each commodity.
In its response to (2), Entergy explained that these 13 commodities are routinely inspected under the existing Structures Monitoring Program (AMP B.1.36); however, they are not explicitly 3-118identified in the program procedures. Therefore, this enhancement will be implemented to ensure that these commodities are explicitly identified in the program.
The staff concurs that all of the commodities identified in the enhancement need to be explicitly included in the Structures Monitoring Program (SMP). Anchorages (base plates, grout, and steel
 
anchors) and connections (welds or bolts) to building steel, associated with all applicable
 
supports should also be clearly identified. During follow-up audit discussions with Entergy, Entergy proposed to add the phrase (including their anchorages) to confirm that the support
 
anchorages are included in the Structures Monitoring Program. The staff accepted Entergys
 
proposal. This additional enhancement to the scope of program element has been added to
 
Commitment 25, in Revision 1 of the List of Regulatory Commitments, submitted by Entergy on
 
December 18, 2007.
The staff also reviewed the LRA Structures AMR Tables 3.5.2-1 through -4 and noted that several structural components, which credit AMP B.1.36 for aging management, are not specifically identified in the existing program scope or in the enhancement. In an audit question, the staff requested Entergy to confirm that all component type/aging effect combinations that
 
credit the Structures Monitoring Program for aging management in Tables 3.5.2-1 through 3.5.2-
 
4 are included in the scope of the Structures Monitoring Program, and are inspected for the
 
designated aging effect (Audit Item 244). In its response, dated December 18, 2007, Entergy
 
stated that all component type/aging effect combinations that credit the Structures Monitoring
 
Program for aging management in Tables 3.5.2-1 through 3.5.2-4 are inspected for designated
 
aging effects; however, some structural components are not specifically identified in the scope
 
of the Structures Monitoring Program. The staff finds this acceptable, because this AMP is
 
applicable to aging management of the vast majority of structures and structural components in
 
the plants. Enhancement 3
. In the LRA, the applicant committed to implement the following enhancement to program elements of scope of program, and detection of aging effects:
Guidance will be added to the Structures Monitoring Program to inspect inaccessible concrete areas that are exposed by excavation for any reason.
 
IPEC will also inspect inaccessible concrete areas in environments where
 
observed conditions in accessible areas exposed to the same environment
 
indicate that significant concrete degradation is occurring.
The staff finds this enhancement acceptable, because it provides additional appropriate guidance for inspection. Enhancement 4
. In the LRA, the applicant committed to implement the following enhancement to program element detection of aging effects:  [r]evise applicable structures monitoring
 
procedures for inspection of elastomers (seals, gaskets, seismic joint filler, and roof elastomers)
 
to identify cracking and change in material properties and for inspection of aluminum vents and
 
louvers to identify loss of material.
The staff finds this enhancement acceptable, because it provides additional guidance for inspection.
3-119Enhancement 5
. In the LRA, the applicant committed to implement the following enhancement to program element detection of aging effects:
Guidance to perform an engineering evaluation of groundwater samples to assess aggressiveness of groundwater to concrete on a periodic basis (at least
 
once every five years) will be added to the Structures Monitoring Program. IPEC
 
will obtain samples from a well that is representative of the ground water
 
surrounding below-grade site structures. Samples will be monitored for sulfates, pH and chlorides.
The staff notes that Entergys above enhancements to the Structures Monitoring Program are necessary for license renewal.
In an audit question, the staff requested Entergy to (Audit Item 87):
(a) describe past and present groundwater monitoring activities at the Indian Point site, including the sulfates, pH and chlorides readings obtained; and the location(s) where test
 
samples were/are taken relative to the safety-related and important-to-safety embedded
 
concrete foundations; and (b) Explain the technical basis for concluding that testing a single well every five (5) years is sufficient to ensure that safety-related and important-to-safety embedded concrete foundations
 
are not exposed to aggressive groundwater.
By letter dated December 18, 2007, the applicant responded to the audit item. In response to (a), Entergy stated:
There is a sufficient number of analytical results to ensure that the ground water is being properly monitored. Large numbers of groundwater wells located
 
adjacent to the structures have been sampled and were analyzed for sulfate and
 
chloride at a contract laboratory, with pH having been determined at the time of
 
sample collection. The data indicates that the ground water is non-aggressive (pH >5.5, Chloride <500 ppm and Sulfate <1500 ppm). Several samples taken
 
along the facility waterfront and adjacent to the discharge canal were noted to
 
have higher than normal levels of chloride. Given the location of samples, these
 
higher than normal levels are believed to be due to the salinity of the brackish
 
Hudson River water at the Indian Point location of the river. In all cases pH
 
results are >5.5 and sulfate concentration < 1500 mg/L. Ground water samples
 
will continue to be obtained on a quarterly basis for one calendar year in order to
 
fully characterize these parameters (Chloride, Sulfate, and pH) for the
 
groundwater at IPEC to account for any seasonal variation. The selected sample
 
locations will provide representative samples of the ground water in the vicinity of
 
the structures. A review of the several hundred ground water pH values collected
 
in late 2005 to present reveal that the ground water had a pH of >5.5 in all cases
 
except four. In those four cases, pH was found to be <5.5 standard unit (SU). All
 
four of these low pH samples were obtained from the same sample point on the
 
same day. To date all subsequent samples taken from this sample point were
 
found to have a pH >5.5 SU.
3-120 In response to (b), Entergy stated: that at least five (5) wells will be tested. A sample frequency of five years in a limited number of wells (at least five wells) adjacent to safety structures and
 
those falling under 10 CFR 54.4 (a)(1) and 10 CFR 54.4 (a)(2) would be sufficient to confirm the
 
non-aggressive nature of the ground water. The large sample population for the initial
 
characterization, the diverse locations from which the samples were obtained and the
 
seasonality of sample collections contribute to Entergys confidence in the understanding of the
 
nature of the ground water. Additionally, Entergy stated it would not normally expect to see the
 
ground water conditions change unless an extraordinary event occurred, such as major
 
withdrawals (such as significant pumping out the ground water) or injections of water on the site
 
or in the vicinity of the site.
The staff finds Entergys responses to be acceptable, on the basis that (1) extensive sampling has been recently conducted, without evidence of an aggressive below-grade environment; and
 
(2) Entergy has committed to increase the sample size from one well to at least five wells in the
 
vicinity of in-scope buried concrete structural elements. This new commitment was added to
 
Commitment 25, in Revision 1 of the List of Regulatory Commitments, submitted by Entergy on
 
December 18, 2007. In LRA Appendix B, Table B-2, the applicant stated that GALL AMP XI.S7 is not credited for aging management of water control structures. Instead, the Structures Monitoring Program manages the effects of aging on the water control structures at IP. GALL AMP XI.S7 offers this option, provided all the attributes of GALL AMP XI.S7 are incorporated in the applicant
=s Structures Monitoring Program.
In an audit question, the staff requested Entergy to (1) identify the specific water control structures that have an intended function for license renewal, and are included in the scope of
 
AMP B.1.36; (2) describe the attributes of AMP B.1.36 that pertain to aging management of
 
water control structures; and (3) explain how these attributes of AMP B.1.36 encompass the attributes of GALL AMP XI.S7, without exception (Audit Item 88).
By letter dated December 18, 2007, the applicant responded to the audit item. In its response to (1), Entergy indicated that the water control structures that have an intended function for license
 
renewal and are included (or will be included) in the scope of the AMP B.1.36 are the intake
 
structure (including intake structure enclosure) and the discharge canal. Since the discharge
 
canal is not specifically stated in the structures monitoring procedures, Entergy indicated that an
 
enhancement for AMP B.1.36 will be to explicitly specify the discharge canal.
The staff concludes that the Structures Monitoring Program B.1.36 can be used to manage aging of the IP water-control structures, in lieu of GALL AMP XI.S7 (RG 1.127, Inspection of
 
Water-Control Structures Associated with Nuclear Power Plants).
In its response to (2), Entergy described the attributes of AMP B.1.36 that pertain to aging management of water-control structures. More detailed information was provided in Entergys
 
response to part (3) of the audit question.
In it response to (3), Entergy provided a description of how the ten attributes of AMP B.1.36 encompass the attributes of GALL AMP XI.S7. Compared to the five year intervals recommended for inspection in GALL AMP XI.S7, Entergy indicated the Structures Monitoring
 
Program (AMP B.1.36) similarly uses intervals of five years for accessible areas and
 
opportunistic inspections for buried components. The staff did not find this consistent with GALL 3-121AMP XI.S7 for submerged structures. During follow-up audit discussions with Entergy, Entergy proposed to revise LRA Commitment 25, to add the following: Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspection of normally submerged concrete
 
portions of the intake structures at lease once every 5 years, or earlier if determined to be
 
necessary. The staff accepted Entergys proposal, on the basis that it is consistent with GALL AMP XI.S7. This enhancement was added to Commitment 25, in Revision 1 of the List of
 
Regulatory Commitments, submitted by Entergy on December 18, 2007.
Based on the staffs review of the LRA, the basis documents, Entergys responses to the audit items discussed above, and Entergys additions to Commitment 25, submitted on December 18, 2007, the staff concludes that the scope of program, parameters monitored or inspected, and
 
the detection of aging effects program elements are consistent with the GALL Report. Also, consistent with the GALL report, the preventive actions program element is not applicable.
Operating Experience. LRA Section B.1.36 states that inspections of structural steel, concrete exposed to fluid, and structural elastomers from 2001 through 2005 revealed signs of
 
degradation: cracks, gaps, and corrosion (rust). Monitoring of concrete structures and
 
components from 2001 through 2006 identified only minor cracks that did not affect the
 
structural integrity of the components. Monitoring of structural steel members revealed only
 
minor corrosion. The applicant states that inspection intervals, adjusted as necessary, ensure
 
that future inspections detect degradation prior to loss of intended function. The applicant also
 
states that detection of degradation and corrective action prior to loss of intended function
 
assure program effectiveness in managing aging effects for structural components.
The staff reviewed the discussion of operating experience for the existing plant-specific Structures Monitoring Program. In addition, the staff reviewed a number of condition Reports (CRs) that briefly describe occurrences of structural degradation at IP2 and IP3. Based on
 
review of the CR summaries, the staff identified a number of apparently significant conditions of
 
aging degradation of structures that are not identified in the LRA, the basis documents for the
 
Structures AMPs, or the Structures AERM.
In a series of audit questions related to plant-specific operating experience for structures, the staff asked Entergy to provide additional information for the following types of degraded
 
conditions:
Water Control Structures Degradation (Audit Item 358)
IP2 Reactor Cavity Leakage (Audit Item 359)
 
IP2 Spent Fuel Pool Crack/Leak Paths (Audit Item 360)
 
IP2 Containment Dome Concrete Spalling (Audit Item 361)
The staff referenced specific CRs that described each type of degradation, and asked Entergy to discuss: (a) history of the degradation (b) evaluation of the extent of degradation (c) operability assessments performed (d) corrective actions taken (describe in detail)
(e) the current status of the degraded condition (f) corrective actions planned prior to the LR period 3-122(g) special or augmented aging management requirements during the period of extended operation(h) license renewal commitments By letter dated, March 24, 2008, the applicant provided responses to the above questions. The staff evaluated Entergys response for IP2 Containment Dome Concrete Spalling (Audit
 
Item 361) in its assessment of Entergys Containment ISI Program, LRA AMP B.1.8. See
 
Section 3.0.3.3.2 of this SER.
Water Control Structures Degradation (Audit Item 358)
In its response for Water Control Structures Degradation, dated March 24, 2008, Entergy described the noted degraded conditions in greater detail, summarized corrective actions taken, and identified the current status of the degradation. For degraded areas that have not been
 
repaired, Entergy will continue to monitor the degradation under the Structures Monitoring
 
Program during the extended period of operation. However, Entergy initially made no
 
commitment for augmented inspection during the extended period of operation for the degraded
 
areas that have not been repaired. The staff informed Entergy that its responses to
 
Items (g) and (h) needed additional clarification and also requested Entergy to provide the
 
technical basis as to why augmented inspection during the extended period of operation is not
 
necessary for the degraded areas.
The applicant provided its supplemental response in a letter dated August 14, 2008. In its response, the applicant stated that evaluations conducted under its corrective action program
 
indicated the degraded conditions did not compromise intended functions at this time. The
 
applicant committed to perform more frequent inspection of these locations (every three years
 
instead of five years) under its Structures Monitoring AMP (Commitment 25).
The applicant has committed to more frequent inspection of the degraded water control structures, which is consistent with the GALL Report recommendation. The GALL Report
 
references RG 1.160 for Maintenance Rule monitoring of structures. RG 1.160 recommends
 
more frequent monitoring for areas of known degradation. The staff concludes that a 3 year
 
monitoring frequency is sufficient to identify further degradation before there is loss of intended
 
function. Therefore, the staff finds the applicants response and supplemental clarification for
 
Audit Question 358 to be acceptable. IP2 Reactor Cavity Leakage (Audit Item 359)
In its response dated March 24, 2008, for IP2 Reactor Cavity Leakage, Entergy described the degraded conditions in greater detail, summarized corrective actions taken, and identified the
 
current status of the degradation. The reactor cavity at IP2 has a history of leakage at the upper
 
elevations of the stainless steel cavity liner when flooded during refueling outages. There is a
 
relatively free flow of water behind the liner, down to the 46-foot elevation inside containment.
 
Attempts have been made over the last several outages to mitigate this condition, with limited
 
success. An action plan is being developed for a permanent fix to this issue. Two technologies
 
are being investigated for the permanent solution.
For the extended period of operation, Entergy will rely on the Structures Monitoring Program for aging management of the reactor cavity concrete and containment internal structures. For aging 3-123 management of the cavity steel liner, Entergy will rely on the Water Chemistry Control - Primary and Secondary Program. However, Entergy made no commitment for augmented inspection
 
during the extended period of operation. The staff informed Entergy that its responses to Items (g) and (h) needed additional clarification. In a follow-up discussion relating to Audit Question
 
359, the staff expressed its concern with regard to the potential for degradation of the
 
underlying concrete and reinforcement due to the leakage of borated water through the cavity
 
liner and potential impact of the leakage on other adjacent structures. The staff requested
 
Entergy to provide the technical basis as to why augmented inspection during the extended
 
period of operation is not necessary, if the recurring leak condition is not permanently fixed.
The applicant provided its supplemental response in a letter dated August 14, 2008. In its response, the applicant stated that the leakage is entirely contained within and is collected in
 
the lower elevation of the containment building. The cavity water leakage is easily replaced from
 
the refueling water storage tank. The collected leakage is pumped to the radioactive liquid
 
waste processing system and the leakage does not affect structures other than the refueling
 
cavity. The applicant stated that the leakage does not pose a threat to the structural integrity of
 
the refueling cavity reinforced concrete walls, which are 4 feet thick, and cited several
 
documented tests that concluded borated water does not significantly degrade concrete
 
properties. In addition, a core sample was removed from the IP2 refueling cavity wall in 1993.
 
Examination showed that the depth of penetration of borated water was 1/2 inch into the concrete
 
at that time. The applicant stated that substantial design margins are available in the concrete
 
and reinforcement. The applicant emphasized that the flooded condition, and therefore the
 
leakage exists for about 2 weeks out of a refueling cycle of about 1.5 years. A number of
 
attempts have been made to rectify this condition, but to date have not been completely
 
successful. The applicant indicated that it will continue to work toward a permanent fix, but will
 
prioritize this effort based on its safety significance and availability of site resources. The
 
applicant has committed to perform a one-time inspection and evaluation of a sample of
 
potentially affected refueling cavity concrete, including embedded reinforcing steel, prior to the
 
period of extended operation, in order to provide additional assurance that the concrete walls
 
have not degraded (Commitment 36).
As noted at the beginning of this program section, the applicant claims that it is consistent with the GALL Report AMP XI.S6 with enhancements. The GALL Report AMP recommends that for
 
each structure/aging effect combination, the specific parameters monitored or inspected should
 
be selected to ensure that aging degradation leading to loss of intended functions will be
 
detected and the extent of degradation can be determined. For the program element detection
 
of aging effects, the AMP recommends that for each structure/aging effect combination, the
 
inspection methods, inspection schedule, and inspector qualifications should be selected to
 
ensure that aging degradation will be detected and quantified before there is loss of intended
 
functions. The staff notes that the applicant plans to enhance the detection of aging effects
 
element of its Structures Monitoring Program to inspect inaccessible concrete areas in
 
environments where observed conditions in accessible areas exposed to the same environment
 
indicate that significant concrete degradation is occurring. However, the leakage is occurring in
 
inaccessible areas, and a similar environment may not exist for accessible areas of concrete.
The staff concluded that Entergys commitment to perform a one-time inspection and evaluation of a sample of potentially affected refueling cavity concrete, including embedded reinforcing
 
steel, prior to the period of extended operation, is appropriate in order to assess the current
 
state of the concrete and rebar. However, because the applicant does not plan to perform
 
periodic inspections of the refueling cavity and affected area, the staff determined that for this 3-124 structure/environment/aging effect combination, the applicant is not consistent with the GALL Report AMP. Additionally, the applicants program did not address concrete exposed to borated
 
water.In a telephone call with Entergy on August 27, 2008 (Audit Item 359), the applicant described its plan for permanent remediation of the IP2 refueling cavity leakage problem. By letter dated
 
November 6, 2008, the applicant submitted a supplemental response to Audit Question 359, describing its plan for implementing a permanent fix over the next three (3) scheduled IP2
 
refueling outages (2010, 2012, 2014).. At the time of issuance of the SER with Open Items, the
 
staff was in the process of reviewing the applicants response. Therefore, this issue was
 
identified as Open Item 3.0.3.2.15-1.
Entergys proposed plan to mitigate the refueling cavity leak includes:  2008 / 2009 - Research available technologies to repair leaks in the refueling cavity. Spring 2010 refueling outage - Repair area of north wall weld seams in the vicinity of the Ceramoloy patch and south wall along area of disbonded Ceramoloy patch. Spring 2012 refueling outage - Repair east wall where large Ceramoloy patch has
 
disbonded and area around access ladder on northwest corner. Spring 2014 refueling outage - Repair areas of lower cavity where Ceramoloy patches
 
have disbonded, and miscellaneous areas observed as suspect from past inspections. During each of the preceding outages, areas not permanently repaired will be
 
temporarily repaired by the application of Instacote. Beginning in the refueling outage in
 
Spring 2016, no Instacote will be applied, to allow Entergy to determine if repairs have
 
successfully stopped the leakage. If not, additional areas will be repaired in subsequent
 
outages until the leakage is corrected.
The staff reviewed the applicant's response dated November 6, 2008, and noted that the applicant did not make a license renewal commitment to permanently remediate the refueling
 
cavity leakage. Therefore, the staff determined that the applicant should define an appropriate
 
aging management program to be implemented if the remediation plan is not completely
 
successful in stopping the leakage.
In an effort to resolve this open item, the staff issued follow-up RAI 1: Open Item 3.0.3.2.15-1 (Audit Question 359), dated April 3, 2009, in which the staff requested the following information: (a) . . . provide additional information on the leakage path from the refueling cavity to the collection point lower in containment, as well as the leak
 
flow-rate. In this regard, describe the leakage path and chemical
 
composition of the leaking fluid, provide historical flow-rate values, and
 
confirm whether or not any leakage enters the reactor cavity inside the
 
primary shield wall. Provide the technical basis as to how the leakage
 
path was determined, with a focus on water entering the reactor cavity.
 
Provide a sketch of containment and the refueling cavity which highlights
 
the leakage path.
3-125(b) . . . In absence of a formal commitment to remedy the source of leakage, the applicants aging management program (AMP) should include a
 
method to monitor for a degrading condition in the refueling cavity, and
 
other structures and components that would be affected by the leakage, during the period of extended operation, or the applicant should explain
 
how the structures monitoring program will adequately manage potential
 
aging of this region during the period of extended operation.
In letter dated May 1, 2009, Entergy responded to follow-up RAI 1: Open Item 3.0.3.2.15-1 (Audit Question 359), stating as follows: (a) During the first refueling outage in 1976, leakage from the refueling cavity was observed coming from the reactor cavity. The original designed
 
temporary seal between the reactor vessel flange and the reactor cavity
 
was not leak tight. The leakage collected in the reactor cavity pit sump
 
and was pumped out. A plant modification was initiated to use a new
 
design seal, which resolved the problem. Leakage also occurred in the
 
reactor vessel inlet and outlet blow out plugs and instrumentation
 
wireways. Leakage through these paths has been minimized by
 
improving sealing methods. The leakages from the above sources were
 
not from behind the reactor cavity liner and through concrete construction
 
joints.In 1993, it was determined that leakage from the refueling cavity was coming through the liner plates. This event initiated detailed investigations
 
and corrective actions to stop the leakage. Unfortunately, the sealing
 
methods have not fully resolved the leakage. The suspect leakage path
 
was determined by visual observation during and after filling the refueling
 
cavity with water. Leakage is observed as the cavity is filled for refueling
 
operations. Leakage starts as the cavity level reaches the 80 ft. elevation
 
which is approximately 50% cavity level. Leakage was observed initially
 
from three significant areas associated with refueling cavity construction.
 
[Applicant referenced Figure 1, included with the response.] Leakage
 
from the refueling cavity collects in a drainage trench on the 46 ft
 
elevation of containment inside the crane wall from where it flows to the
 
containment sump.
A small portion of the leakage from the refueling cavity enters the reactor cavity flowing down the interior primary shield walls to a sump located in
 
the reactor cavity from where it is pumped to the containment sump.
 
Leakage inside the reactor cavity has been primarily attributed to non-
 
liner leakage associated with reactor cavity seal and nozzle inspection
 
box cover isolation issues.
The leaking fluid from the refueling cavity is mixed reactor coolant and refueling water storage tank water with total estimated flow rates on the
 
order of 3 to 7 gpm. No samples of the fluid flowing from the leaking
 
areas have been analyzed for chemical composition. There has been no
 
degradation of containment structural surfaces from this wetting as
 
observed in the Structures Monitoring Program. [Applicant referenced 3-126 Figures 1 through 4, included with the response, for sketches of the containment area and the refueling cavity which show the locations of the
 
observed leakage.] (b) As previously described in IPEC Letter NL-08-127 dated August 14, 2008, Audit Question 359, the refueling cavity is a robust structure, with thick
 
walls and low stress levels when compared to the total structural capacity.
 
Exposure to borated water has not resulted in identified degradation or
 
reduction of structural integrity. Industry and IPEC operating experience
 
for the past years has shown that concrete is not significantly affected by
 
exposure to borated water. The refueling cavity is wet during the limited
 
duration (approximately 14 days) when it is filled and is dry during the
 
subsequent period (approximately 24 months) of normal power
 
operations. Moisture remaining following draining of the cavity would be
 
dried up by the ambient temperatures resulting from reactor operation, thus long-term exposure to borated water that could cause significant
 
degradation of the concrete and embedded reinforcement is not
 
expected.The method to monitor for a degrading condition in the refueling cavity is routine visual inspection of accessible concrete surfaces under the
 
Structures Monitoring Program accompanied by an inspection of concrete
 
that has been exposed to the intermittent borated water leakage for an
 
extended period. The inspection is required by the formal commitment to
 
do core bore samples in the upcoming outage in 2010 for concrete that
 
has been exposed to the leaking borated water on an intermittent basis
 
for much of the life of the plant. If leakage occurs during the upcoming
 
outage, IPEC will obtain a sample of leaking water at an exit point below
 
the cavity and evaluate it for fluid composition.
The results of the sample analysis will be evaluated to establish whether additional aging management activity is necessary during the period of
 
extended operation. Additionally core bore samples will be taken, if
 
leakage is not stopped prior to the end of the first ten years of the period
 
of extended operation (Reference Commitment #36). Other structures
 
and components that could be affected by the leakage that are not
 
addressed under the Structures Monitoring Program would be evaluated
 
under the Boric Acid Corrosion Program. As previously committed to in
 
IPEC Letter NL-08-127, dated August 14, 2008, inspections and activities
 
related to the identification of leakage in the refueling cavity and its impact
 
on the surrounding concrete will provide reasonable assurance that the
 
associated structures will remain capable of fulfilling their license renewal
 
intended functions. The established site operating experience review
 
program ensures that any subsequent new industry or IPEC operating-
 
experience will be incorporated to ensure adequate management of
 
potential aging effects of this region during the period of extended
 
operation.
The staff reviewed the applicants May 1, 2009 response and concluded that additional clarifications were needed before the staff could make a determination whether the applicants 3-127 revised commitments are sufficient to ensure there will be no loss of intended function during the 20 year extended period of operation.
In an effort to resolve this issue, the staff issued follow-up RAI 2: Open Item 3.0.3.2.15-1, dated May 20, 2009, which requested the following: (a) In part (a) of the applicants response, Figures 1 through 4 do not clearly identify the flow path from the refueling cavity liner to the A, B, and C
 
water exit locations.  . . . In an elevation view (similar to Figure 2), cut
 
through each of the exit locations A, B, and C, showing the horizontal and
 
vertical dimension between the entry point through the liner and the exit
 
location. To the extent possible, describe the possible circumferential
 
traverse of the leakage, from the entry point through the liner to the exit
 
location.(b) The staff requests the applicant to provide the following additional information/clarification regarding the revised license renewal
 
commitments in part (b) of the applicants response: (1) The current remediation plan has targeted the 2014 outage for completion. Please identify actions that will be taken if the
 
remediation plan is unsuccessful. (2) Identify the specific location and number of the concrete core samples (e.g., the three water exit locations) that will be removed
 
and tested (i) during the upcoming 2010 refueling outage, and (ii)
 
at 10 years into the extended period of operation (if a permanent
 
solution for the leakage has not been achieved, in accordance
 
with Entergys current remediation plan). Define the tests that will
 
be performed, and the objective of each test. (3) Please advise if the revised commitments in the applicants May 1, 2009 response include chemical analysis of the leaking water (i)
 
during the upcoming 2010 refueling outage, and (ii) at 10 years
 
into the extended period of operation. Please identify the analyses
 
that will be performed, and the objective of each analysis.
In its response, dated June 12, 2009, Entergy responded to follow-up RAI 2: Open Item 3.0.3.2.15-1 as follows: a. Based on leakage investigations, the reactor refueling cavity begins to leak when the water in the cavity reaches an approximate elevation
 
between 80- 85. As can be seen on the attached elevation views of the
 
cavity (Entergy provided Figures 1 thru 4 in its response), horizontal weld
 
seams exist between these elevations, but the exact liner leakage points
 
are unknown. We can, however, make the following observations
 
regarding the relationship between the leakage areas in the concrete
 
structure denoted as points A, B and C, and conditions of the cavity liner:
3-1281. Above point A, defects in the CeramAlloy patch along a horizontal weld seam located on the south wall at an elevation between 80-
 
85 has been observed. The CeramAlloy patch material that
 
covers several weld seams was a previous attempt to mitigate the
 
cavity leakage. This is a potential cavity liner leak point for the
 
observed leakage on the concrete structure at point A. 2. Above the exit point denoted as B, defects in a CeramAlloy patch along a horizontal weld seam located at an elevation between
 
80- 85 on the south wall has been observed. This patch area is
 
an extension from the area discussed in Item 1 above. In addition, the upper internals stand support base is attached to the cavity
 
floor above the vicinity of the observed leakage in the concrete
 
structure at point B. Both these areas in the cavity liner are
 
potential leak point sources for the observed leakage at point B. 3. Above the observed leakage area in the concrete structure denoted as point C, defects in both the CeramAlloy patches along
 
weld seams and potential defects in the weld seams themselves
 
at the north cavity wall have been observed. These defects are
 
located approximately 10-15 above the cavity floor and are
 
potential leak points for the leakage observed at point C. b. The following provides Entergys response to part (b) of the staffs request.1. Should the remediation plan for the cavity liner targeted for completion during the 2014 outage be unsuccessful, Entergy will
 
perform additional monitoring to assess the condition of potentially
 
affected structures. To assure continued structural integrity of the
 
reactor refueling cavity reinforced concrete walls, Entergy will
 
perform further core sampling and inspect reinforcing steel at
 
suspect locations as described in Item 3. 2. (i) During the upcoming 2010 outage, a total of 3 core bore samples will be taken from the reinforced concrete walls that form
 
the outer shell of the reactor refueling cavity steel liner. The
 
locations of these core bores will be chosen based on the
 
following: Locations in the vicinity of observed liner/liner patch degradation in relative proximity to the observed leak
 
points A, B and C on the concrete structure. Accessibility of suspect areas based on the principle of As Low As Reasonably Achievable (ALARA) and physical
 
interferences.
The core samples will be tested and chemically analyzed to determine the effect, if any, past leakage has had on the concrete 3-129 properties. The objectives of the physical and chemical tests of the concrete core samples are as follows:  Determine the compressive strength of concrete. Determine boron and chloride concentration in concrete. Determine pH of concrete.
In addition, a petrographic examination will be performed on the core samples to evaluate the cementitious matrix, and, to the
 
extent possible, determine the durability of the concrete.
In addition, reinforcing steel in the core sample areas will be exposed and inspected. Visual inspections of the reinforcing steel
 
will be performed to determine the extent of material loss, if any, from the steel as a result of the borated water leakage. (ii) If a solution to the leakage has not been achieved, Entergy will perform core samples and reinforcing steel inspections prior to 10
 
years into the period of extended operation. Locations of the core
 
samples will be chosen based on the extent and location of the
 
leakage remaining following previous repair efforts. Core samples
 
will be tested and chemically analyzed as discussed under part 2
 
above. Visual inspections of the reinforcing steel will be performed
 
to determine the extent of material loss, if any, from the steel as a
 
result of the borated water leakage. 3. (i and ii) Revised Commitment 36 includes chemical analysis of water leakage from the refueling cavity. During the upcoming 2010
 
outage, Entergy will collect water samples from the cavity leak and
 
perform chemical analysis. If the leakage has not been stopped, Entergy will collect additional water samples of the leak during the
 
same outage as the core samples are taken, no later than 10
 
years into the period of extended operation. The water that is
 
collected will be analyzed for the following:  Boron concentration  pH  Iron  Calcium Results of the analysis will be evaluated to assess the aggressiveness of the leaking fluid to reinforced concrete
 
structures.
The staff reviewed the applicants responses to the staffs RAIs and clarification concerning the IP2 refueling cavity leakage (Audit Item 359) provided in letters dated March 24, 2008, August
 
27, 2008, November 6, 2008, May 1, 2009, May 20, 2009, and June 12, 2009. The staff noted
 
the following:  The borated water leakage during the reactor refueling operations has not adversely 3-130 affected the structural integrity of the refueling cavity concrete structure. The leakage occurs for a short duration (approximately 14 days) during refueling outages (normally
 
every 24 months). Visual examination of the leakage areas has not identified any
 
degradation of concrete. In addition, previous studies and testing by the nuclear industry
 
and the applicant have not identified any degradation of the concrete or reinforcement
 
when exposed to low concentrations of borated water. The applicant has committed to take three core bore samples of the concrete, at the
 
observed leakage locations, during the upcoming 2010 outage. The samples will
 
determine the compressive strength and the pH value of concrete, as well as the boron
 
and chloride concentration in the concrete. This information will be used to determine
 
the effect of borated water on the concrete. Petrographic examination of the core
 
samples will also help identify the effect of borated water on the durability of the IP2
 
refueling cavity area concrete prior to the period of extended operation. Visual examination of reinforcement exposed during core boring of concrete during the
 
2010 outage will identify any material loss due to corrosion resulting from interaction with
 
borated water. The applicant has committed to analyze the water leaking from the refueling cavity for
 
boron concentration, pH, iron, and calcium during the 2010 outage. This analysis will
 
provide additional information on the effect of the leakage on the reinforced concrete
 
structures. The applicants goal is to permanently remediate the refueling cavity leakage by the end
 
of the 2014 refueling outage. Since the leakage is the source of possible degradation, eliminating the leakage will also eliminate the possible degradation mechanism.
 
However, if the remediation is unsuccessful, the applicant has committed to re-inspect
 
the concrete, rebar, and leaking water prior to the tenth year of extended operation. The
 
staff finds the timing of this inspection acceptable based on site-specific operating
 
experience. IP2 has experienced refueling cavity leakage since 1993, which means the
 
concrete has been exposed to the leakage during refueling outages for at least 16 years
 
with no visible signs of degradation. If the 2010 inspections also show no degradation
 
after 16 plus years of intermittent leakage, there is reasonable assurance that a follow-
 
up inspection within 10 years will detect any future degradation prior to a loss of
 
intended function of the refueling cavity structures.
Based on the inspections conducted to date and the actions the applicant is planning to take prior to and during the period of extended operation, the staff finds that the aging effects on the
 
IP2 refueling cavity concrete will be adequately managed during the period of extended
 
operation, as required by 10 CFR 54.21(a)(3). Therefore, Open Item 3.0.3.2.15-1 is closed.
IP2 Spent Fuel Pool Crack/Leak Paths (Audit Item 360)
In its response for IP2 spent fuel pool (SFP) crack/leak paths, Entergy described the noted degraded conditions in greater detail, summarized corrective actions taken, and identified the
 
current status of the degradation. The leakage was first discovered during excavation for the
 
IP2 Fuel Storage Building in 2005. Entergy believes the conditions leading to leakage have
 
been corrected.
3-131 For the extended period of operation, Entergy will rely on the Structures Monitoring Program for aging management of the spent fuel pool concrete, and rely on the Water Chemistry Control -
 
Primary and Secondary Program and monitoring of the pool level per technical specifications for
 
aging management of the spent fuel pool stainless steel liner. However, Entergy made no
 
commitment for augmented inspection during the extended period of operation. The staff
 
informed Entergy that its responses to Items (g) and (h) needed additional clarification. Due to
 
the lack of a leak-chase channel system at IP2 to monitor, detect and quantify potential leakage
 
through the SFP liner, the staff is concerned that there has been insufficient time following the
 
corrective actions to be certain that the leakage problems have been permanently corrected. In
 
a follow-up discussion with regard to Audit Question 360, the staff requested Entergy to provide
 
the technical basis as to why augmented inspection during the extended period of operation is
 
not necessary.
The applicant provided its detailed response in a letter dated August 14, 2008. In its response, the applicant stated that all known sources of leakage from the IP2 spent fuel pool have been eliminated based on the inspections and repairs already implemented. The licensee stated that
 
it completed, in 2007, a one-time inspection of the accessible 40 percent of the SFP liner above
 
the fuel racks and 100 percent of the SFP transfer canal liner using general visual, robotic
 
cameras and vacuum box testing techniques. To provide additional indication of potential spent
 
fuel pool leakage, the applicant has committed to test the groundwater outside the IP2 spent
 
fuel pool for the presence of tritium from samples taken from adjacent monitoring wells, every 3
 
months. The presence of tritium in the groundwater could be indicative of a continuing leak from
 
the spent fuel pool (Commitment 25). The applicant has also revised the LRA description of its
 
Structures Monitoring AMP to include this special testing as an enhancement.
Although Entergy has taken corrective action and has committed to quarterly monitoring for tritium in the groundwater, the staff was concerned that hidden degradation of concrete and
 
rebar may have resulted from prior leakage, and may be continuing if there is still an active
 
leakage mechanism. In a telephone call with Entergy on September 3, 2008, the staff requested
 
the applicant to submit additional relevant information on the condition of concrete and rebar in
 
areas where leakage was detected, and the existing design margins in these areas.
By letter dated November 6, 2008, the applicant submitted a supplemental response to Audit Item 360, which provided a detailed description of (1) the design margins for the spent fuel pool
 
concrete walls; and (2) the results of prior concrete core sample testing and rebar corrosion
 
testing. At the time of issuance of the SER with Open Items, the staff was in the process of
 
reviewing the applicants response. Therefore, this issue was identified as Open Item
 
3.0.3.2.15-2. The applicants letter of November 6, 2008, provided the following information:
IPEC analyzed the capability of the east spent fuel pool pit wall and the south spent fuel pool pit wall to resist the design basis loads considering potential
 
concrete and reinforcement steel degradation due to observed leakage of fluids
 
through these walls. Finite Element models for both the east and south walls
 
were developed to determine the actual forces in the walls due to loading
 
resulting from the design basis earthquake, hydrostatic forces and dead weight.
 
Due to the symmetry of the spent fuel pit structure, results from the evaluation of
 
these two walls are applicable to the remaining north and west walls. The
 
following summarizes the results and conclusions from these two analyses.
3-132 East Wall Evaluation The capacity of the east wall was evaluated in response to possible degradation due to an observed leak in 1992. It was determined that work in the spent fuel
 
pool in 1990 initiated the leak by inadvertently creating a small hole in the
 
stainless steel liner. This condition was repaired in 1992. A total of 20 core bores
 
were taken from 5 locations on the east wall in the vicinity of the observed
 
leakage to determine the condition of the concrete following exposure to borated
 
water leakage. At each of the 5 locations, 4 individual cores 4" in diameter and
 
15" in length were taken, resulting in a total depth of penetration into the wall of
 
60". In addition, several windows in the outer surface of the wall were created to
 
allow inspection of the outer layer of reinforcing steel. Of the 20 cores taken, all
 
but one had compressive strengths that exceeded the design strength of 3000
 
psi. This one core outlier had a measured compressive strength of 2400 psi.
The lower value was attributed to its close proximity to a known concrete sub-surface delamination in the wall and was not considered to be representative of
 
the general condition of the wall. Analysis of the concrete matrix showed that the
 
borated water had little or no effect on the concrete itself. Little or no corrosion
 
was observed in the rebar except at a location in the wall where spalling had
 
occurred exposing rebar to the elements. Analysis of the rust particles showed
 
high chloride content and low boron concentration indicating that rainwater was
 
the primary cause of the observed corrosion. To determine the available margin
 
in the east wall, moments were calculated using a finite element plate model. The
 
results of the analysis showed the east wall was capable of resisting the
 
applicable forces without any reinforcing steel and would incur little or no
 
cracking as a result of the design loading. Conservatively assuming that the
 
concrete would crack and the bending moments would be carried by the
 
reinforcing steel, the following minimum margins exist with respect to the ultimate
 
moment capacity of the wall. In other words, the load bearing capability of the
 
wall is at least 31% greater than the required load bearing capability.
Northeast Corner 1/ 4to 1/2 wall depth: 31%
Mid Span 1/ 4to 1/2 wall depth: 43%
South Wall Evaluation An evaluation determined the margins in the south wall due to possible rebar degradation as a result of observed fluid emanating from a crack discovered in
 
the west corner during excavation for the dry cask storage project. The
 
reinforcing steel in the area of the observed leak was exposed for inspection. The
 
condition of the reinforcing steel was good with little or no corrosion. To
 
determine the actual forces in the south wall due to the design basis loads, a
 
finite element model of the wall was developed. Based on the resulting moments
 
from the analysis, the margins in the south wall with respect to the ultimate
 
moment capacity of the concrete section are as noted below:
Section with Horizontal Steel at Wall Center: 45%
Section with Horizontal Steel at Crack Location: 51%
 
Section with Vertical Steel at Crack Location: 57%
3-133 Section with Vertical Steel at Base: 25%
The available margins in the east and south walls of the spent fuel pool pit with respect to the as-designed condition range from a low of 25% at the base of the
 
wall for the vertical steel to a high of 57% for the vertical steel at the crack
 
location in the west corner of the wall. The margins for the horizontal rebar at wall
 
mid span range from 43%-45% and up to 51% in the vicinity of the observed
 
crack.The staff reviewed the applicant's November 6, 2008 response, and determined that additional clarifications were necessary before it could conclude that the applicants proposed aging
 
management program for the extended period of operation is sufficient.
In an effort to resolve this open item, the staff issued follow-up RAI 2: Open Item 3.0.3.2.15-2 (Audit Question 360), dated April 3, 2009, which requested the following: (a) In Commitment 25, the applicant commits to sample for tritium in groundwater wells in close proximity to the IP2 spent fuel pool at least
 
every three months to assess for potential indications of spent fuel pool
 
leakage. This commitment does not describe what actions will be taken if
 
leakage continues. If sampling indicates continued leakage, the
 
applicants AMP should include a method to determine if a degraded
 
condition exists during the period of extended operation, or the applicant
 
should explain how the Structures Monitoring Program will adequately
 
manage potential aging of the inaccessible concrete of the IP2 spent fuel
 
pool due to borated water leakage during the period of extended
 
operation.(b) The second paragraph on page 2 of Attachment 1 of the clarification letter dated November 6, 2008, states in part: [l]ittle or no corrosion was
 
observed in the rebar except at a location in the wall where spalling had
 
occurred exposing rebar to the elements. Analysis of the rust particles
 
showed high chloride content and low boron concentration indicating that
 
rainwater was the primary cause of the observed corrosion. The staff
 
requests the applicant to identify any Unit 2 and Unit 3 operating
 
experience related to rebar corrosion, in light of the chloride content in
 
rainwater, and identify the likely source for the high chloride content in the
 
rainwater. Additionally, the applicant is requested to explain whether and
 
how the AMP is adequate to address this environment and the related
 
potential aging effects to ensure there is no loss of intended function
 
during the period of extended operation.
By letter dated May 1, 2009, Entergy provided the following response to follow-up RAI 2: Open Item 3.0.3.2.15-2 (Audit Question 360): (a) As indicated in Entergy letter NL-08-127, dated August 14, 2008, Audit Question 360, degradation has not been attributed to the effects of aging, but to poor construction and workmanship practices during initial
 
construction activities. Consequently, future degraded conditions are not
 
expected.
3-134 The method to determine if a degraded condition exists during the period of extended operation is continued monitoring for leakage by monitoring
 
SFP level and monitoring ground water in the vicinity of the pool exterior
 
walls for indications of pool leakage. The absence of leakage will indicate
 
no degraded condition exists. Leakage, if any, indicates potential
 
degradation. If leakage is found, it will be evaluated under the corrective
 
action program (i.e., Element 7 of the SMP). If sampling indicates that
 
ground water contains constituents indicating pool leakage then
 
evaluation is required under the corrective action program to assess the
 
potential for degradation and determine appropriate corrective actions. An
 
example of the aggressive corrective actions expected in response to
 
identified leakage is found in the condition report described in response to
 
Audit Question 360, Entergy Letter NL-08-127, dated August 14, 2008.
 
Corrective actions for that condition included inspections of all accessible
 
surfaces of the SFP liner, installation of monitoring wells in the vicinity, performance of UT examinations, bore samples, rebar inspections and
 
inspections using remote camera technology.
As stated in the Statement of Consideration (SOC) for the license renewal rule, Given the Commission's ongoing obligation to oversee the safety
 
and security of operating reactors, issues that are relevant to current plant
 
operation will be addressed by the existing regulatory process within the
 
present license term rather than deferred until the time of license
 
renewal. Since the issue of SFP leakage is currently being addressed by
 
the existing licensing and regulatory process that process provides
 
reasonable assurance that appropriate corrective actions will be taken
 
during the current license term. Those actions will continue as appropriate
 
through the period of extended operation. (b) The original 1993 consultant analysis associated with the degraded concrete area speculated that the likely source for the high chloride
 
content was condensation of chloride laden air (chlorides from the
 
brackish Hudson River water) on the outer surface of the pool wall. It has
 
since been concluded that the chloride source was likely associated with
 
the use of rock salt or storage of chemicals or materials in the area.
Studies of the chloride content in rain water and ground water do not support the levels that were found in 1993. Studies typically show the
 
national average of chlorides in rain water to be a maximum of 1.0 to 1.5
 
parts per million (PPM) with values inland approaching 0.2 PPM. The
 
National Atmospheric Deposition Program (NAPD), Hudson Valley
 
location West Point station, located upriver from the plant, chloride data
 
from 1983 to 2007 shows values from 0.18 to 0.66 PPM. This is
 
significantly lower than the values initially reported and does not support
 
the supposition that chlorides originated from rainwater. No IP operating
 
experience has linked high chlorides in rainwater to corrosion of
 
embedded rebar. The pool wall was repaired eliminating the spent fuel
 
pool rebar exposure to rainwater.
3-135 The aging management programs for concrete exposed to the elements, the Structures Monitoring Program and the Containment ISI Program, are
 
adequate to address this environment and the related potential aging
 
effects to ensure there is no loss of intended function during the period of
 
extended operation. Visual inspections performed under these programs
 
have confirmed no loss of intended function due to aging effects. These
 
programs will continue to monitor potential future degradation of the
 
concrete cover that could result in exposure of the underlying rebar to the
 
outdoor environment.
Minor degradation that has been observed during these inspections has shown little change between inspections confirming the adequacy of the
 
inspection frequency of the Structures Monitoring and Containment ISI
 
Programs. If rebar degradation is identified during future inspections (e.g.,
observation of concrete staining during visual inspection), the condition
 
will be evaluated in accordance with the program requirements to ensure
 
necessary corrective actions are taken to prevent loss- of intended
 
function.The staff reviewed the applicants response dated May 1, 2009 and the applicants previous responses concerning spent fuel pool leakage. The staff noted the following:  A leak in the East wall of the spent pool liner was originally observed and repaired in
 
1992. This leak was traced to work performed in the spent fuel pool during 1990. The
 
applicant took 20 core bore samples of the concrete from the affected wall and tested
 
them. In addition, the condition of the reinforcement in the core bored areas was visually
 
examined. Detailed structural analysis of the spent fuel pool structure was performed
 
that concluded that the condition of the spent fuel pool walls was adequate to resist the
 
postulated design loads. Spent fuel pool leakage was again observed in 2005. The applicant performed extensive
 
testing of the spent pool liner using visual, robotic camera, and vacuum box testing
 
techniques in 2007 and eliminated all known sources of spent fuel pool leakage. Currently there is no evidence of continued leakage from the IP2 spent fuel pool. The applicant has committed to sample for tritium in the groundwater wells in close
 
proximity to the IP2 spent fuel pool every three months (Commitment 25). Tritium in the
 
groundwater would indicate leakage from the spent fuel pool, which may lead to
 
degradation. Any identified leakage will be reviewed and the corrective action program
 
will be used to determine the appropriate actions.
Based on inspections conducted under the applicants Structures Monitoring Program, and the applicants additional commitment to monitor the groundwater samples from monitoring wells
 
adjacent to the spent fuel pool, there is reasonable assurance that any degradation of the IP2
 
spent fuel pool would be identified, and evaluated within the corrective action program prior to
 
loss of intended function. Therefore, the staff concludes that the effects of aging will be
 
adequately managed during the period of extended operation as required by
 
10 CFR 54.21(a)(3). On this basis, Open Item 3.0.3.2.15-2 is closed.
3-136 UFSAR Supplement. In LRA Sections A.2.1.35 and A.3.1.35, the applicant provided the UFSAR supplement for the Structures Monitoring Program. By letter dated March 24, 2008, the
 
applicant revised LRA Sections A.2.1.35 and A.3.1.35  and Commitment 25 to: (1) include
 
inspection of anchorages of certain commodities; (2) inspect inaccessible concrete areas that
 
are exposed by excavation for any reason, and inspect inaccessible concrete areas in
 
environments where observed conditions in accessible areas exposed to the same environment
 
indicate that significant degradation is occurring; (3) perform inspections of elastomers to
 
identify cracking and change in material properties, and inspections of aluminum vents and
 
louvers to identify loss of material; (4) obtain samples from at least five monitoring wells that are
 
representative of the ground water surrounding below-grade site structures and perform an
 
engineering evaluation of the results; (5) inspect normally submerged concrete portions of the
 
intake structures at least once every 5 years, and inspect the baffling/grating partition and
 
support platform of the IP3 intake structure at least once every 5 years; and (6) inspect the
 
degraded areas of the water control structure once per 3 years rather than the normal frequency
 
of once per 5 years during the period of extended operation. By letter dated June 12, 2009, the
 
applicant revised Commitment 36, which complements the Structures Monitoring Program, as
 
discussed above. The staff reviewed these sections, as revised, 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).
As documented in LRA Sections A.2.1.35 and A.3.1.35, the applicant has committed to enhance the program prior to entering the period of extended operation (Commitment 25).
Conclusion. On the basis of its audit and review of the applicants Structures Monitoring Program, and review of the applicants responses to the staffs RAIs, the staff determines that
 
those program elements, for which the applicant claimed consistency with the GALL Report, are
 
consistent therewith. Also, the staff reviewed the enhancements and confirmed that their
 
implementation prior to the period of extended operation would make the existing program
 
consistent with the GALL Report AMP to which it was compared. The staff concludes that the
 
applicant has demonstrated that the effects of aging will be adequately managed so that the
 
intended functions will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement
 
for this program 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  Water Chemistry Control - Closed Cooling Water Program
 
Summary of Technical Information in the Application. LRA Section B.1.40 describes the existing Water Chemistry Control - Closed Cooling Water Program as consistent with GALL AMP XI.M21, Closed-Cycle Cooling Water System, with exceptions and enhancements.
The Water Chemistry Control - Closed Cooling Water Program includes preventive measures that manage loss of material, cracking, or fouling for components in closed cooling water
 
systems: CCW, instrument air closed cooling, EDG cooling, SBO/Appendix R diesel generator
 
cooling (IP2), Appendix R diesel generator cooling (IP3), security generator cooling, conventional closed cooling (IP2 only), and turbine hall closed cooling (IP3 only). These chemistry activities monitor and control closed cooling water chemistry using IP procedures and
 
processes based on EPRI guidelines for closed cooling water issued as EPRI TR-1007820, Closed Cycle Cooling Water Chemistry, Revision 1, dated April 2004, superseding EPRI
 
TR-107396, Closed Cycle Cooling Water Chemistry Guideline, Revision 0, issued November 3-137 1997, and a reference in the GALL Report. A description of differences between Revision 0 and Revision 1 follows.
The purpose of Revision 0 was to assist plants in developing water treatment strategies to protect carbon-steel and copper-containing systems from corrosion. This revision provides not
 
precise, but broad direction for plants to develop closed cooling water chemistry control
 
programs by utilizing the report to tailor specific station programs. Revision 0 does not provide
 
tables for control parameters and diagnostic parameters with respective sampling frequency
 
and expected values. However, it shows parameters that should be monitored as control
 
parameters or diagnostic parameters. In general, Revision 0 allows plants a great deal of
 
flexibility in developing their closed cooling water chemistry programs.
Revision 1 is significantly more directive and incorporates action levels with established thresholds for specific actions required. This revision specifically establishes recommended
 
monitoring frequencies and clearly specifies expected parameter values. Revision 0 treats total
 
organic carbon, dissolved oxygen, total alkalinity, calcium/magnesium, and refrigerants as
 
diagnostic but these are not described in Revision 1 which considers none of these parameters (or monitoring of them) as having any effect on the long-term condition of closed cycle cooling
 
water systems.
Both EPRI closed cycle cooling water guidelines distinguish clearly between control parameters and diagnostic parameters. Adherence to control parameters is expected
 
whereas diagnostic parameters are suggested but can be plant-specific. Deviations from EPRI
 
recommended diagnostic parameters are not exceptions to the GALL Report.
Future revisions of the EPRI closed cycle cooling water guidelines will be adopted as required commensurate with industry standards. The One-Time Inspection Program for Water Chemistry
 
utilizes inspections or NDEs of representative samples to verify whether the Water Chemistry
 
Control - Closed Cooling Water Program has been effective in managing aging effects.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Water Chemistry Control - Closed Cooling Water Program to verify consistency with GALL AMP XI.M21. Details of the staffs audit of this AMP are documented in
 
the Audit Report. As documented in the report, the staff found that the Water Chemistry
 
Control - Closed Cooling Water Program element scope of program is consistent with the corresponding element in GALL AMP XI.M21. Because this element is consistent with the GALL
 
Report element, the staff finds that it is acceptable.
The staff reviewed the exceptions and enhancements to determine whether the program will be adequate to manage the aging effects for which it is credited.
Exception 1
. In the LRA, the applicant took the following exception to the GALL Report program element parameters monitored or inspected:  NUREG-1801 states the program monitors the
 
effects of corrosion and SCC by testing and inspection in accordance with guidance in EPRI
 
TR-107396. The IPEC Water Chemistry Control - Closed Cooling Water Program does not
 
perform performance and functional testing.
The staff noted that the discussion of this exception in Section B.1.40 of the LRA includes a footnote, which states the following:
3-138While NUREG-1801, Section XI.M21, Closed Cycle Cooling Water System endorses EPRI report TR-107396 for performance and functional testing
 
guidance, EPRI report TR-107396 does not recommend that equipment
 
performance and functional testing be part of a water chemistry control program.
 
This is appropriate since monitoring pump performance parameters is of little
 
value in managing effects of aging on long-lived, passive CCW system
 
components. Rather, EPRI report TR-107396 states in Section 5.7 (Section 8.4
 
in EPRI report 1007820) that performance monitoring is typically part of an
 
engineering program, which would not be part of water chemistry. In most cases, functional and performance testing verifies that component active functions can
 
be accomplished and as such would be included as part of maintenance rule
 
(10 CFR 50.65) programs. Passive intended functions of pumps, heat
 
exchangers and other components will be adequately managed by the Water
 
Chemistry Control - Closed Cooling Water Program and One-time Inspection
 
Program through monitoring and control of water chemistry parameters and
 
verification of the absence of aging effects.
Exception 2
. In the LRA, the applicant took the following exception to the GALL Report program element detection of aging effects:  NUREG-1801 recommends the use of performance and
 
functional testing to ensure acceptable function of the CCCW systems. The IPEC Water
 
Chemistry Control - Closed Cooling Water Program does not perform performance and
 
functional testing.
The staff noted that the discussion of this exception in Section B.1.40 of the LRA includes a footnote, which states the following: While NUREG-1801, Section XI.M21, Closed Cycle Cooling Water System endorses EPRI report TR-107396 for performance and functional testing
 
guidance, EPRI report TR-107396 does not recommend that equipment
 
performance and functional testing be part of a water chemistry control program.
 
This is appropriate since monitoring pump performance parameters is of little
 
value in managing effects of aging on long-lived, passive CCW system
 
components. Rather, EPRI report TR-107396 states in Section 5.7 (Section 8.4
 
in EPRI report 1007820) that performance monitoring is typically part of an
 
engineering program, which would not be part of water chemistry. In most cases, functional and performance testing verifies that component active functions can
 
be accomplished and as such would be included as part of maintenance rule
 
(10 CFR 50.65) programs. Passive intended functions of pumps, heat
 
exchangers and other components will be adequately managed by the Water
 
Chemistry Control - Closed Cooling Water Program and One-time Inspection
 
Program through monitoring and control of water chemistry parameters and
 
verification of the absence of aging effects.
Exception 3
. In the LRA, and in Amendment 1 to the LRA, Attachment 1, Audit Item 95, dated December 18, 2007, the applicant took the following exception to the GALL Report program
 
element monitoring and trending:  NUREG-1801 recommends internal visual inspections and
 
performance and functional tests periodically to demonstrate system operability. The IPEC
 
Water Chemistry Control - Closed Cooling Water Program does not perform component
 
performance and functional testing.
3-139 The staff noted that the discussion of this exception in Section B.1.40 of the LRA includes a footnote, which states the following: While NUREG-1801, Section XI.M21, Closed Cycle Cooling Water System endorses EPRI report TR-107396 for performance and functional testing
 
guidance, EPRI report TR-107396 does not recommend that equipment
 
performance and functional testing be part of a water chemistry control program.
 
This is appropriate since monitoring pump performance parameters is of little
 
value in managing effects of aging on long-lived, passive CCW system
 
components. Rather, EPRI report TR-107396 states in Section 5.7 (Section 8.4
 
in EPRI report 1007820) that performance monitoring is typically part of an
 
engineering program, which would not be part of water chemistry. In most cases, functional and performance testing verifies that component active functions can
 
be accomplished and as such would be included as part of maintenance rule (10
 
CFR 50.65) programs. Passive intended functions of pumps, heat exchangers
 
and other components will be adequately managed by the Water Chemistry
 
Control - Closed Cooling Water Program and One-time Inspection Program
 
through monitoring and control of water chemistry parameters and verification of
 
the absence of aging effects.
Exception 4
. In the LRA, the applicant took the following exception to the GALL Report program element acceptance criteria:  NUREG-1801 recommends system and component
 
performance test result evaluations. The IPEC Water Chemistry Control - Closed Cooling Water
 
Program does not perform performance and functional testing.
The staff noted that the discussion of this exception in Section B.1.40 of the LRA includes a footnote, which states the following: While NUREG-1801, Section XI.M21, Closed Cycle Cooling Water System endorses EPRI report TR-107396 for performance and functional testing
 
guidance, EPRI report TR-107396 does not recommend that equipment
 
performance and functional testing be part of a water chemistry control program.
 
This is appropriate since monitoring pump performance parameters is of little
 
value in managing effects of aging on long-lived, passive CCW system
 
components. Rather, EPRI report TR-107396 states in Section 5.7 (Section 8.4
 
in EPRI report 1007820) that performance monitoring is typically part of an
 
engineering program, which would not be part of water chemistry. In most cases, functional and performance testing verifies that component active functions can
 
be accomplished and as such would be included as part of maintenance rule (10
 
CFR 50.65) programs. Passive intended functions of pumps, heat exchangers
 
and other components will be adequately managed by the Water Chemistry
 
Control - Closed Cooling Water Program and One-time Inspection Program
 
through monitoring and control of water chemistry parameters and verification of
 
the absence of aging effects.
The applicant stated that the LRA indicates that Water Chemistry Control - Closed Cooling Water Program attributes 3, 4, 5, and 6 have an exception to the GALL Report. In all four cases, the exception is due to the fact that the GALL Report recommends the use of performance and
 
functional testing to ensure acceptable function of the closed cooling water systems, while the 3-140 IPEC Water Chemistry Control - Closed Cooling Water Program does not include performance and functional testing. The exception is the same regardless which revision of the EPRI
 
guideline is used because neither revision of the EPRI guideline recommends that equipment
 
performance and functional testing should be part of a water chemistry program. Rather, the
 
EPRI reports state (Section 5.7 in EPRI report TR-107396 and Section 8.4 in EPRI report
 
1007820) that performance monitoring is typically part of an engineering program, which would
 
not be part of water chemistry.
The staff asked the applicant for additional information to justify not performing testing and functional inspections as part of this AMP (Audit Item 97). In response, by letter dated March 24, 2008, the applicant stated that EPRI report TR-107396 does not recommend that equipment
 
performance and functional testing be part of a water chemistry control program. This is
 
appropriate since monitoring pump performance parameters is of little value in managing effects
 
of aging on long-lived, passive closed cooling water system components. Rather, EPRI report
 
TR-107396 states in Section 5.7 (Section 8.4 in EPRI report 1007820) that performance
 
monitoring is typically part of an engineering program, which would not be part of water
 
chemistry. In most cases, functional and performance testing verifies that component active
 
functions can be accomplished and as such would be included as part of Maintenance Rule (10
 
CFR 50.65) programs. Passive intended functions of pumps, heat exchangers and other
 
components will be adequately managed by the Water Chemistry Control - Closed Cooling
 
Water Program and One-time Inspection Program through monitoring and control of water
 
chemistry parameters and verification of the absence of aging effects.
In addition, the applicant referenced its response to the staffs request for technical justification for not including visual inspection in the program. The applicant stated in the response that the
 
Water Chemistry Control - Closed Cooling Water Program is a preventive program. EPRI
 
Report TR-1007820 refers to inspections performed in conjunction with maintenance activities, which are not specifically included as part of this program. However, components cooled by
 
closed cooling water systems are routinely inspected as part of an eddy current inspection
 
program. These heat exchangers receive a visual inspection in addition to eddy current testing
 
that would detect aging effects and confirm the effectiveness of the Water Chemistry Control-
 
Closed Cooling Water Program. Some of the heat exchangers receiving visual inspections
 
include:IP2 and IP3 Closed Cooling Water 21/22CCHX and ACAHCC1/2 IP2 and IP3 Instrument Air Closed Cooling Water 21/22CWHX and SWM-CLC  31/32-
 
HTXIP2 and IP3 EDG Jacket Water Coolers 21/22/23EDJC and EDG-31/32/33-EDGJWHTX IP2 Conventional Closed Cooling 21/22THCCSHX IP3 Turbine Hall Closed Cooling SWT-CLC-31/32-HTX In addition to these completed inspections, LRA Section B.1.27, One-Time Inspection, describes future inspections planned to verify effectiveness of the water chemistry control
 
programs to ensure that significant degradation is not occurring and component intended
 
function is maintained during the period of extended operation. This will include areas most
 
susceptible to corrosion such as stagnant areas.
The staff reviewed EPRI Report TR-1007820 (Revision 1 to EPRI TR-107396) and determined 3-141 that it does not recommend that performance and functional testing be part of the water chemistry control program. This engineering testing could be performed as part of another
 
program. Usually, the Maintenance Rule (10 CFR 50.65) dictates the requirements of the
 
performance and functional testing. The staff noted that a one-time inspection will be performed
 
to verify the effectiveness of this program for managing aging in the closed loop cooling water
 
systems in the scope of this program. The staff finds that the water chemistry control, monitoring, and inspection activities included in this program are adequate to manage the aging
 
effects for which the program is credited without the need for performance and functional
 
testing. SER Section 3.0.3.1.9 document the staffs evaluation of the One-Time Inspection
 
Program. Based on the above, the staff finds these exceptions acceptable.
The staff reviewed the applicants evaluation and confirmed that the applicant had incorporated EPRI TR-1007820 as the technical basis guideline for its B.1.40 aging management program.
 
The staff determined that the use of EPRI TR-1007820 provides guidance that is consistent with the recommendations in GALL AMP XI.M21, along with more detail on the various water
 
treatment methods used at nuclear power plants, as well as control and diagnostic parameters, monitoring frequencies, operating ranges, and action levels. Therefore, the staff finds the use of
 
EPRI TR-1007820 as the basis for this program acceptable.
Based on the above review, the staff finds the applicants exceptions acceptable.
Enhancement 1
.In the LRA and in Amendment 1 to the LRA, Attachment 2, Commitment Item 28, dated December 18, 2007, the applicant committed to implement the following
 
enhancement to program elements preventive actions, parameters monitored or inspected,
 
monitoring and trending, and acceptance criteria:  IP2: Revise appropriate procedures to
 
maintain water chemistry of the SBO/Appendix R diesel generator cooling system per EPRI
 
guidelines.
The enhancement is necessary to expand the scope of the program to ensure that it bounds all the components within the scope of license renewal. The enhancement does not change
 
program content/criteria.
The staff determined that the applicants enhancement will add water chemistry control, monitoring, and inspection activities for the IP2 SBO/Appendix R diesel generator cooling
 
system. The enhancement will ensure that water chemistry control program activities are
 
provided for all components on the site within the scope of the Water Chemistry control -
 
Closed Cooling Water Program which is consistent with the recommendations in the GALL
 
Report. On this basis, the staff finds this enhancement acceptable. Enhancement 2
.In the LRA and in Amendment 1 to the LRA, Attachment 2, Commitment Item 28, dated December 18, 2007, the applicant committed to implement the following
 
enhancement to program elements preventive actions, parameters monitored or inspected,
 
monitoring and trending, and acceptance criteria:  IP2: Revise appropriate procedures to
 
maintain the security generator cooling water system pH within limits specified by EPRI
 
guidelines.
The enhancement is necessary to expand the scope of the program to ensure that it bounds all the components within the scope of license renewal. The enhancement does not change
 
program content/criteria.
3-142 The staff determined that the applicants enhancement will add water chemistry control, monitoring, and inspection activities for the IP2 security diesel generator cooling system cooling
 
water pH. The enhancement will ensure that water chemistry control program activities are
 
provided for all components on the site within the scope of the Water Chemistry control -
 
Closed Cooling Water Program which is consistent with the recommendations in the GALL
 
Report. On this basis, the staff finds this enhancement acceptable. Enhancement 3
. In the LRA and in Amendment 1 to the LRA, Attachment 2, Commitment Item 28, dated December 18, 2007, the applicant committed to implement the following
 
enhancement to program elements preventive actions, parameters monitored or inspected,
 
monitoring and trending, and acceptance criteria:  IP3: Revise appropriate procedures to
 
maintain security generator cooling water pH within limits specified by EPRI guidelines.
The enhancement is necessary to expand the scope of the program to ensure that it bounds all the components within the scope of license renewal. The enhancement does not change
 
program content/criteria.
The staff determined that the applicants enhancement will add water chemistry control, monitoring, and inspection activities for the IP3 security diesel generator cooling system cooling
 
water pH. The enhancement will ensure that water chemistry control program activities are
 
provided for all components on the site within the scope of the Water Chemistry control -
 
Closed Cooling Water Program which is consistent with the recommendations in the GALL
 
Report. On this basis, the staff finds this enhancement acceptable.
Operating Experience. LRA Section B.1.40 states that in June 2003 the applicant noted that the CCW corrosion inhibitor (molybdate concentration) had been out of specification 50 percent of
 
the time since the new specification was issued in March 2003 due to dilution from water added
 
to this system to compensate for leaks and work activities. Corrective action repaired the leaks
 
and added chemicals to restore the molybdate concentration to specification. Detection of out-
 
of-specification conditions and corrective action prior to loss of intended function assure
 
continued program effectiveness in managing aging effects for passive components.
 
Subsequently, corrosion inhibitor concentration has been satisfactory.
A QA audit of the plant chemistry program in August 2003 found the control of closed cooling water chemistry at IP2 as one of the specific areas improved since the last audit. Continuous
 
program improvement assures continued program effectiveness in managing loss of component
 
material.Reports of closed cooling water chemistry control indicator (corrosion inhibitor and hardness) show that IP2 and IP3 CCW chemistry was within specification throughout 2006 except for part
 
of May when the IP2 system was in maintenance status during refueling outage 2R17.
Adherence to chemistry specifications assures continued program effectiveness in managing
 
component aging effects.
The staffs review of operating experience indicates that this program has been effective in managing aging effects.
The staff confirmed that the operating experience program element satisfies the criteria in SRP-LR Section A.1.2.3.10. The staff finds this program element acceptable.
3-143 UFSAR Supplement. In LRA Sections A.2.1.39 and A.3.1.39, the applicant provided the UFSAR supplement for the Water Chemistry Control - Closed Cooling Water Program. By letter dated
 
June 12, 2009, the applicant amended LRA Section A.2.1.39 to add the IP2 instrument air
 
system to the scope of the program. The staff reviewed these sections, as amended, and
 
determines that the information in the UFSAR supplement is an adequate summary description
 
of the program, as required by 10 CFR 54.21(d).
The applicant stated in the LRA that this program will be implemented prior to the period of extended operation (Commitment 28).
Conclusion. On the basis of its audit and review of the applicants Water Chemistry Control -
Closed Cooling Water Program, the staff determines that those program elements, for which the
 
applicant claimed consistency with the GALL Report, are consistent. In addition, the staff
 
reviewed the exceptions and their justifications and determines that the program is adequate to
 
manage the aging effects for which it is credited. Also, the staff reviewed the enhancements and
 
confirmed that their implementation prior to the period of extended operation would make the
 
existing program consistent with the GALL Report AMP to which it was compared. The staff
 
concludes that the applicant has demonstrated that the effects of aging will be adequately
 
managed so that the intended functions will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the
 
UFSAR supplement for this program 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  Water Chemistry Control - Primary and Secondary Program
 
Summary of Technical Information in the Application. LRA Section B.1.41 describes the existing Water Chemistry Control - Primary and Secondary Program as consistent with GALL AMP XI.M2, Water Chemistry, with enhancement.
The Water Chemistry Control - Primary and Secondary Program manages aging effects caused by corrosion and cracking mechanisms. The program monitors and controls reactor water
 
chemistry based on EPRI TR-105714, Revision 5, Pressurized Water Reactor Primary Water
 
Chemistry Guidelines, and TR-102134, Revision 6, Pressurized Water Reactor Secondary
 
Chemistry Guidelines.
Both the EPRI primary and secondary water chemistry guidelines distinguish clearly between control parameters and diagnostic parameters. Strict adherence to control parameters is
 
expected whereas diagnostic parameters are suggested but can be plant-specific. Deviations
 
from EPRI recommended diagnostic parameters are not exceptions to the GALL Report.
The GALL Report states that the water chemistry control is based on EPRI Reports TR-105714, Revision 3, for primary water chemistry, and TR-102134, Revision 3, for secondary water
 
chemistry. Entergy has adopted TR-105714, Revision 5, renumbered by EPRI to Report
 
1002884, and TR-102134, Revision 6, renumbered by EPRI to Report 1008224.
The Revision 5 changes to TR-105714 consider the most recent operating experience and laboratory data and reflect increased emphasis on plant-specific optimization of primary water
 
chemistry to address individual plant circumstances and the impact of the NEI steam generator
 
initiative, NEI 97-06, which requires utilities to meet the intent of the EPRI guidelines. EPRI
 
TR-105714, Revision 5, attempts to distinguish clearly between prescriptive and non-3-144 prescriptive guidance.
Revision 4 of TR-102134 was issued in November 1996 with increased depth of detail of the corrosion mechanisms affecting steam generators and the balance of plant and additional
 
guidance on how to integrate these and other concerns into the plant-specific optimization
 
process. Revision 5 provides additional details of plant-specific optimization and clarifies which
 
EPRI guidelines are mandatory under NEI 97-06. Revision 6 provides further details on how
 
best to integrate these guidelines into a plant-specific chemistry program while complying with
 
NEI 97-06 and NEI 03-08, Guideline for the Management of Materials Issues.
Future revisions of the EPRI primary and secondary water chemistry guidelines will be adopted as required commensurate with industry standards. The One-Time Inspection Program for
 
Water Chemistry utilizes inspections or NDEs of representative samples to verify whether the Water Chemistry Control - Primary and Secondary Program has been effective in managing
 
aging effects.
Staff Evaluation. During its audit and review, the staff confirmed the applicants claim of consistency with the GALL Report. As described in SER Section 3.0.2.1, the staff audited the
 
program elements of the Water Chemistry Control - Primary and Secondary Program to verify consistency with GALL AMP XI.M2. Details of the staffs audit of this AMP are documented in
 
the Audit Report. As documented in the report, the staff found that the Water Chemistry Control
- Primary and Secondary Program elements scope of program, preventive actions, detection
 
of aging effects, and monitoring and trending, are consistent with the corresponding elements in GALL AMP XI.M2. Because these elements are consistent with the GALL Report elements, the staff finds that they are acceptable.
The staff reviewed the enhancement to determine whether the program will be adequate to manage the aging effects for which it is credited.
The staff reviewed portions of the Water Chemistry Control - Primary and Secondary Program for which the applicant claims consistency with the GALL Report and documented an audit
 
summary evaluation of this AMP in the Audit Report. Furthermore, the staff concludes that the
 
applicants Water Chemistry Control - Primary and Secondary Program reasonably assures
 
management of aging effects so components crediting this program can perform intended
 
functions consistent with the CLB during the period of extended operation. The staff finds the
 
applicants Water Chemistry Control - Primary and Secondary Program acceptable as consistent with the recommended GALL AMP XI.M2, Water Chemistry with the enhancement
 
as described: Enhancement
. In the LRA, the applicant committed to implement the following enhancement to program elements parameters monitored or inspected and acceptance criteria:  [t]he
 
parameters monitored or inspected, will be enhanced to revise appropriate procedures to test
 
sulfates monthly in the RWST for IP2 and acceptance criteria, with a limit of < 150 ppb.
During the audit and review, the staff asked the applicant why the enhancement is being made for IP2 but not for IP3 (Audit Item 99). By letter dated December 18, 2007, the applicant stated
 
that consistent with EPRI TR-105714, Rev. 5 recommendations, IP3 currently monitors RWST
 
sulfates monthly with a limit of < 150 ppb. IP2 has not incorporated this recommendation and an
 
enhancement is required. Thus, the enhancement does not apply to IP3. The staff finds that this
 
enhancement is acceptable because it will follow the EPRI guidance that is recommended in the 3-145 GALL Report. It is also acceptable that it does not apply to IP3 because it was previously instituted for IP3 consistent with the EPRI guidance.
Operating Experience. LRA Section B.1.41 states that a QA audit of the primary and secondary plant chemistry program in August 2003 noted that monitoring and processing requirements for primary and secondary water chemistry complied with both IP2 and IP3 technical specifications, implementing procedures, and the IP3 technical requirements manual. In addition, the chemistry
 
processes effectively implemented industry (e.g., EPRI and INPO) guidelines designed to
 
extend the operating lives of primary and secondary systems and components. Continuous
 
program improvement through adoption of evolving industry guidelines assures continued
 
program effectiveness in managing the effects of aging on plant components.
During the audit and review, the staff asked the applicant about the frequency of the QA audits of the primary and secondary plant chemistry program. The applicant replied that the QA audits
 
are conducted every two years. An extra audit was conducted in 2006 in addition to the regular
 
audit in 2005 in order to adjust the audits to even years for scheduling purposes. These audits
 
were reviewed by the staff during the onsite audit.
The staff confirmed that the operating experience program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program
 
element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.40 and A.3.1.40, the applicant provided the UFSAR supplement for the Water Chemistry Control - Primary and Secondary Program. The staff
 
reviewed these sections and determines that the information in the UFSAR supplement is an
 
adequate summary description of the program, as required by 10 CFR 54.21(d).
The applicant stated that the program enhancements will be implemented prior to entering the period of extended operation (Commitment 29).
Conclusion. On the basis of its audit and review of the applicants Water Chemistry Control -
Primary and Secondary Program, the staff determines that those program elements, for which
 
the applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed
 
the enhancement and confirmed that its implementation prior to the period of extended
 
operation would make the existing program consistent with the GALL Report AMP to which it
 
was compared. The staff concludes that the applicant has demonstrated that the effects of
 
aging will be adequately managed so that the intended functions will be maintained consistent
 
with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff
 
also reviewed the UFSAR supplement for this program and concludes that it provides an
 
adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.3  Programs Not Consistent with or Not Addressed in the GALL Report 3.0.3.3.1  Boral Surveillance Program Summary of Technical Information in the Application. LRA Section B.1.4 describes the existing Boral Surveillance Program as a plant-specific program.
The Boral Surveillance Program verifies whether the Boral neutron absorbers in the spent fuel racks maintain the validity of the criticality analysis in support of the rack design. The program 3-146 relies on representative coupon samples mounted in surveillance assemblies in the spent fuel pool to monitor performance of the absorber material without disrupting the integrity of the
 
storage system. Surveillance assemblies are removed from the spent fuel pool on a prescribed
 
schedule for measurement of physical and chemical properties to assess the stability and
 
integrity of the Boral in the storage cells. This program applies to IP3 only because Boral is not
 
used for criticality control of IP2 spent fuel.
Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.1.4 on the applicants demonstration of the Boral Surveillance Program to ensure
 
that the effects of aging, as discussed above, will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB for the period of extended operation.
The staff reviewed the Boral Surveillance Program against the AMP elements found in the 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 elements. Specifically, the staff reviewed the
 
following seven program elements of the applicants program: (1)scope of the program, (2)
 
preventive actions, (3) parameters monitored or inspected, (4) detection of aging effects,
 
(5) monitoring and trending, (6) acceptance criteria, and (10) operating experience.
The applicant indicated that program elements (7) corrective actions, (8) confirmation process, and (9) administrative controls are parts of the site-controlled QA program. The
 
staffs evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven
 
elements follows:    (1) Scope of the Program - LRA Section B.1.4 states that, the Boral Surveillance Program includes all Boral in the IP3 spent fuel pool. The IP2 spent fuel pool design does not rely
 
on Boral for criticality control.
The staff confirmed that the scope of the program program element satisfies the guidance in SRP-LR Section A.1.2.3.1, since the staff confirmed that Boral was only
 
used in IP3 spent fuel pool and IP2 uses Boraflex. Therefore, the staff finds this program
 
element acceptable.  (2) Preventive Actions - LRA Section B.1.4 states that, this is an inspection program and no actions are taken as part of this program to prevent or mitigate aging degradation.
The staff confirmed that the preventive actions program element satisfies the guidance in SRP-LR Section A.1.2.3.2 since IP3 has a condition monitoring program. Therefore, the staff finds this program element acceptable.    (3) Parameters Monitored or Inspected - LRA Section B.1.4 states that, the program monitors changes in the following physical properties of the Boral material. neutron attenuation blister size, thickness, and location dimensional measurements (length, width, shape, and thickness) specific gravity and density The staff confirmed that the parameters monitored or inspected program element satisfies the guidance in SRP-LR Section A.1.2.3.3. The staff considers this program 3-147 element acceptable because experience has shown that Boral degradation in the SFP environment occurs slowly and can be detected in the early stages by the methods
 
proposed. The measurements of neutron attenuation, physical distortion, and weight
 
change would detect coupon degradation that would precede a loss of functionality in
 
the Boral panels (neutron absorption and fuel assembly spacing). Moreover, unacceptable coupon results would initiate an engineering evaluation and, if considered
 
necessary, direct testing of the storage racks (i.e. blackness testing).    (4) Detection of Aging Effects - LRA Section B.1.4 states that the program monitors representative coupon samples located in the spent fuel pool to determine the condition
 
of the absorber material without disrupting the integrity of the storage system. At
 
specified intervals, the program measures certain physical and chemical properties of
 
removed sample coupons. From this data, the stability and integrity of the Boral in the
 
storage cells are assessed.
The staff confirmed that the detection of aging effects program element satisfies the guidance in SRP-LR Section A.1.2.3.4 since the staff considers the program to collect
 
data from representative coupon samples to assess for stability and integrity of Boral to
 
be acceptable for detection of aging effects. Therefore, the staff finds this program
 
element acceptable.    (5) Monitoring and Trending - LRA Section B.1.4 states that neutron attenuation tests are trended to ensure that slow degradation has not occurred. Observable loss in neutron
 
attenuation ability, if any, is projected to determine when neutron attenuation may fall
 
below acceptance criteria. Size and weight measurements determine the extent of
 
shrinkage or loss of material. This data is trended for indications of degradation. Blister
 
shape and size are recorded and trended to determine whether new blisters are forming, the rate of growth of existing blisters, and the rate of increase in blister thickness. As
 
blister thickness increases, it may become necessary to evaluate whether potential fuel
 
cell deformation is a risk due to blister growth.
The staff confirmed that the monitoring and trending program element satisfies the guidance in SRP-LR Section A.1.2.3.5. The staff finds this program element acceptable
 
because the applicant monitors and trends parameters that would indicate degradation.    (6) Acceptance Criteria - LRA Section B.1.4 states that of the measurements to be performed on the Boral, the most important are neutron attenuation measurements and
 
dimensional measurements. Acceptance criteria for these measurements are as follows. Neutron attenuation testing and B-10 areal density is equal to or greater than the
 
B-10 gm/cm 2 nominal density assumed in the criticality analysis (0.02 g/cm
: 2) Blisters are unacceptable if blister size and shape projected to the next
 
inspection may subsume the available space between the fuel assembly and the
 
cell wall.
In RAI B.1.4, dated December 7, 2007, the staff requested that the applicant provide additional details on the Boral Surveillance Program in regards to the neutron
 
attenuation testing and the acceptance criteria.
3-148 In its response, by letter dated January 4, 2008, the applicant provided the following information: K eff <0.95 is the margin to criticality used in the criticality analyses. Use of Keff
<0.95 as the margin to criticality acceptance criteria is consistent with NUREG
 
0800. IP3 Boral coupon surveillance results to date have not identified any loss of neutron absorption capability between surveillance periods such that the current
 
criterion remains acceptable for use. This is consistent with industry experience. IP3 has sufficient Boral coupon samples to maintain the sampling frequency
 
through the period of extended operation.
Based on the applicants response to the RAI describing the Boral Surveillance Program, the staff finds the applicants response to the RAI B.1.4 acceptable. The staffs concern
 
in RAI B.1.4 is resolved.
The staff confirmed that the acceptance criteria program element satisfies the guidance in SRP-LR Section A.1.2.3.6 since IP3 provided specific values for the acceptance
 
criteria which would provide reasonable assurance that corrective actions could be taken
 
before loss of functionality would occur. The staff finds this program element acceptable.    (10) Operating Experience - LRA Section B.1.4 states that results of an inspection of coupon samples in 2002 showed no significant degradation of Boral material. A review of this
 
program in 2004 addressed the Seabrook Part 21 issue on Boral coupon blistering (NRC21-031006 Part 21) and led to revision of the procedure for IP3 Boral examinations
 
to test in the next inspection (2007) the same full-length Boral sample tested in the last
 
inspection (2002) to allow direct measurement of blister growth and to determine
 
whether the Boral blisters have reached equilibrium.
The applicant stated that its program is based on the NUREG-1801 program description, which in turn is based on industry operating experience. Such operating experience
 
assures continued effectiveness of the Boral Surveillance Program in managing loss of
 
Boral neutron absorber material.
The staff confirmed that the operating experience program element satisfies the guidance in SRP-LR Section A.1.2.3.10, since the operating experience supports the
 
conclusion that the Boral Surveillance Program is effective in managing the loss of Boral
 
neutron absorber material. The staff finds this program element acceptable.
UFSAR Supplement. In LRA Section A.3.1.3, the applicant provided the UFSAR supplement for the Boral Surveillance Program. The staff reviewed this section and finds the UFSAR
 
supplement information an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
Conclusion. On the basis of its technical review of the applicants Boral Surveillance Program, the staff concludes that the applicant has demonstrated that effects of aging will be adequately
 
managed so that the intended functions will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the
 
UFSAR supplement for this program and concludes that it provides an adequate summary 3-149 description of the program, as required by 10 CFR 54.21(d).
3.0.3.3.2 Containment Inservice Inspection Program
 
Summary of Technical Information in the Application. LRA Section B.1.8, as amended by letter dated June 11, 2008, describes the existing Containment Inservice Inspection Program as a
 
plant-specific program.
The applicant states that the Containment Inservice Inspection Program encompasses ASME Section XI Subsection IWE and IWL requirements as modified by 10 CFR 50.55a. The IP2 program uses the ASME Boiler and Pressure Vessel Code, Section XI, 2001 Edition, through 2003 Addenda. The IP3 program uses the ASME Boiler and Pressure Vessel Code, Section XI, 1998 Edition, no addenda. Every 10 years, each units program is updated to the latest ASME Section XI code edition and addenda approved in 10 CFR 50.55a. Visual inspections for IWE of
 
surfaces for evidence of flaking, blistering, peeling, discoloration, and other signs of distress
 
monitor loss of material of the steel containment liners and their attachments, containment
 
hatches and airlocks, moisture barriers, and pressure-retaining bolting. Visual inspections for
 
IWL monitor structural concrete surfaces for evidence of leaching, erosion, voids, scaling, spalls, corrosion, cracking, exposed reinforcing steel, and detached embedment. The applicant
 
also states that the IP2 and IP3 containments are reinforced concrete structures that do not
 
utilize a post-tensioning system; therefore, IWL post-tensioning requirements do not apply.
Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.1.8 on the applicants demonstration of the Containment Inservice Inspection
 
Program to ensure that the effects of aging, as discussed above, will be adequately managed
 
so that the intended functions will be maintained consistent with the CLB for the period of
 
extended operation. The staff noted that the intent in writing GALL Report, Volume 2 Chapter XI was to enable an applicant to take credit for an existing mandated inspection program with minimal effort (i.e.,
simply identify and explain exceptions and enhancements). Entergy has identified AMP B.1.8 -
 
Containment Inservice Inspection as being plant-specific. The staff reviewed LRA Section B.1.8
 
and concluded that the 10-element evaluation does not identify any differences from GALL AMPs XI.S1 (IWE) and XI.S2 (IWL). In an audit question, Entergy was requested to document an element-by-element comparison of LRA AMP B.1.8 to GALL AMPs XI.S1 and XI.S2, identifying and explaining all exceptions and enhancements to the GALL AMPs (Audit Item 26).
By letter dated December 18, 2007, Entergy indicated that the attributes of the program are compared to the ten elements of an aging management program for license renewal as
 
described in SRP-LR, Table A.1-1. Entergy decided to describe the Containment ISI Program as a plant-specific program rather than comparing it to the GALL Report AMPs XI.S1 and XI.S2.
 
Entergy indicated that this was done because the GALL Report programs contain many ASME Section XI table and section numbers which change with different versions of the code.
 
Because of this, comparison with the GALL Report programs would generate many exceptions
 
and explanations. Also, the applicable edition of the Code during the period of extended
 
operation will be different than the edition referenced in the GALL Report. Currently, the GALL AMPs for concrete containment, XI.S1 (for steel elements) and XI.S2 (for concrete elements) provide acceptable programs for the aging management of the
 
containments. Using these AMPs avoids performing extensive reviews with many questions to 3-150 properly evaluate the plant-specific programs. Thus, if a proposed plant-specific AMP for containments is credited, then a detailed review would be required where many items beyond those identified in the XI.S1 and XI.S2 AMPs will need to be identified. GALL AMPs XI.S1 and XI.S2 were developed based on the known provisions contained in the editions of the ASME Code, Section XI, Subsections IWE and IWL that are referenced. If a different edition of the
 
Code is relied on and/or exceptions are taken with respect to the guidance in the GALL AMPs XI.S1 and XI.S2, then justification is needed to demonstrate adequacy. The need for additional justification is explained in the footnote to the XI.S1 and XI.S2 AMPs in GALL. This footnote
 
states that An applicant may rely on a different version of the ASME Code, but should justify such use. This applies to differences between the plant-specific program and the GALL XI.S1 and XI.S2 AMPs. In the case of GALL AMPs XI.S1 and XI.S2, the acceptable code editions of Subsections IWE and IWL are those from the 1992 edition of the ASME Code, Section XI, including the 1992
 
Addenda, through the 2001 Code, and the 2002 and 2003 Addenda. The IP2 program uses the ASME Boiler and Pressure Vessel Code, Section XI, 2001 Edition, 2003 Addenda. The IP3 program uses the ASME Boiler and Pressure Vessel Code, Section XI, 1998 Edition, no Addenda. Every 10 years, each units program is updated to the latest ASME Section XI code
 
edition and addenda approved by the Nuclear Regulatory Commission in 10 CFR 50.55a.
 
Therefore, the editions of the Code that Entergy is using, for both IP2 and IP3, are consistent with those accepted by GALL AMPs XI.S1 and XI.S2. If, as stated in the Entergy response, there are numerous exceptions that would need to be explained, then the staff needs to be
 
informed, in order to evaluate the adequacy of the Containment Inservice Inspection Program.
The concern noted in the Entergy response to the audit question, that the applicable edition of ASME Code, Section XI during the period of extended operation will be different than the edition referenced in the current GALL Report, is addressed in the footnote to GALL AMPs XI.S1 and XI.S2. The footnote states that An applicant may wish to refer to the [statement of
 
considerations] SOC for an update of 10 CFR 50.55a, to justify use of a more recent edition of
 
the Code.
Entergy formally submitted Amendment 1 to the LRA on December 18, 2007. Under Audit Item 26, Entergy presented an element-by-element comparison to GALL AMPs XI.S1 and XI.S2. On the basis of this comparison, as discussed below, the staff finds the applicants plant-
 
specific Containment Inservice Inspection Program to be consistent with the GALL report.
In accordance with Entergys decision to identify the Containment Inservice Inspection Program as a plant-specific AMP, the staff reviewed the Containment Inservice Inspection Program
 
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 elements [(1) scope of the program, (2) preventive actions, (3)
 
parameters monitored or inspected, (4) detection of aging effects, (5) monitoring and
 
trending, (6) acceptance criteria, (7) corrective actions, (8) confirmation process, (9)
 
administrative controls, and (10) operating experience].
The applicant indicated that program elements (7) corrective actions, (8) confirmation process, and (9) administrative controls are parts of the site-controlled QA program. The
 
staffs evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven
 
elements follows:
3-151  (1) Scope of the Program - LRA Section B.1.8 states that the Containment Inservice Inspection Program, under ASME Section XI Subsection IWE, manages aging effects for
 
the containment liners and integral attachments including connecting penetrations and
 
parts forming the leak tight boundary. The applicant further states that Containment Inservice Inspection Program, under ASME Section XI Subsection IWL provides
 
confirmation that the effects of aging on the reinforced concrete containment walls, domes, and basemats will not prevent the performance of intended functions consistent
 
with the CLB through the period of extended operation.
The staff confirmed that the scope of the program program element satisfies the guidance in SRP-LR Section A.1.2.3.1. The staff finds this program element acceptable.    (2) Preventive Actions - LRA Section B.1.8 states that the Containment Inservice Inspection Program is a monitoring program that does not include preventive actions. The staff
 
concurs that this is a monitoring program, and no preventive actions are required.
The staff confirmed that the preventive actions program element satisfies the guidance in SRP-LR Section A.1.2.3.2. The staff finds this program element acceptable.    (3) Parameters Monitored or Inspected - LRA Section B.1.8 states that visual inspections for IWE monitor loss of material of the steel containment liner and its attachments by
 
inspecting the surface for evidence of flaking, blistering, peeling, discoloration, and other
 
signs of distress. The applicant also states that visual inspections for IWL monitor
 
concrete surfaces for evidence of leaching, erosion, voids, scaling, spalls, corrosion, cracking, exposed reinforcing steel, and detached embedment.
In RAI B.1.8-1 dated December 7, 2007, the staff requested that the applicant provide additional details on the condition monitoring of protective coatings in containment. In
 
particular, the staff requested a description of the coating inspections performed on
 
surfaces that are not included in the IWE program.
By letter dated January 4, 2008, which was further clarified during telephone conference calls held on February 7, 2008, and March 7, 2008, the applicant stated that the
 
condition of the protective coatings on metal surfaces at IP, other than the containment
 
liner, is monitored by Structures Monitoring Program. The Structures Monitoring
 
Program governs monitoring the condition of structures or components of structures, including the condition of their protective coatings, as required by 10 CFR 50.65, the
 
Maintenance Rule.
The applicant further explained that the structures are inspected every 5 years and normally inaccessible areas are inspected every 10 years. An inaccessible area is an
 
area that requires destructive removal of a barrier for access. The containment liner
 
insulation is also considered a barrier such that the liner plate behind it is classified as
 
inaccessible. The scope of the inspections includes visual inspection of the coated
 
surfaces for signs of degradation (blistering, peeling, flaking, pinholes, rusting, splitting, and discoloration). The degradation observed during the inspections is evaluated to
 
determine if the current condition is acceptable or further monitoring or corrective actions
 
are necessary. Industry codes and standards including the Maintenance Rule, ASME Section Xl, and building codes are used to perform these evaluations and make
 
determinations as to whether or not the structures are capable of performing their 3-152 intended functions. A structure is classified as acceptable if it is capable of performing its structural functions, including protection or support of safety-related equipment.
The inspections are performed by inspection engineers under the direction of the responsible engineer. The responsible engineer is a degreed civil/structural engineer
 
with at least 10 years of related experience and a registered professional engineer. The
 
responsible engineer and inspection engineers must be knowledgeable in the design, evaluation, and performance requirements of structures. The inspection engineers must
 
be qualified to perform visual examination either directly or remotely to detect evidence
 
of degradation.
The applicant clarified that protective coatings are not relied upon to manage the effects of aging for structures in License Renewal. The existing 10 CFR 50.65 Maintenance
 
Rule Program includes monitoring the condition of coatings and they will continue to be
 
monitored under that program during the period of extended operation.
Additionally the applicant stated that, in response to Generic Safety Issue (GSI)-191, "Assessment of Debris Accumulation on PWR Sump Performance," the Civil/Structural
 
group visually inspects coatings in the vapor containment building during refueling
 
outages. The frequency of the inspection will be at least once every two years or every
 
cycle during the refueling outage. Adverse conditions will be resolved or evaluated as
 
acceptable prior to exiting the refueling outage.
Based on the applicants response to the RAI describing the division in responsibilities between the Structures Monitoring Program and the Maintenance Rule Program, the
 
staff finds the applicants response to the RAI B.1.8-1 acceptable. The staffs concern in
 
RAI B.1.8-1 is resolved.
The staff confirmed that the parameters monitored or inspected program element satisfies the guidance in SRP-LR Section A.1.2.3.3. The staff finds this program element
 
acceptable.  (4) Detection of Aging Effects - LRA Section B.1.8 states that the primary inspection method for the steel containment liner and its integral attachments is general visual examination.
 
Components in examination category E-A receive general visual examination or VT-3.
 
Painted or coated areas are examined for evidence of flaking, blistering, peeling, and
 
discoloration. Non-coated areas are examined for evidence of cracking, discoloration, wear, pitting, corrosion, gouges, and surface irregularities. Components in examination
 
category E-C receive an augmented visual or volumetric examination in accordance with
 
IWE Table 2500-1. The applicant also states that the primary inspection method for the
 
concrete containment shell is a general visual examination in accordance with
 
IWL-2500. Detailed visual examinations are performed to provide sufficient data to
 
conduct an acceptance review when conditions exceeding the screening criteria are
 
noted.The staff noted that the IP2 and IP3 containments have a somewhat unique design feature: thermal insulation on the steel liner plate, at the lower elevations of the
 
cylindrical containment wall. In both UFSARs, this insulation is credited with limiting the
 
liner temperature increase to 80 &deg;F during a design basis accident. Both UFSARs state
 
that the insulation is removable, to permit periodic inspection of the containment liner 3-153 plate. In Audit Item 27, the staff asked Entergy to:
(1) Identify the AMP and describe the specific inspections performed, to ensure that this insulation will continue to perform its intended function.
(2) Describe the plant-specific operating experience related to removal of this insulation and inspection of the containment liner plate normally covered by the insulation. How
 
does the condition of the normally insulated liner plate surface compare to the condition
 
of the normally uncovered liner plate surface? Has augmented inspection, per Category
 
E-C, been necessary?
In its response, dated December 18, 2007, Entergy stated:
(1) As noted in LRA Table 3.5.2-1, the liner plate insulation jacket has no aging effect, and therefore does not require aging management.(2)IP2 and IP3 have approximately 20% of the liner inaccessible due to the insulation at the lower elevations of the containment. At the 46'
 
Elevation, a caulking sealant, used as a moisture barrier, is installed at
 
the junction of the bottom edges of the insulation panels and the floor to
 
prevent moisture from reaching the steel liner. When performing a visual
 
examination of the liner, the insulation covering portions of the
 
containment liner is not removed. The IWE examination includes
 
inspection of the moisture barrier to ensure that it has not degraded. IP2
 
and IP3 will remove insulation during the required IWE examinations if
 
insulation removal is required to meet the requirements in Table IWE-
 
2500-1.During the IWE first interval for IP2, corrosion was discovered on the liner during the first period (April 2000) containment inservice inspection. The
 
corrosion existed in the portion of the liner where it is abutted by the fill
 
slab that covers the base mat liner. A number of inspections, investigations, and evaluations were performed to determine the
 
acceptability of the liner to perform its design function. The inspection
 
found several areas where the moisture barrier was missing or not
 
properly bonded between the floor slab and insulation. The degradation of
 
the moisture barrier raised a concern relative to the condition of the liner.
 
In order to address these concerns, lP2 selected nine (9) panels of the
 
liner insulation for removal to facilitate augmented inspection, per
 
Category E-C. During the removal and re-installation of these insulation
 
panels, the opening covers are re-sealed with the caulking sealant in
 
order to re-establish the moisture barrier.
Entergy further stated that when the insulation was removed, minor corrosion (light rust) was noted. Thickness readings were taken with no significant wall loss detected. As a
 
result of three consecutive inspections of the nine (9) panel areas, the containment liner
 
plate in these areas was found dry and the corrosion inactive, and the liner plate was
 
well within the required containment liner thickness. This augmented exam was
 
completed during the last lP2 Containment lSI interval. Entergy concluded that the IP2
 
liner will perform its intended function and is within acceptance limits for continued 3-154 operation.
For part (a) of Entergys response, the staffs evaluation concludes that there is no aging effect requiring an aging management program  for insulation encapsulated in a
 
stainless steel jacket and subject to an air - indoor uncontrolled environment. The staff
 
accepts Entergys AMR results.
For part (b) of Entergys response, the staff concluded that additional information was needed before the evaluation could be completed. The staff subsequently determined, from review of Entergy documents during the audit, that insulation had been placed over
 
the IP2 liner area that had been damaged (localized permanent deformation due to
 
thermal expansion) by a feedwater line break in 1973. The damaged area is
 
approximately 5 high and 50 around the circumference. Entergy has also treated this
 
damaged area as inaccessible for inspection. While Entergy performed an evaluation at
 
that time, which concluded that the permanent liner degradation would not compromise
 
the integrity of the liner, the staff notes that the condition of the liner in the damaged
 
area has not been examined for over 30 years.
In addition, as discussed previously, Entergy has detected some minor corrosion of the IP2 liner behind the insulation, at the juncture with the concrete floor slab. In discussions
 
with Entergy, the staff expressed concern that similar corrosion may exist in IP3;
 
however, Entergy has not examined the corresponding IP3 location.
Therefore, the staff requested that Entergy conduct a one-time inspection of the steel liner behind the insulation at 2 specific locations: (1) the damaged area of the IP2 steel
 
liner; and (2) the IP3 steel liner at the juncture with the concrete floor slab, in order to
 
confirm the absence of liner plate degradation behind thermal insulation.
The applicant provided a supplemental response to Audit Item 27 in Attachment 1 Operating Experience - Structures to Entergy letter dated August 14, 2008. In its
 
response, the applicant stated that, in order to provide assurance that liner degradation
 
is not occurring in the affected area, Entergy commits to remove insulation and perform
 
a one-time inspection of a representative sample area of the IP2 containment liner
 
affected by the 1973 event prior to entering the period of extended operation. Also, in
 
order to provide further assurance that liner degradation is not occurring in the area at
 
the juncture with the concrete floor slab on IP3, Entergy committed to perform a one-
 
time inspection of sample locations of the IP3 containment liner at the juncture with the
 
concrete floor slab, prior to entering the period of extended operation. These one-time
 
inspections are documented as Commitment 35 in Regulatory Commitment List, Revision 5; Attachment 4 to Entergy letter dated August 14, 2008.
At the staffs request, the applicant has committed to perform the one-time inspections of representative samples of liner areas prior to entering the period of extended operation, to confirm the absence of any liner plate degradation behind thermal insulation. Any
 
degradation that is detected would be dispositioned in accordance with the Containment
 
Inservice Inspection Program, including reanalysis, repair or replacement, and fatigue
 
analysis for IP2, if necessary. Based on this commitment, the staff considers the issue
 
related to liner plate degradation behind thermal insulation to be resolved.
3-155  (5) Monitoring and Trending - LRA Section B.1.8 states that results are compared, as appropriate, to baseline data and other previous test results.
The staff confirmed that the monitoring and trending program element satisfies the guidance in SRP-LR Section A.1.2.3.5. The staff finds this program element acceptable.    (6) Acceptance Criteria - LRA Section B.1.8 states that results are compared, as appropriate, to baseline data, other previous test results, and acceptance criteria of ASME Section XI, Subsection IWE for evaluation of any evidence of degradation.
 
Results are compared, as appropriate, to baseline data, other previous test results, and acceptance criteria of ASME Section XI, Subsection IWL for evaluation of any evidence
 
of degradation.
The staff confirmed that the acceptance criteria program element satisfies the guidance in SRP-LR Section A.1.2.3.6. The staff finds this program element acceptable.    (10) Operating Experience - LRA Section B.1.8 states that results of the IWE containment inspection at IP2 in 2004 were satisfactory.
The applicant states that an IWE containment inspection at IP3 in 2005 detected minor surface corrosion classified as acceptable under the program definitions.
The applicant also states that an IWL inspection at IP2 in 2005 revealed 91 recordable indications reviewed by engineering. None of these indications, which were compared to
 
the results of the 2000 inspection, represented a structural concern. An IWL inspection
 
at IP3 in 2005 found minor spalling and other indications noted in the 2001 inspection
 
with no signs of further degradation. Absence of degradation that could lead to failure, demonstrated through regular program inspections, assures effective program
 
management of aging effects for passive components.
The applicant further states that a self-assessment of the Containment ISI program in October 2004 found all findings and recommendations from earlier EPRI assessments of
 
the program evaluated and corrected. Detection of program weaknesses and
 
subsequent corrective actions assure continued program effectiveness in managing
 
component aging effects.
The staff noted that in 1973 a significant permanent deformation of the IP Unit 2 liner plate occurred at the penetration for feedwater line #22, as described in LRA Section
 
4.6. However, the operating experience element of AMP B.1.8 does not discuss this
 
existing condition, nor the results of periodic inspections conducted under the
 
Containment ISI Program. In Audit Item 30, the staff asked Entergy to: (a) Describe in greater detail the event that resulted in the permanent liner plate deformation. When specifically did it occur? What was identified as the root cause? How
 
was this corrected? (b) Discuss the history of ISI of the permanently deformed liner plate, from 1973 to the present.
3-156 In its response, dated December 18, 2007, Entergy stated: (a) The permanent IP2 liner plate deformation occurred on November 13, 1973 as a result of a break in the feedwater line to Steam Generator No. 22 inside the containment
 
near the feedwater line penetration. The pipe break resulted in a slight bulge, which
 
apparently was caused by the steam and water jet impingement. This was corrected by
 
pressurizing the containment which caused the liner to move 5/8 of an inch at 15 psig
 
and no further during pressurization to 47 psig. Also, a number of modifications were
 
made to prevent water hammers in these lines and to improve the piping and liner ability
 
to withstand such forces. These included rerouting the pipe layout, installing additional
 
pipe supports, installing J Tubes to delay the draining of the feedwater rings, and
 
installing additional insulation above the pipe break area around the inside of the
 
containment. In addition, analyses were performed of the liner plate and pipe material, and some experimental verification was conducted.(b) In 2004, general visual examinations were performed for all accessible areas of the containment liner, including penetrations and airlocks as part of the Containment
 
Inservice Inspection Program. Some minor surface corrosion and/or coating
 
deterioration were observed on the penetrations. Entergy concluded that this is general
 
surface corrosion that did not result in any significant loss of material. A containment
 
leak rate test at IP2 was completed satisfactorily in 2006.
Further staff evaluation of this condition is contained in the Detection of Aging Effects discussion above. Entergy has committed to inspect the damaged liner area, which was
 
covered by insulation after the accident, to confirm the absence of liner degradation, prior to entering the period of extended operation.
The staff reviewed the discussion of operating experience for the existing, plant-specific Containment Inservice Inspection Program as given in the PBD. In a condition report, the staff noted that it stated, The south side of the Containment dome in the alley
 
between the Fan building and VC about 25 feet up is spalling in about 6-7 places. The
 
rebar is exposed to the elements and is showing signs of rust. The openings into the
 
concrete are about 12-14 inches.
IP2 Containment Spalling (Audit Item 361)
In Audit Item 361, the staff asked Entergy to provide additional details, including any commitments for augmented inspection during the period of extended operation. In its
 
response, dated March 24, 2008, Entergy stated that this condition was first noted during
 
the 2000 IWL inspection. The 2005 IWL inspection found little or no change from 2000.
 
The spalls occur at locations where Cadweld' sleeves have insufficient concrete cover, attributed to an original installation deficiency. Rusting is not active and spalls are in an
 
area where the rebar stresses are low. Entergy indicated that Raytheon has evaluated
 
the structural margins for the IP containments, and at the locations of the exposed rebar, there is sufficient margin to accommodate additional loss of material due to corrosion.
 
The condition is being monitored under the IWL program. Remedial action will be taken
 
if the spalls further degrade and affect structural integrity.
Entergy identified several inspection enhancements, beyond general visual inspection, that are being implemented to more accurately measure the extent and progress of 3-157 degradation. However, there is no commitment to continue this augmented inspection during the period of extended operation. In follow-up discussions regarding Audit
 
Item 361, the staff requested Entergy to (1) provide the technical basis why augmented
 
inspection during the extended period of operation is not necessary; and (2) provide its
 
rationale for not proactively precluding progression of the concrete spalls and rebar
 
rust/corrosion during the period of extended operation, by taking reasonable action to
 
remedy this condition.
The applicant provided its supplementary response in a letter dated August 14, 2008. In its response, the applicant stated:
Concrete spalls on the containment were noted during the 2000 containment inservice inspection. In these areas, the exposed reinforcing
 
steel is oxidized, forming a protective coating. These areas have been
 
evaluated under the corrective action program. The evaluations have
 
determined that the spalls occur at locations where cadweld sleeves have
 
insufficient concrete cover. Cadweld splices have diameters larger than
 
the bar and thus have the least amount of concrete cover. The spalled
 
concrete locations are on the vertical cylinder wall of the containment
 
precluding the possibility of standing water that could percolate through
 
the concrete. The location on the vertical wall of containment precludes
 
ready access to allow for repair of a condition determined to have no
 
impact on the ability of the structure to perform its required function.
The 2005 CII-IWL inspection found little or no change of the condition observed in 2000. The identified areas show no signs of corrosion
 
staining or deterioration and no indication that the degradation is
 
progressing.
During the LRA review, Entergy committed to enhance the CII-IWL inspections during the period of extended operation through enhanced
 
characterizing of the degradation (i.e., quantifying the dimensions of
 
noted indications through the use of optical aids) (Ref. audit question
 
533). This better quantification will allow for more effective trending of
 
degradation following future inspections. The enhancement includes
 
obtaining critical dimensional data of degradation where possible through
 
direct measurement or the use of scaling technologies for photographs, and the use of consistent vantage points for visual inspections.
 
Implementation of this enhancement requires the continued use of optical
 
aids to allow effective characterization of indications on the containment
 
wall that are not accessible from the ground or from existing structures.
While Entergy has observed no progression of the containment concrete spall and rebar corrosion conditions during the most recent periodic
 
inspections, the enhanced measures for characterizing degradation
 
during the period of extended operation provide an effective means to
 
detect potential future progression of the degradation such that corrective
 
action to remedy the condition can be taken prior to loss of the license
 
renewal intended function. [Commitment 37]
3-158 The staffs evaluation of Entergys supplemental response concluded that the applicants commitment to use enhanced inspection techniques to better characterize and monitor
 
the degradation is a positive step; however, the applicant had not committed to take
 
remedial action to fix the degraded areas. Therefore, the staff determined that it needed
 
additional clarification of how Entergy plans to implement aging management during the
 
license renewal period.
In a telephone call with the applicant on September 3, 2008, the staff requested additional relevant information for the IP2 and IP3 containments on the existing design
 
margins at the locations of observed degradation, identifying the specific locations and
 
dimensions of the damage. By letter dated November 6, 2008, the applicant submitted a
 
supplemental response to Audit Item 361, describing the design margins for the IP
 
containment structures at the locations of existing concrete degradation. At the time of
 
issuance of the SER with Open Items, the staff was in the process of reviewing the applicants response. Thus, this issue was identified asOpen Item 3.0.3.3.2-1.
In its response dated November 6, 2008, the applicant stated:
Spalling of concrete has been observed on IP2 containment exterior surface. The affected areas are the vertical wall.
The containment structure is designed to withstand seismic, wind, deadweight, pressure, and temperature forces caused by natural
 
phenomena and accident conditions. In addition, the integrated leak rate
 
test is periodically performed on the containment which imposes an
 
internal nominal pressure of 47 psi.
Margin is defined as the difference between the Code allowable forces/stresses and the actual forces/stresses in the structure caused by
 
the most severe loading condition. Meeting the Code provides margin in
 
the form of a safety factor that requires the design strength of the
 
structure to be a multiple of the strength necessary to prevent failure
 
under maximum load conditions. Over and above the safety factor
 
established by meeting Code requirements is margin between actual
 
strength and the strength required to just meet the Code.
All areas of the spalled concrete on the containment structure exceed the strength required to meet Code requirements. The margin available over
 
and above the Code requirements is shown in the following table. As the
 
surface concrete is not credited for tensile strength of the structure, the
 
spalling has no impact on the available margins.
Margin above Code allowable (%)
Elevation (ft above ground) Vertical rebar Horizontal rebar 191.0 51 32 117 58 38 64 52 51 45.7 37 100 3-159 Since the design of the IP3 containment is similar to the IP2 containment design, the margins developed for IP2 are applicable to IP3.
The applicant also tabulated the approximate location (elevation and azimuth), dimensions of spall and the design margin for each spalled area
 
for IP2 and IP3 in its above response.
The staff reviewed the applicant's response dated November 6, 2008, and concluded that the staff required additional clarification before it could determine that the applicants
 
proposed aging management program for the period of extended operation is sufficient.
 
This issue was identified as Open Item 3.0.3.3.2-1.
In an effort to resolve this open item, the staff issued follow-up RAI 3: Open Item 3.0.3.3.2-1 (Audit Question 361), dated April 3, 2009, which requested the
 
following:(a) The clarification for the IP containment spalling states: As the surface concrete is not credited for tensile strength of the
 
structure, the spalling has no impact on the available margins.
 
The strength margins identified appear to be based on the
 
nominal rebar dimensions, without any consideration for rebar
 
degradation due to exposure and potential loss of bond between
 
the concrete and the rebar. Explain how the existing degradation
 
and design margin will be considered in performing periodic
 
inspections to monitor degradation that would ensure that there is
 
no loss of containment intended function during the period of
 
extended operation. (b) In the spent fuel pool discussion, in the letter dated November 6, 2008, the applicant stated: [I]ittle or no corrosion was observed in
 
the rebar except at a location in the wall where spalling had
 
occurred exposing rebar to the elements. Analysis of the rust
 
particles showed high chloride content and, low boron
 
concentration indicating that rainwater was the primary cause of
 
the observed corrosion. The applicant is requested to provide the
 
technical basis for the adequacy of the 5-year IWL frequency of
 
inspection of the degraded areas of the IP containments during
 
the period of extended operation, considering the possibility of an
 
increased site-specific corrosion rate of the exposed rebar on the
 
containments. This should include results of prior inspections, including any available comparative photos showing the
 
progression of degradation.
By letter dated May 1, 2009, Entergy responded to follow-up RAI 3: Open Item 3.0.3.3.2-1 (Audit Question 361), stating as follows: (a) As stated in Letter NL 169, dated November 6, 2008, the existing surface concrete degradation and potential loss of bond
 
between the concrete and the rebar has no impact on the ability of
 
containment to perform its intended function during the period of 3-160 extended operation. The design margins in containment are such that loss of one bar in every 4.5 feet in the vertical direction would
 
not impact the ability of containment to perform its intended
 
function.The ISI-IWL inspections have confirmed that there has been no identified degradation that could result in loss of function of the
 
containment structure (rebar and concrete) due to aging effects.
 
Localized surface rust has been observed at containment areas
 
where rebar has been exposed, but these visual inspection results
 
show no discernable deviation of rebar dimensions from nominal.
 
No degradation has been observed that indicates loss of bond for
 
rebar that is not monitored directly.
As part of the IPEC corrective action program (i.e., program Element 7), if degradation is identified during inspections, the
 
impact of the degradation on design margin will be evaluated to
 
ensure that there has been no loss of containment intended
 
function.Evaluations performed on containment associated with potentially degraded rebar (i.e., localized surface degradation) have shown
 
that loss of a number of reinforcing bars would have an
 
insignificant effect on containment stress margins and would not
 
impact containment intended function. Degradation of the rebar
 
will be readily discernable as obvious changes in bar dimensions
 
well before such degradation could progress to the point of
 
challenging the available design margins. (b) The technical adequacy of the 5-year IWL frequency of inspection of the degraded areas of the IPEC containments has-been
 
demonstrated by past inspection results. No detectable changes
 
have occurred over the 5-year period between past inspections.
 
The rate of degradation of the exposed rebar of the containments
 
has been imperceptible.
Documented inspection history for the first period IWL inspection began in 1999. Photographs taken of exposed rebar in the most
 
recent inspection in 2009 were compared to photographs taken
 
during the first IWL interval inspection in 2000 and a subsequent
 
inspection in 2005. As can be seen from the photos in Figures 5
 
through 7 corrosion of the exposed rebar is almost nonexistent
 
with no noticeable change in appearance over the years. Spalling
 
is confined to a small area around the rebar with no noticeable
 
cracking being present, which would indicate that the degradation
 
is localized or has not progressed along the length of the rebar
 
creating the potential for more spalling. Therefore, based upon
 
past and recent inspection, increased corrosion rates have not
 
been identified and additional degradation, which could prevent
 
the containment from performing its intended function, would be 3-161 readily detected by the established IWL inspections.
The staff reviewed the applicants May 1, 2009 response to follow-up RAI 3: Open Item 3.0.3.3.2-1 (Audit Question 361), and the applicants previous responses
 
concerning the spalling of the IP2 containment exterior surface. The staff noted the
 
following: Spalling on the external surface of the IP2 concrete containment was first documented during the 2000 ASME Subsection IWL inservice inspection. The
 
spalls occurred in the vertical reinforcing steel at locations where the reinforcing
 
bars are spliced using Cadweld sleeves. The diameter of the Cadweld sleeves is
 
about two times that of the reinforcing bars. The 2005 IWL inspection of the IP2 containment found little or no change in the conditions observed previously during 2000. The most recent inspection of the IP2 containment, during 2009, using enhanced remote visual optical aids indicated little, if any, additional degradation of the
 
concrete and reinforcing steel since 2000. This is based on a comparison of
 
photographs taken during 2000 and 2009 of the same areas. According to the applicants analysis and evaluation, the design margin provided at IP2 is at least 37 percent more than what is required by the design code.
 
Currently, the surface corrosion on the exposed Cadweld sleeves is the only
 
observed degradation. This degradation is insignificant when compared to the
 
available margin.
Based on the regular IWL inspections conducted every 5 years, and the use of enhanced remote visual aids to monitor and trend the currently degraded locations, there is reasonable assurance that any additional degradation of the IP2 concrete
 
containment would be identified prior to a loss of intended function. If additional
 
degradation of the IP2 containment is detected during the period of extended operation, the degradation will be evaluated and resolved in accordance with the Containment
 
Inservice Inspection Program. Therefore, the staff concludes that the effects of aging on
 
the IP containment concrete will be adequately managed in accordance with
 
10 CFR 54.21(a)(3). On this basis, Open Item 3.0.3.3.2-1 is closed.
UFSAR Supplement. In LRA Sections A.2.1.7 and A.3.1.7, the applicant provided the UFSAR supplement for the Containment Inservice Inspection Program. The staff reviewed these
 
sections and finds the UFSAR supplement information provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
By letter August 14, 2008, the applicant added Commitment 37 to enhance the Containment Inservice Inspection Program to include inspections of the containment using enhanced
 
characterization of degradation during the period of extended operation.
Conclusion. On the basis of its technical review of the applicants Containment Inservice Inspection Program, and review of the applicants responses to the staffs RAIs, the staff
 
concludes that the applicant has demonstrated that effects of aging will be adequately managed
 
so that the intended functions will be maintained consistent with the CLB for the period of 3-162 extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this program 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  Heat Exchanger Monitoring Program
 
Summary of Technical Information in the Application. LRA Section B.1.17 describes the existing Heat Exchanger Monitoring Program as a plant-specific program.
The Heat Exchanger Monitoring Program inspects by visual or other NDE techniques heat exchangers for loss of material. Inspection of heat exchanger (HX) tubes is at frequencies
 
based on plant- and application-specific history, heat exchanger operating conditions, and heat
 
exchanger availability. Inspection frequencies may be changed based on engineering
 
evaluation of inspection results.
Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.1.17 on the applicants demonstration of the Heat Exchanger Monitoring
 
Program to ensure that the effects of aging, as discussed above, will be adequately managed
 
so that the intended functions will be maintained consistent with the CLB for the period of
 
extended operation.
The staff reviewed the Heat Exchanger Monitoring Program against the AMP elements found in the GALL Report, in SRP-LR 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 elements ((1) scope of
 
the program, (2) preventive actions, (3) parameters monitored or inspected, (4) detection of
 
aging effects, (5) monitoring and trending, (6) acceptance criteria, (7) corrective actions,
 
(8) confirmation process, (9) administrative controls, and (10) operating experience).
The applicant indicated that program elements (7) corrective actions, (8) confirmation process, and (9) administrative controls are parts of the site-controlled QA program. The
 
staffs evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven
 
elements follows:    (1) Scope of the Program - LRA Section B.1.17 states that the Heat Exchanger Monitoring Program manages loss of material on selected heat exchangers required for efficient
 
and reliable power generation. Steam generators are not included in this program.
The applicant indicated it will enhance the applicable procedures of the existing program, to include the following heat exchangers in the scope of the program:      safety injection pump lube oil heat exchangers      RHR heat exchangers      RHR pump seal coolers      non-regenerative heat exchangers      charging pump seal water heat exchangers      charging pump fluid drive coolers      instrument air heat exchangers (IP3 only)      spent fuel pit heat exchangers      secondary system steam generator sample coolers      waste gas compressor heat exchangers 3-163    SBO/Appendix R diesel cooling water heat exchangers (IP2 only)
By letter dated December 18, 2007, in response to Audit Item 52, Entergy described the heat exchangers currently included in the existing program, which is called the Eddy
 
Current Program. Appendices 1 and 2 of the program document provide the detailed list
 
of the heat exchangers for units 2 and 3, respectively. Additionally, Entergy provided a description identifying the correlation between the HX tubes listed in AMR Tables 3.3.2-1 through 3.3.2-16 and those listed in the scope
 
section of the AMP. In response to this question, Entergy also indicated that it needs to
 
revise the LRA to address two items as follows: (1) the line item in AMR Table 3.3.2-2
 
IP3 Service Water refers to the instrument air copper alloy heat exchangers IP3 SWN CLC 31/32 HTX. Including this heat exchanger as part of the enhancement is not
 
appropriate since these are already in the existing eddy current inspection program; (2)
 
the LRA needs to be revised to include the charging pump crankcase oil cooler (IP3-
 
CHRG PP31/32/33 CRANK HTX).
The staff reviewed the response and determined that, with the two corrections noted above, there is a match between the applicable heat exchangers listed in AMR Tables
 
3.3.2-1 through 3.3.2-16 and those listed in the scope section of the AMP. The staff
 
confirmed that Entergy formally amended the LRA, by letter dated December 18, 2007, to incorporate these corrections.
By letter dated December 18, 2007, in response to Audit Item 56, Entergy indicated that this AMP manages the aging effect of loss of material due to wear for the HX tubes
 
included in the scope. Some of the heat exchangers are classified as ISI Class 1, 2, & 3 and do fall under the jurisdiction of ASME, Code Section XI inservice inspection and
 
repair/replacement requirements associated with the pressure boundary. The heat
 
exchanger monitoring program does not implement any of the repair/replacement or
 
inspection activities of these codes.
During the review of the Eddy Current Program, the staff noted that Section 2.2 of the program indicates that the IP Eddy Current Program is not part of the ASME Section XI
 
ISI/inservice testing programs. Section 2.2 also states that the ASME Code does not
 
mandate BOP heat exchanger eddy current inspections. Therefore, inspections are not performed for specific compliance with any ASME Code, Section V or XI requirements.
 
ASME Code, Section V, Article 8, Appendix I is utilized for the development of OD flaw
 
calibration standards.
Based on the description of the heat exchangers included in the existing Eddy Current Program and the additional heat exchangers listed as enhancements, the staff
 
determines that the scope of this AMP includes all components which credit this AMP in
 
the AMR.The staff confirmed that the scope of the program program element satisfies the guidance in SRP-LR Section A.1.2.3.1. The staff finds this program element acceptable.    (2) Preventive Actions - LRA Section B.1.17 states that this is an inspection program and no actions are taken as part of this program to prevent degradation.
3-164 The staff confirmed that the preventive actions program element satisfies the guidance in SRP-LR Section A.1.2.3.2. The staff finds this program element acceptable.    (3) Parameters Monitored or Inspected - LRA Section B.1.17 states that visual or other non-destructive examinations of shell-and-tube HX tubes are performed to determine tube
 
wall thickness, thereby managing the aging effect of loss of material. The applicant
 
indicated it will enhance appropriate procedures, to perform visual inspection on heat
 
exchangers where non-destructive examination, such as eddy current testing, is not
 
possible due to heat exchanger design limitations.
By letter dated December 18, 2007, in response to Audit Item 53, Entergy explained that the wear that is identified by this aging effect occurs on the outside of the tubes due to
 
contact between the tubes and the tube support plates. This wear may be caused by
 
vibrations of the tubes because of high flows or excessive clearance between the tubes
 
and the tube support plates. Wear due to abrasive fluid at high velocity is not expected
 
due to the controlled water chemistry of the fluids on the shell and tube sides. The staff
 
determined that the eddy current testing or visual inspection methods described in this AMP could be used to monitor the wall thickness of the HX tubes to detect the presence
 
of and extent of the loss of material.
By letter dated December 18, 2007, in response to Audit Item 54, Entergy indicated that all of the heat exchangers in the existing program are large enough so that eddy current
 
testing of the tubes can be performed. Visual inspections are not performed routinely.
 
Some of the new heat exchangers added in the enhancement are small, and thus may
 
preclude the possibility to perform eddy current testing. In these cases visual inspection
 
would be needed. The staff concurs that, for those heat exchangers that are not large
 
enough to perform eddy current testing, visual inspection of the tubes for wall loss is an
 
acceptable method to detect loss of material.
By letter dated December 18, 2007, in response to Audit Item 55, Entergy indicated that if eddy current testing of the tubes is not practical due to the size of the heat exchanger, configuration, and tube size, then a remote visual inspection of the tubes may be
 
required. The remote visual examination may be performed using a fiberscope placed
 
inside the tubes or on the tube exterior from the shell side. The specific acceptance
 
criteria of the program will be revised to require that no unacceptable signs of
 
degradation are present. This was identified as Commitment 10. The eddy current tests
 
have an acceptance criterion, which is determined by engineering evaluation on a heat
 
exchanger-specific basis. The staff concludes that the use of remote visual examination
 
methods by a fiberscope placed inside or on the outside surface of the tubes could detect loss of material of the HX tubes, and thus is acceptable. The specific acceptance
 
criterion for the visual inspection consisting of no unacceptable signs of degradation is
 
considered acceptable because it would identify any loss of material of the tube walls.
 
The inclusion of the acceptance criterion for visual inspection of the tubes is a new
 
enhancement to the existing program. Entergy has formally submitted Commitment 10, as part of an LRA amendment.
The staff confirmed that the parameters monitored or inspected program element satisfies the guidance in SRP-LR Section A.1.2.3.3. The staff finds this program element
 
acceptable.
3-165  (4) Detection of Aging Effects - LRA Section B.1.17 states that loss of material is the aging effect managed by this program. Representative tubes within the sample population of
 
heat exchangers are inspected at a frequency determined by plant-specific and industry
 
operating experience to ensure that effects of aging are identified prior to loss of
 
intended function. An appropriate sample population of heat exchangers is determined
 
based on operating experience prior to inspections. The sample population of heat exchangers is determined based on the materials of construction of the HX tubes and
 
the associated environments as well as the type of heat exchanger (for example, shell
 
and tube type). Inspection can reveal loss of material that could result in degradation of the HXs. The applicant indicated it will enhance appropriate procedures, to include
 
consideration of material-environment combination when determining sample population
 
of heat exchangers.
Components whose inspection results continually indicate no new indications from previous inspections are candidates for inspection frequency lengthening. Conversely, the inspection frequencies for components with indications of an increasing trend when
 
compared to previous inspections are evaluated for an increase in inspection frequency.
The staff reviewed Section 2.4 of the applicants Eddy Current Program and noted that the eddy current inspection frequencies are described therein. Appendices 1 and 2 list
 
the specific inspection frequencies for each heat exchanger. Section 2.4 states that the
 
frequencies are based on plant-specific and application-specific knowledge, as well as past history, current HX operating conditions, and unit availability/outage schedules. The
 
existing program also indicates that the established intervals are selected in order to
 
uncover potential tubing problems before failure occurs.
The staff also reviewed Section 2.5 of the Eddy Current Program and noted that the program defines the sampling plan. In general, all of the tubes will be inspected for small HXs. For other HXs, the sampling size depends on the material of the HX tubes and the specific operating experience of the HX. Based on the enhancement described above, the material-environment combination will also be considered when determining sample population of HXs. Appendices 1 and 2 of the Eddy Current Program list the approximate sampling size in percentages of the total number of tubes for each HX.
 
When less than a 100% inspection is performed, the program indicates that efforts be
 
made to ensure that the tubes randomly selected during each inspection are different
 
from the previously inspected tubes in order to approach a 100% inspection of the tubes
 
over the many inspections performed.
As noted in Section 2.13 of the Eddy Current Program, the eddy current vendor provides reports which contain the results of the inspections. A record of all inspections for each
 
component in the program is maintained on an on-going basis.
The staff finds that the eddy current inspection frequencies, sampling plan, and data collection, as summarized above, is appropriate for detecting loss of material before
 
there is a loss of the component intended function, and thus this program element is
 
acceptable.
The staff confirmed that the detection of aging effects program element satisfies the guidance in SRP-LR Section A.1.2.3.4. The staff finds this program element acceptable.
3-166  (5) Monitoring and Trending - LRA Section B.1.17 states that results are evaluated against established acceptance criteria and an assessment made regarding the applicable
 
degradation mechanism, degradation rate and allowable degradation level. This
 
information is used to develop future inspection scope, to modify inspection frequency, or replacement of the component if appropriate. Wall thickness is trended and projected
 
to the next inspection. Corrective actions are taken if projections indicate that the
 
acceptance criteria may not be met at the next inspection.
The staff confirms that the existing program contains monitoring and trending criteria for the HXs. The criteria require that an estimate of the HX remaining service life be made
 
based on the inspection results. The inspection results are compared with previous
 
successive data in order to estimate the growth rate of the tube damage. If the growth
 
rate for a particular tube is estimated to result in the tube exceeding the established
 
plugging criteria prior to the next scheduled inspection, the tube will be plugged as a
 
precautionary measure. The description included in the existing program ensures that
 
monitoring and trending is performed for the collected data and that the data are
 
properly evaluated to determine whether corrective actions are needed before a loss of the HX intended function would occur.
The staff confirmed that the monitoring and trending program element satisfies the guidance in SRP-LR Section A.1.2.3.5. The staff finds this program element acceptable.    (6) Acceptance Criteria - LRA Section B.1.17 states that the minimum acceptable tube wall thickness for each HX inspected is based upon a component-specific engineering
 
evaluation. Wall thickness is acceptable if greater than the minimum wall thickness for
 
the component.
The applicant indicated it will enhance appropriate procedures, establishing the minimum tube wall thickness for the new HXs identified in the scope of the program; and revise appropriate procedures, establishing acceptance criteria for HXs that are visually
 
inspected, to include no unacceptable signs of degradation.
The staff reviewed the acceptance criteria presented in the existing plant program, which define the maximum acceptable tube wall loss for HX tubes, in order to determine whether tube plugging is required. The existing program notes that ASME Section XI does not provide code-allowable minimum wall thickness requirements for HX tubes.
 
Therefore, the existing program utilizes the EPRI guidance for determining the tube
 
plugging criteria. Appendices 3 (for IP2) and 4 (for IP3) of the Eddy Current Program present a summary table for the allowable wall loss percentage for the HXs, based on
 
the EPRI guidance documents. In addition to the tube wall loss criteria, the existing program also provides HX replacement criteria. The program states that a HX and/or
 
tube bundle will be identified for replacement if tube plugging has reached 10 percent or
 
more of the total number of tubes, unless a specific calculation has been previously prepared to the contrary. Inspection results of HX tubes will be compared with previous
 
successive data in order to estimate a growth rate of the tube damage. The growth rate
 
for a particular tube is determined to establish the plugging criterion prior to the next
 
scheduled inspection to determine whether the tube will be plugged as a precautionary
 
measure. A formula is provided in the existing program, which is used as a trending tool
 
to estimate the tube remaining life in terms of the number of refueling cycles.
3-167 The existing program will be enhanced to include the minimum wall thickness for the new HXs added to the scope of the program, and to specify that if visual examination is
 
performed, the acceptance criterion is no unacceptable signs of degradation. The
 
acceptance criteria for the eddy current tests based on minimum wall thicknesses are
 
acceptable. However, the staff determined that the acceptance criteria for visual
 
examination are not clear and appear to be subjective; Entergy needs to clarify, preferably in quantitative terms, what acceptance criteria are used for the visual examination of the HX tubes. In RAI 3.0.3.3.3-1, the staff requested that Entergy define
 
the visual inspection acceptance criteria in greater detail. Pending receipt and review of
 
the applicants response, this was identified as Open Item 3.0.3.3.3-1.
By letter dated December 30, 2008, the staff requested that Entergy clarify, in quantitative terms, which acceptance criteria are used for the visual examination of the HX tubes.
By letter dated January 27, 2009, the applicant stated that the visual examinations of the HX tubes will be performed by a qualified engineer and will focus on the detection of loss
 
of material that might be induced by erosion, wear, corrosion, pitting, fouling or scaling.
 
The applicant also stated that the term no acceptable signs of degradation means no detection of these mechanisms such that the intended function of the HXs would be
 
impaired. The applicant also clarified that if evidence of any of these mechanisms were to be noted by the qualified HX engineer, the engineer would base his evaluation of the degraded condition on design requirements and thickness of the HX tubes when taking
 
into account the surface conditions caused by corrosion, erosion, pitting or wear, and or
 
any scale or other foreign materials noted on the tubes.The staff noted that ASME Code, Section XI cites VT-3 and VT-1 visual examination methods as acceptable visual examination methods for detecting surface discontinuities
 
or imperfections in plant components, including those that might be indication of wear, erosion, corrosion (including pitting corrosion). The staff finds this to be acceptable because the applicant will be performing visual examinations of these HX tubes using methods that are capable of detecting surface discontinues or imperfections in the HX
 
tubes and because the applicant will base acceptance of any relevant condition on the
 
design requirements and thickness of the tubes. The staff concludes that RAI 3.0.3.3.3-1 is resolved and Open Item 3.0.3.3.3-1is closed.
The staff confirmed that the acceptance criteria program element satisfies guidance in SRP-LR Section A.1.2.3.6. The staff finds this program element acceptable.    (10) Operating Experience - LRA Section B.1.17 states that results of eddy current testing of the tubes for several different IP2 HXs during 2000 through 2006 have indicated which
 
tubes should be plugged, thus preventing the loss of the pressure boundary intended
 
function. Detection of degradation, followed by corrective action prior to loss of intended
 
function, proves that the program effectively manages aging effects for passive
 
components.A review of the IP2 HX inspection plan in September 2003 compared the scope of the IP2 inspections planned for refueling outage 2R16 (2004) against the typical scope of
 
inspections planned for an IP3 refueling outage, and implemented recommended
 
changes in the IP2 inspection scope. Use of shared best practices in the development of 3-168 inspection plans assures continued program effectiveness in managing aging effects for passive components. Results of eddy current testing of the tubes for several different IP3 HXs from 1997 through 2004 have indicated which tubes should be plugged, thus preventing the loss of
 
the pressure boundary intended function. Detection of degradation and corrective action
 
prior to loss of intended function prove that the program effectively manages aging
 
effects for passive components.
An ongoing plan from a review of inspection intervals for IP3 components in April 2003 includes programmatic and technical activities for a wide range of HXs at IP3 to track
 
improvements and corrective actions for the program. Detection of program weaknesses
 
and subsequent corrective actions assure that the program will continue to manage loss
 
of component material effectively.
The staff reviewed the program basis document discussion of operating experience for more information on applicable operating experience. The program basis document
 
discussed the results of past eddy current testing of the tubes for several different IP2 and IP3 HXs, which resulted in the plugging of certain tubes.
The staff also reviewed a results report that was referenced in a program basis document. This document contains an IP3 Eddy Current Program Heat Exchanger
 
Listing, which presents results from past operating experience of the tubes for different IP3 HXs during the period 1997 through 2004. The review of this table confirmed that the
 
program is able to identify aging effects of loss of tube thickness before the loss of the
 
pressure boundary intended function, and that corrective action was taken by plugging
 
the appropriate tubes. This reference also has examples where the eddy current test
 
frequency was increased (e.g., changed from once per eight years to once per two years in July 2000 for a particular HX), which demonstrates that the frequency of inspection is
 
revised based on the operating experience.
The staff confirmed that the operating experience program element satisfies the guidance in SRP-LR Section A.1.2.3.10. The staff finds this program element
 
acceptable.
UFSAR Supplement. In LRA Sections A.2.1.16 and A.3.1.16, the applicant provided the UFSAR supplement for the Heat Exchanger Monitoring Program. The staff reviewed these sections and
 
finds the UFSAR supplement information an adequate summary description of the program, as
 
required by 10 CFR 54.21(d).
Conclusion. On the basis of its review of the applicants Heat Exchanger Monitoring Program, the staff concludes that the applicant has demonstrated that effects of aging will be adequately
 
managed so that the intended functions will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the
 
UFSAR supplement for this program and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3-169 3.0.3.3.4  Inservice Inspection Program Summary of Technical Information in the Application. LRA Section B.1.18, as amended by letter dated June 11, 2008, describes the existing Inservice Inspection Program as a plant-specific
 
program.LRA Section B.1.18 states that the Inservice Inspection Program encompasses ASME Section XI, Subsections IWA, IWB, IWC, IWD, and IWF requirements and 10 CFR 50.55a imposes ISI requirements of ASME Code, Section XI, for Classes 1, 2, and 3 pressure-retaining
 
components, their attachments, and supports in light-water cooled power plants. Inspection, repair, and replacement of these components are addressed in Subsections IWA, IWB, IWC, IWD, and IWF. The program includes periodic visual, surface, and volumetric examination and
 
leakage tests of Classes 1, 2, and 3 pressure-retaining components, their attachments, and
 
supports.ISI of supports for ASME piping and components is addressed in ASME Code, Section XI, Subsection IWF, which constitutes a mandated program for aging management of ASME
 
Classes 1, 2, 3, and MC supports for license renewal. The program uses NDE techniques to
 
detect and characterize flaws. Three types of examinations used are volumetric, surface, and
 
visual. Volumetric examinations use radiographic, ultrasonic, or eddy current methods to locate
 
surface and subsurface flaws. Surface examinations use magnetic particle or dye penetrant
 
testing to locate surface flaws.
Three levels of visual examinations are specified. VT-1 visual examination, which assesses the surface condition of the part examined for cracks and symptoms of wear, corrosion, erosion, or
 
physical damage, can be by either direct or remote visual observation using various
 
optical/video devices. The VT-2 examination specifically locates evidence of leakage from
 
pressure-retaining components (period pressure tests). While the system is under pressure for
 
a leakage test, visual examinations detect direct or indirect indication of leakage. The VT-3
 
examination determines the general mechanical and structural condition of components and
 
supports and detects discontinuities and imperfections. The Inservice Inspection Program is based on the ASME Section XI Inspection Program B (IWA-2432), which has 10-year inspection intervals. Every ten years the program is updated to the latest ASME Code, Section XI edition
 
and addenda in 10 CFR 50.55a.
IP2 entered the fourth ISI interval on March 1, 2007. The ASME Code edition and addenda for the fourth interval for IP2 is the 2001 Edition with 2003 addenda. IP3 is currently in the third ISI
 
interval. The ASME Code edition and addenda for IP3 is the 1989 Edition with no addenda. The
 
program consists of periodic volumetric, surface, and visual examination of components and
 
their supports for assessment, signs of degradation, flaw evaluation, and corrective actions.
 
Augmented ISIs are also included as required by 10 CFR 50.55a, the staff, responses to
 
requests for additional information, or as necessary under the program.
Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.1.18 on the applicants demonstration of the Inservice Inspection Program to
 
ensure that the effects of aging, as discussed above, will be adequately managed so that the
 
intended functions will be maintained consistent with the CLB for the period of extended
 
operation.
3-170 The staff noted that the applicant has categorized its Inservice Inspection Program as a plant-specific program.
The staff reviewed the Inservice Inspection Program against the staffs recommended program element criteria that are provided in SRP-LR Section A.1.2.3, and in SRP-LR Table A.1-1. The
 
staff focused its review on assessing how the plant-specific program elements for the Inservice
 
Inspection Program would ensure adequate aging management when compared to the
 
recommended program element criteria that are given in SRP-LR Section A.1.2.3. Specifically, the staff reviewed the following eight program elements of the applicants program: (1)scope of
 
the program, (2) preventive actions, (3) parameters monitored or inspected, (4) detection of
 
aging effects, (5) monitoring and trending, (6) acceptance criteria, (7) corrective actions,
 
and (10) operating experience.
The applicant indicated that program elements (7) corrective actions, (8) confirmation process, (9) administrative controls, are part of the site-controlled QA program. The staffs evaluation of the applicants Quality Assurance Program is documented in SER Section 3.0.4.
The staffs evaluation of the remaining program elements are given in the paragraphs that follow:  (1) Scope of the Program - LRA Section B.1.18 states that [t]he ISI Program provides the requirements for ISI, repair, and replacement. The components within the scope of the
 
program are specified in Subsections IWB-1100, IWC-1100, IWD-1100, and IWF-1100
 
for Classes 1, 2, and 3 components and supports, Quality Groups A, B, and C
 
respectively, and include all pressure-retaining components and their integral
 
attachments. The components described in Subsections IWB-1220, IWC-1220, and
 
IWD-1220 are exempt from the examination requirements of Subsections IWB-2500, IWC-2500, and IWD-2500.
The ISI Program manages cracking for carbon steel, carbon steel with stainless steel cladding, and stainless steel components, including bolting. The ISI Program implements applicable requirements of ASME Code, Section XI, Subsections IWA, IWB, IWC, IWD, IWF and other requirements specified in 10 CFR 50.55a with approved NRC
 
alternatives. The ISI Program also manages reduction of fracture toughness for valve
 
bodies and pump casing made of cast austenitic stainless steel. Both IP2 and IP3 use
 
ASME Code Case N-481 as approved in Regulatory Guide 1.147 for managing the
 
effects of loss of fracture toughness due to thermal aging embrittlement of CASS pump
 
casing pressure retaining welds. ASME Code Case N-481 has been incorporated in later
 
editions of the code and IP2 will not reference Code Case N-481 in the 4th interval.
SRP-LR Section A.1.2.3.1 states, [t]he 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 noted that the requirements for inservice inspection program are mandated by the provisions in 10 CFR 50.55a. The staff verified that the rule requires U.S. licensees
 
to establish inservice inspection (ISI) programs for their ASME Code Class components, structures, and component supports and requires U.S. licensees to apply the ISI
 
requirements that are provided in the provisions of the ASME Boiler and Pressure Vessel Code, Section XI, Division 1 (henceforth ASME Code, Section XI), Subsections 3-171 IWA, IWB, IWC, and IWD for the AMSE Code Class 1, 2, and 3 components, in Subsection IWF for ASME Code Class component supports, and in Subsection IWA for
 
generic ISI requirements. The current edition of the rule permits use of ASME Code, Section XI editions through 2001 Edition of the ASME Code, Section XI, inclusive of the
 
2003 Addenda.
In LRA Amendment 5, dated June 11, 2008, the applicant amended AMP B.1.18 to clarify that the applicable edition credited for aging management of ASME Code Class
 
components at IP2 within the scope of the AMP is the 2001 Edition of the ASME Code, Section XI, inclusive of the 2003 Addenda. Although the Inservice Inspection Program is
 
a plant-specific AMP for the LRA and does not need to conform to the staffs program element guidance in GALL AMP XI.M1, ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, the staff noted that GALL AMP XI.M1 identifies that the 2001 Edition of the ASME Code, Section XI, inclusive of the 2003 Addenda, is an acceptable ASME Code, Section XI edition for Inservice Inspection Programs that are
 
credited for aging management of ASME Code Class components. Thus, the staff finds
 
this update of the Inservice Inspection Program to be acceptable because it is in conformance with the scope of program program element in GALL AMP XI.M1.
In LRA Amendment 5, dated June 11, 2008, the applicant amended AMP B.1.18 to clarify that the applicable edition credited for aging management of ASME Code Class
 
components at IP3 within the scope of the AMP is the 1989 Edition of the ASME Code, Section XI, with no addenda. Although the Inservice Inspection Program is a plant-
 
specific AMP for the LRA and does not need to conform to the staffs program element guidance in GALL AMP XI.M1, ASME Section XI Inservice Inspection, Subsections
 
IWB, IWC, and IWD, the staff noted that the staffs 1995 SOC on 10 CFR Part 54 identifies that ASME Code, Section XI editions up through the 2001 Edition of the ASME Code, Section XI, inclusive of the 2003 Addenda, are acceptable ASME Code, Section XI editions for Inservice Inspection Programs that are credited for aging management of ASME Code Class components. Thus, the staff finds the ASME Code, Section XI edition (i.e., the 1998 edition of the code) credited for IP3 is acceptable for aging management
 
because it is in conformance with the staffs SOC position on 10 CFR Part 54 regarding the ASME Code, Section XI editions that are acceptable for aging management.
The staff verified that components within the scope of the program include the ASME Code Class 1, 2, and 3 components that are specified in Subsections IWB-1100, IWC-1100, IWD-1100, and the ASME Code Class 1, 2, and 3 component supports that are specified in AMSE Code Section XI Subsection IWF-1100. The staff verified that the
 
components include all pressure-retaining components and their integral attachments.
 
Based on this review the staff finds that the applicants identification of components that
 
are within the scope of the applicants Inservice Inspection Program is acceptable
 
because is in compliance with the applicable components that are mandated for inspection in the ASME Code, Section XI, Subsections IWB, IWC, IWD, and IWF, as
 
endorsed for use through reference in 10 CFR 50.55a.
Entergy also stated that the ISI programs manage loss of material for piping and component supports, anchorages, and base plates by visual examination of components
 
using NDE techniques, frequencies, and sample sizes specified in Subsection IWF
 
examination categories. Twenty-five percent of Class 1 piping supports, 15 percent of
 
Class 2 piping supports, 10 percent of Class 3 piping supports, and 100 percent of other 3-172 supports are subject to VT-3 visual examination, as required by the Code. Entergy stated that the examination categories are in accordance with Table IWF-2500-1 and
 
that for piping supports, the total percentage sample is comprised of supports from each
 
system where the individual sample sizes are proportional to the total number of
 
nonexempt supports of each type and function within each system. Thus, the staff
 
concludes that the scope of the Entergys ISI program for the component supports is acceptable because it includes the items identified in GALL AMP XI.S3, and because
 
this provides an acceptable basis for meeting SRP-LR Section A.1.2.3.1 with respect to
 
the scoping of components supports for the program.
Based on this review, the staff confirmed that the scope of the program program element satisfies the guidance in SRP-LR Section A.1.2.3.1 because: (1) the scope of
 
the program includes the applicable ASME Code 1, 2, and 3 components that are mandated for inservice inspection in the 1989 Edition of the ASME Code, Section XI, Subsection IWB, IWC, IWD and IWF, and because this in compliance with the
 
requirements of 10 CFR 50.55a and in conformance with the staffs SOC on 10 CFR
 
Part 54, and (2) consistent with the recommendation in SRP-LR Section A.1.2.3.1, the
 
applicant identified the components that are with the scope of the AMP. The staff finds
 
this program element acceptable.    (2) Preventive Actions - LRA Section B.1.18 states that the ISI Program is a condition monitoring program that does not include preventive actions.
For condition monitoring programs, SRP-LR Section A.1.2.3.2 states, For condition or performance monitoring programs, they do not rely on preventive actions and
 
thus, this information need not be provided.
The staff observed that the applicants Inservice Inspection Program is characterized as a condition monitoring program that uses a combination of non-destructive and visual
 
inspection methods to monitor for the effects of aging that are applicable to ASME Code
 
Class 1, 2, and 3 components and their components supports. Based on its review, the
 
staff concludes that the recommended guidance in SRP-LR Section A.1.2.3.2 is not
 
applicable to the applicants Inservice Inspection Program. Therefore, the applicants
 
preventive actions program element discussion for the Inservice Inspection Program is
 
acceptable.  (3) Parameters Monitored or Inspected - LRA Section B.1.18 states that the program uses nondestructive examination (NDE) techniques to detect and characterize flaws.
 
Volumetric examinations such as radiographic, ultrasonic or eddy current examinations
 
are used to locate surface and subsurface flaws. Surface examinations, such as
 
magnetic particle or dye penetrant testing, are used to locate surface flaws. Visual
 
examinations detect cracks and symptoms of wear, corrosion, physical damage, evidence of leakage, and general mechanical and structural condition.
For condition monitoring programs, SRP-LR Section A.1.2.3.3 states, [t]he parameters to be monitored or inspected should be identified and linked to the
 
degradation of the particular structure and component intended function(s), and
 
[f]or a condition monitoring program, the parameter monitored or inspected
 
should detect the presence and extent of aging effects. Some examples are
 
measurements of wall thickness and detection and sizing of cracks.
3-173 The staff noted that Subsection IWA-2200 defines the ASME inspection methods that may be applied to ASME Code Class components and the parameters that these
 
inspection methods are credited for. The staff also noted that IWA-2000 identifies that
 
the various ASME inspection methods as a whole detect for aging effect parameters
 
such as discontinuities or flaws (including cracking, pitting surface wastage, etc.), wear, corrosion, erosion, loss of integrity at bolted connections, and general mechanical and
 
structural condition of the components. The staff also noted that the aging parameters
 
discussed in IWA-2000 relate to the aging effects of loss of material, cracking, loss of
 
preload, and reduction of fracture toughness in ASME Code Class components, The
 
staff also noted that the aging effects identified in the applicants parameters monitored
 
or inspected program element were the same parameters as those identified and credited for in the ASME Code, Section XI, Subsection IWA-2200 paragraphs. Based on
 
this review, the staff confirmed that the parameters monitored or inspected program
 
element satisfies the guidance in SRP-LR Section A.1.2.3.3 because: (1) the parameters
 
identified as being within the scope of the applicants program are in compliance with those identified in ASME Code, Section XI, Subsection IWA-2200, and (2) the aging
 
parameters within the scope of the program relate back to either to the aging effects of
 
loss of material, cracking, loss of preload, or reduction of fracture toughness in ASME
 
Code Class components. Based on this review, the staff finds this program element
 
acceptable.  (4) Detection of Aging Effects - LRA Section B.1.18 states that the ISI Program manages cracking on subcomponents of the reactor vessel, as applicable, for carbon steel, nickel
 
alloy, carbon steel with stainless steel cladding, and stainless steel components, including bolting, using NDE techniques specified in ASME Section XI, Subsection IWB
 
examination category.
The ISI Program manages loss of material due to wear on reactor vessel internal subcomponents, as applicable, for nickel alloy and stainless steel clevis inserts, radial
 
keys, core alignment pins, and head/vessel alignment pins using NDE techniques specified in ASME Section XI, Subsections IWB examination categories.
The ISI Program manages cracking on reactor coolant system components, as applicable, for carbon steel, carbon steel with stainless steel cladding, stainless steel
 
and cast austenitic stainless steel components, including bolting and support skirts, using NDE techniques specified in ASME Section XI, Subsections IWB examination
 
categories. The Inservice Inspection Program also manages reduction of fracture
 
toughness for valve bodies and pump casing made of cast austenitic stainless steel.
The ISI Program manages cracking on steam generator system components, as applicable, for carbon steel, carbon steel with stainless steel cladding, and stainless steel components, using NDE techniques specified in ASME Section XI, Subsections
 
IWB examination categories.
The ISI Program manages loss of material for ASME Class MC and Classes 1, 2, and 3 piping and component supports and their anchorages and base plates by visual examination of components using NDE techniques specified in ASME Section XI, Subsection IWF examination categories.
3-174 No aging effects requiring management are identified for lubrite sliding supports.
However, the ISI Program will confirm the absence of aging effects through the period of
 
extended operation.
In the LRA, the applicant stated that the ISI Program will be revised to provide periodic inspections to confirm the absence of aging effects for lubrite sliding supports used in
 
the steam generator and reactor coolant pump supports.
Both IP2 and IP3 have adopted risk-informed inservice inspection (RI-ISI) as an alternative to current ASME Section XI inspection requirements for Class 1, Category
 
B-F and B-J welds pursuant to 10 CFR 50.55a(a)(3)(i). The RI-ISI was developed in
 
accordance with the EPRI methodology contained in EPRI TR-112657, Revision B-A, Revised Risk-Informed Inservice Inspection Evaluation Procedure. The risk informed
 
inspection locations are identified as Category R-A.For IP2, Article IWF of ASME Section XI, 2001 Edition and 2003 Addenda, does not contain any specific exemption criteria for component supports. For IP3, components
 
exempt from examination are in accordance with the criteria contained in Code Case N-
 
491-2, Alternate Rules for Examination of Classes 1, 2, 3 and MC Component Supports of Light-Water Cooled Power Plants, Section XI, Division 1, IWF-1230.
The staff reviewed this program element against the criteria in SRP-LR Section A.1.2.3.4.
The staff noted that the specific Examination Categories and Inspection Items in Table IWB-2500-1 establish the inspection methods, inspection frequencies, and flaw
 
acceptance standards that are to be used on ASME Code Class 1 components and that
 
Examination Categories and Inspection Items in Tables IWF-2500-1 establish the
 
inspection methods, inspection frequencies, and flaw acceptance standards that are to
 
be used on ASME Code Class component supports. The staff noted that the applicant
 
has credited the inspection requirements and inspection frequencies in applicable Table-
 
IWB-2500-1 Examination Categories and Inspection Items for ASME Code Class 1
 
components and the inspection requirements, inspection frequencies, and sample sizes
 
in applicable Table IWF-2500-1 Examination Categories and Inspection Items for ASME
 
Code Class component supports. The staff finds this to be acceptable because it is in compliance with the requirements of 10 CFR 50.55a and the ASME Code, Section XI.
The staff noted that the LRA indicated that the applicant is crediting the inspection requirements and inspection frequencies in the applicable Table IWB-2500-1
 
Examination Categories and Inspection Items for the detection of aging effects in the
 
steam generator (SG) secondary side shell, cone, and head components. The staff
 
noted that, normally, the inspection requirements and inspection frequencies for the SG
 
secondary side shell, cone, and head components would be performed in accordance with applicable requirements in the ASME Code, Section XI, Table IWC-2500-1 unless
 
these components were designed to ASME Code Class 1 standards. The staff noted that the ASME Code, Section XI requirements in Subsection IWB are normally more
 
stringent that those for ASME Code Class 2 and 3 requirements because the
 
components are part of the reactor coolant pressure boundary. Thus, based on this
 
review, the staff finds that using the inspection method and inspection frequency
 
requirements for SG shell, cone, and head components is conservative because either 3-175 the components were designed for ASME Code Class 1 standards and are inspecting in accordance with the applicable Examination Category and Inspection Items for these components in ASME Code, Section XI, Table IWB-2500-1 or that the components are
 
ASME Code Class 2 or 3 components and use of the applicable Examination Category and Inspection Items for these components in ASME Code, Section XI, Table IWB-2500-
 
1 is conservative relative to the requirements for inspection in Tables IWC-2500-1 or
 
IWD-2500-1.
The staff noted that the AMRs in LRA Chapters 3.2, 3.3, and 3.4 did not credit the Inservice Inspection Program for aging management of the ESF components, auxiliary system (AUX) components, and steam and power conversion system (S&PC)
 
components. Thus, the staff noted that the applicant was not crediting its implementation of the Examination Category requirements in ASME Code, Section XI, Table IWC-2500-
 
1 for aging management of the ASME Code Class 2 components and the Examination Category requirements in ASME Code, Section XI, Table IWD-2500-1 for aging
 
management of the ASME Code Class 3 components. The staff found this to be
 
acceptable because the AMRs in Sections, V, VII, and VII of the GALL Report, Volume 2 do not credit GALL AMP XI.M1, ASME Code, Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, for aging management of any of the aging effects that are attributed to ESF, AUX, and S&PC components.
The staff noted that the applicant indicated that it plans to enhance the Inservice Inspection Program to provide for periodic visual inspections of lubrite sliding supports
 
used in the SG supports and reactor coolant pump (RCP) supports in order to confirm
 
the absence of aging effects. The staff noted that the applicant could only treat this as
 
an enhancement of the program if the AMP were categorized as an AMP that is consistent with the program elements in GALL AMP XI.M1, ASME Section XI Inservice
 
Inspection, Subsections IWB, IWC, and IWD, and if the enhancement would make the
 
detection of aging effects program element of the AMP consistent with the detection of aging effects program element criteria that are provided in GALL AMP XI.M1. Thus, the
 
staff informed the applicant that the aging effects that are applicable to the lubrite SG
 
and RCP supports would need to be identified during the staffs review of the LRA and
 
that the applicant would need to establish and justify its selection of the inspection
 
methods, inspections frequencies, sample sizes, and acceptance criteria that are
 
applicable to these lubrite components, and the corrective actions that would
 
implemented if these acceptance criteria are exceeded. This was identified as Open
 
Item 3.0.3.3.4-1.
The applicant responded to RAI 3.0.3.3.4-1 in a letter dated January 27, 2009. In this letter, the applicant identified the lubrite sliding supports in the SGs and RCPs as ASME
 
code class supports that are within the scope of the requirement in the ASME Code, Section XI, Article IWF. In this letter, the applicant identified loss of material by wear and
 
locking of the lubrite sliding supports by abnormal surface roughness as applicable
 
aging effects for the lubrite sliding supports. The applicant clarified that there have not
 
been any recordable indications of wear or abnormal surface roughness in the lubrite
 
sliding supports detected to date and that as a result of this, the inspections performed
 
on the sliding lubrite supports will be VT-3 visual examinations in order to confirm that
 
these conditions do not exist in the supports. The applicant clarified that the inspection
 
frequency and sample size of these VT-3 visual examinations will be done in accordance with the requirements of the ASME Code, Section XI, Article IWF, and that if any wear or 3-176 abnormal surface roughness is detected, the applicant will evaluate the recordable conditions against the acceptance criteria in ASME Code, Section XI paragraph IWF-
 
3410(a). The applicant stated that corrective actions for the component supports would
 
be initiated in accordance with the requirements of the applicants 10 CFR Part 50, Appendix B quality assurance program.
The staff noted that these lubrite sliding supports are supports for the RCPs, which are ASME Code Class 1 pumps in the reactor coolant pressure boundary, and for the SGs, which are classified as ASME Code class vessels/heat exchangers that have both an
 
ASME Code Class 1 reactor coolant pressure boundary side and either an ASME Code
 
Class 2 or Class 3 non-reactor coolant pressure boundary side. The staff also noted that
 
the inspection methods, frequency and sample size for these supports is mandated by
 
10 CFR 50.55a and by Inspection Item F1.40, Supports Other Than Piping Supports, in the ASME Code, Section XI, Table IWF-2500-1, Examination Category F-A. The staff
 
noted that this inspection item pertains to non-piping supports in ASME Code Class 1, 2, and 3 piping systems and in MC structures, and calls for a VT-3 examination of 100% of
 
these supports once every 10-Year ISI interval. Based on these verifications, the staff
 
finds that the applicant has provided an acceptable basis for inspecting these lubrite
 
sliding supports because: (1) the applicant has indicated that it will inspect the supports
 
using the applicable ISI requirements for the supports, (2) these inspections will be done
 
in accordance with the requirements of Inspection Item F1.40, Supports Other Than Piping Supports, in the ASME Code, Section XI, Table IWF-2500-1, Examination
 
Category F-A, and (3) this is consistent with the detection of aging effects and monitoring and trending program elements in GALL AMP XI.S3, ASME Section XI, Subsection IWF. The staff concludes that RAI 3.0.3.3.4-1 is resolved and Open
 
Item 3.0.3.3.4-1 is closed with respect to the inspection methods, frequencies, and
 
sample sizes that are credited for these lubrite sliding supports. The staff noted that Subparagraph IWF-3410(a) of the ASME Code, Section XI provides the appropriate acceptance criteria for relevant conditions in ASME Code Class 1, 2, or
 
3 components supports, including (but not limited to) those that induce deformations, structural degradations, misalignments, or improper clearances of the supports (such as
 
might be induced if wear were occurring in the components), or abnormal surface
 
roughness (such as might be induced if scaling or corrosion products were to form on
 
the components). Based on this verification, the staff finds that the applicant has
 
provided an acceptable basis for evaluating any relevant indications in the lubrite sliding
 
supports because: (1) the applicant will use the mandated acceptance criteria in Subparagraph IWF-3410(a) of the ASME Code, Section XI as its basis for evaluating
 
any relevant conditions that might occur in these ASME Code Class lubrite sliding
 
supports and (2) this is consistent with the acceptance criteria program element in GALL AMP XI.S3. The staff concludes that RAI 3.0.3.3.4-1 is resolved and Open
 
Item 3.0.3.3.4-1 is closed with respect to the acceptance criteria that are credited for
 
these lubrite sliding supports. The staff noted the GALL AMP XI.S3 identifies that the applicants 10 CFR Part 50, Appendix B quality assurance program is an acceptable basis for establishing the
 
corrective actions for ASME Code Class component supports because the Quality
 
Assurance program would ensure that the corrective actions would be implemented in accordance with applicable requirements in the ASME Code, Section XI, Subparagraph
 
IWF-3122. Based on this verification, the staff finds that the applicant has provided 3-177 acceptable corrective actions for the lubrite sliding supports because: (1) the applicant has specified that the corrective actions for these supports will be implemented in
 
accordance with the applicants 10 CFR Part 50, Appendix B program, and (2) this is consistent with the corrective actions program element in GALL AMP XI.S3. The staff
 
concludes that RAI 3.0.3.3.4-1 is resolved and Open Item 3.0.3.3.4-1 is closed with
 
respect to the corrective actions that are credited for these lubrite sliding supports.
In Audit Item 60, the staff asked the applicant to justify its basis for using risk-informed inservice inspection (RI-ISI) for Examination Category B-J and B-F piping welds and for
 
applying and using NRC-approved Code Case N-532 during the period of extended
 
operation. In its response, dated December 18, 2007, Entergy amended the LRA to
 
remove from the LRA sentences referencing these items. At the same time, Entergy
 
stated that IP ISI programs would continue to be implemented in full compliance with the
 
Code requirements during the period of license renewal. The staff verified the applicant updated its Code of Record for IP2 to the 2001 Edition of the ASME Code, Section XI
 
through 2003 Addenda. For IP3, the Code of Record is the 1989 Edition of the ASME Code, Section XI with no Addenda. The staff finds this to be acceptable because the
 
SOC on 10 CFR Part 54 clarifies that the 2001 Edition of the ASME Code through 2003
 
Addenda and the 1989 Edition of the ASME Code with no Addenda are acceptable editions of the ASME Code, Section XI to use for aging management.
Based on this review, the staff confirmed that the detection of aging effects program element satisfies the guidance in SRP-LR Section A.1.2.3.4 because the applicant is
 
applying the inspection methods, inspection frequencies, and samples sizes in Table
 
IWB-2500-1 for ASME Code Class 1 components and for SG secondary side shell, cone, and head components and in Table IWF-2500-1 for ASME Code Class
 
components supports and because these methods meet the SRP-LR Section A.1.2.3.4
 
criteria for applicants to justify the inspection methods, inspection frequencies and
 
sample sizes that they select for aging management. Based on this review, the staff
 
finds this program element acceptable.    (5) Monitoring and Trending - LRA Section B.1.18 states that results are compared, as appropriate, to baseline data and other previous test results. Indications are evaluated in accordance with ASME Section XI. If the component is qualified as acceptable for
 
continued service, the area containing the indication is reexamined during subsequent
 
inspection periods. Examinations that reveal indications that exceed the acceptance
 
standards are extended to include additional examinations in accordance with ASME Section XI.
Inservice Inspection results are recorded every operating cycle and provided to the NRC after each refueling outage via Owner's Activity Reports. These reports include scope of
 
inspection and significant inspection results. They are prepared and submitted in accordance with NRC-accepted ASME Section XI Code Case N-532-1 as referenced in
 
RG 1.147.
The staff reviewed this program element against the criteria in SRP-LR Section A.1.2.3.5.
The staffs bases for approving the applicant inspection frequencies and sample sizes used in the inspections of ASME Code Class components has been discussed and 3-178 justified in the staffs evaluation of the detection of aging effects program element for this AMP.The staff noted that the applicant indicated that indications are evaluated against stated standards in the ASME Code, Section XI, and if found acceptable for service, the areas
 
containing the indications are re-inspected during the next scheduled outage. The staff
 
noted that that Articles IWB-2000, IWC-2000, and IWD-2000 all include criteria for
 
performing successive inspections on component indications that are found to be
 
acceptable for continued service, and for expanding the sample size if the indications
 
exceed the applicable flaw standard used for analysis in the Code. Based on this review, the staff finds the applicants monitoring and trending program element description for
 
performing successive inspections and sample expansion to be acceptable because it is in compliance with the requirements in ASME Code, Section XI.
In terms of record retention and reporting of data requirements, the staff noted that the applicant stated that records are prepared and provided to the NRC in accordance with
 
applicable Owners Activity Reports. The staff also noted that the ASME Code, Section XI, Article IWA-6000 provides the requirements for recording of data and reporting this
 
data to the NRC, including requirements for defining owner activities and responsibilities, completing of NIS-1 data record forms, preparation of summary reports, submittal of
 
summary to the NRC authorities, retaining records, reproducing records (including
 
digitization requirements and microfiche requirements), retention of construction record
 
requirements, maintenance of ISI records, retention of repair/replacement and
 
supplement evaluation records. Based on this review, the staff finds that the applicants
 
basis for the preparation, recording, and submittal of plant ISI data and data summaries
 
is acceptable because it is in compliance with the staffs record retention and reporting requirements in ASME Code, Section XI, Article IWA-6000.
Based on this review, the staff confirmed that the monitoring and trending program element satisfies the guidance in SRP-LR Section A.1.2.3.5 because: (1) the applicant
 
has demonstrated that it will continue to comply with the requirements in Article
 
IWA-6000 for record preparation, record retention and data and record reporting
 
requirements and in Articles IWB-2000, IWC-2000, and IWD-2000 for performing
 
successive inspections and for sample expansion, and (2) because the applicant has
 
satisfied the monitoring and trending program element in SRP-LR Section A.1.2.3.5 for
 
performing successive inspections of relevant flaw indications, sample expansion, and
 
for record preparation, record retention, and data reporting. Based on this review, the
 
staff finds this program element acceptable.    (6) Acceptance Criteria - LRA Section B.1.18 states that a pre-service, or baseline, inspection of program components was performed prior to startup to assure freedom
 
from defects greater than code-allowable. This baseline data also provides a basis for
 
evaluating subsequent inservice inspection results. Since plant startup, additional
 
inspection criteria for Classes 2 and 3 components have been imposed by
 
10 CFR 50.55a for which baseline and inservice data has also been obtained. Results of
 
inservice inspections are compared, as appropriate, to baseline data, other previous test results, and acceptance criteria of the ASME Section XI, for evaluation of any evidence
 
of degradation.
3-179 The ISI Program acceptance standards for flaw indications, repair procedures, system pressure tests and replacements for ASME Classes 1, 2, and 3 components and piping are defined in ASME Section XI subsections IWA, IWB, and IWC paragraphs 3000, 4000, 5000 and 7000, respectively. Acceptance standards for examination evaluations, repair procedures, inservice test requirements, and replacements for ASME Class 1 component and piping supports are defined in ASME Section XI paragraphs IWF-3000, IWF-4000, IWF-5000 and IWF-7000, respectively.
The staff reviewed this program element against the criteria in SRP-LR Section A.1.2.3.6.
The staff noted that the applicant indicated that it is using the applicable acceptance criteria in the ASME Code, Section XI, Subsections IWB, IWC, and IWD as its bases for
 
establishing the acceptance criteria for assessing relevant indications in ASME Code
 
Class components and in Subsection IWF for ASME Code Class supports. The staff noted that the flaw acceptance standards in the ASME Code, Section XI are based on
 
satisfying the design basis loading conditions that are applicable to ASME Code Class
 
components. The staff finds this to be acceptable because: (1) it is in compliance with the acceptance criteria requirements in the ASME Code, Section XI for Code Class 1, 2, and 3 components and their components supports, (2) these flaw evaluation criteria
 
are based on a standard of meeting design basis loading conditions, and (3) this is in
 
conformance with the recommended criteria in SRP-LR Section A.1.2.3.6.
Based on this review, the staff confirmed that the acceptance criteria program element satisfies the guidance in SRP-LR Section A.1.2.3.6 because: (1) the applicant is using the applicable acceptance criteria in the ASME Code, Section XI for the IP2 and IP3
 
ASME Code Class 1, 2, and 3 components and their components supports, and (2) this
 
satisfies the criterion in SRP-LR Section A.1.2.3.6 to provide for timely corrective action
 
before loss of intended function under these CLB design loads. The staff finds this
 
program element acceptable. (7) Corrective Actions - LRA Section B.1.8 states that [i]f a flaw is discovered during an ISI examination, an evaluation is conducted in accordance with articles IWA-3000 as
 
appropriate. If flaws exceed acceptance standards, such flaws are removed or repaired, or the component is replaced prior to its return to service. For Class 1, 2, and 3, repair
 
and replacement are in conformance with IWA-4000 and IWA-7000. Acceptance of flaws
 
which exceed acceptance criteria may be accomplished through analytical evaluation
 
without repair, removal or replacement of the flawed component if the evaluation meets
 
the criteria specified in the applicable article of the code. Corrective actions for this
 
program will be administered under the site QA program which meets requirements of
 
10 CFR Part 50, Appendix B.
The staff reviewed this program element against the criteria in SRP-LR Section A.1.2.3.7. As discussed in the evaluation of the scope of program program element for the Inservice Inspection Program, the staff verified that the applicants ASME Section XI
 
Code of Record for IP2 for the 4 th 10-year ISI interval is the 2001 Edition of ASME Code, Section XI through 2003 Addenda, and for IP3 for the 3 rd 10-year ISI interval is the 1989 Edition of ASME Code, Section XI with no Addenda. The staffs corrective actions for 3-180ASME Code Class 1, 2, and 3 components in these ASME Code, Section XI editions are defined and specified in General Article IWA-4000, and in the specific corrective action
 
provisions in IWB-4000 for Class 1 components, IWC-4000 for ASME Code Class 2
 
components, and IWD-4000 for ASME Code Class 3 components. The staff verified that
 
the specific corrective action in articles IWB-4000, IWC-4000, and IWD-4000, provides
 
either specific corrective action criteria for a specific ASME Code Class component or
 
refers back to general corrective action provisions for these components that are
 
contained in Article IWA-4000. The staff also verified that these corrective actions are
 
mandated for these components in accordance with inservice inspection requirements in
 
10 CFR 50.55a. The staff noted that the corrective actions program element for AMP B.1.18, Inservice Inspection Program, credits only the corrective actions in the ASME Code, Section XI, Articles IWA-4000 and IWA-7000 as the corrective action criteria for the program. The ASME Code, Section XI editions of record for IP are the 2001 Edition of the ASME Code, Section XI inclusive of the 2003 Addenda for IP2, and the 1989 Edition of the ASME Code, Section XI, with no addenda for IP3. The staff noted that Entergy did not credit component-specific corrective action criteria in ASME Section XI, Article IWB-
 
4000/7000 for Class 1 components, Article IWC-4000/7000 for Class 2 components, Article IWD-4000/7000 Class 3 components, or Article IWF-4000/7000 for ASME Code
 
Class component supports as being within the scope of the corrective action program
 
element for this AMP. By letter dated December 30, 2008, the staff asked the applicant
 
to clarify whether the content of the corrective actions program element was intended
 
to mean that Entergy will implement the corrective action provisions in the ASME Code, Section XI, Subsections IWA, IWB, IWC, IWD, and IWF that are applicable to the component Code Class in the applicable ASME Code, Section XI edition of record. This
 
was identified as Open Item 3.0.3.3.4-2.
The applicant responded to the staffs RAI in a letter dated January 27, 2009. In this letter the applicant clarified that the content of the corrective actions program element
 
discussion for this AMP is intended to mean that the corrective actions for this AMP will
 
be implemented in accordance with the corrective actions provisions that are appropriate for ASME Code Class 1, 2, 3 components in the ASME Code, Section XI, Articles IWA, IWB, IWC, and IWD and for ASME Code Class component supports in the ASME Code, Section XI, Article IWF.
The staff noted that the applicants response cited the appropriate ASME Code, Section XI corrective action articles for ASME Code Class 1, 2, and 3 components and for ASME
 
Code Class supports. The staff also noted that the applicants 10 CFR Part 50, Appendix
 
B, quality assurance program includes appropriate quality assurance activities to ensure
 
that inspections and corrective actions for ASME Code Class 1, 2, and 3 components
 
and component supports will be done in accordance with appropriate requirements in the ASME Code, Section XI, ASME Code Cases referenced for use in 10 CFR 50.55a
 
and the latest revision of NRC Regulatory Guide 1.147, or through applicable relief
 
requests that are requested and approved by the staff through the alternative ISI
 
requirements process in 10 CFR 50.55a(a)(3). The staff finds the corrective actions
 
program element for this AMP, as amended in the response to RAI 3.0.3.3.4-2, to be
 
acceptable because: (1) the applicant has indicated that the corrective actions for the
 
ASME Code Class 1, 2, and 3 components and component supports will be done in accordance with appropriate ASME Code, Section XI requirements, (2) the applicants 3-181 10 CFR Part 50, Appendix B quality assurance program provides an acceptable basis to ensure that corrective actions for ASME Code Class 1, 2, and 3 components and component supports will be done in accordance with appropriate AMSE Code Section XI
 
requirements, NRC-approved ASME Code Cases, or alternative program requirements
 
approved in accordance with 10 CFR 50.55a, and (3) this is consistent with the
 
corrective actions program element criteria for ASME Code Class 1, 2, and 3 components in GALL AMP XI.M1 and for ASME Code Class component supports in GALL AMP XI.S3. The staff concludes that RAI 3.0.3.3.4-2 is resolved and Open Item
 
3.0.3.3.4-2 is closed with respect to the acceptability of the corrective actions program
 
element for this AMP.    (10) Operating Experience - LRA Section B.1.18 states that:
ISI examinations at IP2 and IP3 were conducted during 2004 and 2005.
Results found to be outside of acceptable limits were either repaired, evaluated for acceptance as is, or replacement activities were initiated.
 
Identification of degradation and performance of corrective action prior to
 
loss of intended function are indications that the program is effective for
 
managing aging effects.
A self-assessment of the ISI program was completed in October 2004.
Review of current scope for 2R16 (2004) and 3R13 (2005) verified that
 
the proper inspection percentages had been planned for both outages. A
 
follow-up assessment was held for IP2 in March 2006 to ensure that all
 
inspection activities required to close out the third 10-year ISI interval
 
were scheduled for 2R17 (2006). Confirmation of compliance to program
 
requirements provides assurance that the program will remain effective
 
for managing loss of material of components.
QA surveillances in 2005 and 2006 revealed no issues or findings that could impact effectiveness of the program.
The staff reviewed the self-assessment and QA audit reports for the ISI program and confirmed that the QA audit documents indicated that the IP ISI program appropriately
 
identified and took corrective measures on the inspection findings. The staff also noted
 
that the QA audit documents indentified several deficiencies with the applicants ISI
 
Program and provided appropriate recommendations to correct them. The staff noted
 
that the QA audit documents did not indicate any programmatic weaknesses that would
 
impact the effectiveness of the ISI Program in accomplishing its intended objectives or
 
functions.
In RAI RCS-2, the staff asked the applicant, in part, to clarify how it performed its condition report review for relevant operating experience related to implementation of
 
this program. The applicant provided its response to RAI RCS-2 in a letter dated June 5, 2008. The staffs evaluation of the applicants response is documented in SER Section
 
3.0.3.2.9.
The staff noted that the applicants response to RAI RCS-2 indicated that the applicant had performed an extensive enough review to search for and locate reports or
 
documentation that would provide evidence of age-related aging effects in the IP2 or IP3 3-182 ASME Code Class 1 components. Thus, based on the response to RAI RCS-2, as made relative to the Inservice Inspection Program, the staff concludes that the applicant has
 
performed a sufficient review for relative operating experience (OE) that is relevant to
 
the AMSE Code Class 1 components and to the SG secondary shell side components
 
that are inspected and evaluated ASME Code Class 1 standards in ASME Code, Section XI Article IWB. The staff verified that the program is not credited for aging management of the ESF, Auxiliary System, and S&PC System components. RAI RCS-2
 
is resolved with respect to the operating experience review performed by the applicant
 
for the ASME Code Class 1 components and the SG secondary shell-side components.
In RAI RCS-1, as issued relative to the applicants Inservice Inspection Program, the staff asked the applicant to provide relevant operating experience information or CRs on
 
borated water leakage, Class 1 seal housing bolt cracking, steam generator (SG) tube
 
indications, and RV closure head weld indications that the staff had determined were
 
applicable to the application.
The applicant responded to RAI RCS-1 by letter dated June 5, 2008. In its response, the applicant clarified that relevant condition reports existed that demonstrated applicable
 
age-related degradation events for the following ASME Code Class 1 components:  Boric acid leakage events for control rod drive (CRDs), CRD mechanisms, resistance temperature devices, RV lower head BMI nozzles, and RV seal tables, penetrations, fittings, and thimble tubes. Seal housing bolt cracking events  SG tube indications  Upper RV closure head weld indications The staff has evaluated the boric acid leakage OE relative to the operating experience program element of AMP B.1.5, Boric Acid Corrosion Prevention Program. The staff
 
evaluation of the operating experience program element of the Boric Acid Corrosion
 
Prevention Program is given in SER Section 3.0.3.1.1 and includes the staffs basis for
 
concluding that the system walkdowns and bare metal visual examinations of the Boric
 
Acid Corrosion Prevention Program, as implemented through the Inservice Inspection
 
Program, bound this operating experience and are capable of managing boric acid
 
leakage and potential loss of material in steel ASME Class 1 components as a result of
 
boric acid induced corrosion and wastage.
The staff evaluated the OE related to SG tube indications relative to the operating experience program element of AMP B.1.35, Steam Generator Integrity Program. The
 
staff evaluation of the operating experience program element of the Steam Generator
 
Integrity Program is given in SER Section 3.0.3.2.14 and includes the staffs basis for
 
concluding that the inservice inspections that are performed in accordance with the
 
Steam Generator Integrity Program, as implemented through the Inservice Inspection
 
Program, bound this operating experience and are capable of managing loss of material
 
and cracking in SG tubes, tubesheets and support plates.
In regard to the OE related to cracking in the upper RV closure head welds, the applicant stated that a recordable indication was detected in the #2 meridional weld of the IP3
 
upper RV closure head as a result of an ISI volumetric examination that was performed 3-183 on the weld during the 2005 refueling outage. The applicant stated that the indication was similar to the indication from the original pre-service inspection record for the weld, which indicated that the indication was not from cracking and was acceptable for
 
service. The applicant stated that the indication was recorded to allow for comparisons
 
to be made during future inservice inspections of the components. The applicant also
 
stated that the remaining five meridional welds in the head were examined but the
 
inspections were negative for recordable indications. The monitoring and trending
 
activities and acceptance criterion comparisons taken by the applicant to compare the
 
inspection results of the #2 meridional weld to past pre-service inspection results and to
 
expand the sample size to the remaining meridional welds in the IP3 head are in compliance with ASME Code, Section XI requirements and demonstrate that the
 
applicant is taking appropriate measures to assess relevant recordable indications for
 
acceptability. Based on this review, the staff finds that applicant has appropriately
 
addressed the OE relative to the #2 meridional weld in the IP3 upper RV closure head
 
and that the applicants Inservice Inspection Program bounds this OE because the steps
 
taken to evaluated the recordable indication and expand the sample size of inspections
 
performed on the meridional welds of the IP3 upper RV closure head are in compliance with ASME Code, Section XI requirements.
The staff evaluated the OE related to seal housing bolt cracking relative to the operating experience program element of AMP B.1.2, Bolting Integrity Program. The staff
 
evaluation of the operating experience program element of the Bolting Integrity
 
Program is given in SER Section 3.0.3.2.2 and includes the staffs basis for concluding
 
that the inservice inspections that are performed on these Class 1 bolting component, as
 
performed in accordance with the Bolting Integrity Program and implemented through
 
the Inservice Inspection Program, bound this operating experience and are capable, in
 
part, of managing cracking in ASME Code Class 1, 2, and 3 bolting, including the
 
Class 1 seal housing bolts.
Based on this review, and the discussions in the previous four paragraphs, the staff finds the applicant has accounted for the OE relative to Class 1 components discussed in RAI
 
RCS-1 and that the inspections of the Boric Acid Corrosion Prevention Program, the
 
Steam Generator Integrity Program, the Reactor Vessel Head Penetration Inspection
 
Program, or Bolting Integrity Program are bounding for the operation experience on
 
these components and are capable of managing the applicable aging effects that are
 
within the scope of the CRs on the operating experience. RCS-1 is resolved relative to
 
the relationship of this OE to the Inservice Inspection Program.
Based on this review, the staff confirmed that the operating experience program element satisfies the guidance in SRP-LR Section A.1.2.3.10. The staff finds this
 
program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.17 and A.3.1.17, the applicant provided the UFSAR supplement for the Inservice Inspection Program. The staff noted the UFSAR Supplement
 
summary descriptions provided in LRA Sections A.2.1.17 and A.3.1.17 incorporated the
 
recommended summary description criteria from the SRP-LR that the program consists of
 
periodic volumetric, surface, and/or visual examination of components and their supports for
 
assessment, signs of degradation, and corrective actions. However, the staff noted that the
 
applicants summary description also incorporated the applicants proposal to enhance the
 
program for lubrite components, as provided in LRA Commitment 11, which references these 3-184 UFSAR Supplement sections.
In response to RAI 3.0.3.3.4-1 and Open Item 3.0.3.3.4-1, dated January 27, 2009, the applicant clarified that the inspection criteria, acceptance criteria, and corrective action criteria
 
for the RCP and SG lubrite sliding supports would be implemented in accordance with the ISI
 
requirements for ASME Code Class non-piping component supports in the ASME Code, Section XI, Article IWF. Based on this clarification, the staff finds that the applicant has fulfilled
 
Commitment No 11 on specifying the inspection methods, frequency, sample size, acceptance
 
criteria and corrective actions for the lubrite component supports and that the UFSAR
 
Supplement summary descriptions for the applicants Inservice Inspection Program are acceptable because they clarify that the Inservice Inspection Program will be implemented in accordance with the requirements of the ASME Code, Section XI, and 10 CFR 50.55a. The staff
 
concludes that the issues raised in RAI 3.0.3.3.4-1 concerning UFSAR Supplement Summary
 
Sections A.2.1.17 and A.3.1.17 are resolved and Open Item 3.0.3.3.4-1 is closed.
The staff reviewed LRA Sections A.2.1.17 and A.3.1.17 and finds the UFSAR supplement contains an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its review of the applicants Inservice Inspection Program, the staff concludes that the applicant has demonstrated that effects of aging will be adequately managed
 
so that the intended functions will be maintained consistent with the CLB for the period of
 
extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR
 
supplement for this program, and concludes that it provides an adequate summary description
 
of the program, as required by 10 CFR 54.21(d).
3.0.3.3.5  Nickel Alloy Inspection Program
 
Summary of Technical Information in the Application. LRA Section B.1.21 describes the existing Nickel Alloy Inspection Program as a plant-specific program.
The Nickel Alloy Inspection Program manages aging effects of Alloy 600 items and 82/182 welds in the reactor coolant system not addressed by the Reactor Vessel Head Penetration
 
Inspection Program or the Steam Generator Integrity Program. The aging effect requiring
 
management for nickel alloys exposed to borated water at an elevated temperature is PWSCC.
 
The Nickel Alloy Inspection Program includes elements of the Inservice Inspection Program, which specifies the NDE techniques and acceptance criteria for evaluation of cracks, and of the
 
Boric Acid Corrosion Control Program. The Water Chemistry Control - Primary and Secondary
 
Program maintains primary water in accordance with EPRI guidelines to minimize potential
 
crack initiation and growth. Indian Point will continue to implement commitments to (a) NRC
 
orders, bulletins, and generic letters addressing nickel alloys and (b) staff-accepted industry
 
guidelines.
Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.1.21 on the applicants demonstration of the Nickel Alloy Inspection Program to
 
ensure that the effects of aging, as discussed above, will be adequately managed so that the
 
intended functions will be maintained consistent with the CLB for the period of extended
 
operation.
The staff reviewed the Nickel Alloy Inspection Program against the staffs recommended program element criteria that are provided in SRP-LR Section A.1.2.3, and in SRP-LR 3-185 Table A.1-1. The staff focused its review on assessing how the plant-specific program elements for the Nickel Alloy Inspection Program would ensure adequate aging management when
 
compared to the recommended program element criteria that are given in SRP-LR Section
 
A.1.2.3. Specifically, the staff reviewed the following seven program elements of the applicants
 
program: (1) scope of the program, (2) preventive actions, (3) parameters monitored or
 
inspected, (4) detection of aging effects, (5) monitoring and trending, (6) acceptance
 
criteria, and (10) operating experience.
The applicant indicated that program elements (7) corrective actions, (8) confirmation process, and (9) administrative controls are parts of the site-controlled QA program. The staff
 
evaluates the Nickel Alloy Inspection Programs corrective actions, confirmatory process and
 
administrative controls program elements as part of the staffs evaluation of the applicants
 
Quality Assurance Program. The staffs evaluation of the applicants Quality Assurance Program
 
is given in SER Section 3.0.4. The staffs evaluation of the remaining program elements are
 
given in the paragraphs that follow:    (1) Scope of the Program - LRA Section B.1.21 states that the following reactor vessel and reactor coolant system pressure boundary items are within the scope of the Nickel Alloy
 
Inspection Program:      Reactor inlet and outlet nozzle safe end weld material      Reactor bottom mounted instrumentation tubes      Reactor core support lugs (pads)      Reactor closure head vent safe ends and welds      Reactor head vent and Reactor flange leakoff piping SRP-LR Section A.1.2.3.1 states:  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.GALL Report XI.M11, Nickel-Alloy Nozzles and Penetrations, denotes that this AMP has been replaced in part by AMP 11A, Nickel-Alloy Penetration Nozzles Welded to the
 
Upper Reactor Vessel Closure Heads of Pressurized Water Reactors (PWRs only), and
 
that guidance for the aging management of other nickel-alloy nozzles and penetrations
 
is provided in the AMR line items of GALL Report Chapter IV, as appropriate.
Guidance for the aging management of other nickel-alloy nozzles and penetrations is provided in the AMR line items of Chapter IV, Reactor Vessel, Internals, and Reactor
 
Coolant System, as appropriate in the GALL Report. The items applicable to nickel-alloy
 
material in Westinghouse reactors are found within sections A2, Reactor Vessel (Pressurized Water Reactor), B2, Reactor Vessel Internals (PWR) - Westinghouse,
 
C2, Reactor Coolant System and Connected Lines (Pressurized Water Reactor), and
 
D1, Steam Generator (Recirculating).
The staff verified that the materials in the IP pressurizer nozzles and welded joints are not fabricated from Alloy 82/182/600 materials. The staff also verified the reactor coolant
 
system contained no additional nickel alloy welds from those identified above. The staff
 
also noted there have been numerous RAIs based on the review of the AMRs
 
associated with the nickel alloy components. The staff determined that satisfactory
 
resolution of RAI 3.1.2-1 is necessary for confirmation of the scope of the program.
3-186 This was identified as part of Open Item 3.1.2-1.
The applicant responded to RAI 3.1.2-1 in a letter dated January 27, 2009. In this response, the applicant clarified that the following ASME Code Class 1 reactor coolant
 
pressure boundary components are fabricated from Alloy 600 base metal materials or
 
Alloy 82 or 182 weld filler metals:  CRDM housing tubes (i.e., the CRDM nozzles)  CRDM housing-to-housing tube safe-end adapter full penetration welds  CRDM housing tube-to-upper reactor vessel closure head (RVCH) partial penetration welds  upper RVCH vent adapter  upper RVCH vent adapter-to-heat vent full penetration weld  reactor vessel (RV) bottom mounted instrumentation (BMI) nozzles  RV BMI nozzle-to-nozzle safe-end welds The staff noted that these components are ASME Code Class 1 pressure boundary components and welds that are within the scope of B.1.21, Nickel Alloy Inspection
 
Program. Based on this clarification, the staff finds that the applicant has resolved the
 
issues raised in RAI 3.1.2-1 concerning the scope of program element for this AMP.
The staff concludes that RAI 3.1.2-1 is resolved and Open Item 3.1.2-1 is closed with respect to the applicants identification of nickel alloy base metal and weld
 
components that are within the scope of the Nickel Alloy Inspection Program.
The staff also verified that the augmented inspection basis for the nickel alloy CRDM housing tubes (i.e., CRDM penetration nozzles) and their nickel alloy partial penetration
 
upper RVCH-to-housing tube welds are within the scope of the applicants Reactor
 
Vessel Head Penetration Inspection Program (LRA AMP B.1.31). The staffs evaluation of the ability of the Reactor Vessel Head Penetration Program to manage cracking in the CRDM housing tubes and their nickel alloy upper RVCH-to-housing tube welds is
 
in SER Section 3.0.3.1.12.
Based on this review, the staff confirmed that the scope of the program program element satisfies the guidance in SRP-LR Section A.1.2.3.1. The staff finds this program
 
element acceptable.    (2) Preventive Actions - LRA Section B.1.21 states that [n]o actions are taken as part of this program to prevent aging effects or mitigate aging degradation. However, primary water
 
chemistry is maintained in accordance with EPRI guidelines by the Water Chemistry
 
Control - Primary and Secondary Program, which minimizes the potential for PWSCC.
For condition monitoring program, SRP-LR Section A.1.2.3.2 states:  For condition or performance monitoring programs, they do not rely on preventive actions and
 
thus, this information need not be provided.
The staff found that the Nickel Alloy Inspection Program uses nondestructive and visual examination methods to monitor the aging of the nickel alloy components as required by
 
the ISI program and as augmented by the recommendations of applicable bulletins, generic letters and NRC approved industry guidance.
3-187 Based on this review, the staff confirmed that the preventive actions program element satisfies the guidance in SRP-LR Section A.1.2.3.2. The staff finds this program element
 
acceptable.  (3) Parameters Monitored or Inspected - LRA Section B.1.21 states that the Nickel Alloy Inspection Program detects degradation by using the examination and inspection requirements of ASME Section XI, augmented as appropriate by examinations in
 
response to NRC Orders, Bulletins and Generic Letters, or to accepted industry
 
guidelines. The parameters monitored are the presence and extent of cracking.
For condition monitoring programs, SRP-LR Section A.1.2.3.3 states:
 
The parameters to be monitored or inspected should be identified and linked to the degradation of the particular structure and component intended function(s), and [f]or a
 
condition monitoring program, the parameter monitored or inspected should detect the
 
presence and extent of aging effects. Some examples are measurements of wall
 
thickness and detection and sizing of cracks.
The staff notes that the Nickel Alloy Inspection Program uses the appropriate volumetric, surface and visual NDE techniques for detection of degradation of the components identified in the scope of the program as required by ASME Code and recommended by
 
the applicable bulletins, generic letters and industry guidance.
Based on this review, the staff confirmed that the parameters monitored or inspected program element satisfies the guidance in SRP-LR Section A.1.2.3.3. The staff finds this
 
program element acceptable.    (4) Detection of Aging Effects - LRA Section B.1.21 states that the Nickel Alloy Inspection Program detects cracking due to PWSCC prior to loss of component intended function.
 
Some of the nickel alloy locations receive volumetric, surface and visual examination in accordance with ASME Section XI, supplemented as appropriate for current industry
 
PWSCC considerations. Items receiving volumetric, surface and visual examination are
 
listed below. Reactor vessel nozzle-to-safe end dissimilar metal welds receive a visual inspection every other outage and examination by volumetric techniques at 10-year intervals per ASME Section XI, Examination Category B-F.      Bottom mounted instrumentation nozzles receive a visual examination from the exterior of the vessel in accordance with ASME Section XI, Examination
 
Category B-P. The core support pads and guide lugs receive a visual examination in accordance with ASME Section XI, Examination Category B-N-2.      The head vent and reactor flange leakoff piping receive a visual examination.
The EPRI MRP in conjunction with the Westinghouse owners groups (WOG) is developing a strategic plan to manage and mitigate PWSCC of nickel based alloy items.
 
The main goal of this program will be to provide short and long term guidance for
 
inspection, evaluation, and management of nickel alloy material and weld metal locations in PWR primary systems. Guidance developed by the MRP and WOG will be 3-188 used to identify critical locations for inspection and augment existing ISI inspections where appropriate.
The staff reviewed this program element against the criteria in SRP-LR Section A.1.2.3.4.
The staff noted that specific techniques and frequencies for monitoring the nickel alloy components are prescribed by ASME Code, Section XI for those components examined
 
in accordance with the ISI program. For the other items included in the scope of the
 
Nickel Alloy Inspection program the methods and frequencies of examination are
 
recommended in the applicable bulletins, generic letters and industry guidance.
Based on this review, the staff confirmed that the detection of aging effects program element satisfies the guidance in SRP-LR Section A.1.2.3.4. The staff finds this program
 
element acceptable.    (5) Monitoring and Trending - LRA Section B.1.21 states that Records of the inspection program, examination and test procedures, examination/ test data, and corrective
 
actions taken or recommended are maintained in accordance with the requirements of ASME Section XI, Subsection IWA.
The staff reviewed this program element against the criteria in SRP-LR Section A.1.2.3.5.The staff noted that ASME Section XI requires, recording of examination and test results that provide a basis for evaluation and facilitate comparison with the results of subsequent examinations. ASME Section XI also requires, retention of all inspection, examination, test, and repair/replacement activity records and flaw evaluation calculations for the service lifetime of the component or system. ASME Section XI
 
additionally provides rules for additional examinations (i.e., sample expansion), when
 
flaws or relevant conditions are found that exceed the applicable acceptance criteria, to
 
assist in determination of an extent of condition and causal analysis.
Based on this review, the staff confirmed that the monitoring and trending program element satisfies the guidance in SRP-LR Section A.1.2.3.5. The staff finds this program
 
element acceptable.    (6) Acceptance Criteria - LRA Section B.1.21 states that Acceptance criteria for the volumetric inspections of dissimilar metal welds will be in accordance with ASME Section XI, IWB-3514. The acceptance standards for visual examination are specified in
 
MRP-139. Acceptance standards for visual inspection of the core support pads are given
 
in IWB-3520. Acceptance criteria for identified external surface damage, such as from borated water leaks, are given in ASME Section XI, IWA-5250. Should additional
 
inspections (volumetric, surface or visual) of nickel-based alloy locations (weld and base
 
metal) be identified based on industry operating experience, where acceptance standards are not included in ASME Section XI, acceptance standards will be developed
 
using appropriate analytical techniques.
The staff reviewed this program element against the criteria in SRP-LR Section A.1.2.3.6.
3-189The staff noted that ASME Section XI, IWB-3000, contains acceptance criteria appropriate for the reactor coolant pressure boundary components examined in accordance with Section XI. Also, ASME Section XI, IWA-5250, was verified to contain
 
acceptable steps for evaluation and corrective measures for sources of leakage
 
identified by visual examinations for leakage.
Based on this review, the staff confirmed that the acceptance criteria program element satisfies the guidance in SRP-LR Section A.1.2.3.6. The staff finds this program element
 
acceptable.(10) Operating Experience - LRA Section B.1.21 states that:
The Nickel Alloy Inspection Program incorporates proven monitoring techniques and acceptance criteria for detection of cracking in nickel alloy components prior to a loss of function. Reactor coolant pressure
 
boundary inspections have found no indications of cracking of nickel alloy
 
components. The program considers industry operating experience, responds to industry trends in inspection, evaluation, repair, and
 
mitigation activities, and is structured to be compatible with corresponding
 
programs across the industry. In response to NRC Bulletin 2003-02, there
 
were bare-metal visual examinations of the lower head of the reactor
 
vessel in the fall of 2004 for IP2 and in the spring of 2005 for IP3.
 
Examination of the area adjacent to each bottom-mounted
 
instrumentation penetration, including each Alloy 600 penetration, the
 
nickel alloy weld pad, and the circumference around the annulus between
 
the penetration and weld pad, detected no cracking.
The staff confirms that the operating experience program element satisfies the guidance in SRP-LR Section A.1.2.3.10. The staff finds this program element
 
acceptable.
UFSAR Supplement. In LRA Sections A.2.1.20 and A.3.1.20, the applicant provided the UFSAR supplement for the Nickel Alloy Inspection Program. The staff reviewed these sections and finds
 
the UFSAR supplement information an adequate summary description of the program, as
 
required by 10 CFR 54.21(d).
UFSAR Supplement A.2.1.41, Reactor Vessel Internals Aging Management Activities, includes a commitment that the site will (1) participate in the industry programs for investigating and
 
managing aging effects on reactor internals; (2) evaluate and implement the results of the
 
industry programs as applicable to the reactor internals; and (3) upon completion of these
 
programs, but not less than 24 months before entering the period of extended operation, submit
 
an inspection plan for reactor internals to the NRC for review and approval.
By letter dated June 11, 2008, the applicant revised the statement in the UFSAR Supplement sections A.2.1.20 and A.3.1.20 to incorporate the response to RAI 3.0.3.3.5-2 and stated IP
 
would comply with future applicable NRC Orders and implement applicable (1) Bulletins and
 
Generic Letters and (2) staff-accepted industry guidelines associated with nickel alloys. The
 
staff finds this to be acceptable because it is consistent with the aging management review
 
basis for non-upper RVCH nozzle nickel alloy components, as provided in Table IV.A2 of the 3-190 GALL Report, Volume 2, and the criteria in SRP-LR Section 3.1.3.2.13.
Conclusion. On the basis of its review of the applicants Nickel Alloy Inspection Program, the staff concludes that the applicant has demonstrated that effects of aging will be adequately
 
managed so that the intended functions will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the
 
UFSAR supplement for this program and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3.0.3.3.6  Non-EQ Bolted Cable Connections Program
 
Summary of Technical Information in the Application. LRA Section B.1.22 describes the new Non-EQ Bolted Cable Connections Program as a plant-specific program. The applicant stated
 
that this program provides for one-time inspections on a sample of connections to be completed
 
prior to the period of extended operation. The factors considered for sample selection will be
 
application (medium and low voltage defined as less than 35kV), circuit loading (high loading),
and location (high temperature, high humidity, vibration, etc.). The technical basis for the
 
sample selections will be documented. If an unacceptable condition or situation is detected in
 
the selected sample, the corrective action program will evaluate the condition and determine
 
appropriate corrective action. The applicant also stated that this program will ensure that
 
electrical cable connections perform intended functions through the period of extended
 
operation and will be implemented prior to it.
Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.1.22 on the applicants demonstration of the Non-EQ Bolted Cable Connections
 
Program to ensure that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB for the period of extended operation.
The staff reviewed the Non-EQ Bolted Cable Connections Program 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 elements ((1)
 
scope of the program, (2) preventive actions, (3) parameters monitored or inspected, (4)
 
detection of aging effects, (5) monitoring and trending, (6) acceptance criteria, (7)
 
corrective actions, (8) confirmation process, (9) administrative controls, and (10) operating
 
experience).
The applicant indicated that program elements (7) corrective actions, (8) confirmation process, and (9) administrative controls are parts of the site-controlled QA program. The
 
staffs evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven
 
elements follows:    (1) Scope of the Program - LRA Section B.1.22 states that non-EQ connections associated with cables in the scope of license renewal are part of this program. This program does
 
not include the high voltage (greater than 35kV) switchyard connections. In-scope
 
connections are evaluated for applicability of this program. The criteria for including
 
connections in the program are that the connection is a bolted connection that is not covered under the EQ program or an existing preventive maintenance program.
SRP-LR Appendix A.1.2.3.1 states that the program scope includes the specific structures and components of which the program manages the aging.
3-191 The staff confirmed that the specific commodity groups for which the program manages aging effects are identified (Non-EQ bolted cable connections associated with cables
 
within the scope of license renewal), which satisfies the guidance in SRP-LR Appendix
 
A.1.2.3.1. The staff also determined that the exclusion of high-voltage (>35 kV)
 
switchyard connections, connections covered under EQ program and the existing PM
 
program is acceptable. Switchyard connections are addressed in SER Section 3.6.2.2.
 
EQ cable connections are covered under 10 CFR 50.49. Cable connections under a
 
preventive maintenance program are periodically inspected. On this basis, the staff finds
 
that the applicants scope of program program element is acceptable.    (2) Preventive Actions - LRA Section B.1.22 states that this one-time inspection program is a condition monitoring program; therefore, no actions are taken as part of this program
 
to prevent or mitigate aging degradation.
SRP-LR Appendix A.1.2.3.2 states that condition monitoring programs do not rely on preventive actions, and thus, preventive actions need not be provided.
The staff confirmed that the preventive actions program element satisfies the guidance in SRP-LR Appendix B.1.2.3.2. The staff finds it acceptable because this is a condition
 
monitoring program and there is no need for preventive actions. On this basis, the staff
 
finds the applicants preventive actions program element is acceptable.    (3) Parameters Monitored or Inspected - LRA Section B.1.22 states that this program will focus on the metallic parts of the cable connections. The one-time inspection verifies
 
that loosening of bolted connections due to thermal cycling, ohmic heating, electrical
 
transients, vibration, chemical contamination, corrosion, and oxidation is not an aging
 
effect that requires a periodic aging management program.
SRP-LR Appendix A.1.2.3.3 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 parameter monitored or inspected should detect
 
the presence and extent of aging effects.
The staff confirmed that the parameters monitored/inspected program element satisfies the guidance in Appendix A.1.2.3.3 of the SRP-LR. Loosening (or high resistance) of
 
bolted cable connections are the potential aging effects due to thermal cycling, ohmic
 
heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation.
 
The design of bolted cable connections usually account for the above stressors. The
 
one-time inspection is to confirm that these stressors are not an issue that requires a
 
periodic AMP. On this basis, the staff finds that the applicants parameters monitored or
 
inspected program element is acceptable
.  (4) Detection of Aging Effects - LRA Section B.1.22 states that a representative sample of electrical connections within the scope of license renewal and subject to aging
 
management review will be inspected or tested prior to the period of extended operation
 
to verify there are no aging effects requiring management during the period of extended
 
operation. The applicant stated that factors considered for sample selection will be
 
application (medium and low voltage), circuit loading (high loading), and location (high
 
temperature, high humidity, vibration, etc.). The technical basis for the sample selected 3-192 will be documented. Inspection methods may include thermography, contact resistance testing, or other appropriate methods including visual based on plant configuration and
 
industry guidance. The applicant also stated that one-time inspection provides additional
 
confirmation to support industry operating experience that shows that electrical
 
connections have not experienced a high degree of failures, and that existing installation
 
and maintenance practices are effective.
SRP-LR Appendix A.1.2.3.4 states that detection of aging effects should occur before there is a loss of the structure and component intended function(s). The parameters to
 
be monitored or inspected should be appropriate to ensure that the structure and
 
component intended functions will be adequately maintained for license renewal under
 
all CLB design conditions. The GALL Report AMP XI.E6 states that testing may include thermography, contact resistance testing, and other appropriate testing methods. In AMP B.1.22, the applicant states that inspection methods may include thermography, contact resistance testing, or
 
other appropriate methods including visual inspection based on plant configuration and
 
industry guidance. The staff requested the applicant to explain how visual inspection
 
alone, if used, can detect loosening of bolted connections (Audit Item 63). In a letter
 
dated December 18, 2007, the applicant responded that visual inspection is an alternate
 
technique to thermography or measuring connection resistance of bolted connections
 
that are covered with heat shrink tape, sleeving, insulating boots, etc., where the only
 
alternative to visual inspection is destructive examination. The applicant also stated that
 
an example of where visual inspection may be used is motor connections, where the
 
motor lead is connected to the field cable in a local junction box. Typically these
 
connections are completely covered with field splices, so there is no method to perform
 
connection resistance testing of the connection. The practice would be to not remove the
 
junction box cover when the cable is energized, so thermography would not be an option
 
to determine a loose connection. Another example of using visual inspection would be in
 
remote switchgear panels where the entire connection to the bus is covered with tape or
 
an insulating boot.
In a letter dated March 24, 2008, the applicant supplemented its response and stated that because of personal safety practices, the junction box cover would not be removed
 
when the cable is energized, so thermography could only be performed with the junction
 
box in place, which may not provide accurate results. Contact resistance measurements
 
would require the destructive examination of the connection. The applicants policies for
 
personnel safety for energized components at a potential greater than 600V are to
 
observe a restricted approach boundary, which would preclude the removal of a bolted
 
cover from energized components at a potential of greater than 600V. The applicant
 
stated that numbers of bolted connections that are greater than 600V are limited to large
 
motor, transformer, or generator connections (less than 30 connections, which are 3
 
connections per phase for 10 motors) for both units and 5 remote motor control centers
 
for both units.
On August 29, 2007, the staff issued proposed license renewal interim staff guidance LR-ISG-2007-02, Changes to Generic Lesson Learned (GALL) Report Aging Management Program (AMP) XI.E6, Electrical Cable Connections Not Subject to
 
10 CFR 50.49 Environmental Qualification Requirements, for public comment. In this ISG, the staff proposed changes to GALL AMP XI.E6 to clarify and recommend a one-3-193 time inspection, on a representative sampling, to ensure that either aging of metallic cable connections is not occurring or an existing preventive maintenance program is
 
effective, such that a periodic testing is not required. Based on public and stakeholder
 
comments, the staff has determined that resistance measurement or thermography may
 
be a preferred method for testing loose cable connections. However, if resistance
 
measurement can not be performed with the insulation in place, and for reasons of
 
personnel safety, energized equipment can not be accessed to perform thermography, then visual inspection is an acceptable alternate inspection method for cable
 
connections covered with insulation materials. The staff has previously permitted visual inspections every 5 years for covered bus connections in GALL XI.E4, Metal Enclosed
 
Bus. If the applicant chooses visual inspection as an alternate to thermography or
 
resistance measurement of cable connections covered with insulating materials (heat
 
sink tapes, sleeving, insulation boots etc.), it can not use a one-time inspection and must
 
perform periodic visual inspections. Periodic visual inspection can effectively detect
 
loosening of cable connections by inspecting insulation materials for discoloration, cracking, chipping, or surface contamination. Absence of insulation deterioration will
 
ensure that cable connections will not be loose. The staff is finalizing its position in the final ISG to permit periodic visual inspections for cable connections covered with
 
insulation.
In a letter dated August 14, 2008, the applicant stated that following a telephone conference call held on June 2, 2008, with the NRC, Entergy agreed that visual
 
inspections would not be used for one-time inspections in the Indian Point Non-EQ
 
Bolted Cable Connection Program and the applicant revised LRA Section B.1.22 as
 
follows: B.1.22 Non-EQ Bolted Cable Connection Program, Detection of Aging Effects. A representative sample of electrical connections within the
 
scope of license renewal and subjected to aging management review will
 
be inspected or tested prior to the period of extended operation to verify
 
there are no aging effects requiring management during the period of
 
extended operation. The factors considered for sample selection will be
 
application (medium and low voltage), circuit loading (high loading),
location (high temperature, high humidity, vibration, etc.). The technical
 
basis for the sample selected will be documented. Inspection methods
 
may include thermography, contact resistance testing, or other
 
appropriate methods based on plant configuration and industry guidance.
 
The one-time inspection provides additional confirmation to support
 
industry operating experience that shows that electrical connections have
 
not experienced a high degree of failures, and that existing installation
 
and maintenance practice are effective.
The staff finds the applicant supplemental response acceptable because the applicant committed to inspect or test a representative sample of electrical connections using
 
methods such as thermography, contact resistance testing, or other appropriate
 
methods. Resistance measurement or thermography is a preferred method for testing
 
loose cable connections. These test methods are consistent with those in the GALL Report AMP XI.E6. On this basis, the staff finds that the applicants description of
 
parameters monitored or inspected program element is acceptable.
3-194  (5) Monitoring and Trending - LRA Section B.1.22 states that trending actions are not included as part of this program because this is a one-time inspection program.
SRP-LR Appendix A.1.2.3.5 states that monitoring and trending activities should be described, and they should provide predictability of the extend of degradation and thus
 
affect timely corrective or mitigative actions. This program element describes how the
 
data collected are evaluated and may also include trending for a forward look. The
 
parameter or indicator trended should be described.
The staff confirmed that absence of trending for testing is acceptable since the test is a one-time inspection and the ability of trending is limited by the available data.
 
Furthermore, the staff did not see a need for such activities. On this basis, the staff finds
 
the applicants monitoring and trending program element is acceptable.  (6) Acceptance Criteria - LRA Section B.1.22 states that the acceptance criteria for each inspection / surveillance are defined by the specific type of inspection or test performed
 
for the specific type of cable connections. Acceptance criteria ensure that the intended
 
functions of the cable connections can be maintained consistent with the CLB.
SRP-LR Appendix A.1.2.3.6 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 functions are maintained under all CLB design conditions during the period of
 
extended operation.
The staff confirmed that this program element satisfies the guidance in Appendix A.1.2.3.6 of the SRP-LR. The staff finds it acceptable on the basis that acceptance
 
criteria for inspection/surveillance are defined by the specific type of inspection or test
 
performed for the specific type of connection. The specific type of test when
 
implemented, and acceptance criteria will ensure that the license renewal intended
 
functions of the cable connections will be maintained consistent with the current
 
licensing basis.  (10) Operating Experience - LRA Section B.1.22 states that operating experience shows that loosening of connections and corrosion of connections could be a problem without
 
proper installation and maintenance. The applicant stated that industry operating
 
experience supports this one-time inspection program in lieu of a periodic testing
 
program to verify whether installation and maintenance have been effective. The
 
Non-EQ Bolted Cable Connections Program is new. The applicant will consider industry
 
operating experience when implementing this program.
SRP-LR Appendix A.1.2.3.10 states that operating experience should provide objective evidence to support the conclusion that the effect of aging will be managed adequately
 
so that the structure and component intended functions will be maintained during the
 
period of extended operation.
The staff notes that only a limited number of cases related to failed connections due to aging have been identified and these operating experiences do not support a periodic inspection as currently recommended in GALL AMP XI.E6. On August 29, 2007, the staff
 
issued proposed license renewal interim staff guidance LR-ISG-2007-02, Changes to Generic Lesson Learned (GALL) Report Aging Management Program (AMP) XI.E6, 3-195Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements for public comments. In this ISG, the staff proposed changes to GALL AMP XI.E6 to clarify and recommend a one-time inspection, on a representative
 
sampling, to ensure that either aging of metallic cable connections is not occurring or an
 
existing preventive maintenance program is effective, such that a periodic testing is not
 
required. The staff agreed with the applicants assessment of operating experience. The
 
staff finds that the proposed one-time inspection program will ensure that either aging of
 
metallic cable connections is not occurring or the existing preventive maintenance
 
program is effective such that a periodic inspection program is not required. On this
 
basis, the staff finds that the applicants operating experience element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.21 and A.3.1.21, the applicant provided the UFSAR supplement for the Non-EQ Bolted Cable Connections Program. The staff reviewed these
 
sections and finds the UFSAR supplement information an adequate summary description of the
 
program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its review of the applicants Non-EQ Bolted Cable Connections Program, the staff concludes that the applicant has demonstrated that effects of aging will be
 
adequately managed so that the intended functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed
 
the UFSAR supplement for this program and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3.0.3.3.7  Periodic Surveillance and Preventive Maintenance Program
 
Summary of Technical Information in the Application. LRA Section B.1.29, as amended by letters dated December 18, 2007, August 14, 2008, January 27, 2009, June 12, 2009, and June
 
30, 2009, describes the existing Periodic Surveillance and Preventive Maintenance Program as
 
a plant-specific program.
Periodic inspections and tests in the Periodic Surveillance and Preventive Maintenance Program manage aging effects not managed by other AMPs. The Periodic Surveillance and
 
Preventive Maintenance Program enhancements add new activities to the plants preventive maintenance and surveillance programs, which generally implement preventive maintenance
 
and surveillance testing activities through repetitive tasks or routine monitoring of plant
 
operations. Visual and other NDE techniques inspect the following systems and structures:  reactor building  safety injection system  main steam system  circulating water system  city water system  condensate system  river water system  fresh water cooling system  wash water system  chemical and volume control system  plant drains  station air system  instrument air system 3-196 heating, ventilation, and air conditioning (HVAC) systems  emergency diesel generators  security generator system  IP2 SBO/Appendix R diesel generator  fuel oil system  IP3 Appendix R diesel generator  auxiliary feedwater  containment cooling and filtration  control room HVAC  nonsafety-related systems affecting IP2 safety-related systems  nonsafety-related systems affecting IP3 safety-related systems Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.1.29 on the applicants demonstration of the Periodic Surveillance and
 
Preventive Maintenance Program to ensure that the effects of aging, as discussed above, will
 
be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation.
The staff reviewed the Periodic Surveillance and Preventive Maintenance Program against the AMP elements found in the GALL Report, in SRP-LR 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 elements ((1) scope of the program, (2) preventive actions, (3)
 
parameters monitored or inspected, (4) detection of aging effects, (5) monitoring and
 
trending, (6) acceptance criteria, (7) corrective actions, (8) confirmation process, (9)
 
administrative controls, and (10) operating experience).
The applicant indicated that program elements (7) corrective actions, (8) confirmation process, and (9) administrative controls are parts of the site-controlled QA program. The
 
staffs evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven
 
elements follows: (1) Scope of the Program - LRA Section B.1.29 states that the IPEC Periodic Surveillance and Preventive Maintenance Program, with regard to license renewal, includes those
 
tasks credited with managing aging effects identified in aging management reviews.
The staff reviewed this program element against the criteria in SRP-LR Section A.1.2.3.1.
The staff noted that the applicant had identified this AMP as a plant-specific AMP that does not have a GALL Report counterpart. The staff also noted that, of the aging
 
management activities mentioned in the program description, the applicant had identified
 
that the applicant had identified that the majority of the activities were new, and that for
 
these activities, the scope of program, parameters monitored or inspected, detection
 
of aging effects, and acceptance criteria program elements for the AMP are enhanced
 
as follows:
Program activity guidance documents will be developed or revised as necessary to assure that the effects of aging will be managed such that applicable components
 
will continue to perform their intended functions consistent with the current licensing
 
basis through the period of extended operation.
3-197 The applicant included this enhancement in Commitment 21 (refer to the letter of March 24, 2008). Because the Periodic Surveillance and Preventive Maintenance Program is a
 
plant-specific AMP, the program activities for the components within the scope of the
 
AMP should be defined in the program element discussions that are provided in the LRA
 
for the AMP.
The staff noted that the scope of program program element for the Periodic Surveillance and Preventive Maintenance Program did not specify which components
 
were within the scope of the program, although it did appear that the applicant had
 
provided this type of information in the program description for the AMP. Thus, the staff
 
was of the opinion that the applicants scope of program program element for the
 
Periodic Surveillance and Preventive Maintenance Program did not conform to the staffs
 
general recommendation in SRP-LR Section A.1.2.3.1 because the applicant did not
 
define the components that are within the scope of the program in its scope of program
 
program element for the AMP. In RAI 3.0.3.3.7-1, Part 1, the staff informed the applicant
 
that it would need to define the components and systems that are within the scope of the
 
Periodic Surveillance and Preventive Maintenance Program. This was identified as Open
 
Item 3.0.3.3.7-1, Part 1.
The applicant responded to RAI 3.0.3.3.7-1, Part 1 in a letter dated January 27, 2009. In this letter the applicant clarified that the components and systems within the scope of the
 
scope of program program element for the Periodic Surveillance and Preventive
 
Maintenance Program are those components and systems that have been identified in
 
the program description for the AMP. The staff verified that the components and systems
 
within the scope of the Periodic Surveillance and Preventive Maintenance Program are identified in the program description for the AMP, as amended by applicable system and
 
component scoping information for this AMP that was provided by the applicant in letters
 
dated December 18, 2007, and August 14, 2008.
The staff noted that in the applicants letter dated December 18, 2007, the applicant amended the scope of program program element for the Periodic Surveillance and
 
Preventive Maintenance Program to add the main steam safety valve tailpipes in the
 
main steam system and the atmospheric dump valve silencers to the scope of the
 
Periodic Surveillance and Preventive Maintenance Program.
The staff also noted that in the applicants letter dated August 14, 2008, the applicant amended the scope of program program element for the Periodic Surveillance and
 
Preventive Maintenance Program to add the IP2 138 kV underground transmission cable
 
for the offsite power feeder to the scope of the Periodic Surveillance and Preventive
 
Maintenance Program.
The staff confirmed that information provided by the applicant in LRA Section B.1.29, as amended in its letters dated December 18, 2007, August 14, 2008, January 27, 2009, June 12, 2009, and June 30, 2009, clarified that the following systems and components
 
are within the scope of the Periodic Surveillance and Preventive Maintenance Program:  reactor building:  reactor building cranes (polar and manipulator), crane rails, and girders, and refueling platform  safety injection (SI) system:  recirculation pump motor cooling coils and housing 3-198 city water system:  piping, piping elements and piping components  chemical and volume control system (CVCS):  charging pump casings  plant drains:  piping, piping components, and piping elements in the drains, and for IP2, the backwater valves  station air system:  station air containment penetration piping  heating, ventilation and air conditioning (HVAC) systems:  HVAC duct flexible
 
connections, stored portable blowers, and flexible trunks  emergency diesel generator (EDG) systems:  EDG exhaust gas piping, piping
 
components and piping elements; EDG duct flexible connections; EDG air
 
intake and aftercooler piping, piping components and piping elements; EDG air
 
start piping, piping components and piping elements; and EDG cooling water
 
makeup supply valves  security generator system:  security generator exhaust piping, piping
 
components and piping elements; and security generator radiator tubes  IP2 station blackout/fire protection diesel generator (SBO/Appendix R DG):
 
SBO/Appendix R DG exhaust gas piping, piping components, and piping
 
elements; SBO/Appendix R diesel engine turbocharger and aftercooler
 
housing, including external surfaces of the tubes and fins; and SBO/Appendix R
 
jacket water heat exchanger bonnet and tubes  IP3 fire protection diesel generator (Appendix R DG):  Appendix R DG exhaust
 
gas piping, piping components, and piping elements; Appendix R DG radiator;
 
Appendix R DG aftercooler; Appendix R starting air piping, piping components, and piping elements; and Appendix R DG crankcase exhaust subsystem
 
piping, piping components and piping elements fuel oil system:  SBO/Appendix R diesel fuel oil cooler, and the diesel fuel oil
 
trailer transfer tank and associated valves  auxiliary feedwater system:  piping, piping components, and piping elements
 
containment cooling and filtration system:  containment cooling duct flexible
 
connections; and containment cooling fan units, including damper housings, filter housings, moisture separators, and heat exchanger headers, housings, and tubes  control room HVAC:  condensers and evaporators; control room HVAC ducts
 
and drip pans; and duct flexible connections  IP2 non-safety system affecting safety systems (NSAS):  piping, piping
 
components, and piping elements in the circulating water system (including
 
flexible elastomer piping), city water system, intake structure, EDG system, fresh water cooling water system, instrument air system, integrated liquid waste
 
handling system, lube oil system, radiation monitoring system, river water
 
service system, station air system, waste disposal system, wash water system, water treatment plant, and other miscellaneous NSAS piping systems  IP3 NSAS:  piping, piping components, and piping elements in the chlorination
 
system, circulating water system (including flexible elastomer piping), EDG
 
system, floor drain system, gaseous waste disposal system, instrument air
 
system, liquid waste disposal system, nuclear equipment drain system, river
 
water system, station air system, steam generator sampling system, and
 
secondary plant sampling system  IP2 and IP3 pressurizer relief tanks  main steam safety valve tailpipes  atmospheric dump valve silencers  IP2 138 kV underground transmission cable for the offsite power feeder 3-199 main condenser tube internal surfaces  instrument air aftercooler tube internal surfaces  fresh water/river water heat exchanger internal and external surfaces Based on this verification, the staff finds that the applicants scope of program element, as amended in the applicants letter of December 18, 2007, August 14, 2008, January
 
27, 2009, June 12, 2009, and June 30, 2009, is acceptable because: (1) the amended
 
basis clarifies which plant systems and components at IP2 and IP3 are within the scope
 
of the Periodic Surveillance and Preventive Maintenance Program, and (2) the systems
 
and components listed in the amended basis conform to the recommendation in SRP-LR
 
Section A.1.2.3.1 that systems and components within the scope of an AMP should be
 
identified in the scope of program program element for the AMP.
The staff concludes that RAI 3.0.3.3.7-1, Part 1 is resolved and Open Item 3.0.3.3.7-1, Part 1 is closed with respect to identifying the systems and components that are within
 
the scope of the Periodic Surveillance and Preventive Maintenance Program.
Based on this review, the staff confirmed that the scope of the program program element satisfies the guidance in SRP-LR Section A.1.2.3.1. (2) Preventive Actions - LRA Section B.1.29 states that inspection and testing activities used to identify component aging effects do not prevent aging effects. However, activities are intended to prevent failures of components that might be caused by aging
 
effects.The staff reviewed this program element against the criteria in SRP-LR Section A.1.2.3.2.
The staff noted that the applicant has identified the Periodic Surveillance and Preventive Maintenance Program as a both an existing condition monitoring program and an
 
existing performance monitoring program, and that the program does not include any
 
aging management activities to prevent or mitigate the effects of aging that are
 
applicable to the components within the scope of the AMP. Based on this review, the
 
staff concludes that the applicant has provided an acceptable basis for concluding that
 
the criterion in SRP-LR A.1.2.3.2 is not applicable to the Periodic Surveillance and
 
Preventive Maintenance Program because the program is not a preventive or mitigative-
 
based AMP and does not include any activities that are designed to prevent or mitigate
 
the effects of aging.
The staff confirms that the preventive actions program element satisfies the guidance in SRP-LR Section A.1.2.3.2. (3) Parameters Monitored or Inspected - LRA Section B.1.29 states that this program provides instructions for monitoring structures, systems, and components to detect
 
degradation. Inspection and testing activities monitor various parameters including
 
system temperatures, wall thickness, surface condition, and signs of cracking.
The staff reviewed this program element against the criteria in SRP-LR Section A.1.2.3.3.
3-200 The staff noted that SRP-LR Section A.1.2.3.3 recommends that parameters monitored or inspected program element for AMPs is made to accomplish two objectives: (1)
 
identify the aging effect(s) (degradation types) that the program manages, and (2)
 
provide a link between the parameters that the program monitors for and the aging
 
effect(s) the program is credited to manage. The staff noted that in the parameters
 
monitored or inspected program element for the AMP, the applicant only mentioned
 
system temperatures, wall thickness, surface condition, and signs of cracking as
 
examples of the parameters that the program monitors for. The staff noted that, in the
 
program description for the AMP, the applicant listed the following four (4) aging effects
 
that the program monitors for: (1) cracking, (2) loss of material, (3) fouling, and (4)
 
changes in material properties for elastomeric or polymeric (including rubber) materials.
 
The staff noted, however, that, with the exception of cracking, the applicant did not
 
identify the aging effects that are within the scope of the AMP and that AMP monitors or
 
inspects for and that the applicant also did not specifically identify and link the specific
 
parameters that the program monitors or inspects for to each of the aging effects that
 
are within the scope of the program.
To address these issues, the staff issued RAI 3.0.3.3.7-1, Part 2. In this RAI, the staff asked to applicant to clarify which aging effects are managed by the Periodic
 
Surveillance and Preventive Maintenance Program, which parameters are indicative of
 
these aging effects and would be monitored for as part of the applicants implementation
 
of the program, and which inspection techniques would be used to detect the
 
parameters that are indicative of the applicable aging effects. This was identified as
 
Open Item 3.0.3.3.7-1, Part 2. By letter dated January 27, 2009, the applicant responded to RAI 3.0.3.3.7-1, Part 2. In this letter, the applicant included an aging effect monitoring table that: (1) identifies the
 
particular aging effects that are managed by the Periodic Surveillance and Preventive
 
Maintenance Program, (2) provides the aging mechanisms that could induce each of
 
particular aging effects requiring management under the program, (3) provides the
 
parameters that would be indicative of the particular aging effects that will be managed
 
and monitored for under the AMP, and (4) provides the inspection techniques that would
 
be used to detect the parameters that the applicant is monitoring for.
3-201 The table below summarizes the information provided in the applicants aging effect monitoring table. Parameters Monitored and Inspection Methods for Specific Aging Effects and Mechanisms Aging Effect By Aging MechanismParameter Monitored Inspection Method  Crevice Corrosion Surface condition or wall thickness Visual (VT-1 or equivalent) or or Volumetric (RT or UT)Galvanic Corrosion Surface condition or wall thickness Visual (VT-3 or equivalent) or Volumetric (RT or UT) General Corrosion Surface condition or wall thickness Visual (VT-3 or equivalent) or Volumetric (RT or UT)
Microbiologically
 
Influenced Corrosion (MIC)Surface condition or wall thickness Visual (VT-3 or equivalent) or Volumetric (RT or UT) Pitting Corrosion Surface condition or wall thickness Visual (VT-1 or equivalent) or Volumetric (RT or UT)
Loss of MaterialErosion Surface condition or wall thickness Visual (VT-3 or equivalent) or Volumetric (RT or UT) Cracking SCC or cyclical loadingCracks Enhanced Visual (VT-1 or equivalent) or Volumetric (RT or UT)
Cracking in
 
elastomeric
 
component s Cracks Visual (VT-3 or equivalent)
Changes in material properties
 
of elastomeric
 
component s Hardening or Cracks Visual (VT-3 or equivalent)
The staff found the clarifications and information provided in the aging effect monitoring table were acceptable, with certain exceptions, because the information was in
 
conformance with the similar aging-effect-parameter combinations recommended for aging management in GALL AMP XI.M32, One-Time Inspection. The exceptions in the
 
applicants aging effect monitoring table that needed further clarification are discussed
 
and evaluated below.
The staff noted that in the applicants letter of December 18, 2007, the applicant identified fouling as an aging mechanism and monitoring parameter that could be used
 
to provide indication of a loss of material or loss of heat transfer capability in heat
 
exchanger tubes or cooling coil fins that are within the scope of this AMP. The
 
identification of fouling as an aging mechanism which can lead to a loss of material or a loss of heat transfer capability is consistent with GALL Report Table IX.F. Because the
 
applicants position is consistent with the recommendation in the GALL Report, the staff
 
finds this acceptable.
The staff also noted that the aging effect monitoring table in the applicants response to RAI 3.0.3.3.7-1, Part 2, indicated that elastomeric flexible connections would be 3-202 monitored to detect cracking. The staff finds this to be acceptable because cracks in solid materials are extrinsic thermodynamic properties that can be directly monitored by
 
inspection. The applicant also clarified that monitoring of cracks and the hardness of
 
elastomeric components would be monitored for indications of any changes that might
 
occur in the material properties of the elastomers during the period of extended
 
operation. The staff finds this to be acceptable because the presence of a crack in the
 
elastomeric material may provide an indirect indication on whether the material is
 
undergoing embrittlement or is losing its elastic properties over time. In addition, the
 
monitoring of hardness by flexible manipulation of the materials will be capable of
 
demonstrating whether the elastomeric materials are degrading. Thus, the staff
 
concludes that the applicant has established an acceptable basis for the parameters that
 
will be used to monitor for cracking and/or changes of the material properties of
 
elastomeric components.
Based on its review, the staff confirmed that the parameters monitored or inspected program element satisfies the recommendations in the GALL Report and the guidance in
 
SRP-LR Section A.1.2.3.3. The staff concludes that RAI 3.0.3.3.7-1, Part 2 is resolved, and Open Item 3.0.3.3.7-1, Part 2 with respect to the acceptability of the parameters
 
monitoring or inspected program element for this AMP is closed. (4) Detection of Aging Effects - LRA Section B.1.29 states that:
Preventive maintenance activities provide for inspections to detect aging effects. Periodic surveillances provide for testing to detect aging effects.
 
Inspection and testing intervals are established such that they provide
 
timely detection of degradation. Inspection and testing intervals are
 
dependent on component material and environment and take into
 
consideration industry and plant-specific operating experience and
 
manufacturers' recommendations. Each inspection or test occurs at least
 
once every five years with the exception of the following. Components associated with emergency and Appendix R diesel
 
generators are inspected every six years in accordance with
 
manufacturer recommendations. Appendix R diesel generator crankcase exhauster inspection is
 
every ten years in accordance with manufacturer
 
recommendations. Copper alloy components exposed to city water are inspected
 
every ten years since city water is treated per New York State
 
requirements and aging effects are not expected. The internals of each pressurizer relief tank are inspected every
 
ten years since the tank is coated.
The extent and schedule of inspections and testing assure detection of component degradation prior to loss of intended functions. Established
 
techniques such as visual inspections or NDE are used. In cases where a
 
representative sample is inspected by this program, the sample size will
 
be based on Chapter 4 of EPRI document 107514, Age Related
 
Degradation Inspection Method and Demonstration, which outlines a 3-203 method to determine the number of inspections required for 90 percent confidence that 90 percent of the population does not experience
 
degradation (90/90). Each group of components with the same material-
 
environment combination is considered a separate population. The
 
program provides for increasing inspection sample size in the event that
 
aging effects are detected. Unacceptable inspection findings are
 
evaluated in accordance with the IPNG corrective action process to
 
determine the need for accelerated inspection frequency and for
 
monitoring and trending the results.
The staff compared this program element against the criteria in SRP-LR Section A.1.2.3.4.
The staff noted that the applicants detection of aging effects program element did identify that either visual examinations or NDE would be performed on the specific system components that are within the scope of the AMP at any inspection interval of at
 
least once every five years with the following exceptions:  Appendix R fire protection diesel generators: passive components inspected at
 
least once every 6 years in accordance with manufacturer recommendations, with the exception of the crank case exhaust piping components once every 10
 
years in accordance with manufacture recommendations. Copper components exposed to city water once every 10 years  Pressurizer relief tank internal surfaces once every 10 years The staff also noted that the applicant appeared to be crediting visual examinations, in part, to manage cracking but did not specify that the visual techniques would be VT-1, enhanced VT-1, VT-2 or VT-3 techniques. The ASME Code, Section XI, an NRC
 
endorsed document in 10 CFR 50.55a, indicates that only volumetric inspection
 
techniques (such as UT or RT) are capable of detecting a crack throughout the volume
 
of a component and that only VT-1 or enhanced VT-1 visual examination techniques or
 
surface examination techniques (such as PT or MT) are capable of detecting surface
 
penetrating cracks. Thus, the staff needed additional information on the inspection
 
techniques that would be credited under this AMP to detect cracking in the components
 
that are within the scope of the Periodic Surveillance and Preventive Maintenance
 
Program and for which cracking is identified as an applicable aging effect requiring
 
management.
The staff noted that, for the majority of the elastomeric or polymeric components within the scope of the AMP, the applicant credited both visual examinations and manual
 
flexing of the components to manage changes in material properties of these
 
elastomeric or polymeric components. The staff noted that material properties are intrinsic thermodynamic properties that cannot be monitored by direct visual or NDE
 
inspection methods, and that changes in material properties (such as loss of fracture
 
toughness, hardening, or increases or reductions in strength) are more appropriately
 
managed through appropriate material property analyses (including destructive
 
analyses) or though performance of physical tests (such as flexing, etc.) that could
 
provide some indication of whether the material properties for the components were
 
changing. Thus, the staff sought clarification on: (1) how a visual examination method 3-204 would be capable of indicating a change in the material properties of the elastomeric or polymeric components that are within the scope of the AMP, and (2) why flexing had not
 
been credited for managing changes in these material properties for the flexible trunks
 
used in the circulating water system and in the elastomeric flexible connections that are
 
located in the intake portion of the EDG duct.
To address these issues, the staff issued RAI 3.0.3.3.7-1, Part 2. In this RAI, the staff asked the applicant to clarify which aging effects are managed by the Periodic Surveillance and Preventive Maintenance Program, which parameters are indicative of these aging effects and would be monitored as part of the applicants implementation of
 
the program, and which inspection techniques would be used to detect the parameters
 
that are indicative of the applicable aging effects. This was identified as Open
 
Item 3.0.3.3.7-1, Part 2.
The applicant responded to RAI 3.0.3.3.7-1, Part 2, in a letter dated January 27, 2009. In this letter, in order to demonstrate conformance with the recommendations for
 
parameters monitored or inspected program elements in SRP-LR Section A.1.2.3.3, the applicant included an aging effect monitoring table that: (1) identifies the particular
 
aging effects that are managed by the Periodic Surveillance and Preventive
 
Maintenance Program, (2) provides the aging mechanisms that could induce each of
 
particular aging effects requiring management under the program, (3) provides the
 
parameters that would be indicative of the particular aging effects that will be managed
 
and monitored for under the AMP, and (4) provides the inspection techniques that would
 
be used to detect the parameters that the applicant is monitoring. The table above
 
summarizes the information provided in the applicants aging effect monitoring table. The
 
staff noted that in the applicants aging effect monitoring table, it identified that the
 
following inspection techniques would be used as condition monitoring methods for this
 
AMP.(1)  VT-3 or equivalent visual techniques, or UT or radiographic techniques (i.e., volumetric methods), will be used to manage loss of material due to general
 
corrosion, galvanic corrosion, MIC, or erosion. The staff finds this to be acceptable because: (1) AMSE Code Section XI, paragraph IWA-2213 lists VT-3
 
visual examination methods as acceptable method for detecting surface
 
discontinuities or imperfections that may result from mechanisms such as corrosion or erosion, and (2) ASME Code, Section XI, paragraphs IWA-2231 and
 
IWA-2232 list UT and RT methods as acceptable volumetric inspection methods
 
that are capable of detecting any discontinuities that may occur throughout the
 
material and thickness of a component.(2) VT-1 or equivalent visual techniques, or UT or radiographic techniques (i.e., volumetric methods), will be used to manage loss of material by pitting corrosion
 
or crevice corrosion. The staff finds this to be acceptable because: (1) AMSE Code Section XI, paragraph IWA-2213 list VT-1 visual examination methods as
 
acceptable visual examination techniques for detecting surface discontinuities or
 
imperfections cracks, wear, corrosion or erosion, and (2) ASME Code, Section XI, paragraphs IWA-2231 and IWA-2232 list UT and RT methods as acceptable
 
volumetric inspection methods that are capable of detecting any discontinuities
 
that may occur throughout the material and thickness of a component, 3-205(3) VT-1 or equivalent visual techniques, or volumetric methods (e.g., UT or RT), will be used to manage cracking in metallic components. The staff finds this to be acceptable because: (1) AMSE Code Section XI, paragraph IWA-2213 lists VT-1
 
visual examination methods as acceptable visual examination techniques for
 
detecting surface discontinuities or imperfections, cracks, wear, corrosion or erosion and (2) ASME Code, Section XI, paragraphs IWA-2231 and IWA-2232
 
list UT and RT methods as acceptable volumetric inspection methods that are
 
capable of detecting any discontinuities that may occur throughout the material
 
and thickness of a component, (4)  VT-3 or equivalent visual techniques, coupled with physical manipulations, will be used to manage cracking in elastomer components. The staff finds this to be
 
acceptable because flexing of the components will capable of distorting (opening
 
up) surfaces such that surface breaking cracks in the materials will be capable of
 
being detected as a surface discontinuity, and because the flexible manipulations
 
will be capable of determining whether the elastomeric materials are losing their
 
elastic properties or are hardening or embrittling over time.
Based on this review, the staff finds that the applicants detection of aging effects program element, as supplemented with information in the applicants letter of
 
January 27, 2009, is acceptable because the applicant has proposed valid inspection or
 
functional testing to manage the effects of aging for the components within the scope of
 
this AMP. Additionally, the applicants program element meets the recommendation in
 
SRP-LR Section A.1.2.3.4 to identify the methods that will be used to monitor the effects
 
of aging and the parameters that are indicative of the aging effects.
The staff concludes that RAI 3.0.3.3.7-1, Part 2 is resolved and Open Item 3.0.3.3.7-1, Part 2 is closed with respect to identify the inspection methods that will be used to
 
monitor for the effects of aging under this AMP. (5) Monitoring and Trending - LRA Section B.1.29 states that preventive maintenance and surveillance testing activities provide for monitoring and trending of aging degradation.
The staff reviewed this program element against the criteria in SRP-LR Section A.1.2.3.5.
The staff noted that the applicants monitoring and trending program element discussion for the Periodic Surveillance and Preventive Maintenance Program only
 
mentioned that the activities within the scope of the AMP provided for adequate
 
monitoring and trending. The staff noted that the monitoring and trending program
 
element for the AMP did not provide any discussion on how the data from the
 
inspections performed under the detection of aging effects program element would be
 
collected, quantified, or evaluated against applicable acceptance criteria, and used to
 
make predictions related to degradation growth or to schedule re-inspections of the
 
components. Thus, the staff determined that the monitoring and trending program
 
element for the Periodic Surveillance and Preventive Maintenance Program would need
 
to be amended to specify how the data from the inspections performed under the
 
detection of aging effects program element would be collected, quantified, or evaluated
 
against applicable acceptance criteria, and used to make predictions related to
 
degradation growth or to schedule re-inspections of the components.
3-206 To address these issues, the staff issued RAI 3.0.3.3.7-1, Part 3. In this RAI, the staff asked the applicant to clarify how the inspection results and flexible manipulation data
 
for this AMP would be collected and quantified, or evaluated against appropriate
 
acceptance criteria, and how the trending results would be used to make predictions
 
relative to degradation growth or to schedule re-inspections or repairs of the components
 
that are managed by this AMP. This was identified as Open Item 3.0.3.3.7-1, Part 3. The applicant responded to RAI 3.0.3.3.7.1-1, Part 3 in a letter dated January 27, 2009.
In this response, the applicant stated that the initial periodicity of inspections and manual
 
flexing is based on vendor recommendations, industry guidance, input from other
 
Entergy nuclear sites, and IP specific operating experience
, and that the results of these inspections and manual flexing are collected as part of the work control process. The
 
applicant also clarified that any indications or relevant conditions of degradation are
 
reported and submitted for evaluation under the corrective action program and that the
 
evaluation is performed against criteria which ensure that the structure or component
 
intended function(s) are maintained under all current licensing basis design conditions
 
during the period of extended operation. The applicant stated that the results of these
 
inspections and manual flexing are trended by an assigned "responsible engineer," and
 
that, if a potential need for a change in scope or frequency of inspections is indicated
 
based on identified patterns of degradation, a preventive maintenance change request is
 
processed. The staff finds this to be acceptable because it is in conformance with the
 
quality assurance requirements in the applicants quality assurance program for
 
monitoring of conditions adverse to quality and for taking appropriate corrective actions
 
for conditions that are unacceptable for further service. Based on this response, the staff finds that the applicants monitoring and trending program element, as supplemented with the information in the applicants response to
 
RAI 3.0.3.3.7-1, Part 3, is acceptable because the applicant has clarified how the
 
inspection results and results of physical manipulation flexing tests for elastomeric
 
components will be collected and trended consistent with the recommendations in SRP-
 
LR Section A.1.2.3.5.
The staff confirmed that the monitoring and trending program element satisfies the guidance in SRP-LR Section A.1.2.3.5. The staff finds this program element acceptable.
 
RAI 3.0.3.3.7-1, Part 3 is resolved and Open Item 3.0.3.3.7-1, Part 3 is closed.  (6) Acceptance Criteria - LRA Section B.1.29 states that the Periodic Surveillance and Preventive Maintenance Program acceptance criteria are defined in specific inspection
 
and testing procedures. Acceptance criteria include appropriate temperature, no
 
significant wear, corrosion, cracking, change in material properties (for elastomers), and
 
significant fouling based on applicable intended functions established by plant design
 
basis.The staff reviewed this program element against the criteria in SRP-LR Section A.1.2.3.6.
The staff noted that the applicants acceptance criteria program element for the Periodic Surveillance and Preventive Maintenance Program only made a general
 
statement as to what the acceptance criteria are and did not establish specific 3-207 acceptance criteria for each of the aging effects that are applicable to the components within the scope of the AMP. The staff also noted that the applicant had indicated that
 
the acceptance criteria program element would be enhanced, in part, to specific what
 
these acceptance criteria are. The staff sought clarification as to why establishment of
 
the acceptance criteria for this AMP could be deferred through the applicants
 
enhancement of the program, as stated in LRA Commitment No. 21. Therefore, in RAI
 
3.0.3.3.7-1, Part 4, the staff asked the applicant to define what the acceptance criteria
 
are for each of the aging effects that are managed under the scope of the AMP. This
 
was identified as Open Item 3.0.3.3.7-4.
The applicant responded to RAI 3.0.3.3.7.1-1, Part 4 in a letter dated January 27, 2009.
In this response, the applicant stated that any indications or relevant conditions of
 
degradation are reported and submitted for further evaluation as part of the corrective
 
action program and that these evaluations are performed against specific acceptance
 
criteria which ensure that the structure or component intended function(s) will be
 
maintained under all current licensing basis design conditions during the period of
 
extended operation. The applicant clarified that these acceptance criteria include no
 
unacceptable wear, corrosion, cracking, change in material properties (for elastomers),
or significant fouling, and that the specific quantitative or qualitative criteria (i.e., limits)
 
on acceptability are contained in manufacturer information or vendor manuals for some
 
individual components. The applicant clarified that an engineering review process is
 
used to establish the acceptance criteria for those situations where appropriate
 
manufacturer data are unavailable. The staff noted that this is consistent with the
 
following guidance in SRP-LR Section A.1.2.3.6:
Acceptance criteria could be specific numerical values, or could consist of a discussion of the process for calculating specific numerical values of conditional
 
acceptance criteria to ensure that the structure and component intended function(s)
 
will be maintained under all CLB design conditions.
Based on its review, the staff finds that the applicant acceptance criteria program element, as supplemented by information in the applicants response to RAI 3.0.3.3.7-1, Part 4, is acceptable because the applicant has clarified what the acceptance criteria are
 
for the aging effects within the scope of this AMP.
The staff concludes that RAI 3.0.3.3.7-1, Part 4 is resolved and Open Item 3.0.3.3.7-1, Part 4 is closed. (10) Operating Experience - LRA Section B.1.29, as amended by letter dated June 30, 2009, states that typical inspection results of this program include:  IP2 reactor building polar crane (May 2006): no indication of corrosion, cracking, or wear in the crane structural members. IP3 reactor building polar crane (February 2001 and March 2005): no indication
 
of corrosion, cracking, or wear in the crane structural members. IP2 and IP3 recirculation pumps and related system components (2005 and
 
2006): no deficiencies. IP2 diesel generator building floor drain backwater valves (October 2006): no 3-208 loss of material. IP2 and IP3 EDGs (2005 and 2006): no unacceptable loss of material. Security generator (January 2002 and December 2005): no significant corrosion or wear. IP3 Appendix R diesel generator (September 2006 and December 2006): no
 
significant corrosion or wear.
The applicant stated that use of proven monitoring techniques and acceptance criteria assures continued program effectiveness in managing aging effects for passive
 
components.
SRP-LR Section A.1.2.3.10 establishes the following recommendations for discussion of operating experience for existing AMPs:
Operating experience with existing programs should be discussed. The operating experience of aging management programs, including past
 
corrective actions resulting in program enhancements or additional
 
programs, should be considered. A past failure would not necessarily
 
invalidate an aging management program because the feedback from
 
operating experience should have resulted in appropriate program
 
enhancements or new programs. This information can show where an
 
existing program has succeeded and where it has failed (if at all) in
 
intercepting aging degradation in a timely manner. This information
 
should provide objective evidence to support the conclusion that the
 
effects of aging will be managed adequately so that the structure and
 
component intended function(s) will be maintained during the period of
 
extended operation.
The staff noted that the applicant had indicated that the program was already implementing inspections on the IP2 and IP3 reactor building polar cranes, IP2 and IP3
 
recirculation pumps and related system components, IP2 diesel generator building floor
 
drain backwater valves, IP2 and IP3 emergency diesel generators (EDGs), the security
 
generator, and the IP3 Appendix R fire protection diesel generator. The staff noted that
 
of the inspections performed, the applicants indicated that there were no indications of
 
aging only for the inspections that were performed on polar cranes, and on the IP2
 
diesel generator building floor drain backwater valves. The staff noted that, for the aging
 
statements on the inspections that were performed on the other components, the
 
statements were ambiguous in that the applicant did not distinguish whether aging had
 
been detected but that the amount of aging was determined to be acceptable when
 
compared to the acceptance criteria for the aging effect or whether the inspections did
 
not identify the presence of aging effects in the components being inspected. Thus, the
 
staff needed additional information on the following aging statements that were made in
 
the operating experience program element discussion for the AMP: 1. Inspection statement for the IP3 NaOH tank - requesting clarification on the statement no deficiencies. Ultrasonic measurement of wall thickness was
 
satisfactory and in particular whether loss of material had been detected in the
 
component even though the amount of loss material was found to be acceptable.
3-2092. Inspection statement for the IP2 and IP3 recirculation pumps and related system components - requesting clarification on the statement no deficiencies and in
 
particular whether this means that no aging effects had been detected, or that
 
some specific aging (e.g., cracking, loss of material, etc.) l had been detected in
 
the component even though the amount of aging was found to be acceptable. 3. Inspection statements for the IP2 and IP3 EDGs, the security diesel generator, and the IP3 Appendix R fire protection diesel generator  - requesting clarification
 
on the statements no unacceptable loss of material and no significant
 
corrosion or wear and in particular whether this means that no loss of material
 
by corrosion, erosion or wear (or other mechanisms) was detecting or that some
 
loss of material was detected in the components even though the amount of loss
 
of material was found to be acceptable.
The staff sought clarification on whether any aging effects had been detected in these components as a result of the past periodic surveillance and Preventive maintenance
 
inspections that had been performed on these components, and if so, identification of
 
what the appropriate corrective actions were for dispositioning these components in
 
order to ensure that the program is implementing its appropriate corrective actions
 
program element criteria. In RAI 3.0.3.3.7.1-1, Part 5, the staff asked the applicant to
 
clarify the meaning of its references to no unacceptable degradation. This was identified
 
as Open Item 3.0.3.3.7-1, Part 5.
The applicant responded to RAI 3.0.3.3.7-1, Part 5 in a letter dated January 27, 2009. A portion of this response was amended by letter dated June 30, 2009, due to a plant modification which eliminated the sodium hydroxide (liquid injection) from the
 
containment spray system. In its response, the applicant clarified that the inspections of
 
the IP2 and IP3 recirculation pumps, IP2 and IP3 EDGs, the security generator, and the
 
IP3 Appendix R fire protection diesel generator found no evidence of loss of material.
 
The staff finds that the applicants response to RAI 3.0.3.3.7-1, Part 5 resolves the staffs
 
issue with the operating experience discussion because it clarifies that the inspections of
 
these components confirmed that there was no loss of material occurring in the
 
components. Thus, the staff finds the applicants operating experience program
 
element, as modified by the information in the applicants response to RAI 3.0.3.3.7-1, Part 5, to be acceptable because the applicant has clarified that it has been performing
 
periodic condition monitoring of the subject components as part of the periodic
 
inspections that are implemented as part of this AMP. The staff concludes that RAI
 
3.0.3.3.7-1, Part 5 is resolved and Open Item 3.0.3.3.7-1, Part 5 is closed. The staff
 
notes that the applicants operating experience discussion for this AMP, as
 
supplemented in the applicants response to RAI 3.0.3.3.7-1, Part 5, meets the
 
recommendation in SRP-LR Section A.1.2.3.10 because the applicant adequately
 
summarized the periodic inspections that the applicant had performed under this AMP
 
over the last 5 years of plant operation and had summarized the results of the
 
inspections, demonstrating there had not been any age-related degradation in the
 
components that were inspected under this AMP.
Based on this review, the staff finds that the applicants operating experience program element, as supplemented by the applicants response to RAI 3.0.3.3.7-1, Part 5, is
 
acceptable because it meets the recommendation in SRP-LR Section A.1.2.3.10 to 3-210 discuss the relevant operating experience for the components that have been inspected through the implementation of an existing AMP.
The staff confirmed that the operating experience program element satisfies the guidance in SRP-LR Section A.1.2.3.10. The staff finds this program element
 
acceptable.
UFSAR Supplement. In LRA Sections A.2.1.28 and A.3.1.28, the applicant provided the UFSAR supplement for the Periodic Surveillance and Preventive Maintenance Program. The staff
 
reviewed these sections and finds the UFSAR supplement information is an adequate summary
 
description of the program, as required by 10 CFR 54.21(d). The staff notes that the UFSAR
 
Supplement summary description provided an acceptable summary listing of the components
 
and activities that are within scope of this AMP. The staff also notes that, in this UFSAR
 
Supplement, the applicant included LRA Commitment 21, in which the applicant committed to
 
enhance the scope of program, parameters monitored or inspected, detection of aging
 
effects, and acceptance criteria program elements of the AMP as follows:  Program activity
 
guidance documents will be developed or revised as necessary to assure that the effects of
 
aging will be managed such that applicable components will continue to perform their intended
 
functions consistent with the current licensing basis through the period of extended operation.
Based on this review, the staff finds that the applicant has provided an acceptable UFSAR Supplement summary description for this AMP because: (1) the summary description
 
appropriately summarizes the components and activities that are within the scope of the AMP, (2) the applicant has clearly defined what the program elements are for this AMP, and has
 
provided its bases on why these program elements are in conformance with the
 
recommendations of SRP-LR Section A.1.2.3, and (3) in LRA Commitment No. 21, the applicant
 
has committed to enhance the program to develop activity documents to reflect the program
 
elements for this AMP. The staff concludes that RAI 3.0.3.3.7-1, Parts 1, 2, 3, ,4 and 5 are
 
resolved and Open Item 3.0.3.3.7-1, Parts 1, 2, 3, 4, and 5 are closed with respect to the
 
acceptability of the UFSAR Supplement summary description for this AMP.
Conclusion. On the basis of its review of the applicants Periodic Surveillance and Preventive Maintenance Program, 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 program and
 
concludes that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.3.8  Water Chemistry Control - Auxiliary Systems Program
 
Summary of Technical Information in the Application. LRA Section B.1.39 and Amendment 1 to the LRA, Attachment 1, describe the existing Water Chemistry Control - Auxiliary Systems
 
Program as a plant-specific program.
The Water Chemistry Control - Auxiliary Systems Program manages loss of material and cracking for components exposed to treated water by sampling and analysis to minimize
 
component exposure to aggressive environments for the stator cooling water systems. The
 
One-Time Inspection Program for Water Chemistry utilizes inspections or nondestructive
 
evaluations of representative samples to verify whether the Water Chemistry Control - Auxiliary 3-211 Systems Program has been effective in managing aging effects.
Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.1.39 on the applicants demonstration of the Water Chemistry Control - Auxiliary
 
Systems Program to ensure that the effects of aging, as discussed above, will be adequately
 
managed so that the intended functions will be maintained consistent with the CLB for the
 
period of extended operation.
The staff reviewed the Water Chemistry Control - Auxiliary Systems Program against the AMP elements found in the GALL Report, in SRP-LR 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 elements ((1) scope of the program, (2) preventive actions, (3) parameters monitored or
 
inspected, (4) detection of aging effects, (5) monitoring and trending, (6) acceptance
 
criteria, (7) corrective actions, (8) confirmation process, (9) administrative controls, and
 
(10) operating experience).
In Audit Item 90, the staff asked the applicant to describe past and present surveillance tests, sampling, and analysis activities for managing the effects of aging on components within the
 
scope of this AMP. By letter dated December 18, 2007, the applicant stated that since thickness
 
measurements are performed every five years under the Periodic Surveillance and Preventive
 
Maintenance Program, use of the Water Chemistry Control - Auxiliary Systems Program for the
 
NaOH tank is not required. By letter dated December 18, 2007 the applicant amended the LRA
 
to remove the Water Chemistry Control - Auxiliary Systems Program as an aging management
 
program for the NaOH tank. By letter dated June 30, 2009, the applicant amended the LRA due
 
to a plant modification which eliminated the NaOH tank and piping and fittings from the
 
containment spray system.
The applicant indicated that program elements (7) corrective actions, (8) confirmation process, and (9) administrative controls are parts of the site-controlled QA program. The
 
staffs evaluation of the QA program is in SER Section 3.0.4. Evaluation of the remaining seven
 
elements follows: (1) Scope of the Program - LRA Section B.1.39, as amended, states that program activities include sampling and analysis of the stator cooling water system to minimize component
 
exposure to aggressive environments.
The staff reviewed the program basis document and determined that it adequately describes the specific system and components in the scope of this program for which
 
aging will be managed. The staff reviewed the system and determined that it uses
 
treated water as the cooling medium. Since this program manages aging by monitoring
 
and analyzing the coolant, the stator cooling water systems are appropriate for inclusion
 
in the scope of this program.
The staff confirmed that the scope of the program program element satisfies the guidance in SRP-LR Section A.1.2.3.1. The staff finds this program element acceptable. (2) Preventive Actions - LRA Section B.1.39 states that the program includes monitoring and control of treated water for components included in the scope of the program to
 
minimize exposure to aggressive environments, thereby mitigating the effects of aging.
3-212 The staff determined that the program includes monitoring and control of water chemistry to minimize component exposure to aggressive water environments. The
 
aging effects managed by this program are loss of material, fouling, and cracking, which
 
are directly related to the purity and aggressiveness of the water to which the
 
components are exposed. Therefore, monitoring and controlling the water chemistry is
 
an effective means of managing loss of material for the components in the scope of this
 
program. The staff finds these preventive actions to be appropriate to manage the aging
 
effects for which this program is credited.
The staff confirmed that the preventive actions program element satisfies the guidance in SRP-LR Section A.1.2.3.2. The staff finds this program element acceptable. (3) Parameters Monitored or Inspected - LRA Section B.1.39, as amended, states that treated water is monitored to mitigate degradation through control of impurities. Stator
 
cooling water is monitored for copper and conductivity monthly.
The staff noted that this program is credited to manage loss of material, fouling, and cracking for components exposed to treated water. These aging effects are directly
 
related to the purity and aggressiveness of the water, which are based on the
 
conductivity, pH, and dissolved oxygen in the water. Therefore, monitoring these
 
parameters is an effective means of assessing the purity and aggressiveness of the
 
water, and determining whether corrective actions are needed to modify the water
 
chemistry. On this basis, the staff finds these parameters acceptable for this program.
In Audit Item 91, the staff asked the applicant to describe the procedures used to perform surveillance activities and the basis for acceptance criteria and sample
/ test frequencies. By letter dated December 18, 2007, the applicant stated that the stator
 
cooling water systems are high purity systems in which poor oxygen control can cause
 
an increase in copper corrosion products. Based on this experience, stator cooling water
 
is monitored monthly for conductivity and copper. The staff determined that the
 
applicants basis for selection of parameters is acceptable since it considers vendor
 
specifications, industry standards, and operating experience.
The staff confirmed that the parameters monitored or inspected program element satisfies the guidance in SRP-LR Section A.1.2.3.3. The staff finds this program element
 
acceptable.(4) Detection of Aging Effects - LRA Section B.1.39 states that the program manages loss of material and cracking for stainless steel, carbon steel, and copper alloy components
 
included in the scope of the program. This is a mitigation program and does not provide
 
for detection of aging effects. However, the One-Time Inspection Program describes
 
inspections planned to verify the effectiveness of water chemistry control programs to
 
ensure that significant degradation has not occurred and component intended function is
 
maintained during the period of extended operation.
The staff determined that this program includes monitoring and control of water chemistry to manage loss of material, fouling, and cracking of auxiliary system
 
components. These aging effects are directly related to the purity and aggressiveness of
 
the water; therefore, monitoring these parameters will provide an effective means of
 
mitigating aging. The monitoring frequencies will provide for timely detection of adverse 3-213 water chemistry such that corrective actions can be taken prior to a loss of component intended function. The staff finds these activities appropriate for managing the aging
 
effects for which this program is credited since they will provide reasonable assurance
 
that the component intended function will be maintained for the extended period of
 
operation.
The staff confirmed that the detection of aging effects program element satisfies the guidance in SRP-LR Section A.1.2.3.4. The staff finds this program element acceptable.    (5) Monitoring and Trending - LRA Section B.1.39 states that initially, analytical results are interpreted by the chemist performing the analysis. Abnormal trends in the chemistry
 
data are evaluated by that person given the status of that system at that time. Any
 
significant abnormality or trend, as well as out of specification or out of control band
 
chemistry parameter is brought to the attention of the Shift Manager and Chemistry
 
Management. Values from analyses are archived for long-term trending and review.
 
Trending is not required to predict the extent of degradation since maintaining
 
parameters within acceptance criteria prevents degradation. Operating experience
 
indicates effectiveness in preventing aging effects if parameters are maintained within
 
limits.The staff reviewed the applicants program implementing procedures and determined that appropriate administrative controls and program activities are in place to monitor
 
and trend chemistry parameters to identify aging effects and take corrective actions prior
 
to the loss of a component intended function. The staff finds that the applicants use of
 
site chemistry staff reviews and quarterly group data review sessions is an effective
 
means of monitoring water chemistry parameters.
The staff confirmed that the monitoring and trending program element satisfies the guidance in SRP-LR Section A.1.2.3.5. The staff finds this program element acceptable. (6) Acceptance Criteria - LRA Section B.1.39, as amended, states the following acceptance criteria for stator cooling water systems: ParameterAcceptance CriteriaConductivity < 0.5 mhos/cmCopper < 20 ppb The staff confirmed that the acceptance criteria program element satisfies the guidance in SRP-LR Section A.1.2.3.6. The staff finds this program element acceptable.    (10) Operating Experience - LRA Section B.1.39 states that the QA audits of the chemistry control program in 2005 and 2006 found compliance with all guidelines (INPO 03-004, EPRI TR-105714, and TR-102134) for chemistry performance satisfactory with sufficient
 
parameters measured to detect abnormal conditions or condition changes. The audits found all chemistry parameters maintained within specified bands and auxiliary systems treated and controlled to industry guidelines. Adherence to chemistry specifications
 
assures continued program effectiveness in managing the effects of aging.
In Audit Item 90, the staff asked the applicant about past and present surveillance tests, sampling and analysis activities for managing the effects of aging on components within 3-214 the scope of this AMP. By letter dated December 18, 2007, the applicant stated that recent monthly tests of stator cooling water samples have been within the specification.
 
The applicant further stated that monthly stator cooling water analysis will continue per
 
the requirements of the applicants procedure.
The staff reviewed the operating experience provided in the LRA, and the applicants operating experience review results report, and determined that there were no aging
 
effects identified that are not bounded by industry operating experience. Recent
 
operating experience indicated that all chemistry parameters have been maintained
 
within specified bands and auxiliary systems treated and controlled to industry
 
guidelines. This operating experience provides objective evidence that this program is
 
effective in detecting and managing aging effects in the auxiliary cooling water systems.
The staff confirmed that the operating experience program element satisfies the guidance in SRP-LR Section A.1.2.3.10. The staff finds this program element acceptable.
UFSAR Supplement. In LRA Sections A.2.1.38 and A.3.1.38, the applicant provided the UFSAR supplement for the Water Chemistry Control - Auxiliary Systems Program. In Amendment 1, dated December 18, 2007, the applicant revised the second paragraphs of Sections A.2.1.38
 
and A.3.1.38 as follows:
Program activities include sampling and analysis to minimize component exposure to aggressive environments for stator cooling water systems.
The staff reviewed these sections and finds the UFSAR supplement information 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 applicants Water Chemistry Control - Auxiliary Systems Program, the staff concludes that the applicant has demonstrated that effects of aging
 
will be adequately managed so that the intended functions will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this program and concludes that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.4  QA Program Attributes Integral to Aging Management Programs 3.0.4.1  Summary of Technical Information in the Application In Sections A.2.1, A Aging Management Program and Activities,@ and B.0.3, A Corrective Actions, Confirmation Process and Administrative Controls,@ of the LRA, the applicant described the elements of corrective action, confirmation process, and administrative controls that are applied to the AMPs for both safety-related and nonsafety-related components. The Entergy Quality
 
Assurance Program (EQAP) 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 EQAP regardless of the safety
 
classification of the components. LRA Sections A.2.1 and B.0.3, stated that the EQAP
 
implements the requirements of 10 CFR 50, Appendix B, and is consistent with the GALL
 
Report.
3-215 3.0.4.2  S taff Evaluation Pursuant to 10 CFR 54.21(a)(3), the applicant is required to demonstrate that the effects of aging on SCs subject to an AMR will be adequately managed so that their intended functions
 
will be maintained consistent with the CLB for the period of extended operation. SRP-LR, BTP RLSB-1, Aging Management Review - Generic, describes ten elements of an acceptable
 
AMP. Elements (7), (8), and (9) are associated with the QA activities of corrective actions,
 
confirmation process, and administrative controls. BTP RLSB-1 Table A.1-1, Elements of an
 
Aging Management Program for License Renewal, provides the following description of these
 
program elements:    (7) Corrective Actions - Corrective actions, including root cause determination and prevention of recurrence, should be timely.    (8) Confirmation Process - The confirmation process should ensure that preventive actions are adequate and that appropriate corrective actions are completed and effective.    (9) Administrative Controls - Administrative controls should provide for a formal review and approval process.
SRP-LR BTP IQMB-1, Quality Assurance for Aging Management Programs, notes that AMP aspects that affect the quality of safety-related SSCs are subject to the QA requirements of
 
10 CFR Part 50 Appendix B. Additionally, for nonsafety-related SCs subject to an AMR, the
 
applicant may use the existing 10 CFR Part 50 Appendix B QA program to address the
 
elements of corrective actions, confirmation process, and administrative controls.
 
BTP IQMB-1 provides the following guidance on the QA attributes of AMPs: 1. Safety-related structures and components are subject to 10 CFR Part 50 Appendix B requirements, which are adequate to address all quality-
 
related aspects of an aging management program consistent with the
 
CLB of the facility for the period of extended operation. 2. For nonsafety-related structures and components that are subject to an AMR for license renewal, an applicant has an option to expand the scope
 
of its 10 CFR Part 50 Appendix B program to include these structures and
 
components to address corrective actions, the confirmation process, and
 
administrative controls for aging management during the period of
 
extended operation. The reviewer should verify that the applicant has
 
documented such a commitment in the FSAR 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 Updated Final Safety Analysis Report Supplement,@ and Appendix B, A Aging Management Programs and Activities,@ of the LRA, and the associated implementing documents. The purpose of this review was to ensure that the quality assurance attributes (corrective action, confirmation process, and administrative controls) are consistent with the
 
staff=s guidance described in SRP-LR BTP RLSB-1 and BTP IQMPB-1. In addition, the staff reviewed the enhancements for the corrective actions program element as specified in LRA Sections B.1.16 and B.1.26, and determined that the enhancements did not affect the
 
applicants application of the EQAP. Based on the NRC staff
=s evaluation, the descriptions of the AMPs and their associated quality attributes provided in Appendix A, Section A.2.1, and 3-216 Appendix B, Section B.0.3, of the LRA were determined to be 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 descriptions and applicability of the plant-specific AMPs and their associated quality attributes provided in Appendix A, Section A.2.1, and Appendix B, Section B.0.3 of the LRA, the quality assurance elements corrective actions,
 
confirmation process, and administrative controls, as applied to the applicants programs
 
were determined to be consistent with the staff
=s position regarding QA for aging management.
The staff concludes that the QA attributes corrective action, confirmation process, and administrative control, of the applicant's programs 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 staffs review of the applicants AMR results for the
 
reactor vessel, internals, and reactor coolant system components and component groups of:  reactor vessel  reactor vessel internals  reactor coolant system and pressurizer  steam generator 3.1.1  Summary of Technical Information in the Application LRA Section 3.1 provides AMR results for the reactor vessel, reactor vessel internals, and reactor coolant system components and component groups. LRA Table 3.1.1, Summary of
 
Aging Management Programs for the Reactor Coolant System Evaluated in Chapter IV of
 
NUREG-1801, is a summary comparison of the applicants AMRs with those evaluated in the
 
GALL Report for the reactor vessel, reactor vessel internals, and reactor coolant system
 
components and component groups.
The applicants AMRs evaluated and incorporated applicable plant-specific and industry operating experience in the determination of AERMs. The plant-specific evaluation included
 
condition reports and discussions with appropriate site personnel to identify AERMs. The
 
applicants review of industry operating experience included a review of the GALL Report and
 
operating experience issues identified since the issuance of the GALL Report.
 
====3.1.2 Staff====
Evaluation The staff reviewed LRA Section 3.1 to determine whether the applicant provided sufficient information to demonstrate that the effects of aging for the reactor vessel, reactor vessel
 
internals, and reactor coolant system components within the scope of license renewal and
 
subject to an AMR, will be adequately managed so that the intended 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 conducted an onsite audit of AMRs to ensure the applicants claim that certain AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters 3-217 described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The
 
staffs evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staffs audit
 
evaluation are documented in SER Section 3.1.2.1.
In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicants further evaluations
 
were consistent with the SRP-LR Section 3.1.2.2 acceptance criteria. The staffs audit
 
evaluations are documented in SER Section 3.1.2.2.
The staff also conducted a technical review of the remaining AMRs not consistent with or not addressed in the GALL Report. The technical review evaluated whether all plausible aging
 
effects have been identified and whether the aging effects listed were appropriate for the
 
material-environment combinations specified. The staffs evaluations are documented in SER
 
Section 3.1.2.3.
For components which the applicant claimed were not applicable or required no aging management, the staff reviewed the AMR line items and the plants operating experience to
 
verify the applicants claims.
Table 3.1-1 summarizes the staffs 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 andReactor Coolant System Components in the GALL Report Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff 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 See SER Section 3.1.2.2.1 Steel; stainless steel; steel with nickel alloy or stainless steel cladding; nickel alloy
 
reactor vessel components: flanges; nozzles; penetrations; safe ends; thermal sleeves; vessel
 
shells, heads and welds (3.1.1-2)Cumulative fatigue damage TLAA, evaluated in accordance with
 
10 CFR 54.21(c) and environmental effects are to be addressed
 
for Class 1 componentsYes Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.2.1) 3-218 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff Evaluation Steel; stainless steel; steel with nickel alloy or stainless steel cladding; nickel alloy
 
reactor coolant pressure boundary piping, piping
 
components, and piping elements exposed to reactor
 
coolant (3.1.1-3)Cumulative fatigue damage TLAA, evaluated in accordance with
 
10 CFR 54.21(c) and
 
environmental effects are to be addressed
 
for Class 1 componentsYes Not applicable Not applicable to PWRs (see SER Section 3.1.2.2.1)
Steel pump and
 
valve closure bolting (3.1.1-4)Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) check Code limits for allowable cycles (less than 7000 cycles) of thermal stress range Yes Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.2.1)
Stainless steel and nickel alloy reactor vessel internals components
 
(3.1.1-5)Cumulative fatigue damage TLAA, evaluated in accordance with
 
10 CFR 54.21(c) Yes TLAA Consistent with GALL Report (see
 
SER Section 3.1.2.2.1)Nickel Alloy tubes and sleeves in a reactor coolant and secondary feedwater/steam
 
environment (3.1.1-6)Cumulative fatigue damage TLAA, evaluated in accordance with
 
10 CFR 54.21(c) Yes TLAA Consistent with GALL Report (see
 
SER Section 3.1.2.2.1)
Steel and stainless steel reactor coolant pressure boundary closure bolting, head
 
closure studs, support skirts and attachment welds, pressurizer relief tank components, SG components, piping and
 
components external surfaces and bolting (3.1.1-7)Cumulative fatigue damage TLAA, evaluated in accordance with
 
10 CFR 54.21(c) Yes TLAA Consistent with GALL Report (see
 
SER Section 3.1.2.2.1) 3-219 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff Evaluation Steel; stainless steel; and nickel alloy reactor coolant pressure boundary
 
piping, piping
 
components, piping elements; flanges;
 
nozzles and safe ends; pressurizer vessel shell heads and welds; heater sheaths and sleeves; penetrations; and thermal sleeves
 
(3.1.1-8)Cumulative fatigue damage TLAA, evaluated in accordance with
 
10 CFR 54.21(c) and
 
environmental effects are to be addressed for Class 1
 
componentsYes TLAA Consistent with GALL Report (see
 
SER Section 3.1.2.2.1)
Steel; stainless steel; steel with nickel alloy or stainless steel cladding; nickel alloy
 
reactor vessel
 
components: flanges; nozzles;penetrations;
 
pressure housings; safe ends; thermal sleeves; vessel
 
shells, heads and welds (3.1.1-9)Cumulative fatigue damage TLAA, evaluated in accordance with
 
10 CFR 54.21(c) and
 
environmental effects are to be addressed for Class 1
 
componentsYes TLAA Consistent with GALL Report (see SER Section
 
3.1.2.2.1)
Steel; stainless steel; steel with nickel alloy or stainless steel cladding; nickel alloy
 
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
 
componentsYes TLAA Consistent with GALL Report (see SER Section
 
3.1.2.2.1)
Steel top head enclosure (without cladding) top head nozzles (vent, top head spray or RCIC, and spare) exposed to reactor coolant
 
(3.1.1-11)
Loss of material due to general, pitting, and crevice corrosionWater Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.2.2) 3-220 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff Evaluation Steel steam generator shell assembly exposed to secondary feedwater
 
and steam
 
(3.1.1-12)
Loss of material due to general, pitting, and crevice corrosionWater Chemistry and One-Time InspectionYes Water Chemistry Control - Primary and Secondary One-Time InspectionConsistent with GALL Report (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 corrosionWater Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.2.2(2))
Stainless steel, nickel alloy, and steel with nickel alloy or
 
stainless steel
 
cladding reactor
 
vessel flanges, nozzles, penetrations, safe
 
ends, vessel shells, heads and welds (3.1.1-14)
Loss of material due to pitting
 
and crevice corrosionWater Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.2.2(3))
Stainless steel; steel with nickel alloy or stainless steel cladding; and nickel alloy reactor coolant pressure boundary components exposed
 
to reactor coolant
 
(3.1.1-15)
Loss of material due to pitting
 
and crevice corrosionWater Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.2.2(3))
Steel steam generator upper and lower shell and transition cone
 
exposed to secondary feedwater and steam
 
(3.1.1-16)
Loss of material due to general, pitting, and crevice corrosion Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry and, for Westinghouse Model 44 and 51 S/G, if general
 
and pitting corrosion of the shell is known to exist, additional inspection
 
procedures are to be developed.
Yes Inservice Inspection and Water Chemistry Control - Primary and Secondary Consistent with GALL Report (see SER Section
 
3.1.2.2.2(4))
3-221 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff EvaluationSteel (with or without stainless steel cladding) reactor vessel beltline shell, nozzles, and welds
 
(3.1.1-17)
Loss of fracture toughness due
 
to neutron irradiation embrittlementTLAA, evaluated in accordance with
 
10 CFR 50, Appendix G, and RG 1.99. The applicant may
 
choose to demonstrate that the materials of the
 
nozzles are not controlling for the TLAA evaluations. Yes TLAA Consistent with GALL Report (see
 
SER Section 3.1.2.2.3(1))Steel (with or without
 
stainless steel cladding) reactor vessel beltline shell, nozzles, and welds; safety injection nozzles (3.1.1-18)
Loss of fracture toughness due
 
to neutron irradiation embrittlement Reactor Vessel SurveillanceYes Reactor Vessel SurveillanceConsistent with GALL Report (see
 
SER Section 3.1.2.2.3(2))
Stainless steel and nickel alloy top head enclosure vessel flange leak detection
 
line (3.1.1-19)
Cracking due to stress corrosion
 
cracking (SCC) and intergranular
 
stress corrosion cracking (IGSCC)A plant-specific aging management
 
program is to be evaluated.Yes Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.2.4(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 Not applicable to PWRs (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 loadingTLAA Yes Not applicable Not applicable (see SER Section
 
3.1.2.2.5) 3-222 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff Evaluation Stainless steel and nickel alloy reactor vessel internals components exposed
 
to reactor coolant
 
and neutron flux (3.1.1-22)
Loss of fracture toughness due
 
to neutron irradiation embrittlement, void swelling FSAR supplement commitment to
 
(1) participate in industry RVI aging programs (2) implement applicable results (3) submit for NRC approval > 24
 
months before the extended period an RVI inspection plan based on industry
 
recommendation.
No, but licensee commitment
 
needs to be confirmed Committed to Reactor Vessel Internals Inspection plan
 
being developed by the industry Consistent with GALL Report (see
 
SER Section 3.1.2.2.6)
Stainless steel reactor vessel closure head flange leak detection line
 
and bottom-mounted
 
instrument guide tubes (3.1.1-23)
Cracking due to SCC A plant-specific aging management
 
program is to be evaluated.
Yes Inservice Inspection and Water Chemistry Control - Primary and Secondary Consistent with GALL Report (see
 
SER Section
 
3.1.2.2.7(1))
Class 1 cast
 
austenitic stainless steel piping, piping components, and
 
piping elements exposed to reactor coolant (3.1.1-24)
Cracking due to SCCWater Chemistry and, for CASS
 
components that do not meet the NUREG-0313
 
guidelines, a plant-specific AMP Yes Water Chemistry Control - Primary and Secondary and Thermal Embrittlement of
 
Cast Austenitic
 
Stainless Steel (CASS)supplemented by
 
the Inservice Inspection ProgramConsistent with GALL Report (see SER Section
 
3.1.2.2.7(2))
Stainless steel jet
 
pump sensing line (3.1.1-25)
Cracking due to cyclic loading A plant-specific aging management program is to be evaluated.Yes Not applicable Not applicable to PWRs (see SER Section 3.1.2.2.8(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 Not applicable to PWRs (see SER
 
Section 3.1.2.2.8(2))
3-223 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff Evaluation Stainless steel and nickel alloy reactor vessel internals screws, bolts, tie rods, and hold-down
 
springs (3.1.1-27)
Loss of preload due to stress
 
relaxation FSAR supplement commitment to
 
(1) participate in industry RVI aging programs (2) implement applicable results (3) submit for NRC
 
approval > 24
 
months before the extended period an
 
RVI inspection plan based on industry recommendation.
No, but licensee commitment needs to be confirmed Committed to Reactor Vessel Internals Inspection plan
 
being developed by the industry Consistent with GALL Report (see SER Section 3.1.2.2.9)
Steel steam generator feedwater impingement plate and support exposed to secondary feedwater (3.1.1-28)
Loss of material due to erosion A plant-specific aging management
 
program is to be evaluated.Yes None Not applicable (see SER Section
 
3.1.2.2.10)
Stainless steel steam dryers exposed to reactor coolant (3.1.1-29)
Cracking due to flow-induced vibration A plant-specific aging management
 
program is to be evaluated.Yes Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.2.11)
Stainless steel
 
reactor vessel internals components (e.g., Upper internals assembly, RCCA
 
guide tube assemblies, Baffle/former assembly, Lower internal assembly, shroud assemblies, Plenum cover and plenum cylinder, Upper grid assembly, Control rod guide tube (CRGT) assembly, Core
 
support shield assembly, Core barrel assembly, Lower grid assembly, Flow distributor assembly, Thermal
: shield, Instrumentation
 
support structures)
 
(3.1.1-30)
Cracking due to SCC, irradiation-assisted SCC Water Chemistry and FSAR supplement commitment to (1) participate in industry RVI aging programs (2) implement
 
applicable results
 
(3) submit for NRC approval less than 24 months before the
 
extended period an RVI inspection plan based on industry
 
recommendation.
No, but licensee commitment
 
needs to be confirmedWater Chemistry Control - Primary and Secondary Committed to Reactor Vessel Internals Inspection plan
 
being developed by the industry Consistent with GALL Report (see SER Section
 
3.1.2.2.12) 3-224 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff EvaluationNickel alloy and steel with nickel alloy cladding piping, piping component, piping elements, penetrations, nozzles, safe ends, and welds (other than reactor vessel head); pressurizer
 
heater sheaths, sleeves, diaphragm plate, manways and flanges; core support
 
pads/core guide lugs
 
(3.1.1-31)
Cracking due to primary water
 
stress corrosion
 
cracking (PWSCC)Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry and FSAR supplement commitment to
 
implement applicable plant commitments to (1) NRC Orders, Bulletins, and
 
Generic Letters associated with nickel alloys and
 
(2) staff-accepted industry guidelines.
No, but licensee commitment needs to be
 
confirmed Inservice Inspection, Water Chemistry Control
- Primary and Secondary, and Nickel Alloy InspectionPrograms (with
 
commitment)Consistent with GALL Report (see
 
SER Section
 
3.1.2.2.13)
Steel steam generator feedwater inlet ring and supports (3.1.1-32)
Wall thinning due to flow-accelerated corrosion A plant-specific aging management
 
program is to be evaluated.Yes Steam Generator Integrity Consistent with GALL Report (see
 
SER Section 3.1.2.2.14)
Stainless steel and nickel alloy reactor vessel internals components
 
(3.1.1-33)
Changes in dimensions due to void swelling FSAR supplement commitment to
 
(1) participate in industry RVI aging programs (2) implement applicable results (3) submit for NRC
 
approval less than 24 months before the extended period an
 
RVI inspection plan based on industry recommendation.
No, but licensee commitment
 
needs to be confirmed Committed to Reactor Vessel Internals Inspection plan
 
being developed by the industry Consistent with GALL Report (see SER Section 3.1.2.2.15)
Stainless steel and nickel alloy reactor control rod drive head penetration
 
pressure housings (3.1.1-34)
Cracking due to SCC and PWSCC Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry and for nickel alloy, comply with applicable NRC Orders and provide a
 
commitment in the FSAR supplement to implement applicable
 
(1) Bulletins and
 
Generic Letters and (2) staff-accepted industry guidelines.
No, but licensee commitment
 
needs to be confirmed Inservice Inspection, Water Chemistry Control
- Primary and Secondary, and Reactor Vessel Head Penetration Inspection (with commitment)Consistent with GALL Report (see SER Section 3.1.2.2.16(1))
3-225 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff EvaluationSteel 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 PWSCC Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry and for nickel alloy, comply with applicable NRC Orders and provide a commitment in the
 
FSAR supplement to implement applicable (1) Bulletins and
 
Generic Letters and
 
(2) staff-accepted industry guidelines.
No, but licensee commitment needs to be
 
confirmed Inservice Inspection and Water Chemistry Control - Primary and Secondary for carbon steel with stainless steel
 
clad.Water Chemistry Control - Primary and Secondary and Steam Generator Integrity for carbon steel with Nickel alloy clad (with commitment).Consistent with GALL Report (see
 
SER Section
 
3.1.2.2.16(1))Nickel alloy, stainless
 
steel pressurizer spray head (3.1.1-36)
Cracking due to SCC and PWSCCWater Chemistry and One-Time Inspection and, for nickel alloy welded spray heads, comply with
 
applicable NRC Orders and provide a commitment in the
 
FSAR supplement to implement applicable (1) Bulletins and
 
Generic Letters and
 
(2) staff-accepted industry guidelines.
No, but licensee commitment
 
needs to be confirmedNot used Not applicable (see SER Section 3.1.2.2.16(2))
Stainless steel and nickel alloy reactor vessel internals components (e.g., Upper internals assembly, RCCA guide tube assemblies, Lower internal assembly, CEA shroud assemblies, Core shroud assembly, Core support shield assembly, Core barrel assembly, Lower grid assembly, Flow distributor assembly)
 
(3.1.1-37)
Cracking due to SCC, PWSCC, irradiation-
 
assisted SCC Water Chemistry and FSAR supplement commitment to
 
(1) participate in industry RVI aging programs (2) implement applicable results (3) submit for NRC
 
approval > 24
 
months before the extended period an RVI inspection plan based on industry recommendation.
No, but licensee commitment needs to be
 
confirmedWater Chemistry Control - Primary and Secondary and committed to Reactor Vessel
 
Internals Inspection plan being developed by the industry Consistent with GALL Report (see
 
SER Section
 
3.1.2.2.17) 3-226 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff EvaluationSteel (with or without stainless steel cladding) control rod drive return line
 
nozzles exposed to
 
reactor coolant (3.1.1-38)
Cracking due to cyclic loading BWR Control Rod Drive Return Line
 
NozzleNo Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.1.1) Steel (with or without
 
stainless steel cladding) feedwater nozzles exposed to
 
reactor coolant (3.1.1-39)
Cracking due to cyclic loading BWR Feedwater NozzleNo Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.1.1)
Stainless steel and nickel alloy penetrations for control rod drive stub
 
tubes instrumentation, jet pump instrumentation, standby liquid control, flux monitor, and drain line
 
exposed to reactor coolant (3.1.1-40)
Cracking due to SCC, IGSCC, cyclic loading BWR Penetrations and Water ChemistryNo Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.1.1)
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 Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.1.1)
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 Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.1.1)
Stainless steel fuel
 
supports and control rod drive assemblies control rod drive
 
housing exposed to reactor coolant (3.1.1-43)
Cracking due to SCC and IGSCC BWR Vessel Internals and Water Chemistry No Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.1.1) 3-227 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff Evaluation Stainless steel and nickel alloy core shroud, core plate, core plate bolts, support structure, top guide, core spray lines, spargers, jet
 
pump assemblies, control rod drive housing, nuclear
 
instrumentation guide tubes (3.1.1-44)
Cracking due to SCC, IGSCC, irradiation-
 
assisted SCC BWR Vessel Internals and Water Chemistry No Not applicable Not applicable to PWRs (see SER Section 3.1.2.1.1)
Steel piping, piping
 
components, and piping elements exposed to reactor
 
coolant (3.1.1-45)
Wall thinning due to flow-
 
accelerated corrosionFlow-Accelerated CorrosionNo Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.1.1) Nickel alloy core
 
shroud and core plate access hole cover (mechanical
 
covers)(3.1.1-46)
Cracking due to SCC, IGSCC, irradiation-assisted SCC Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry No Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.1.1)
Stainless steel and nickel alloy reactor vessel internals exposed to reactor
 
coolant (3.1.1-47)
Loss of material due to pitting
 
and crevice corrosion Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry No Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.1.1)
Steel and stainless
 
steel Class 1 piping, fittings and branch connections less
 
than 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 Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.1.1) 3-228 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff EvaluationNickel alloy core shroud and core plate access hole cover (welded
 
covers)
(3.1.1-49)
Cracking due to SCC, IGSCC, irradiation-assisted SCC Inservice Inspection (IWB, IWC, and IWD), Water Chemistry, and, for BWRs with a
 
crevice in the access
 
hole covers, augmentedinspection using UT
 
or other demonstrated
 
acceptable inspection of the access hole cover welds No Not applicable Not applicable to PWRs (see SER Section 3.1.2.1.1) High-strength low alloy steel top head closure studs and nuts exposed to air with reactor coolant
 
leakage (3.1.1-50)
Cracking due to SCC and IGSCC Reactor Head Closure Studs No Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.1.1)
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
 
embrittlementThermal Aging and Neutron Irradiation
 
Embrittlement of CASSNo Not applicable Not applicable to PWRs (see SER
 
Section 3.1.2.1.1)
Steel and stainless
 
steel reactor coolant pressure boundary (RCPB) pump and
 
valve closure bolting, manway and holding bolting, flange
 
bolting, and closure
 
bolting in high-pressure and high-temperature systems
 
(3.1.1-52)
Cracking due to SCC, loss of
 
material due to wear, loss of preload due to
 
thermal effects, gasket creep, and self-looseningBolting Integrity No Bolting Integrity Consistent with GALL Report (see SER Section
 
3.1.2.1.2)
Steel piping, piping
 
components, and piping elements exposed to closed cycle cooling water (3.1.1-53)
Loss of material due to general, pitting, and crevice corrosionClosed-Cycle Cooling Water System No Water Chemistry Control - Closed
 
Cooling Water Consistent with GALL Report 3-229 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff EvaluationCopper 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 corrosionClosed-Cycle Cooling Water System No Not applicable Not applicable (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 greater than 250&deg;C (less than 482&deg;F)(3.1.1-55)
Loss of fracture toughness due
 
to thermal aging embrittlement Inservice Inspection (IWB, IWC, and IWD).
Thermal aging susceptibility
 
screening is not necessary, inservice inspection requirements are
 
sufficient for managing these aging effects. ASME
 
Code Case N-481 also provides an alternative for pump
 
casings.No Inservice InspectionConsistent with GALL Report Copper alloy greater
 
than 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 MaterialsNo Not applicable Not applicable (see SER Section
 
3.1.2.1.1)
Cast austenitic
 
stainless steel Class 1 piping, piping component, and
 
piping elements and control rod drive pressure housings
 
exposed to reactor
 
coolant greater than 250&deg;C (less than 482&deg;F)(3.1.1-57)
Loss of fracture toughness due to thermal aging embrittlementThermal Aging Embrittlement of CASSNo Thermal Aging Embrittlement of
 
Cast Austenitic Stainless Steel (CASS)Consistent with GALL Report Steel reactor coolant pressure boundary external surfaces exposed to air with borated water leakage (3.1.1-58)
Loss of material due to boric acid
 
corrosionBoric Acid Corrosion No Boric Acid Corrosion PreventionConsistent with GALL Report 3-230 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff Evaluation Steel steam generator steam nozzle and safe end, feedwater nozzle and
 
safe end, AFW
 
nozzles and safe ends exposed to secondary feedwater/steam (3.1.1-59)
Wall thinning due to flow-
 
accelerated corrosionFlow-Accelerated CorrosionNo Flow-Accelerated CorrosionConsistent with GALL Report (see
 
SER Section
 
3.1.2.1.5)
Stainless steel flux thimble tubes (with or without chrome plating)
(3.1.1-60)
Loss of material due to wear Flux Thimble Tube InspectionNo Flux Thimble Tube InspectionConsistent with GALL Report Stainless steel, steel
 
pressurizer integral support exposed to air with metal
 
temperature up to 288&deg;C (550&deg;F)(3.1.1-61)
Cracking due to cyclic loading Inservice Inspection (IWB, IWC, and IWD)
No Inservice InspectionConsistent with GALL Report 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 Inservice InspectionConsistent with GALL Report (see
 
SER Section 3.1.2.1.3)
Steel reactor vessel flange, stainless steel and nickel alloy reactor vessel
 
internals exposed to reactor coolant (e.g., upper and lower internals assembly, CEA shroud assembly, core support barrel, upper grid assembly, core support shield assembly, lower grid assembly)
(3.1.1-63)
Loss of material due to wear Inservice Inspection (IWB, IWC, and IWD)
No Inservice InspectionConsistent with GALL Report 3-231 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff Evaluation Stainless steel and steel with stainless steel or nickel alloy cladding pressurizer
 
components
 
(3.1.1-64)
Cracking due to SCC, PWSCC Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry No Inservice Inspection and Water Chemistry Control - Primary and Secondary (for steel with stainless steel or nickel alloy clad)Consistent with GALL Report (see
 
SER Section
 
3.1.2.1.3)Nickel alloy reactor
 
vessel upper head
 
and control rod drive
 
penetration nozzles, instrument tubes, head vent pipe (top head), and welds
 
(3.1.1-65)
Cracking due to PWSCC Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry and Nickel-Alloy
 
Penetration Nozzles Welded to the Upper Reactor Vessel
 
Closure Heads of Pressurized Water Reactors No Inservice Inspection, Water Chemistry Control - Primary and Secondary, and Nickel Alloy
 
InspectionConsistent with GALL Report (see SER Section
 
3.1.2.1.3)
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 used See SER Section 3.1.2.1.6Steel 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 Inservice Inspection and Water Chemistry Control - Primary and Secondary Consistent with GALL Report (see
 
SER Section 3.1.2.1.3) 3-232 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff Evaluation 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 Inservice Inspection, Water Chemistry Control - Primary and Secondary, and One Time Inspection (for
 
non-ISI components)Consistent with GALL Report (see SER Section 3.1.2.1.3)
Stainless steel, nickel alloy safety injection nozzles, safe ends, and associated welds and buttering exposed to reactor coolant
 
(3.1.1-69)
Cracking due to SCC, PWSCC Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry No Inservice Inspection and Water Chemistry Control - Primary and Secondary (for
 
SS components only) Consistent with GALL Report (see
 
SER Section
 
3.1.2.1.3)
Stainless steel; steel with stainless steel cladding Class 1 piping, fittings and
 
branch connections less than 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 Inservice Inspection, Water Chemistry Control
- Primary and Secondary and One Time Inspection (small bore piping) Consistent with GALL Report High-strength low alloy steel closure head stud assembly exposed to air with
 
reactor coolant leakage (3.1.1-71)
Cracking due to SCC; loss of
 
material due to wear Reactor Head Closure Studs No Reactor Head Closure Studs Consistent with GALL Report Nickel alloy steam
 
generator tubes and sleeves exposed to secondary feedwater/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 Steam Generator Integrity and Water Chemistry Control
- Primary and Secondary Consistent with GALL Report 3-233 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff EvaluationNickel alloy steam generator tubes, repair sleeves, and tube plugs exposed
 
to reactor coolant
 
(3.1.1-73)
Cracking due to PWSCC Steam Generator Tube Integrity and Water Chemistry No Steam Generator Integrity and Water Chemistry Control - Primary and Secondary Consistent with GALL Report Chrome plated steel, stainless steel, nickel alloy steam generator anti-
 
vibration bars exposed to secondary feedwater/steam
 
(3.1.1-74)
Cracking due to SCC, loss of
 
material due to crevice corrosion and
 
fretting Steam Generator Tube Integrity and Water Chemistry No Steam Generator Integrity, Water Chemistry Control
- Primary and Secondary and One Time InspectionConsistent with GALL Report (see SER Sections 3.1.2.1.4,3.1.2.1.7, and 3.1.2.1.8) Nickel alloy once-
 
through steam generator tubes exposed to secondary feedwater/steam (3.1.1-75)
Denting due to corrosion of
 
carbon steel tube support plate Steam Generator Tube Integrity and Water Chemistry No Not applicable Not applicable (see SER Section
 
3.1.2.1.1)
Steel steam
 
generator tube support plate, tube bundle wrapper
 
exposed to secondary feedwater/steam
 
(3.1.1-76)
Loss of material due to erosion, general, pitting, and crevice corrosion, ligament cracking due to corrosion Steam Generator Tube Integrity and Water Chemistry No Steam Generator Integrity and Water Chemistry Control
- Primary and Secondary Consistent with GALL Report Nickel alloy steam generator tubes and sleeves exposed to phosphate chemistry in secondary feedwater/steam (3.1.1-77)
Loss of material due to wastage
 
and pitting corrosion Steam Generator Tube Integrity and Water Chemistry No Not applicable Not applicable (see SER Section
 
3.1.2.1.1)
Steel steam
 
generator tube support lattice bars exposed to secondary feedwater/steam (3.1.1-78)
Wall thinning due to flow-accelerated corrosion Steam Generator Tube Integrity and Water Chemistry No Not applicable Not applicable (see SER Section
 
3.1.2.1.1) 3-234 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff EvaluationNickel alloy steam generator tubes exposed to secondary feedwater/steam
 
(3.1.1-79)
Denting due to corrosion of
 
steel tube support plate Steam Generator Tube Integrity; Water Chemistry and, for plants that could experience denting
 
at the upper support
 
plates, evaluate potential for rapidly propagating cracks
 
and then develop and take corrective
 
actions consistent with NRC Bulletin 88-02.No Not applicable Not applicable (see SER Section
 
3.1.2.1.1)
Cast austenitic stainless steel reactor vessel internals (e.g., upper internals assembly, lower internal assembly, CEA shroud assemblies, control rod guide tube assembly, core support shield assembly, lower grid assembly)
(3.1.1-80)
Loss of fracture toughness due
 
to thermal aging
 
and neutron irradiation embrittlementThermal Aging and Neutron Irradiation Embrittlement of
 
CASSNo Thermal Aging and Neutron Irradiation Embrittlement of
 
Cast Austenitic Stainless Steel (CASS)Consistent with GALL Report Nickel alloy or nickel alloy clad steam generator divider plate exposed to
 
reactor coolant (3.1.1-81)
Cracking due to PWSCCWater Chemistry No Water Chemistry Control - Primary and Secondary Consistent with GALL Report Stainless steel steam generator primary side divider plate exposed to reactor
 
coolant (3.1.1-82)
Cracking due to SCCWater Chemistry No Not applicable Not applicable (see SER Section 3.1.2.1.1)
Stainless steel; steel with nickel alloy or stainless steel cladding; and nickel alloy reactor vessel internals and reactor coolant pressure boundary components exposed
 
to reactor coolant
 
(3.1.1-83)
Loss of material due to pitting
 
and crevice corrosionWater Chemistry No Water Chemistry Control - Primary and Secondary and Steam Generator Integrity (SG tubes) Consistent with GALL Report 3-235 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, or AmendmentsStaff EvaluationNickel alloy steam generator components such as, secondary side
 
nozzles (vent, drain, and instrumentation) exposed to secondary feedwater/steam (3.1.1-84)
Cracking due to SCCWater Chemistry and One-Time Inspection
 
or Inservice Inspection (IWB, IWC, and IWD). No Not applicable to IP2Water Chemistry Control - Primary and Secondary and One-Time Inspection, and
 
Steam Generator Integrity for IP3 Not applicable to IP2 (see SER Section 3.1.2.1.1) Consistent with GALL Report for IP3Nickel alloy piping, piping components, and piping elements exposed to air -
 
indoor uncontrolled (external)
(3.1.1-85)None None NA 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 NA None Consistent with GALL Report Steel piping, piping
 
components, and piping elements in concrete (3.1.1-87)None None NA Not applicable Not applicable (see SER Section
 
3.1.2.1.1)
The staffs review of the reactor vessel, reactor vessel internals, and reactor coolant system component groups followed any one of several approaches. In one approach, documented in
 
SER Section 3.1.2.1, the staff reviewed AMR results for components that the applicant indicated
 
are consistent with the GALL Report and require no further evaluation. In the second approach, documented in SER Section 3.1.2.2, the staff reviewed AMR results for components that the
 
applicant indicated are consistent with the GALL Report and for which further evaluation is
 
recommended. In the third approach, documented in SER Section 3.1.2.3, the staff reviewed
 
AMR results for components that the applicant indicated are not consistent with, or not
 
addressed in, the GALL Report. The staffs review of AMPs credited to manage or monitor aging
 
effects of the reactor vessel, reactor vessel internals, and reactor coolant system components is
 
documented in SER Section 3.0.3.
3-2363.1.2.1  AMR Results Consistent with the GALL Report LRA Section 3.1.2.1 identifies the materials, environments, AERMs, and the following programs that manage aging effects for the reactor vessel, reactor vessel internals, and reactor coolant
 
system components:  Bolting Integrity Program  Boric Acid Corrosion Prevention Program  External Surfaces Monitoring Program  Flux Thimble Tube Inspection Program  Inservice Inspection Program  Nickel Alloy Inspection Program  One-Time Inspection - Small Bore Piping Program  Reactor Head Closure Studs Program  Reactor Vessel Head Penetration Inspection Program  Reactor Vessel Surveillance Program  Steam Generator Integrity Program  Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program  Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel
 
Program Water Chemistry Control - Closed Cooling Water Program  Water Chemistry Control - Primary and Secondary Program LRA Tables 3.1.2-1-IP2 through 3.1.2-4-IP2 and 3.1.2-1-IP3 through 3.1.2-4-IP3 summarize the results of AMRs for the reactor vessel, reactor vessel internals, and reactor coolant system
 
components and indicate AMRs claimed to be consistent with the GALL Report.
For component groups evaluated in the GALL Report, for which the applicant claimed consistency with the report, where the report does not recommend further evaluation, the staffs
 
audit and review determined whether the plant-specific components of these GALL Report
 
component groups were bounded by the GALL Report evaluation.
For each AMR line item, the applicant stated how the information in the tables aligns with the information in the GALL Report. Notes A through E indicate how the AMR is consistent with the
 
GALL Report. The staff audited these AMRs.
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 3-237 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 applicants AMP was consistent with the
 
GALL Report AMP and whether the AMR was valid for the site-specific conditions.
Note C indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is
 
consistent with the GALL Report AMP. This note indicates that the applicant was unable to find
 
a listing of some system components in the GALL Report; however, the applicant identified in
 
the GALL Report a different component with the same material, environment, aging effect, and
 
AMP as the component under review. The staff audited these line items to verify consistency
 
with the GALL Report. The staff also determined whether the AMR line item of the different
 
component was applicable to the component under review and whether the AMR was valid for
 
the site-specific conditions.
Note D indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes
 
some exceptions to the GALL Report AMP. The staff audited these line items to verify
 
consistency with the GALL Report. The staff verified whether the AMR line item of the different
 
component was applicable to the component under review and whether the identified
 
exceptions to the GALL Report AMPs have been reviewed and accepted. The staff also
 
determined whether the applicants 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 reactor coolant system components that are subject
 
to an AMR.
In response to RAI B.1.15-1, by letter dated January 4, 2008, the applicant revised the LRA to include an AMR line item for carbon steel blowdown pipe connection (nozzle) with an internal
 
environment of treated water, an aging effect of loss of material, and Note C. The staff
 
reviewed the applicants revision and found that the AMR result is consistent with the GALL
 
Report for this combination of material, environment, and aging effect. On the basis of its
 
review, the staff finds that all applicable aging effects were identified, and the aging effect listed
 
is appropriate for the combination of material and environment identified.
3-238 On the basis of its audit and review, the staff determines that, for AMRs not requiring further evaluation, as identified in LRA Table 3.1.1, the applicants references to the GALL Report are
 
acceptable and no further staff review is required.
3.1.2.1.1  AMR Results Identified as Not Applicable
 
LRA Table 3.1.1, Line Items 38 - 51 discuss the applicants determination on GALL AMR line items that are applicable only to BWR-designed reactors. In the applicant AMR discussions for
 
these items, the applicant indicates that the AMR Line Items 38 - 51 in Table 1 of the GALL
 
Report, Volume 1 are not applicable to the IP2 and IP3 LRAs because IP2 and IP3 are
 
Westinghouse-designed PWRs. The staff verified that AMR Line Items 38 - 51 in Table 1 of the
 
GALL Report, Volume 1 are only applicable to BWR designed reactors, and that IP2 and IP3
 
are 4-Loop Westinghouse-design PWRs with dry ambient containments. Based on this
 
determination, the staff finds that the applicant has provided an acceptable basis for concluding
 
AMR Line Items 38 - 51 in Table 1 of the GALL Report, Volume 1 are not applicable to IP2 and
 
IP3.LRA Table 3.1.1, Line Item 54 addresses loss of material due to pitting, crevice, and galvanic corrosion of copper alloy piping, piping components, and piping elements exposed to closed
 
cycle cooling water. The GALL Report recommends the closed-cycle cooling water system AMP
 
to manage loss of material in these component groups. LRA Table 3.1.1, line item 56 addresses
 
loss of material due to selective leaching in copper alloy >15 percent zinc piping, piping
 
components, and piping elements exposed to closed cycle cooling water. The GALL Report
 
recommends selective leaching of materials AMP to manage loss of material in these
 
component groups. However, the LRA states that no copper alloy components exist in the Class
 
1 reactor vessel, vessel internals or reactor coolant pressure boundary and, therefore, these
 
line items are not applicable. The staff verified from LRA Section 3.1.2.1 that there are no
 
copper alloy components exposed to closed cycle cooling water at IP; therefore, the staff
 
agrees that this line item is not applicable.
LRA Table 3.1.1, Line Item 75 addresses denting due to corrosion of carbon steel tube support plate in nickel alloy once-through steam generator (SG) tubes exposed to secondary feedwater/
 
steam. The GALL Report recommends steam generator tube integrity and water chemistry
 
AMPs to manage denting in this component group. However, the LRA states that this line item
 
applies to once through SGs, but IP2 and IP3 use recirculating SGs and, therefore, this line item
 
is not applicable. The staff verified from LRA Section 2.3.1.4 that IP2 replaced its SGs in 2001
 
and IP3 replaced its SGs in 1989 with Westinghouse 44F recirculating models; therefore, the
 
staff agrees that this line item is not applicable.
LRA Table 3.1.1, Line Item 77 addresses loss of material due to wastage and pitting corrosion in nickel alloy steam generator tubes and sleeves exposed to phosphate chemistry in secondary
 
feedwater/ steam. The GALL Report recommends steam generator tube integrity and water
 
chemistry AMPs to manage loss of material in these component groups. However, the LRA
 
states that the IP SGs are not exposed to phosphate chemistry in secondary feedwater or
 
steam and, therefore, this line item is not applicable. The staff verified the water chemistry for
 
secondary water during the audit and determined that IP does not use phosphate chemistry in
 
its water chemistry control program for secondary water/steam. Therefore, the staff finds this
 
acceptable.
3-239 LRA Table 3.1.1, Line Item 78 addresses wall thinning due to flow-accelerated corrosion in steel steam generator tube support lattice bars exposed to secondary feedwater/ steam. The GALL
 
Report recommends steam generator tube integrity and water chemistry AMPs to manage wall
 
thinning in these component groups. However, the LRA states that IP SGs do not employ tube
 
support lattice bars and, therefore, this line item is not applicable. The staff verified from LRA
 
Table 3.1.2-4-IP2 and 3.1.2-4-IP3 that IP SGs employ stainless steel tube support plates
 
instead of lattice bar types support plates; therefore, the staff agrees that this line item is not
 
applicable.
LRA Table 3.1.1, Line Item 79 addresses denting due to corrosion of steel tube support plate in nickel alloy steam generator tubes exposed to secondary feedwater/ steam. The GALL Report
 
recommends steam generator tube integrity and water chemistry AMPs. For plants that could
 
experience denting at the upper support plates, the GALL Report recommends that the potential
 
for rapidly propagating cracks be evaluated, and for applicants to develop and take applicable
 
corrective actions consistent with staffs recommendations in NRC Bulletin 88-02. However, LRA states that IP SG tube support plates are made out of stainless steel and, therefore, this
 
line item is not applicable. The staff verified from LRA Tables 3.1.2-4-IP2 and 3.1.2-4-IP3 that IP
 
SGs employ stainless steel tube support plates instead of carbon steel support plates;
 
therefore, the staff agrees that this line item is not applicable.
LRA Table 3.1.1, Line Item 82 addresses cracking due to SCC in stainless steel steam generator primary side divider plate exposed to reactor coolant. The GALL Report recommends
 
water chemistry AMP to manage SCC in this component. However, the LRA states that the IP
 
SG divider plates are made out of nickel alloy and, therefore, this line item is not applicable. The
 
staff verified from LRA Tables 3.1.2-4-IP2 and 3.1.2-4-IP3 that the IP SGs employ nickel alloy
 
channel head divider plates; therefore, the staff agrees that this line item is not applicable.
LRA Table 3.1.1, Line Item 84 addresses cracking due to SCC in nickel alloy SG components such as, secondary side nozzles (vent, drain, and instrumentation) exposed to secondary
 
feedwater/ steam. The GALL Report recommends water chemistry and one time inspection or
 
inservice inspection AMPs to manage SCC in this component. However, LRA Table 3.1.2-4-IP2
 
does not contain a similar entry for the IP2 SGs. The staff questioned the applicant in Audit Item
 
210 regarding this dissimilarity. In its response, dated December 18, 2007, the applicant stated
 
that only IP3 has a nickel alloy RTD boss component; therefore, the staff finds this acceptable.
LRA Table 3.1.1, Line Item 87 addresses no aging effect in steel piping, piping components, and piping elements in concrete. The GALL Report recommends no aging management
 
programs since there is no aging effect applicable to these components when buried in
 
concrete. However, the LRA states that IP does not have components of the Class 1 reactor
 
vessel, vessel internals or reactor coolant pressure boundary exposed to concrete and, therefore, this line item is not applicable. The staff confirmed during an audit that IP does not
 
have any such components buried in concrete and, therefore, the staff finds this acceptable. 3.1.2.1.2Cracking Due to Stress Corrosion Cracking, Loss Of Material Due to Wear, and Loss of Preload Due to Thermal Effects, Gasket Creep, and Self-Loosening of Bolting LRA Table 3.1.1, Line Item 52 (LRA AMR 3.1.1-52) addresses cracking due to SCC, loss of material due to wear, and loss of preload due to thermal effects, gasket creep, and self-
 
loosening of steel and stainless steel reactor coolant pressure boundary (RCPB) pump and
 
valve closure bolting, manway and holding bolting, flange bolting, and closure bolting in high-3-240 pressure and high-temperature systems. The GALL Report recommends the bolting integrity AMP to manage these aging effects.
The GALL AMR that corresponds to LRA AMR 3.1.1-52 identifies that cracking due to SCC, loss of material due to wear, and loss of preload due to thermal effects, gasket creep, and self-
 
loosening are applicable aging effects requiring management for steel and stainless steel
 
reactor coolant pressure boundary (RCPB) pump and valve closure bolting, manway and
 
holding bolting, flange bolting, and closure bolting in high-pressure and high-temperature
 
systems. The staff noted that the LRA indicated that GALL item is not applicable to IP2 and IP3 because the applicant did not consider cracking due to SCC, loss of preload due to stress relaxation, or
 
loss of material due to wear to be applicable AERM for the bolts used in the RCS bolted
 
connections. In particular, the applicant indicated that cracking due to SCC is not an AERM for
 
these bolts because the RCS bolts that were purchased and used under the applicants QA
 
program were of low to moderate tensile strengths. The applicant also indicated that its AMR
 
process concluded that loss of material due to wear was not a significant aging effect and that
 
loss of preload is an event driven condition.
The staff also noted that, since LRA AMR 3.1.1-52 did not identify any AERMs for the ASME Code Class 1 bolting in the reactor vessel, or RCS piping or steam generator designs, Tables
 
3.1.2-1-IP2, 3.1.2-1-IP3, 3.1.2-3-IP2, and 3.1.2-3-IP3 do not identify any applicable aging effects
 
for the ASME Code Class 1 bolting used in RV and ASME Code Class 1 piping designs at IP2
 
and IP3.For bolting components, the staff in Table IX.E of the GALL Report, Volume 2 identifies cracking and loss of preload as applicable potential aging effects for license renewal applications. Table IX.F of the GALL Report, Volume 2, identifies that SCC is an applicable mechanism that may lead to cracking of metallic components. Table IX.F of the GALL Report, Volume 2, indicates
 
that wear is a mechanism that may lead to loss of material; that SCC is a mechanism that can
 
lead to cracking; and that stress relaxation and thermal effects, gasket creep, and self-loosening
 
are all potential aging mechanisms that may lead to loss of preload in bolted connections.
The staff did not accept the applicants position that there are not any AERMs for the RCS bolting components because the applicants position differed from the staffs recommendation in
 
GALL AMRs IV.A2-6, IV.A2-7, IV.A2-8, IV.C2-7, IV.C2-8, IV.D1-2, and IV.D1-10, and from the aging effect/aging effect criteria for bolted assembly components in Tables IX.E and IX.F of the
 
GALL Report, Volume 2. During an audit, the staff asked the applicant to clarify its position on
 
the aging management of Class 1 bolting within the RCS (Audit Item 201).
The applicant provided the following response in a letter dated December 18, 2007, and amended LRA AMR 3.1.1-52 as follows:
Not applicable.
High strength low alloy steel is not used for these bolting applications at IPEC.
Applied stress For stainless steel closure bolting appl ications should be much less than 100 ksi. Consequently, cracking of bolting due to stress corrosion cracking is not an aging mechanism requiring management. Industry operating
 
experience indicates that loss of material due to wear is not a significant aging
 
effect for this bolting. Occasional thread failures due to wear related 3-241 mechanisms, such as galling, are event driven conditions that are resolved as required. Loss of preload is a design driven effect and not an aging effect
 
requiring management. Bolting at IPEC is standard grade B7 low alloy steel, or
 
similar material, except in rare specialized applications such as where stainless
 
steel bolting is utilized. Loss of preload due to stress relaxation (creep) would
 
only be a concern in very high temperature applications (> 700 &deg;F) as stated in
 
the ASME Code, Section II, Part D, Table 4. No IPEC bolting operates at
 
> 700&deg;F. Therefore, loss of preload due to stress relaxation (creep) is not an applicable aging effect for the reactor coolant system. Other issues that may
 
result in pressure boundary joint leakage are improper design or maintenance
 
issues. Improper bolting application (design) and maintenance issues are current
 
plant operational concerns and not related to aging effects or mechanisms that
 
require management during the period of extended operation. Nevertheless, the
 
Bolting Integrity Program manages loss of preload for all external bolting in the
 
reactor coolant system with the exception of the reactor vessel studs. As
 
described in the Bolting Integrity Program, IPEC has taken actions to address
 
NUREG-1339, Resolution to Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants.
These actions include implementation of good bolting practices in accordance with EPRI NP-5067, "Good Bolting Practices."
Proper joint preparation and make-up in accordance with industry standards is
 
expected to preclude loss of preload. This has been confirmed by operating
 
experience at IPEC.
The staff noted that SRP-LR Section A.1.2.1 provides the staffs position that leakage past a bolted connection is not to be treated as an abnormal event and that the aging effects leading to
 
such leaking or resulting from such leakage need to be evaluated for the period of extended
 
operation. This section of the SRP also states that:
Specific aging effects from abnormal events need not be postulated for license renewal. However, if an abnormal event has occurred at a particular plant, its
 
contribution to the aging effects on structures and components for license
 
renewal should be considered for that plant. For example, if a resin intrusion has
 
occurred in the reactor coolant system at a particular plant, the contribution of
 
this resin intrusion event to aging should be considered for that plant.
However, leakage from bolted connections should not be considered as abnormal events. Although bolted connections are not supposed to leak, experience shows that
 
leaks do occur, and the leakage could cause corrosion. Thus, the aging effects from
 
leakage of bolted connections should be evaluated for license renewal.
The staff reviewed the applicants LRA AMR items relative to the applicable aging effects for SA-193, Grade B7 bolting components, as amended in the applicants response to Audit
 
Item 201. The staff noted that, with respect to the management of cracking due to SCC in the
 
applicants SA-193 Grade B7 bolts, the information in the LRA indicates that the cracking due to
 
SCC would not be an aging effect requiring management (AERM) because the bolting
 
components were procured to yield strengths less than 150 ksi (i.e. the applicant has indicated
 
that the RCS bolts that were purchased and used under the applicants QA program were of low
 
to moderate tensile strengths, meaning the yield strengths for the materials are even lower. In
 
the staffs safety evaluation on WCAP-14574-NP-A dated October 26, 2000, the staff provided
 
its basis that cracking due to SCC does not need to be managed in SA-193 Grade B7 bolting 3-242 materials if it was confirmed that the materials for the bolting components were procured to either yield strengths less than 150 ksi (considered high yield strengths) or to hardness values
 
less than or equal to 32 on a Rockwell C Hardness scale. The staff finds that the applicant has
 
provided an acceptable basis for concluding that cracking due to SCC is not an aging effect
 
requiring management for these bolting components because it is consistent with the staffs
 
basis in its SE on WCAP-14574-NP-A that cracking of SA-193, Grade B7 would not need to be
 
managed if the materials for the bolting components were procured to either yield strengths less
 
than 150 ksi or to hardness values less than or equal to 32 on a Rockwell C Hardness scale.
The staff noted, however, that the applicants response to Audit Item 201 also indicated that loss of material due to wear and loss of preload due to stress relaxation were not aging effects
 
and mechanisms that need to be managed in the SA 193, Grade B7 bolting components.
 
However, in spite of this basis, the staff did note that the applicants response to Audit Item 201
 
did indicate that these bolting components are included within the scope of the applicants
 
Bolting Integrity Program. Thus, the staff finds that by including the SA-193 Grade B7 bolting
 
within the scope of the Bolting Integrity Program, the applicant will manage any loss of material, loss of preload, or potential cracking of the bolting that may occur during the period of extended
 
operation. Audit Item 201 is resolved.
3.1.2.1.3  Cracking Due to Cycling Loading, Stress Corrosion Cracking, and Primary Water Stress Corrosion Cracking LRA Table 3.1.1, Line Item 62 (LRA AMR 3.1.1-62) addresses cracking due to cyclic loading in 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. AMR Item 62 in Table 1 of the
 
GALL Report, Volume 1 (GALL1 AMR 1-62) recommends an AMP corresponding to GALL AMP XI.M1, ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, be credited to
 
manage cracking due to cyclical loading in these components.
In LRA AMR 3.1.1-62, the applicant stated that GALL1 AMR 1-62 was not used because cracking due to cyclic loading is addressed in other LRA AMR items on cracking due to fatigue.
 
In this AMR Item, the applicant also stated that in spite of this fact, the Inservice Inspection
 
Program is credited to manage cracking of all ASME Code Class 1 stainless steel piping that is
 
greater than four (4) inches in diameter (i.e., 4-inch NPS). Because the applicant did not use the
 
GALL1 AMR item, the staff did not find any applicable AMRs in LRA Tables 3.1.2-3-IP2 and
 
3.1.2-3-IP3 on cracking in these large bore ASME Code Class 1 piping, piping components, or
 
piping elements. In Audit Item 203, the staff asked the applicant to clarify its position on this
 
component group.
The applicant responded to Audit Item 203 in a letter dated December 18, 2007. In this response, the applicant stated:
Cracking due to cyclic loading is addressed in other items as cracking due to fatigue. The Inservice Inspection Program manages cracking of stainless steel
 
piping > 4 nps.
Table 3.1.2-3-1P2 and Table 3.1.2-3-1P3 line item piping >4" nps / Treated borated water >140 deg F (int) / Cracking is revised to add the following
 
NUREG-1 801 Vol. 2 item, Table 1 item, and Note.
3-243 IV.C2-26 (R-56) / 3.1.1-62 / E Information to be incorporated into the LRA.
The staff verified that the applicant made the stated changes to the LRA in the letter of December 18, 2007, and that the changes made to LRA AMR 3.1.1-62 are consistent with the
 
position in GALL1 AMR 1-62. The staff also verified that, by the same letter, the applicant
 
amended the AMRs on cracking of large bore piping in LRA Tables 3.1.2-3-IP2 and 3.1.2-3-IP3
 
to be consistent with the AMR in GALL AMR Item IV.C2-26. Based on the applicants response
 
and the applicants amendment of the LRA, the staff confirmed that the applicant amended its
 
AMRs on cracking due to cyclical loading of the large bore ASME Code Class 1 piping at IP2
 
and IP3 to be consistent with the staffs position provided in the GALL Report recommending
 
the Inservice Inspection Program be credited to manage cracking due to cyclical loading of
 
these components. Based on the staffs review and confirmation of the appropriate amendments
 
of the LRA, the staff finds that the applicant has proposed an acceptable basis for managing
 
cracking due to cyclical loading in these large bore ASME Code Class 1 piping, piping
 
components, and piping elements because the applicants basis is consistent with the staffs
 
position in the GALL Report.
LRA Table 3.1.1, Line Item 64 (LRA AMR 3.1.1-64) addresses cracking due to SCC or primary water stress corrosion cracking (PWSCC) in stainless steel and steel with stainless steel or
 
nickel alloy cladding pressurizer components. The AMR that corresponds to LRA AMR 3.1.1-64
 
is AMR Item 64 in the GALL Report, Volume 1 (GALL1 AMR Table 1-64), This GALL AMR
 
invokes GALL AMR IV.C2-19 and together these AMRs recommend that programs corresponding to GALL AMPs XI.M1, ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, and XI.M2, Water Chemistry, be credited to manage cracking in pressurizer
 
components that are made from either stainless steel or steel with internal stainless steel or
 
nickel alloy cladding.
The staff noted that the LRA indicated that the Water Chemistry Control Program - Primary and Secondary and Inservice Inspection Program are credited to manage cracking in steel with
 
stainless steel or nickel alloy clad components and the management of cracking in the stainless
 
steel components is addressed in other LRA Table 3.1.1 AMR items.
The staff asked the applicant to identify the additional pressurizer component AMRs that are used to manage cracking of the stainless steel pressurizer components or steel pressurizer
 
components that are designed with internal stainless steel or nickel alloy cladding (Audit
 
Item 204). In its response, dated December 18, 2007, the applicant stated that AMRs on
 
cracking of the IP2 and IP3 pressurizer components are given in LRA Tables 3.1.2-3-IP2 and
 
3.1.2-3-IP3, respectively. The applicant also stated that these AMR items include those for the
 
pressurizer heater sheaths, heater wells, manway insert plates, pressurizer penetrations, pressurizer spray heads, pressurizer spray head couplings and locking bars, thermal sleeves, and thermowells. The applicant further stated that the Table 1 rollup items for these
 
components are Items 3.1.1-24, 3.1.1-68, or 3.1.1-70.
Regarding the applicants response to the Table 2 AMR on cracking of the CASS pressurizer spray heads (as given in LRA Table 3.1.2-3-IP2 and 3.1.2-3-IP3), the staff noted that the
 
applicant aligned the Table 2 AMR to LRA AMR Item 3.1.1-24. SER Section 3.1.2.2.7, Subsection (2) documents the staffs evaluation of the applicants Table 2 AMR on cracking of
 
the CASS pressurizer spray head.
3-244 Regarding the applicants response to the Table 2 AMR on cracking of the IP2 pressurizer heater sheaths, heater wells, manway insert plates, pressurizer penetrations, pressurizer spray
 
head couplings and locking bars, pressurizer thermal sleeves, and thermowells, the staff noted
 
that the applicant aligned its Table 2 AMR items for these components to LRA AMR
 
Item 3.1.1-68. The staffs evaluation of the applicants Table 2 AMR items for these components
 
is documented later in this SER section.
The staff noted that the LRA did not include any AMRs on cracking of the steel pressurizer shell or head components (with internal stainless steel cladding) that aligned to GALL AMR IV.C2-19.
 
Although the LRA did include some AMRs on cracking of the steel pressurizer shell courses and
 
heads that are clad internally with stainless steel, the applicant aligned its AMRs on cracking of
 
these pressurizer components to LRA AMR 3.1.1-67 and to GALL AMR IV.C2-18. These pertain
 
to cracking in pressurizer components induced by cyclical loading (fatigue). The staff also noted
 
that in these AMRs the applicant credited its Inservice Inspection Program to manage cracking
 
in pressurizer components. This is the same program recommended in GALL AMR IV.C2-19 for
 
managing cracking in the components if the cracking is induced by SCC or PWSCC. Thus, the
 
staff concludes the alignment on cracking of these pressurizer shells and heads (including
 
internal stainless steel cladding) to LRA AMR 3.1.1-67 and to GALL AMR IV.C2-18 adequately
 
covers both alignment to LRA 3.1.1-67 and GALL AMR IV.C2-18 and to LRA AMR 3.1.1-64 and
 
GALL AMR IV.C2-19. This is because the volumetric inservice inspections for these
 
components would detect for cracking initiated by cyclical loading (fatigue) or by SCC or
 
PWSCC. Therefore, the staff finds that the applicant has adequately addressed cracking in the
 
steel pressurizer head and shells that are clad internally with stainless steel and are exposed to
 
the reactor coolant.
The staff also noted that, in LRA Tables 3.1.2-1-IP2 and 3.1.2-1-IP3, the applicant also aligned the following AMRs for steel RV components that are clad internally with stainless steel to GALL
 
AMR IV.C2-19, including those for the RV closure heads, RV closure head flanges, RV shell
 
flanges, RV inlet and outlet nozzles, RV closure head vents, RV upper shells, RV intermediate
 
shells, RV lower shells, and associated welds. The staff noted that in these AMRs, the applicant
 
credited its Water Chemistry Control Program - Primary and Secondary and Inservice
 
Inspection Program for aging management of the components. The staff finds this to be
 
acceptable because these RV components have the same material, environment, and aging
 
effect combinations as those for the steel pressurizer components that are clad internally with
 
stainless steel or nickel alloy materials and because the applicants aging management basis
 
for these RV components is consistent with the staffs recommended position in GALL AMR
 
IV.C2-19.LRA Table 3.1.1, Line Item 65 (LRA AMR 3.1.1-65) addresses cracking due to PWSCC in nickel alloy upper reactor vessel closure head (RVCH) control rod drive penetration nozzles, instrument tubes, head vent pipes (top head), and welds, and in the nickel alloy reactor vessel (RV) inlet and outlet nozzle safe-end welds. Item 65 in Table 1 of the GALL Report, Volume 1 (GALL1 AMR 1-65), which corresponds to LRA AMR 3.1.1-65, invokes GALL AMRs IV.A2-9
 
and IV.A2-18, as applicable to the management of cracking in control rod drive (CRD)
 
penetration nozzles and upper RVCH head vent pipes and instrumentation tubes, and their
 
associated nickel alloy nozzle-to-RV welds. Collectively, these GALL-based AMRs all recommend that programs corresponding to GALL AMP XI.M1, ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, GALL AMP XI.M2, Water Chemistry, and GALL AMP XI.M11A, Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure 3-245 Heads of Pressurizer Water Reactors, manage cracking in these nickel alloy nozzle components and their associated nickel alloy nozzle-to-RV penetration welds.
The staff noted that in LRA AMR Item 3.1.1-65, the applicant credited only its Water Chemistry Control Program - Primary and Secondary (LRA AMP B.1.41) and the Nickel Alloy Inspection
 
Program (LRA AMP B.1.21) to manage cracking in the nickel alloy upper RVCH penetration
 
nozzles or any upper RVCH nozzles that are welded to the upper RVCH using nickel alloy
 
nozzle-to-RV penetration welds, and in the nickel alloy RV inlet and outlet nozzle safe-end
 
welds. The staff had two issues with this aging management basis: (1) the applicant did not
 
credit its Inservice Inspection Program, as is otherwise recommended in the applicable GALL
 
AMRs, and (2) in LRA AMR. 3.1.1-65, the applicant credited its general nickel alloy aging
 
management program for the upper RVCH penetration nozzle and its associated nickel alloy
 
nozzle-to-RV welds. The staff addressed these issues in Audit Item 205.
In its response dated December 18, 2007, the applicant amended AMR line items in LRA Table 3.1.2-1-IP2 and LRA Table 3.1.2-1-IP3 to add the applicants Inservice Inspection Program to
 
the Water Chemistry Program and the Nickel Alloy Inspection Program as the basis for
 
managing cracking due to PWSCC. The staff noted that the applicable components included the
 
upper RVCH head vent safe end and their associated welds and the nickel alloy RV inlet and
 
outlet nozzle safe-end welds. The staff noted that addition of the Inservice Inspection Program
 
will make the AMRs for these penetration nozzles consistent with the staffs recommended AMR
 
guidance in GALL1 AMR 1-65.
With respect to aging management of cracking in nickel alloy RV inlet and outlet nozzle safe-end welds, the staffs basis in GALL AMR IV.A2-15 recommends Inservice Inspection Programs
 
be credited for aging management. This is because the RV inlet and outlet nozzle safe end
 
welds are ASME Code Class 1 full penetration butt welds that are required to be inspected by
 
volumetric inspection techniques once every 10-year ISI Interval. These volumetric
 
examinations are also required to be subject the NRCs performance demonstration initiative
 
requirements (PDI) that are defined and required in 10 CFR 50.55a. Thus, the staff found that
 
the applicants response to Audit Item 205 and LRA amendment of the Table 2 AMR entry on
 
cracking of the nickel alloy RV inlet and outlet nozzle safe-end welds resolved the staffs issue
 
with respect to these components. This is because the addition of the Inservice Inspection
 
Program as an added basis for aging management makes the AMR entry for these components
 
consistent with the staff aging management recommendations in IV.A2-15, with the added
 
conservatism that the Nickel Alloy Inspection Program is also credited for aging management of
 
cracking in these nickel alloy components.
The staff determined that the applicants response to Audit Item 205 and the LRA amendment provided in the December 18, 2007, letter did not resolve the issue with respect to the AMPs
 
that should be credited for aging management of cracking in the upper RVCH penetration
 
nozzles. The staffs basis for this finding is as follows: GALL1 AMR 1-65, and GALL AMRs
 
IV.A2-9 and IV.A2-18, which derive from this GALL1 AMR, deal only with management of
 
cracking due to PWSCC in nickel alloy upper RVCH penetration nozzles in PWRs (including
 
CRD penetration nozzles, and upper RVCH head vent and instrumentation nozzles), and their
 
associated nickel alloy nozzle-to-RV welds.
7 These GALL AMRs recommend that programs that 7GALL1 AMR 1-65, and GALL AMRs IV.A2-9 and IV.A2-18 are only applicable to CRD penetration nozzles and upper RV head vent nozzles and their nickel alloy welds and are not applicable to CRD pressure housings. The GALL AMRs on cracking of CRD pressure housings is addressed in AMR Item 34 of Table 1 to the GALL Report, Volume 1 (GALL1 AMR 1-34), and in GALL AMR IV.A2-11 which is derived from this GALL1 AMR. The GALL AMRs on 3-246correspond to GALL AMP XI.M1, ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, GALL AMP XI.M2, Water Chemistry, and GALL AMP XI.M11A, Nickel-Alloy
 
Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water
 
Reactors, be credited to manage cracking due to PWSCC in these upper RVCH nickel alloy
 
components. In contrast, the applicants AMR entry in LRA 3.1.1-65 for any upper RVCH
 
nozzles made from nickel alloy base metals and are welded to the upper RVCH using nickel
 
alloy nozzle-to-RV welds or for any non-nickel alloy RVCH nozzles that are welded to the upper
 
RVCH using nickel alloy nozzle-to-RV welds, in part, credited AMP B.1.21, Nickel Alloy
 
Inspection Program. In addition, B.1.31, Reactor Vessel Head Penetration Inspection Program and GALL AMP XI.M11A are based on compliance with the staffs augmented inspection
 
requirements for PWR upper RVCH penetration nozzles, as issued in NRC Order EA-03-009, and amended in the First Revised Order EA-03-009 (henceforth referred to as the Order as
 
Amended). Thus, the applicants entry in LRA AMR 3.1.1-65 should specify that AMP B.1.31, Reactor Vessel Head Penetration Inspection Program is credited for aging management, because that is the applicants nickel alloy management program that corresponds to GALL AMP XI.M11A, "Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure
 
Heads of Pressurized Water Reactors (PWRs Only)," and not AMP B.1.21, Nickel Alloy
 
Inspection Program, which is not based on compliance with the Order as Amended.
8 The staff reviewed LRA Tables 3.1.2-1-IP2 and 3.1.2-1-IP3 to see if the applicants Table 2
 
AMRs on cracking of the upper RVCH nozzles appropriately credited the proper AMPs
 
recommended in GALL AMRs IV.A2-9 and IV.A2-18. The staff noted that the applicant includes
 
only one AMR entry each in LRA Table 3.1.2-1-IP2 and Table 3.1.2-1-IP3 for its nickel alloy
 
RVCH penetration nozzles (which is the AMR entry for the CRD head penetration housing tubes
 
[nozzles]) and that in this Table 2 AMR item entry, the applicant appropriately credited its
 
Reactor Vessel Head Penetration Inspection Program, along with the Water Chemistry Control
 
Program - Primary and Secondary and the Inservice Inspection Program, to manage cracking
 
of the components. However, the staff also noted that the applicant inappropriately aligned this
 
Table 2 AMR item to LRA AMR 3.1.1-34 which is for CRD pressure housings, and not to
 
LRA 3.1.1-65, which is the appropriate Table 1 AMR for CRD penetration nozzles and upper
 
RVCH head vent and instrumentation nozzles. The staff also noted that the applicants Table 2
 
AMRs in LRA Tables 3.1.2-1-IP2 and 3.1.2-1-IP3 did include an entry on cracking of the upper
 
RVCH head vent nozzles and that in these AMR items, the applicant identified that the upper
 
RVCH head vent nozzle was made of carbon steel with stainless steel cladding. However, the
 
staff noted that the AMRs entries on the upper RVCH head vent nozzles did not clarify whether
 
the head vent nozzle-to-RV weld for the upper RVCH head vent nozzles were made of nickel
 
alloy filler weld material. Thus, the staff determined that the applications AMR inputs for the
 
upper RVCH penetration nozzles and CRD pressure housings needed additional information
 
and clarification.                                                                                                                                                                          cracking of RV inlet and outlet nozzles safe ends and safe end welds is addressed in AMR Item 69 of Table 1 to the GALL Report, Volume 1 (GALL1 AMR 1-69), and in GALL AMR IV.A2-15 which is derived from this GALL1 AMR.
8For the Table 2 AMR entries on cracking in LRA Table 3.1.2-1-IP2 and 3.1.2-1-IP3 for the CRD penetration housing tubes (i.e., the CRD penetration nozzles), the staff noted that the applicant appropriately credited, in part, LRA AMP B.1.31, Reactor Vessel Head Penetration Inspection Program for aging management. Thus, the issue is with the general AMR basis discussed in LRA AMR 3.1.1-65 for upper RVCH penetrations, and with a question on whether the upper RVCH vent nozzles and any upper RVCH instrumentation nozzles are welded to the upper RVCHs using nickel alloy nozzle-to-RV welds.
3-247 In a letter dated December 30, 2008, the staff issued RAI 3.1.2-1, Part A to resolve these issues. This was identified as part of Open Item 3.1.2-1.
The applicant responded to RAI 3.1.2-1 in a letter dated January 27, 2009. In this response, the applicant clarified that the CETNA nozzles used in the upper RV head designs are fabricated
 
from stainless steel and do not include any nickel alloy base metal or weld materials. Instead, the applicant clarified that the CETNA assemblies are fabricated as follows:
A CET head port adapter is connected to the penetration housing adapter flange, and then connected to the CETNA assembly via a conoseal joint. All CETNA assemblies are sealed to
 
the CET columns with Grafoil seals using a compression collar and a hold down nut with no
 
welds. As shown in the LRA Tables, the CETNA are constructed from stainless steel.
Based on this supplemental information, the applicant has provided an acceptable basis for concluding that the CETNA assemblies do not need to be within the scope of and managed by the Nickel Alloy Inspection Program because these components do not include any nickel alloy
 
base metal or weld components.
In the applicants response to RAI 3.1.2-1, the applicant also clarified that the only nickel alloy welds associated with the upper RVCH vent nozzles are those nickel alloy welds that join these
 
nozzles to the nickel alloy closure head vent nozzle safe-end. The applicant explained the vent
 
nozzles are carbon steel nozzles with internal stainless steel cladding that are welded to the
 
carbon steel upper RVCH using carbon steel weld materials that have been post weld heat
 
treated. The applicant clarified that the nickel alloy welds associated with the nickel alloy vent
 
nozzle safe ends are within the scope of the applicants Nickel Alloy Inspection Program. Based
 
on this review, the staff finds that the applicant has provided an acceptable basis for concluding
 
that the upper RVCH head vent nozzle-to-upper RVCH welds do not need to be managed by or
 
be within the scope of the either the Nickel Alloy Inspection Program or Reactor Vessel Head
 
Penetration Inspection Program because these components and their associated welds are not
 
fabricated from nickel alloy materials.
Based on this review, the staff finds that the applicant has provided an acceptable basis for managing cracking in these upper RVCH head vent nozzles and CETNA nozzles because:
 
(1) the applicant has clarified which of nozzle designs include nickel alloy base metal or weld
 
materials, (2) the applicant has appropriately credited its Nickel Alloy Inspection Program and
 
Water Chemistry Program to manage cracking in the nickel alloy upper RVCH head vent nozzle
 
safe ends and their nickel alloy safe-end-to-nozzle welds, and (3) in the applicants AMRs for
 
the CETNA nozzles and upper RVCH head vent nozzles, as given in LRA Tables 3.1.2-IP2-1
 
and 3.1.2-IP3, the applicant has appropriately credited its Water Chemistry Program and
 
Inservice Inspection Program for any cracking that may develop in the components. RAI 3.1.2-1
 
is resolved and Open Item 3.1.2-1 is closed with respect to the management of cracking in the
 
upper RVCH head vent nozzles and the CETNA nozzles.
LRA Table 3.1.1, Line Item 69 (LRA AMR Item 3.1.1-69) addresses cracking due to SCC and PWSCC in stainless steel and nickel alloy safety injection nozzles, safe ends, and associated
 
welds and buttering exposed to reactor coolant. AMR Item 69 in Table 1 of the GALL Report, Volume 1 (GALL1 AMR 1-69) is the GALL AMR that corresponds to LRA AMR 3.1.1-69. In this
 
GALL1 AMR, and in GALL AMR IV.A2-15, the staff recommends that AMPs corresponding to GALL AMP XI.M1, ASME Section XI Inservice Inspection, Subsection IWB, IWC, and IWD, and GALL AMP XI.M2, Water Chemistry, be credited to manage cracking in these components 3-248 under exposure to the reactor coolant.
The staff verified that, in LRA Table 3.1.2-1-IP2, the applicant includes two AMRs that aligned to GALL AMR IV.A2-15: (1) cracking of the stainless steel reactor vessel (RV) inlet and outlet
 
nozzle safe-ends, and (2) cracking of the stainless steel RV bottom head safe-ends and safe-
 
end welds. In these AMRs, the staff noted that the applicant credited its Water Chemistry Control Program - Primary and Secondary and its Inservice Inspection Program to manage
 
cracking in the stainless steel component surfaces that are exposed to the reactor coolant. This
 
is in conformance with the recommendation in GALL AMR IV.A2-15, that AMPs corresponding to GALL AMP XI.M1, ASME Section XI Inservice Inspection, Subsection IWB, IWC, and IWD, and GALL AMP XI.M2, Water Chemistry, be credited to manage cracking in stainless steel RV
 
inlet nozzle, outlet nozzle and safety injection nozzle safe end components and their associated
 
nickel alloy safe-end welds.
In Audit Item 208, the staff asked the following question:
In LRA Table 3.1.1, Item 3.1.1-69, Entergy states, The Water Chemistry Control -
Primary and Secondary and Inservice Inspection Programs manage cracking in
 
stainless steel nozzles and penetrations. Nickel alloy used for such applications
 
is compared to other lines. Identify which other lines applicable to Ni-alloy
 
components exposed to reactor coolant and manage cracking due to SCC and
 
PWSCC.In its response, dated December 18, 2007, the applicant stated the LRA AMR 3.1.1-69 is a rollup only for the stainless steel RV inlet and outlet nozzle safe-ends and the safe ends and
 
safe-end welds on the bottom head drains. The applicant stated that the LRA Tables 3.1.2 IP2 through 3.1.2-4-IP2 and LRA Tables 3.1.2-1-IP3 through 3.1.2-4-IP3 include numerous
 
AMR items for nickel alloy components. Examples are the control rod drive penetrations, the RV
 
inlet/outlet nozzle safe end welds, and the bottom head instrument penetrations. The applicant
 
stated that these AMR items are compared to Items IV.A2-18 and IV.A2-19, which roll up to
 
table entries 3.1.1-31 and 3.1.1-65. The applicant stated that the AMR in LRA AMR 3.1.1-69 is
 
only for management of cracking in the RV inlet and outlet nozzle safe-ends and the RV bottom
 
head drain safe-ends.
The staff reviewed LRA Tables 3.1.2-1-IP2 and 3.1.2-1-IP3 to determine whether the information in the applicants response to Audit Item 208 was valid with respect to the
 
applicants basis for managing cracking due to SCC or PWSCC in the nickel alloy components
 
associated with the RV bottom heads. The staff noted that, in the applicants response to Audit
 
Item 208, the applicant mentioned that the nickel alloy components in the RV bottom heads, which align to LRA AMR 3.1.1-69, are the nickel alloy safe-ends for the RV bottom head drains.
 
However, the staff also noted that LRA Tables 3.1.2-1-IP2 and 3.1.2-1-IP3 do not include any
 
AMR entries for RV bottom head drains or specifically for nickel alloy bottom head drain safe
 
ends and welds. Thus, the staff determined that the applicant would need to better define which
 
of the components and welds associated with the RV bottom heads are made from nickel alloy
 
materials and what the applicants basis is for managing cracking due to SCC or PWSCC in
 
these nickel alloy RV bottom head components and welds. By letter dated December 30, 2008, the staff issued RAI 3.1.2-1, Part B to resolve this issue. The staffs acceptance of LRA
 
AMR 3.1.1-69 is pending acceptable resolution of RAI 3.1.2-1, Part B on aging management of
 
nickel alloy components that are associated with the RV bottom heads or their penetration
 
nozzles. This was identified as part of Open Item 3.1.2-1.
3-249 By letter dated January 27, 2009, the applicant responded to RAI 3.1.2-1, Part B. In this response, the applicant clarified that neither the IP2 nor IP3 reactor vessels have bottom head
 
drains, and that the response to Audit Item 208 should have referred to the nickel alloy welds in
 
bottom head safe ends instead of the bottom head drain safe end welds. The staff noted that
 
the clarification made in the response to RAI 3.1.2-1, Part B is consistent with the actual design
 
of the RV bottom head nozzle at IP2 and IP3. The staff finds this response provides an
 
acceptable basis for resolving which components in RV bottom heads are fabricated with nickel
 
alloy welds because the clarification is consistent with the actual design of IP2 and IP3 RV
 
bottom heads. The staff confirmed that the LRA indicates that the applicant is crediting its Water
 
Chemistry Control Program, the Inservice Inspection Program, and the Nickel Alloy Inspection
 
Program to manage cracking due to PWSCC in the RV bottom head instrumentation nozzles
 
and their nickel alloy safe end welds. This is consistent with the AMPs recommended for aging
 
management in GALL AMR Item IV.A2-19. RAI 3.1.2-1, Part B is resolved and Open Item 3.1.2-
 
1 is closed with respect to identifying which of the RV bottom head components and associated
 
welds are fabricated from nickel alloy materials.
In LRA Tables 3.1.2-3-IP2 and 3.1.2-3-IP3, the applicant includes AMRs on cracking of the stainless steel regenerative heat exchanger bonnet, shell, and tube surfaces that are exposed
 
to borated treated water (i.e. to the reactor coolant). The applicant aligned these AMRs to LRA
 
Table 3.3.1, AMR item 3.3.1-8, which states Stainless steel components of some heat
 
exchangers to which this NUREG-1801 line item applies, including the regenerative heat
 
exchanger, are in the reactor coolant systems in series 3.1.2-x tables. SER Section 3.3.2.2.4, Item (2) documents the staffs evaluation of these AMRs.
LRA Table 3.1.1, Line Item 68 (LRA AMR 3.1.1-68) addresses cracking due to SCC in 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 that are made from either stainless steel or steel with internal stainless steel cladding.
 
AMR Item 68 in Table 1 of the GALL Report, Volume 1 (GALL1 AMR 1-68) is the GALL AMR
 
that corresponds to LRA AMR 3.1.1-68. In this GALL1 AMR, and in GALL AMRs IV.C2-2, IV.C2-5, IV.C2-20, IV.C2-22, IV.C2-27, and IV.D1-1 which are invoked by this GALL1 AMR, the staff recommends that AMPs corresponding to GALL AMP XI.M1, ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, and GALL AMP XI.M2, Water Chemistry, be
 
credited to manage cracking in these components.
The staff noted that in the LRA, the applicant credited its Water Chemistry Control Program -
Primary and Secondary and its Inservice Inspection Program to manage cracking in all ASME
 
Code Class 1 reactor coolant pressure boundary components that are subject to inservice
 
inspections. This includes the stainless steel (including CASS) ASME Code Class 1 large bore
 
( 4-inch NPS) piping, piping components, piping elements; pump casings; large bore ( 4-inch NPS) valve bodies, pressurizer penetration nozzles, pressurizer manway inserts, pressurizer
 
heater sheaths and wells, and pressurizer thermal sleeves; SG primary manways, and SG
 
primary nozzles. The staff finds that the applicants aging management basis for managing
 
cracking in these components is acceptable because the crediting of the Water Chemistry
 
Control Program - Primary and Secondary and the inservice Inspection Program is consistent
 
with the programs recommended for aging management in GALL1 AMR 1-68 and GALL AMRs
 
IV.C2-2, IV.C2-5, IV.C2-20 and IV.D1-1.
3-250 For the non-ASME Code Class 1 (non-pressure boundary) stainless steel components in the RCS, including the pressure spray head couplings and locking bars and the primary SG
 
manway cover inserts, the applicant credited only its Water Chemistry Control Program -
 
Primary and Secondary to manage cracking in the components.
The staff noted that the applicant did not credit an inspection-based program to verify the effectiveness of the Water Chemistry Control Program - Primary and Secondary in managing
 
cracking of these stainless steel non-ASME Code Class 1 (non-pressure boundary)
 
components. In Audit Item 207, the staff asked the applicant to justify its basis for crediting only
 
the Water Chemistry Control Program - Primary and Secondary for management of cracking in
 
the pressurizer spray head couplings and locking bars, and for not crediting a One Time
 
Inspection to verify the effectiveness of Water Chemistry Control Program - Primary and
 
Secondary in managing this aging effect. In Audit Item 357, the staff asked the applicant to
 
justify its basis for crediting only the Water Chemistry Control Program - Primary and
 
Secondary as the basis for managing cracking in the SG primary manway cover inserts and why
 
the Inservice Inspection Program had not been credited for cracking in these components.
In its response to Audit Items 207 dated December 18, 2007, the applicant clarified that the pressurizer spray head couplings and locking bars are not AMSE Code Class components and, therefore, these couplings and locking bars are not within the scope of the applicants Inservice
 
Inspection Plan. The applicant clarified that a One Time Inspection will be used to verify the
 
effectiveness of the Water Chemistry Control Program - Primary and Secondary in managing
 
cracking of the pressurizer spray head couplings and locking bars as a result of SCC.
In its response to Audit Item 357 dated December 18, 2007, the applicant clarified that the primary SG manway cover inserts are ASME Code Class 1 components and that these
 
components are within the scope of the applicants Inservice Inspection Program. As a result, the applicant stated that it is crediting both the Water Chemistry Control Program - Primary and
 
Secondary and the Inservice Inspection Program to manage cracking of the primary SG
 
manway inserts and that the applicable Table 2 AMRs in LRA Tables 3.1.2-4-IP2 and
 
3.1.2-4-IP3 for the primary SG manway insert would be amended accordingly.
With respect to the applicants response to Audit Item 357, the staff verified that the applicant made the appropriate changes to the AMRs on cracking of the primary SG manway cover
 
inserts in the LRA amendment dated December 18, 2007. The staff also verified that this
 
change makes the AMRs in LRA Tables 3.1.2-4-IP2 and 3.1.2-4-IP3 for the primary SG
 
manway cover inserts consistent with the aging management guidance in GALL1 AMR 1-68 and
 
GALL AMR IV.D1-1. Based on this LRA amendment the staff finds that the applicants AMRs on
 
cracking of the primary SG manway cover inserts are acceptable because the applicants
 
amended AMRs for the components have been verified as being consistent with staffs
 
recommended aging management position that is provided in GALL AMR IV.D1-1. The staff
 
also confirmed that, in the applicants AMRs in LRA Table 3.1.2-3-IP2 and 3.1.2-3-IP3 on
 
cracking of ASME Code Class 1 piping and pressurizer components, in LRA Tables 3.1.2-4-IP2
 
and 3.1.2-4-IP3 on cracking of ASME Code Class 1 SG components, the applicant has provided
 
an acceptable basis for crediting the Water Chemistry Control Program - Primary and
 
Secondary and the Inservice Inspection Program to manage cracking of the components under
 
exposure to the reactor coolant. Based on the review, the staff finds that the applicants AMRs
 
for these components are acceptable because they are consistent with the recommended
 
guidance in GALL1 AMR 1-68 and in GALL AMR IV.C2-2, IV.C2-5, IV.C2-20 or IV.D1-1. Audit
 
Item 357 is resolved.
3-251 With respect to the applicants response to Audit Item 207 on aging management of cracking due to SCC of the pressurizer spray head couplings and locking bars, the staff concludes that
 
the applicant has provided an acceptable basis for crediting the Water Chemistry Control
 
Program - Primary and Secondary and the One-Time Inspection Program to manage cracking
 
in the pressurizer spray head coupling and locking bars because the components are not
 
categorized as ASME Code Class 1 components and because, consistent with the staffs guidance in GALL AMP XI.M32, One-Time Inspection, the One Time Inspection Program will
 
be used to verify that the Water Chemistry Control Program - Primary and Secondary is
 
effective in managing cracking of these components as a result of SCC. Audit Item 207 is
 
resolved.3.1.2.1.4  Cracking Due to Stress Corrosion Cracking and Loss of Material Due to Crevice Corrosion and Fretting LRA Table 3.1.1, Line Item 74 (LRA AMR 3.1.1-74) addresses cracking due to SCC and loss of material due to crevice corrosion and fretting in chrome plated steel, stainless steel, nickel alloy
 
SG anti-vibration bars exposed to secondary feedwater/steam.
GALL AMR IV.D1-15 pertains to the management of loss of material due to crevice corrosion or fretting in carbon steel SG antivibration bars in PWRs with recirculating SGs. In this AMR, the staff recommends that programs corresponding to GALL AMP XI.M2, Water Chemistry, and GALL AMP XI.M19, Steam Generator Tube Integrity, be credited for aging management of
 
loss of material due to crevice corrosion or fretting in chrome plate steel, stainless steel, or
 
nickel alloy component surfaces that are exposed to secondary treated water or steam
 
environments (i.e., to FW or steam).
The staff noted that for anti-vibration bars and end caps, peripheral retaining rings, feedwater (FW) nozzle thermal sleeves, the applicant credited both its Water Chemistry Control Program -
 
Primary and Secondary Program and its Steam Generator Integrity Program for aging
 
management of loss of material in the component surfaces that are exposed to either a treated
 
water or steam environment, which is consistent with the recommendations in GALL AMR
 
IV.D1-15. SER Sections 3.0.3.2.17 and 3.0.3.2.14 document the staffs evaluation of the Water
 
Chemistry Control Program - Primary and Secondary Program and the Steam Generator
 
Integrity Program, respectively.
3.1.2.1.5  Wall Thinning Due to Flow-Accelerated Corrosion
 
LRA Table 3.1.1, Line Item 59 (LRA AMR 3.1.1-59) addresses wall thinning due to flow-accelerated corrosion in steel SG steam nozzle and safe end, feedwater nozzle and safe end, AFW nozzles and safe ends exposed to secondary feedwater/steam. AMR Item 59 in Table 1 of
 
the GALL Report, Volume 1 (GALL1 AMR 1-59) is the AMR that corresponds to LRA
 
AMR 3.1.1-59. For PWRs with recirculating SGs (like IP2 and IP3), AMR IV.D1-5 is the
 
component specific AMR that derives from GALL1 AMR 1-59. In these AMRs, the staff recommends that an AMP corresponding to GALL AMP XI.M17, Flow-Accelerated Corrosion,
 
be credited to manage wall thinning in these components as a result of flow-accelerated
 
corrosion.
In LRA AMR 3.1.1-59, the applicant stated that the SG steam outlet nozzle contains a nickel alloy flow restrictor and the SG feedwater (FW) nozzle contains a nickel alloy thermal sleeve 3-252 that isolate the carbon steel nozzles from high fluid velocities. Based on these design features, the applicant concluded that these components are not susceptible to flow-accelerated
 
corrosion. However, during the audit, the staff found that a small section of the SG FW nozzle
 
next to the FW piping is exposed to FW flow and is, therefore, susceptible to flow-accelerated
 
corrosion requiring aging management. The staff asked why the design features for these SG
 
nozzles would be sufficient to mitigate the potential for flow-accelerated corrosion to initiate in
 
the component surfaces that are exposed to the feedwater or steam environments (Audit
 
Item 202). Specifically, the staff asked the applicant to explain: (1) why the flow restrictor for the
 
nickel alloy SG steam outlet nozzle is considered to be sufficient for isolating the SG outlet
 
nozzles and their safe-ends from a two-phase steam environment (i.e., steam with some water
 
content in it), and (2) why the thermal sleeves for the SG FW and auxiliary feedwater (AFW)
 
nozzles are considered to be sufficient for isolating these SG nozzles and their safe-end from
 
the secondary treated water environment, The applicant responded to Audit Item 202 in a letter dated December 18, 2007. With respect to the SG steam outlet nozzles, the applicant clarified that the flow restrictors for the SG outlet
 
nozzles totally isolate the components from exposure to a two-phase steam environment. In
 
addition, the applicant clarified that, even if the carbon steel nozzles were exposed to the steam
 
environment, flow-accelerated corrosion would not be an aging mechanism of concern because the steam environment would be of a high quality (i.e., dry). In GALL AMP XI.M17, Flow-
 
Accelerated Corrosion, the staff endorses EPRI Report NSAC-202, Revision 2 as an
 
acceptable basis for identifying whether carbon steel or alloy steel materials are susceptible to
 
flow-accelerated corrosion. In this document, the industry identifies that carbon steel or alloy
 
steel materials with less than 0.75 percent chromium contents are susceptible to flow-
 
accelerated corrosion if they are subjected to high velocity aqueous environments (i.e. high
 
velocity water-based solutions) or high velocity water/steam environments (i.e. high velocity two-
 
phased aqueous flow environments). The staffs finds this to be an acceptable response
 
because the steam environment coming off the SG steam dryers are essentially 99.9 percent
 
dry steam and this environment does not have a sufficient water content to be considered a high
 
velocity two-phase aqueous environment. As a result, the staff finds that the applicant has
 
provided an acceptable basis for concluding that loss of material due to flow-accelerated
 
corrosion is not an AERM in the SG steam outlet nozzles or their safe-ends. Audit Item 202 is
 
resolved with respect to the SG steam outlet nozzles and the safe-ends.
With respect to the AFW nozzles, the applicant clarified, in a letter dated December 18, 2007, that the AFW system is not normally in service and that, as a result of this operational basis, loss of material due to flow-accelerated corrosion is not an AERM for the period of extended
 
operation. The staff noted that the SRP-LR Section A.1.2.1, Item 7, provides the following
 
discussion about using an operational consideration as a basis for identifying whether an aging
 
effect is applicable to a specific component:
The applicable aging effects to be considered for license renewal include those that could result from normal plant operation, including plant/system operating
 
transients and plant shutdown. Specific aging effects from abnormal events need
 
not be postulated for license renewal. However, if an abnormal event has
 
occurred at a particular plant, its contribution to the aging effects on structures
 
and components for license renewal should be considered for that plant. For
 
example, if a resin intrusion has occurred in the reactor coolant system at a
 
particular plant, the contribution of this resin intrusion event to aging should be
 
considered for that plant.
3-253 For PWR designs, AFW systems are initiated only during anticipating operational transients that result in a SCRAM of the reactor, during postulated design basis accidents, or during
 
initiations of the systems that are implemented to meet required technical specification (TS)
 
surveillance requirements. Thus, the staff finds that the applicants basis for concluding that
 
loss of material due to flow-accelerated corrosion is not an AERM for the SG AFW nozzles
 
is acceptable because it is in conformance with the position in SRP-LR Section A.1.2.1, Item 7, that specific aging effects from abnormal events need not be postulated for license
 
renewal. Audit Item 202 is resolved with respect to the SG AFW nozzles.
With respect to the SG FW nozzles and safe-ends, the applicant clarified, in a letter dated December 18, 2007, that, upon further review, the design of the carbon steel SG FW nozzles
 
includes a portion of the nozzles (next to the FW piping) that is exposed to the FW treated water
 
environment. To address this issue, the applicant stated that the LRA would be amended to
 
include new AMRs in LRA Tables 3.1.2-4-IP2 and 3.1.2-4-IP3 on loss of material due to flow-
 
accelerated corrosion for the SG FW nozzles that are exposed to treated water. In addition, in
 
the AMRs consistent with the staffs aging management basis in GALL AMR IV.D2-7 (which
 
provides equivalent aging management basis to the staffs aging management basis in GALL
 
AMR IV.D1-5), the applicant will credit the Flow-Accelerated Corrosion Program with the
 
management of this aging effect/aging mechanism.
The staff verified that the applicant made the applicable amendments of the LRA in the letter of December 18, 2007. The staff also verified that the applicants amended AMR basis for
 
managing loss of material due to flow-accelerated corrosion in the SG FW nozzle components
 
is consistent with the staffs basis for managing loss of material due to flow-accelerated
 
corrosion in SG FW nozzles, as given in either GALL AMR IV.D1-5 or GALL AMR IV.D2-7.
 
Based on this amendment of the LRA, the staff finds the applicant has provided an acceptable
 
basis for managing loss of material due to flow-accelerated corrosion in the IP2 and IP3 SG FW
 
nozzles. This is because, consistent with the staffs aging management basis in GALL AMR
 
IV.D1-5 or IV.D2-7, the applicant has identified that loss of material due to flow-accelerated
 
corrosion is an AERM for the SG FW nozzles, and because the applicant has credited its
 
Flow-Accelerated Corrosion Program to manage loss of material due flow-accelerated corrosion
 
in these components. Audit Item 202 is resolved with respect to the SG FW nozzles.
3.1.2.1.6  Loss of Material Due to Erosion
 
LRA Table 3.1.1, Line Item 66 (LRA AMR 3.1.1-66) addresses loss of material due to erosion in steel steam generator secondary manways and handholds (cover only) exposed to air with
 
leaking secondary-side water and/or steam. AMR Item 66 in Table 1 of the GALL Report, Volume 1 (GALL1 AMR 1-66), and GALL AMR IV.D2-5 recommend that an AMP corresponding to GALL AMP XI.M1, ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD,
 
be credited to manage loss of material in the secondary manways and handholds (cover only) of
 
once-through SG designs.
The staff noted that in LRA AMR 3.1.1-66, the applicant stated that GALL1 AMR 1-66 was not used, since erosion at manways and handholes is the result of leaking joints that have not been
 
corrected. The applicant clarified in the application that leaks at IP2 and IP3 are repaired as
 
soon as practical, and that if damage due to erosion occurred, it would also be repaired. In Audit
 
Item 206, the staff asked the applicant to provide further clarification on its basis for concluding
 
that loss of material due to erosion is not an aging effect requiring management for the SG 3-254 secondary manways and handhold.
By letter dated December 18, 2007, the applicant provided the following response to the staffs question: Erosion at manways and handholes results from abnormal conditions, that is, leakage. This mechanism can cause loss of material independent of the age of the components. Pressure leak tests are required by ASME Section XI, IWC.
 
Because ISI of secondary components manages potential leaks, erosion of
 
manways and handholes due to leakage is not an applicable aging effect.
The staff noted that the applicant used an argument that leakage past the bolted connections in the secondary SG manway and handhold covers is an abnormal event, and that because of this
 
fact, loss of material due to erosion does not need to be identified as an AERM for these
 
components. In Section A.1.2.1, Item 7 of the Appendix A of the SRP-LR (i.e., NUREG-1800, Revision 1), the staff takes the following position on whether correction of leakage from in-scope
 
components can be used as a basis for concluding that a specific aging effect is not applicable
 
and does not need to be managed:
The applicable aging effects to be considered for license renewal include those that could result from normal plant operation, including plant/system operating
 
transients and plant shutdown. Specific aging effects from abnormal events need
 
not be postulated for license renewal. However, if an abnormal event has
 
occurred at a particular plant, its contribution to the aging effects on structures
 
and components for license renewal should be considered for that plant. For
 
example, if a resin intrusion has occurred in the reactor coolant system at a
 
particular plant, the contribution of this resin intrusion event to aging should be
 
considered for that plant.
[Design basis events] DBEs are abnormal events; they include: design basis pipe break, LOCA, and safe shutdown earthquake (SSE). Potential degradations
 
resulting from DBEs are addressed, as appropriate, as part of the plants CLB.
 
There are other abnormal events which should be considered on a case-by-case
 
basis. For example, abuse due to human activity is an abnormal event; aging
 
effects from such abuse need not be postulated for license renewal. When a
 
safety-significant piece of equipment is accidentally damaged by a licensee, the
 
licensee is required to take immediate corrective action under existing
 
procedures (see 10 CFR Part 50 Appendix B) to ensure functionality of the
 
equipment. The equipment degradation is not due to aging; corrective action is
 
not necessary solely for the period of extended operation.
However, leakage from bolted connections should not be considered as abnormal events. Although bolted connections are not supposed to leak, experience shows that leaks do occur, and the leakage could cause corrosion.
 
Thus, the aging effects from leakage of bolted connections should be evaluated
 
for license renewal.
The staff noted that the applicants response to Audit Item 206 was inconsistent with NRCs position in the SRP-LR that leakage from bolted connections should not be considered as
 
abnormal events, and that the aging effects from leakage of bolted connections should be 3-255 evaluated for license renewal. Thus, the staff would normally take the position that the applicants position should be consistent with the staffs aging effect identification criterion in
 
Section A.1.2.1, Item 7 of the Appendix A of the SRP-LR (i.e., NUREG-1800, Revision 1), and
 
that leakage past the SG secondary manway bolting should be assessed for aging effects that
 
could impact the integrity of the manway covers or their bolts. However, the staff did note that
 
the applicants response to Audit item 201 did indicate that the SA-193, Grade B7 bolting at IP2
 
and IP3 is included within the scope of the applicants Bolting Integrity Program. Thus, the staff
 
finds that by including the SA-193 Grade B7 bolting within the scope of the Bolting Integrity
 
Program, the applicant will manage any loss of material, loss of preload, or potential cracking of
 
the bolting that may occur during the period of extended operation. Thus, the staff was of the
 
opinion that the applicants response to Audit Item 201 was an extension of the applicants
 
response to Audit Item 206 and that any aging of the manway and handhole cover would be
 
adequately managed because the applicants implementation of its Bolting Integrity Program
 
would be sufficient to manage any cracking, loss of material, or loss of preload that would occur
 
in the SG secondary manway and handhole cover bolted connections. Audit Item 206 is
 
resolved after taking into account that the information in the applicants response to Audit
 
Item 201, dated December 18, 2007.
3.1.2.1.7  Loss of Material in Nickel Alloy SG Secondary Side Handhold Cover RTD Bosses
 
In LRA Table 3.1.2-4-IP3, the applicant includes its AMR Item on management of loss of material in the IP3 SG secondary handhold cover RTD bosses, which are made from nickel
 
alloy. The applicant aligned this AMR item to LRA AMR 3.1.1- 74 and to AMR Item IV.D1-15 in
 
GALL Report, Volume 2 (GALL AMR Item IV.D1-15). For this AMR the applicant credited only
 
the Water Chemistry Control Program - Primary and Secondary Program to manage loss of
 
material in the component surfaces that are exposed to the secondary-side treated water
 
environment (i.e., to FW).
GALL AMR IV.D1-15 pertains to the management of loss of material due to crevice corrosion or fretting in carbon steel SG antivibration bars in PWRs with recirculating SGs. In this AMR, the staff recommends that programs corresponding to GALL AMP XI.M2, Water Chemistry, and GALL AMP XI.M19, Steam Generator Tube Integrity, be credited for aging management of
 
loss of material due to crevice corrosion or fretting in chrome plate steel, stainless steel, or
 
nickel alloy component surfaces that are exposed to secondary treated water or steam
 
environments (i.e., to FW or steam).
The staff noted, that for other IP3 AMRs that the applicant had aligned to GALL AMR Item IV.D1-15 (e.g., those on loss of material of the IP3 SG antivibration bars and peripheral
 
aligning rings SG FW nozzle thermal sleeves), the applicant credited both its Water Chemistry
 
Control Program - Primary and Secondary Program and its Steam Generator Integrity Program
 
for aging management of loss of material in the component surfaces that are exposed to either
 
a treated water or steam environment, which is consistent with the recommendations in GALL
 
AMR IV.D1-15. The staff noted, however for the AMR on loss of material in the IP3 SG
 
secondary handhold cover RTD bosses, the applicant only credited its Water Chemistry Control
 
Program - Primary and Secondary Program to manage loss of material in the component
 
surfaces that are exposed to the secondary-side treated water environment (i.e., FW). The staff
 
noted that this was not consistent with the applicants aging management basis for the SG
 
antivibration bars and peripheral aligning rings or the SG FW nozzle thermal sleeves because
 
the applicant did not credit its Steam Generator Integrity Program as an additional AMP for
 
managing this aging effect. In Audit Item 209, the staff asked the applicant to provide its basis 3-256 why the Steam Generator Integrity Program had not been credited for the SG secondary handhold cover RTD bosses.
By letter dated December 18, 2007, the applicant amended its LRA to add the Steam Generator Integrity Program as an additional program (i.e., in addition to the Water Chemistry Control
 
Program - Primary and Secondary Program) to manage loss of material in both the IP3 SG
 
secondary handhold cover RTD bosses and IP3 SG secondary handhold cover RTD well. The
 
staff finds that the applicants amended AMR for managing loss of material in both the IP3 SG
 
secondary handhold cover RTD bosses and IP3 SG secondary handhold cover RTD well is
 
acceptable because it is consistent with the staff recommendations in GALL AMR IV.D1-15 in
 
that the applicant is crediting both its Water Chemistry Control Program - Primary and
 
Secondary Program and its Steam Generator Integrity Program to manage loss of material in
 
component surfaces that are exposed to the treated water environment.
The staff finds that the applicants amended AMR for managing loss of material in both the IP3 SG secondary handhold cover RTD bosses and IP3 SG secondary handhold cover RTD well is
 
acceptable because it is consistent with the staffs recommendations in GALL AMR IV.D1-15 that programs correspond to GALL AMP XI.M19, Steam Generator Tubing Integrity and GALL AMP XI.M2, Water Chemistry, be credited to manage loss of material in chrome plated steel, stainless steel or nickel alloy SG component surfaces that are exposed to either a secondary
 
treated water or steam environment. Audit Item 209 is resolved with respect to this AMR item.
3.1.2.1.8  Cracking in Stainless Steel SG Secondary Side Handhold RTD Wells
 
In LRA Table 3.1.2-4-IP3, the applicant includes its AMR item on management of cracking in the IP3 SG secondary side handhold RTD well, which is made from austenitic stainless steel. The
 
applicant aligned this to LRA AMR 3.1.1-74 and to AMR Item IV.D1-14 in GALL Report, Volume
 
2 (GALL AMR Item IV.D1-14). In this AMR, the applicant credited only its Water Chemistry
 
Control Program - Primary and Secondary Program to manage cracking in the stainless steel
 
component surfaces that are exposed to secondary treated water.
GALL AMR IV.D1-14 pertains to the management of cracking in chrome plated steel, stainless steel, or nickel alloy SG antivibration bars in PWRs with recirculating SGs. In this AMR, the staff recommends that programs corresponding to GALL AMP XI.M2, Water Chemistry, and GALL AMP XI.M19, Steam Generator Tube Integrity, be credited for aging management of cracking
 
due to SCC in chrome plated steel, stainless steel, or nickel alloy component surfaces that are
 
exposed to secondary treated water or steam environments.
The staff noted, that for other IP3 AMRs that the applicant had aligned to GALL AMR Item IV.D1-14 (e.g., those on cracking of the IP3 SG flow restrictor and flow baffle distribution
 
plate), the applicant credited both its Water Chemistry Control Program - Primary and
 
Secondary Program and its Steam Generator Integrity Program for aging management of
 
cracking in the component surfaces that are exposed to either treated water or steam, which is
 
consistent with the recommendations in GALL AMR IV.D1-14. In contrast, the staff noted that
 
for management of cracking in the IP3 SG secondary side handhold RTD well, the applicant
 
credited only its Water Chemistry Control Program - Primary and Secondary Program to
 
manage cracking in the stainless steel component surfaces that are exposed to treated water.
 
In Audit Item 210, the staff asked the applicant why the Steam Generator Integrity Program had
 
not been credited as an additional program to manage cracking in the IP3 SG secondary side
 
handhold RTD well.
3-257 The applicant responded to Audit Item 209 in a letter dated December 18, 2007. In this letter the applicant amended its LRA to add the Steam Generator Integrity Program as an additional
 
program (i.e., in addition to the Water Chemistry Control Program - Primary and Secondary
 
Program) to manage cracking in the IP3 SG secondary handhold cover RTD well. The staff
 
finds that the applicants amended AMR for managing cracking in the IP3 SG secondary
 
handhold cover RTD well is acceptable because it is consistent with the staffs recommendations in GALL AMR IV.D1-14 that programs correspond to GALL AMP XI.M19, Steam Generator Tubing Integrity and GALL AMP XI.M2, Water Chemistry, be credited to
 
manage cracking in chrome plated steel, stainless steel or nickel alloy SG component surfaces
 
that are exposed to either a secondary treated water or steam environment. Audit Item 209 is
 
resolved with respect to this AMR item.
3.1.2.1.9  Conclusion for AMRs Consistent with the GALL Report
 
The staff evaluated the applicants claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicants consideration of recent operating experience
 
and proposals for managing 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. 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 functions will be
 
maintained consistent with the CLB during the period of extended operation, as required by
 
10 CFR 54.21(a)(3). 3.1.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation is Recommended In LRA Section 3.1.2.2, the applicant further evaluates aging management, as recommended by the GALL Report, for the reactor vessel, internals, and reactor coolant system components and
 
provides information concerning how it will manage the following aging effects:  cumulative fatigue damage  loss of material due to general, pitting, and crevice corrosion  loss of fracture toughness due to neutron irradiation embrittlement  cracking due to SCC and 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 PWSCC  wall thinning due to flow-accelerated corrosion  changes in dimensions due to void swelling  cracking due to SCC and PWSCC  cracking due to SCC, PWSCC, and irradiation-assisted SCC  QA for aging management of nonsafety-related components 3-258 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 applicants evaluation. The staff determined whether the applicant
 
adequately addressed the issues for which further evaluation is recommended. The staff
 
reviewed the applicants further evaluations against the criteria contained in SRP-LR
 
Section 3.1.2.2. The staffs review of the applicants further evaluation follows.
3.1.2.2.1  Cumulative Fatigue Damage
 
LRA Section 3.1.2.2.1 stated that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the staffs
 
review of the applicants evaluation of this TLAA. However, since many of the RCS components
 
do not have fatigue usage factor calculations of their original design, Entergy will manage them
 
using aging management programs in accordance with 10CFR54.21(c)(iii). Therefore, the staff
 
assessments of these components are discussed below.
LRA Section 3.1.2.2.1 stated that, with the exception of the pressurizer support skirts, evaluation of the fatigue TLAA for the Class 1 portions of the reactor coolant pressure boundary
 
piping and components, including those for interconnecting systems, is discussed in LRA
 
Section 4.3.1. No fatigue analysis was required for the pressurizer support skirts. Cracking, including cracking due to fatigue, will be managed by the Inservice Inspection Program for the
 
pressurizer support skirts.
SRP-LR Section 3.1.2.2.1 states that [f]atigue is a time-limited aging analysis (TLAA) as defined in 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 10 CFR
 
54.21(c)(1). This TLAA is addressed separately in Section 4.3, 'Metal Fatigue Analysis,' of this
 
SRP-LR. For Westinghouse designed PWRs with recirculating SGs, SRP-LR Section 3.1.2.2.1
 
invokes the AMRs on cumulative fatigue damage in AMR Items 1, 5, 6, 7, 8, 9, and 10 of Table
 
1 to the GALL Report, Volume 1 and the plant-specific AMRs on cumulative fatigue damage
 
for reactor vessel (RV) components, reactor vessel internal (RVI) components, RCS piping and
 
pressurizer components, and SGs in Sections IV.A2, IV.B2, IVC2, and IV.D1 of the GALL
 
Report Volume 1. In these AMRs, the GALL Report recommends that the PWR applicants credit
 
their TLAAs on metal fatigue for management of cumulative fatigue damage in these
 
components.
The staff noted that instead of referring to the aging effect term cumulative fatigue damage, the applicants applicable AMRs on metal fatigue refer to the aging effect as cracking -
 
fatigue. The staff finds the slight difference in terminology to be acceptable because the
 
coalescence of any fatigue damage in the microstructure will manifest itself in the form of a
 
fatigue crack. Based on this assessment, the staff verified that the applicants AMRs on
 
management cracking -fatigue in the LRA are those that correspond to the staffs AMRs in the
 
GALL report which refer to management of cumulative fatigue damage.
The staff verified that the applicant credits its TLAA on metal fatigue, as given in LRA Section 4.3 and its subsections, for management of cumulative fatigue damage in the IP ASME Code
 
Class 1 RV components, RVI components, RCS piping, piping components, and piping
 
elements, and pressurizer components, with the exception of metal fatigue analyses for the
 
pressurizer support skirts.
3-259 SRP-LR Table 3.1.1, Item 7 addresses the TLAA for cumulative fatigue damage in steel and stainless steel RV support skirts and attachment welds in the RCS. The staff noted from LRA
 
Tables 3.1.2-1-IP2 and 3.1.2-1-IP3 line items that the reactor vessels are not supported by RV
 
support skirts, but instead use support pads that are welded to the underside of the primary inlet
 
and outlet nozzles as the means of RV support. By letter dated December 18, 2007, the
 
applicant responded to Audit Item 191A, and clarified that the support pads for the reactor
 
vessel are part of the inlet and outlet nozzle forgings and are evaluated as part of those
 
nozzles. The staff verified that that the metal fatigue analyses of the RV components, as
 
discussed in LRA Section 4.3.1.1, include cumulative usage factor inputs for the RV inlet and
 
outlet nozzles. Therefore, the staff finds that the management of the RV support pads is
 
consistent with the guidance in SRP-LR Section 3.1.2.2.1. The staff also finds that the LRA
 
does not need to include any AMR item on management of cumulative fatigue damage in RV
 
support skirts because the IP designs do not use this type of component for RV support.
The staff noted that in the response to Audit Item 191A, Entergy confirmed that the CLB does not include any fatigue analysis for the pressurizer support skirts. Based on this review, the staff
 
finds that the LRA does not need to include any AMR corresponding to GALL AMR IV.C2-10 on
 
cumulative fatigue damage of pressurizer integral supports but the CLB does not include any
 
fatigue analyses for these components at IP. Instead, the staff noted that the applicant is
 
crediting its Inservice Inspection Program to manage cracking of these components, including
 
the applicants aging effect of cracking - fatigue. The staff finds this to be an acceptable
 
alternative because it is in conformance with the staffs AMR on cracking of pressurizer integral
 
supports, as given in GALL AMR IV.C2-16.
LRA Tables 3.1.2-1-IP2, 3.1.2-1-IP3, 3.1.2-3-IP2, 3.1.2-3-IP3, 3.1.2-4-IP2, and 3.1.2-4-IP3 all indicate a TLAA line item referring to Table 3.1.1-7 for the RCS components. The LRA Table 2
 
line items associated with this TLAA do not include the support skirts and/or attachment welds
 
for SGs and reactor coolant pumps (RCP). In Audit Item 191c, the staff requested IPNG to
 
clarify how cracking - fatigue of the RCP and SG supports is managed. In its response, dated
 
December 18, 2007, Entergy stated that the SGs are supported by pads attached to the primary
 
channel heads and that the AMRs in LRA Tables 3.1.2-4-IP2 and 3.1.2-4-IP3 for the primary
 
channel heads (which include the integral pads) do not include any AMRs on cracking -fatigue
 
because the CLB does not include any fatigue analyses for these components. The staff verified
 
that the CLB does not include any fatigue analyses for the SG primary channel head support
 
pads. Based on this determination, the staff finds that the TLAA on metal fatigue of the Class 1
 
RCS piping components does not need to include any metal fatigue analysis for the SG primary
 
channel head support pads because the CLB does not include any metal fatigue analysis for
 
these components, and thus, the components are not subject to a metal fatigue TLAA under the
 
TLAA definition criteria that are provided in 10 CFR 54.3.
The staff also noted that in the IP design, the RCPs are supported by feet that are directly attached to the pump casings and that these components are within the scope of the AMRs in
 
LRA Tables 3.1.2-3-IP2 and 3.1.2-3-IP3. The staff verified that the CLB for IP does not include
 
any metal fatigue analyses for these RCP supports. Based on this determination, the staff finds
 
that the TLAA on metal fatigue of the Class 1 RCS piping components does not need to include
 
any metal fatigue analysis for the RCP supports (i.e., feet) because the IP CLB does not include
 
any metal fatigue analysis for these components and thus, the components are not subject to a
 
metal fatigue TLAA under the TLAA definition criteria of 10 CFR 54.3.
3-260 Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.1 criteria. For those line items that apply to LRA Section 3.1.2.2.1, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3).
3.1.2.2.2  Loss of Material Due to General, Pitting, and Crevice Corrosion
 
The staff reviewed LRA Section 3.1.2.2.2 against the criteria in SRP-LR Section 3.1.2.2.2.
  (1) LRA Section 3.1.2.2.2 addresses loss of material due to general, pitting, and crevice corrosion in steam generator steel components exposed to secondary feedwater and
 
steam, stating that the Water Chemistry Control - Primary and Secondary Program
 
manages this aging effect. The One-Time Inspection Program will confirm the
 
effectiveness of the Water Chemistry Control - Primary and Secondary Program by
 
inspection of a representative sample of components crediting this program, including
 
those in areas of stagnant flow.
SRP-LR Section 3.1.2.2.2 states that loss of material due to general, pitting, and crevice corrosion may occur in the steel PWR SG shell assembly exposed to secondary
 
feedwater and steam. Loss of material due to general, pitting, and crevice corrosion also
 
may occur in the steel top head enclosure (without cladding) top head nozzles (vent, top
 
head spray or reactor core isolation cooling, and spare) exposed to reactor coolant. The
 
existing program controls reactor water chemistry to mitigate corrosion. However, control
 
of water chemistry does not preclude loss of material due to pitting and crevice corrosion
 
at locations with stagnant flow conditions. Therefore, the effectiveness of water
 
chemistry control programs should be verified to ensure that corrosion does not occur.
 
The GALL Report recommends further evaluation of programs to verify the effectiveness
 
of water chemistry control programs. A one-time inspection of selected components at
 
susceptible locations is an acceptable method to determine whether an aging effect is
 
occurring or is slowly progressing such that the components intended functions will be
 
maintained during the period of extended operation.
LRA Table 3.1-1, Item 11, which addresses loss of material due to general, pitting, and crevice corrosion in the steel top head enclosure (without cladding) top head nozzles (vent, top head spray or reactor core isolation cooling, and spare) exposed to reactor
 
coolant, is identified as not applicable because it applies to boiling water reactors (BWRs) only. Because IP2 and IP3 are PWRs, the staff finds that this component/aging
 
effect combination does not apply to IP.
The staff noted that the SGs at IP2 and IP3 are Westinghouse Model 44F replacement SGs. The staff also noted that in LRA Tables 3.1.2-4-IP2 and 3.1.2-4-IP3, the applicant
 
aligned the following AMR line items for its SG components to LRA Table 1 AMR
 
Item 3.1.1-12 and to GALL AMR IV.D2-8 (R-224) for once-through SG secondary side
 
components: secondary side of the tubesheets, feedwater nozzles, secondary manways
 
and manway covers, secondary handholds and handhold covers, secondary SG shell
 
drain connection, secondary side instrument connections and SG blowdown piping, The
 
staff noted that in the applicant AMRs for these components, the applicant credited its
 
Water Chemistry Control Program - Primary and Secondary to manage loss of material 3-261 in the component surfaces that are exposed secondary treated water or steam. The staff also noted that the applicant did not credit its One-Time Inspection Program or apply
 
LRA AMR plant-specific Note 104,which states that the One-Time Inspection Program
 
will be used to verify the effectiveness of the Water Chemistry Control Program -
 
Primary and Secondary in managing loss of material in these components. In Audit Item
 
192, the staff asked the applicant to justify why the AMRs on loss of material in the
 
secondary side of these carbon steel SG components did not credit LRA AMP B.1.27, One-Time Inspection Program, to verify the effectiveness of the Water Chemistry Control
 
Program - Primary and Secondary in managing loss of material in the secondary side
 
surfaces of these carbon steel SG components.
By letter dated December 18, 2007, the applicant clarified that the One-Time Inspection Program is credited with verifying the effectiveness of Water Chemistry Control Program
 
- Primary and Secondary in managing loss of material in these secondary side SG
 
components. The applicant stated that it would amend the AMR items in LRA Table
 
3.1.2-4-IP2 and 3.1.2-4-IP3 on loss of material in secondary side SG components
 
referencing LRA Table 1 Item 3.1.1-12 and GALL AMR Item IV.D2-8 (R-224) to add
 
plant-specific AMR Note 104, which credits a one-time inspection for verification of the
 
effectiveness of the Water Chemistry Control Program - Primary and Secondary in
 
managing this aging effect.
The staff verified that, in its letter of December 18, 2007, the applicant amended the applicable AMRs for the secondary side SG tubesheets, feedwater nozzles, manways
 
and manway covers, handholds and handhold covers, shell drain connections, instrument connections, and blowdown piping to add LRA AMR Note 104 and to credit in
 
One-Time Inspection Program for verification of the effectiveness of the Water
 
Chemistry Control Program - Primary and Secondary in managing loss of material due
 
to pitting and crevice corrosion in the secondary side component surfaces that are
 
exposed to treated water. The staff finds that the amended AMRs are acceptable
 
because the AMPs credited for aging management are consistent with the staffs aging
 
management position that is recommended in SRP-LR Section 3.1.2.2.2, Item (1) and in
 
the GALL AMRs that are based on this SRP-LR Section.    (2) LRA Section 3.1.2.2.2 addresses loss of material due to general, crevice, and pitting corrosion in BWR isolation condenser components exposed to reactor coolant, stating
 
that this aging effect is not applicable to IP, which are PWRs.
SRP-LR Section 3.1.2.2.2 states that loss of material due to pitting and crevice corrosion may occur in stainless steel BWR isolation condenser components exposed to reactor
 
coolant. Loss of material due to general, pitting, and crevice corrosion may occur in steel
 
BWR isolation condenser components.
The staff finds that SRP-LR Section 3.1.2.2.2, Item (2) is not applicable to IP because IP2 and IP3 are PWRs, and the staff guidance in this SRP-LR section is only applicable
 
to BWRs that are designed with isolation condensers.    (3) LRA Section 3.1.2.2.2 addresses loss of material due to general, crevice, and pitting corrosion in reactor vessel shells, heads, and welds; flanges; nozzles; penetrations;
 
pressure housings; and safe ends, stating that this aging effect is not applicable to IP, which are PWRs.
3-262 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. This SRP-LR Section invokes AMR
 
14 in Table 1 of the GALL Report, Volume 1 and the associated AMRs in the GALL
 
Report, Volume 2 which are applicable to 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 in BWR-designed reactors.
The staff finds that SRP-LR Section 3.1.2.2.2, Item (3) is not applicable to IP because IP2 and IP3 are PWRs, and the staff guidance in this SRP-LR section is only applicable
 
to BWR-designed reactors.    (4) LRA Section 3.1.2.2.2 addresses loss of material due to general, pitting, and crevice corrosion in the steel steam generator shell and transition cone exposed to secondary
 
feedwater and steam, stating that the Inservice Inspection and Water Chemistry Control
- Primary and Secondary Programs manage this aging effect. IP steam generators have
 
been replaced. The replacement generators, Model 44Fs, have no high-stress region at
 
the shell to transition cone weld as described in NRC Information Notice (IN) 90-04 and, as such, require no additional inspection procedures.
SRP-LR Section 3.1.2.2.2 states that loss of material due to general, pitting, and crevice corrosion may occur in the steel PWR steam generator upper and lower shell and
 
transition cone exposed to secondary feedwater and steam. The existing program
 
controls chemistry to mitigate corrosion and inservice inspection (ISI) to detect loss of
 
material. The extent and schedule of the existing steam generator inspections are
 
designed to ensure that flaws cannot attain a depth sufficient to threaten the integrity of
 
the welds; however, according to IN 90-04, the program may not be sufficient to detect
 
pitting and crevice corrosion, if general and pitting corrosion of the shell is known to
 
occur. The GALL Report recommends augmented inspection to manage this aging
 
effect. Furthermore, the GALL Report clarifies that this issue is limited to Westinghouse
 
Model 44 and 51 steam generators with a high-stress region at the shell to transition
 
cone weld.
The staff noted that the staffs guidance in SRP-LR Section 3.1.2.2.2, Item (4) is applicable to only to Westinghouse SG Models 44 and 51 with high stress regions at the
 
shell to transition cone weld. The IP SGs were replaced with Westinghouse model 44F
 
units which do not have this transition weld susceptible to pitting and crevice corrosion.
 
Therefore, the staff determined that the IP SGs do not require any additional augmented
 
inspections of the SG shell-to-transition cone regions as recommended in SRP-LR
 
Section 3.1.2.2.2 or the GALL Report for Westinghouse Model 44 or 51 SG designs.
Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.2 criteria. For those line items that apply to LRA Section 3.1.2.2.2, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3).
3-263 3.1.2.2.3  Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement The staff reviewed LRA Section 3.1.2.2.3 against the criteria in SRP-LR Section 3.1.2.2.3.
  (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 staffs review of the applicants
 
evaluation of this TLAA.    (2) LRA Section 3.1.2.2.3 addresses loss of fracture toughness due to neutron irradiation embrittlement, stating that the Reactor Vessel Surveillance Program manages reduction
 
in fracture toughness due to neutron embrittlement of RV beltline materials to maintain
 
the pressure boundary function of the reactor pressure vessel for the period of extended
 
operation. The program evaluates radiation damage by pre- and post-irradiation testing
 
of Charpy V-notch and tensile specimens from the most limiting plate in the reactor
 
vessel core region with reports submitted as required by 10 CFR Part 50, Appendix H.
SRP-LR Section 3.1.2.2.3 states that loss of fracture toughness due to neutron irradiation embrittlement may occur in BWR and PWR reactor vessel beltline shell, nozzle, and welds exposed to reactor coolant and neutron flux. A reactor vessel
 
materials surveillance program monitors neutron irradiation embrittlement of the reactor
 
vessel. Reactor vessel surveillance programs are plant-specific, depending on matters
 
such as the composition of limiting materials, availability of surveillance capsules, and
 
projected fluence levels. In accordance with 10 CFR Part 50, Appendix H, an applicant is
 
required to submit its proposed withdrawal schedule for approval prior to
 
implementation. Untested capsules placed in storage must be maintained for future
 
insertion. Thus, further staff evaluation is required for license renewal. Specific recommendations for an acceptable AMP are provided in GALL Report Chapter XI, Section M31.
The staff reviewed the IP Reactor Vessel Surveillance Program that manages reduction in fracture toughness due to neutron embrittlement of the vessel beltline region material, excluding the vessel nozzles. During an onsite audit, the staff identified a statement in
 
WCAP-16212, Entergy Nuclear Operations, Incorporated, Indian Point Nuclear
 
Generating Unit No. 3, Stretch Power Uprate, License Amendment Request Package,
 
June 2004, that indicated that the typical fluence at the nozzle of an IP vintage vessel is
 
about 0.6 percent of the peak vessel fluence. Based on this statement, the staff was
 
concerned that the neutron fluence for the nozzle shell course could exceed
 
1x10 17 n/cm 2. Therefore, via a telephone conference call, the staff requested that the applicant perform a neutron fluence evaluation for the components in the nozzle shell
 
course. SER Section 4.2.2.2 documents the staffs evaluation of the applicants analysis.
Based on the reviews discussed in the paragraphs above
, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.3 criteria. For those line items that apply to
 
LRA Section 3.1.2.2.3, the staff determines that the LRA is consistent with the GALL Report and
 
that the applicant has demonstrated that the effects of aging will be adequately managed so
 
that the intended functions will be maintained consistent with the CLB during the period of
 
extended operation, as required by 10 CFR 54.21(a)(3).
3-264 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 criteria in SRP-LR Section 3.1.2.2.4.
  (1) LRA Section 3.1.2.2.4 addresses cracking due to SCC and intergranular SCC (IGSCC) in BWR vessel leak detection lines, stating that this aging effect is not applicable to IP, which are PWRs.
SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCC may occur in the stainless steel and nickel alloy BWR top head enclosure vessel flange leak detection
 
lines.The staff finds that SRP-LR Section 3.1.2.2.4, Item (1) is not applicable to IP2 and IP3 because IP2 and IP3 are PWRs, and the staff guidance in this SRP-LR section is only applicable to BWR-designed reactors.    (2) LRA Section 3.1.2.2.4 addresses cracking due to SCC and IGSCC in BWR isolation condenser components, stating that this aging effect is not applicable to IP, which are
 
PWRs.SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCC may occur in stainless steel BWR isolation condenser components exposed to reactor coolant.
The staff finds that SRP-LR Section 3.1.2.2.4, Item (2) is not applicable to IP2 and IP3 because IP2 and IP3 are PWRs, and the staff guidance in this SRP-LR section is only
 
applicable to BWR-designed reactors that are designed with isolation condensers.
Based on the above, the staff concludes that the staffs guidance criteria of SRP-LR Section 3.1.2.2.4, Items (1) and (2) do not apply to IP2 and IP3 because the guidance is
 
applicable to BWR-designed reactors and because IP2 and IP3 are PWRs.
3.1.2.2.5  Crack Growth Due to Cyclic Loading
 
The staff reviewed LRA Section 3.1.2.2.5 against the criteria in SRP-LR Section 3.1.2.2.5.
 
LRA Section 3.1.2.2.5 states that growth of intergranular separations (underclad cracks) in the heat-affected zone under austenitic steel cladding is not an applicable aging effect because the
 
IP vessel shells are not composed of SA 508-CI 2 forgings with stainless steel cladding
 
deposited with a high heat input welding process.
SRP-LR Section 3.1.2.2.5 states that crack growth due to cyclic loading could occur in reactor vessel shell forgings clad with stainless steel using a high-heat-input welding process. Growth
 
of intergranular separations (underclad cracks) in the heat affected zone under austenitic
 
stainless steel cladding is a TLAA to be evaluated for the period of extended operation for all
 
SA 508-Cl 2 forgings where the cladding was deposited with a high heat input welding process.
 
The methodology for evaluating the underclad flaw should be consistent with the current well-established flaw evaluation procedure and criterion in the ASME Section XI Code. See the
 
SRP-LR, Section 4.7, Other Plant-Specific Time-Limited Aging Analysis, for generic guidance
 
for meeting the requirements of 10 CFR 54.21(c).
3-265 The staff confirmed that, in Table 5.1-2 of WCAP-16157-NP, Westinghouse Electric Company reports that the IP2 RV shells are fabricated from SA-533 alloy steel plate materials, and in
 
WCAP-16251-NP, Revision 0, Westinghouse Electric Company reports that the IP3 RV shells
 
are fabricated from SA-302 Grade B alloy steel plate materials. Based on this review, the staff
 
finds that the applicant has provided an acceptable basis for concluding that the staffs guidance
 
on RV underclad cracking, as given in SRP-LR Section 3.1.2.2.5, is not applicable to IP
 
because the IP2 and IP3 RV shells are not fabricated from SA 508, Class 2 or Class 2 alloy
 
steel forging materials.
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 change in dimensions (void swelling) that could occur in stainless steel and
 
nickel alloy RVI components exposed to reactor coolant and neutron flux, stating that to manage
 
loss of fracture toughness in such components, Entergy will (1) participate in industry programs
 
for investigating and managing aging effects on reactor internals, (2) evaluate and implement
 
the results of the industry programs pertinent to reactor internals, and (3) upon completion of
 
these programs but not less than 24 months before the period of extended operation, submit an
 
inspection plan for RVI to the staff for review and approval. This commitment is in the UFSAR
 
Supplement, LRA Appendix A, Sections A.2.1.41 and A.3.1.41.
SRP-LR Section 3.1.2.2.6 states that loss of fracture toughness due to neutron irradiation embrittlement and void swelling may occur in stainless steel and nickel alloy reactor vessel
 
internals components exposed to reactor coolant and neutron flux. The GALL Report
 
recommends no further AMR if the applicant commits in the FSAR supplement (1) to participate
 
in industry programs for investigating and managing aging effects on reactor internals, (2) to
 
evaluate and implement the results of the industry programs as applicable to the reactor
 
internals, and (3) upon completion of these programs, but not less than 24 months before
 
entering the period of extended operation, to submit an inspection plan for reactor internals to
 
the staff for review and approval.
For Westinghouse-designed reactor vessel internals, SRP-LR Section 3.1.2.2.6 refers to the staffs guidance in AMR 22 of Table 1 to the GALL Report, Volume 1, and in GALL AMRs IV.B2-
 
3, IV.B2-6, IV.B2-9, IV.B2-17, IV.B2-18, and IV.B2-22. These AMRs are applicable to the
 
management of loss of fracture toughness due to neutron irradiation embrittlement and/or void
 
swelling in Westinghouse-designed RVI core baffle/former assembly plates; core baffle/former
 
assembly bolts and screws; core barrel (CB), CB flange, CB outlet nozzles, and thermal shield;
 
lower internals assembly fuel alignment pins, lower support plate column bolts, and clevis insert
 
bolts; lower internals assembly core plate; and lower internals assembly - lower support forging
 
or castings and lower support columns.
The commitment that is recommended by the staff includes a provision for PWR applicants to submit an inspection plan for their RVI components that is based on the industrys augmented
 
inspection program recommendations for PWR RVI components to the NRC for review and
 
approval at least two years prior to entering the period of extended operation. The staff verified
 
that LRA Tables 3.1.2-2-IP2 and 3.1.2-2-IP3 include all of the appropriate AMRs on loss of 3-266 fracture toughness due neutron irradiation embrittlement and/or void swelling for the various IP2 and IP3 RVI components The staff verified that Entergy has made the applicable commitment for IP2 and IP3 in Commitment 30, which was provided in Entergy letter dated March 24, 2008, and included in
 
UFSAR Supplements A.2.1.41 and A.3.1.41 for the IP2 PWR Vessel Internals Program and the
 
IP3 PWR Vessel Internals Program, respectively.
Thus, based on this review, the staff finds that the applicant has provided an acceptable basis for using Commitment 30 as its basis for aging management of loss of fracture toughness due
 
to neutron irradiation embrittlement and/or void swelling in these IP2 and IP3 RVI components.
 
The staff confirmed that Entergy has committed to participate in industry programs for
 
investigating and managing aging effects on IP2 and IP3 RVI components in the UFSAR
 
Supplement Sections A.2.1.41 and A.3.1.41, and therefore, the staff finds this acceptable.
Based on the applicants commitment (Commitment 30),,the staff concludes that the applicant meets SRP-LR Section 3.1.2.2.6 criteria. For those line items that apply to LRA
 
Section 3.1.2.2.6, the staff determines that the LRA is consistent with the GALL Report and that
 
the applicant has demonstrated that the effects of aging will be adequately managed so that the
 
intended functions will be maintained consistent with the CLB during the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
3.1.2.2.7  Cracking Due to Stress Corrosion Cracking
 
The staff reviewed LRA Section 3.1.2.2.7 against the criteria in SRP-LR Section 3.1.2.2.7.
  (1) LRA Section 3.1.2.2.7 addresses cracking due to SCC in the stainless steel bottom-mounted instrument (BMI) guide tube components exposed to reactor coolant, stating
 
that the Inservice Inspection and Water Chemistry Control - Primary and Secondary
 
Programs manages this aging effect by minimizing contaminants which promote SCC.
 
The Inservice Inspection Program provides periodic pressure testing of these
 
components.
SRP-LR Section 3.1.2.2.7, Item (1) states that cracking due to SCC may occur in the PWR stainless steel reactor vessel flange leak detection lines and BMI guide tubes
 
exposed to reactor coolant. The GALL Report recommends that a plant-specific AMP be
 
evaluated to ensure that this aging effect is adequately managed.
The staff verified that in LRA Table 3.1.2-1-IP2 and 3.1.2-1-IP3, the applicant credits its Water Chemistry Control - Primary and Secondary Program and Inservice Inspection
 
Program to manage cracking in stainless steel BMI guide tube components, including
 
the BMI guide tubes, BMI seal tables and BMI flux thimble tube bullet plugs, which are
 
ASME Code Class 1 components. The staff also verified that the applicants Inservice
 
Inspection Program credits periodic ISI inspections and pressure testing ensures that
 
the cracking of these components are not occurring and the water chemistry program
 
manages the contaminants that are detrimental to SCC in stainless steel will be controlled by the applicant. The staff verified that, in GALL AMP XI.M1, ASME Section XI Inservice Inspection, Subsection IWB, IWC, and IWD, the staff endorses inservice
 
inspection programs as acceptable condition monitoring AMPs for managing the aging
 
effects (including cracking) that are applicable ASME Code Class components. The staff 3-267verified that, in GALL AMP XI.M2 Water Chemistry, the staff endorses water chemistry control programs as acceptable preventive/mitigative AMPs for controlling the water
 
impurities that may induce aging effects (including cracking) in plant components (included ASME Code Class components) that are exposed to water-based coolants (i.e., treated water-type environments).
Based on this review, the staff finds that the applicant has provided an acceptable basis for crediting of the Inservice Inspection Program and the Water Chemistry Control
 
Program - Primary and Secondary to manage cracking in these stainless steel BMI
 
components because it conforms to the staffs recommendation that a plant-specific
 
AMP or AMPs be evaluated and credited for aging management of cracking in the
 
components, and because the crediting of these program is consistent with the bases in GALL AMP XI.M1 and XI.M2 for ASME Code Class components.
With regard to RV flange leak detection lines, the staff noted that the applicant identified that the RV flange leakage detection lines are composed of nickel alloy. As a result of
 
this fabrication material, the AMR items in LRA Table 3.1.2-1-IP2 and 3.1.2-1-IP3 for the
 
RV flange leakage detection lines are aligned to LRA Section 3.1.2.2.13, AMR Item 31 in
 
LRA Table 3.1.1, and GALL IV.C2-13 for nickel alloy ASME Code Class 1 piping less
 
than 4-inch NPS. The staff evaluates the applicants AMRs on management of cracking
 
in the nickel alloy RV flange leakage detection lines in SER Section 3.1.2.2.13.    (2) LRA Section 3.1.2.2.7 addresses cracking due to SCC in CASS reactor coolant system piping, piping components, and piping elements exposed to reactor coolant, stating that
 
the Water Chemistry Control - Primary and Secondary and Thermal Aging Embrittlement
 
of Cast Austenitic Stainless Steel (CASS) programs manage this aging effect by (a)
 
determining the susceptibility of CASS components to thermal aging embrittlement
 
based on casting method, molybdenum content, and percent ferrite, and (b)
 
accomplishing aging management for potentially susceptible components through either
 
enhanced volumetric examination or plant- or component-specific flaw tolerance
 
evaluation. The Inservice Inspection Program supplements these programs for some
 
components.
SRP-LR Section 3.1.2.2.7, Item (2) states that cracking due to SCC may occur in Class 1 PWR CASS reactor coolant system piping, piping components, and piping
 
elements exposed to reactor coolant. The existing program controls water chemistry to
 
mitigate SCC. However SCC may occur in CASS components that do not meet the
 
NUREG-0313 guidelines with regard to ferrite and carbon content. The GALL Report
 
recommends further evaluation of a plant-specific program for these components to
 
ensure this aging effect is adequately managed.
The staff noted that in LRA Tables 3.1.2-3-IP2 and 3.1.2-3-IP3, the applicant included the following AMRs on cracking of CASS RCS piping, piping components, and piping
 
elements that aligned to SRP-LR Section 3.1.2.2.7, Item (2) and the staffs guidance in
 
GALL AMR IV.C2-3:  Class 1 RCS piping elements made from CASS, including ASME Code Class 1
 
CASS elbows, flange components, scoops and tees  The CASS pressurizer spray head, which in not categorized as an ASME Code
 
Class component 3-268 For the ASME Code Class 1 CASS elbows, flange components, scoops and tees, the staff verified that the applicant identified the components as exceeding the NUREG-0313
 
acceptance criteria for cracking, and that the applicants AMR credited a combination of
 
the Water Chemistry Program - Primary and Secondary, the Inservice Inspection
 
Program, and Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)
 
Program for management of cracking due to SCC in the component surfaces that are
 
exposed to the reactor coolant. In contrast, for the CASS pressurizer spray head, the
 
staff noted that the applicant only credited the Water Chemistry Program - Primary and
 
Secondary and Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)
 
Program for management of this aging effect.
The staff verified that the applicants Water Chemistry Program - Primary and Secondary is credited as an preventive and mitigative-based AMP for managing aging
 
effects, including SCC, on metallic components from corrosion. The AMP is consistent with the staffs recommended program element criteria in GALL AMP XI.M2, Water
 
Chemistry. Based on this review, the staff finds that the applicants crediting of the
 
Water Chemistry Program - Primary and Secondary for the ASME Code Class 1 CASS
 
elbows, flange components, scoops and tees, and for the non-ASME Code Class CASS
 
pressurizer spray head, is consistent with the staff recommended position in SRP-LR
 
Section 3.1.2.2.7, Item 2 and in GALL AMR IV.C2-3, and is acceptable. The staffs
 
evaluation of the Water Chemistry Program - Primary and Secondary is given in SER
 
Section 3.0.3.2.17. The staffs evaluation of this program includes its basis for accepting
 
that the Water Chemistry Program - Primary and Secondary, when enhanced, is an
 
acceptable program for preventing or mitigating the aging effects that are applicable to
 
metallic components as a result of corrosion. The staffs evaluation includes the basis for
 
accepting this program for the management of cracking in these CASS components.
The staff noted that the applicants Inservice Inspection Program (described in LRA Section B.1.18) is credited, in part, as an acceptable plant-specific condition monitoring
 
program for the management of cracking in ASME Code Class 1 components, including
 
ASME Code Class 1 CASS components. However, the staff noted that the inspections
 
credited under this program might be either ultrasonic test (UT) examinations or
 
enhanced VT-1 visual examinations. The staff sought additional clarification on how a
 
UT method for CASS material would be capable of differentiating between a UT reflector
 
that results from a actual flaw indication in the material as opposed to a UT reflector that
 
results as a background noise signal from the complexity of the CASS microstructure or
 
the complexity of the component geometry.
By letter dated December 30, 2008, the staff issued RAI 3.1.2.2.7.2-1, Part A, and asked the applicant to clarify how current state of the art UT methods, as implemented through
 
the Inservice Inspection Program or other programs, would be adequate to detect cracks
 
in CASS materials, or else to credit an alternative non-destructive inspection technique
 
for the detection of cracking in the CASS components at IP if the current state-of-the-art
 
UT techniques are incapable of detecting cracks in the CASS materials. This was
 
identified as Open Item 3.1.2.2.7.2-1, Part A.
The applicant responded to RAI 3.1.2.2.7.2-1, Part A in a letter dated January 27, 2009.
In this response, the applicant stated that current volumetric examination methods, (including UT) are not currently reliable for the detection of cracking in CASS materials 3-269 and therefore are not credited for aging management of cracking in the CASS components, including the CASS pressurizer spray heads. Thus, the staff noted that the
 
applicant is currently relying on enhanced VT-1 visual examination methods to manage
 
cracking in the CASS pressurizer spray heads. The staff finds this to be acceptable
 
because current UT technology methods are currently unable to differentiate between
 
UT reflections that result from actual flaw indications in the CASS material and those UT
 
reflections that result from a background noise signal due to the complexity of the CASS microstructure. In addition, ASME Code, Section XI lists VT-1 visual examination
 
methods as acceptable examination techniques for the detection of cracking. RAI
 
3.1.2.2.7.2-1, Part A is resolved and Open Item 3.1.2.2.7.2-1, Part A is closed with
 
respect to the inspection techniques that are credited to manage cracking in the CASS
 
pressurizer spray heads.
The staff also noted that the applicants Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program (LRA Section B.1.37) was credited for: (1) evaluation of thermal aging embrittlement in both the Code Class 1 CASS elbows, flanges, tees, and
 
scoops, and in the non-ASME Code Class CASS pressurizer spray head, and (2)
 
detection of cracking in the non-ASME Code Class CASS pressurizer spray head. The
 
staff verified that the applicants Thermal Aging Embrittlement of Cast Austenitic
 
Stainless Steel (CASS) Program is credited as an acceptable condition monitoring
 
program for the management of reduction of fracture toughness as a result of thermal
 
aging in CASS components. The staff also verified that this program has been identified
 
as a new AMP that is consistent with the staffs recommended program element criteria in GALL AMP XI.M12, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS).The staff also noted that the applicants program includes a flaw evaluation methodology for CASS components that are susceptible to thermal aging embrittlement. This AMP
 
may propose UT or enhanced VT-1 visual examinations as an indirect basis for
 
managing loss/reduction of fracture toughness as a result of thermal aging. However, the staff noted that the applicants program is not specifically credited for the
 
management of cracking in CASS components. Thus, while the applicants Thermal
 
Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program could be used
 
as an acceptable basis for meeting the staffs flaw evaluation methodology for CASS
 
components that are susceptible to thermal aging embrittlement criterion in GALL AMR
 
IV.C2-3, the staff noted that the program may not be valid to manage cracking in these
 
components because the aging effect addressed by the corresponding program in GALL AMP XI.M12 is limited to management of loss/reduction of fracture toughness in CASS
 
components.
By letter dated December 30, 2008, the staff issued RAI 3.1.2.2.7.2-1, Part B, and asked the applicant to justify its basis crediting AMP B.1.37, Thermal Aging Embrittlement of
 
Cast Austenitic Stainless Steel (CASS) Program, to manage and detect for cracking in the CASS pressurizer spray heads at IP2 and IP3; GALL AMP XI.M12 only credits this
 
type of program for management of reduction or fracture toughness in components
 
made from CASS and the program may not actually be performing inspections of this
 
component (i.e., the program has the option only to do the flaw tolerance evaluation
 
without implementation of either a UT or EVT-1 examination). This was identified as
 
Open Item 3.1.2.2.7.2-1, Part B.
3-270 The applicant responded to RAI 3.1.2.2.7.2-1, Part A in a letter dated January 27, 2009.
In this response, the applicant stated that the Water Chemistry Program is credited for
 
the management of cracking in the CASS pressurizer spray heads and that the One-
 
Time Inspection Program will be used to verify the effectiveness of the Water Chemistry
 
Program in managing cracking of these components. The staff noted that the applicants
 
response to RAI 3.1.2.2.7.2-1 clarified that this one-time inspection will be done using
 
enhanced VT-1 techniques (EVT-1). The staff finds this to be acceptable because it is in
 
conformance with the recommend AMPs for managing cracking in CASS pressurizers in
 
GALL AMR IV.C2-17, and with the recommended inspection methods in GALL AMP XI.M12 for detecting cracking in CASS materials. RAI 3.1.2.2.7.2-1, Part B is resolved
 
and Open Item 3.1.2.2.7.2-1, Part B is closed.
Based on the programs identified above, pending acceptable resolution of Open Item 3.1.2.2.7.2-1, Parts A and B, the staff concludes that the applicants programs meet
 
SRP-LR Section 3.1.2.2.7 criteria. For those line items that apply to LRA Section 3.1.2.2.7, pending acceptable resolution of Open Item 3.1.2.2.7.2-1, Parts A and B, the staff determines
 
that the LRA is consistent with the GALL Report and that the applicant has demonstrated that
 
the effects of aging will be adequately managed so that the intended functions will be
 
maintained consistent with the CLB during the period of extended operation, as required by
 
10 CFR 54.21(a)(3).
3.1.2.2.8  Cracking Due to Cyclic Loading
 
The staff reviewed LRA Section 3.1.2.2.8 against the 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 BWR jet pump sensing lines, stating that this aging effect is not applicable to IP, which are PWRs.
SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in the stainless steel BWR jet pump sensing lines.
The staff verified that SRP-LR Section 3.1.2.2.8, Item (1) is not applicable to IP2 and IP3 because IP2 and IP3 are PWRs and the staff guidance in this SRP-LR section is only
 
applicable to BWR-designed reactors that are designed with stainless steel jet pump
 
sensing lines.    (2) LRA Section 3.1.2.2.8 addresses cracking due to cyclic loading in BWR isolation condenser components, stating that this aging effect is not applicable to IP, which are
 
PWRs.SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in steel and stainless steel BWR isolation condenser components exposed to reactor coolant.
The staff verified that SRP-LR Section 3.1.2.2.8, Item (2) is not applicable to IP2 and IP3 because IP2 and IP3 are PWRs and the staff guidance in this SRP-LR section is only
 
applicable to BWR-designed reactors that are designed with isolation condensers.
Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.8 criteria do not apply to the IP2 and IP3 LRA.
3-271 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 (creep), stating that this aging effect would be a concern only in very high temperature (more than 700&deg;F)
 
applications as stated in ASME Code, Section II, Part D, Table 4. No IP internals components
 
operate at more than 700&deg;F. Therefore, loss of preload due to stress relaxation (creep) is not an
 
applicable aging effect for reactor vessel internals components. Nevertheless, loss of preload of
 
stainless steel and nickel alloy reactor vessel internals components will be managed to the
 
extent that industry-developed reactor vessel internals AMPs address the aging effect. The
 
applicants commitment to these programs is in the UFSAR Supplement, LRA Appendix A, Sections A.2.1.41 and A.3.1.41.
SRP-LR Section 3.1.2.2.9 states that loss of preload due to stress relaxation may occur in stainless steel and nickel alloy PWR RVI screws, bolts, tie rods, and hold-down springs
 
exposed to reactor coolant. The GALL Report recommends no further AMR if the applicant
 
commits in the FSAR supplement (1) to participate in the industry programs for investigating
 
and managing aging effects on reactor internals, (2) to evaluate and implement the results of
 
the industry programs as applicable to the reactor internals, and (3) upon completion of these
 
programs, but not less than 24 months before entering the period of extended operation, to
 
submit an inspection plan for reactor internals to the staff for review and approval.
For Westinghouse-designed RVI, SRP-LR Section 3.1.2.2.9 refers to the staffs guidance in AMR 27 of Table 1 to the GALL Report, Volume 1, and in GALL AMRs IV.B2-5, IV.B2-14, IV.B2-
 
25, IV.B2-33, and IV.B2-38, as applicable to the management of loss of preload due to stress
 
relaxation in Westinghouse-designed RVI baffle/former bolts, clevis insert bolts, lower support
 
plate column bolts, upper internals assembly hold-down springs, and upper support column
 
bolts.The staff verified that Entergy has made the applicable commitment for these IP2 and IP3 AMRs in Commitment 30, which was provided in a letter dated March 24, 2008, and included in
 
UFSAR Supplements A.2.1.41 and A.3.1.41 for the IP2 and IP3 PWR Vessel Internals
 
Programs, respectively.
Thus, based on this review, the staff finds that the applicant has provided an acceptable basis for using Commitment 30 as its basis for aging management of loss of preload due to stress
 
relaxation in the RVI bolting, hold-down springs and fastener components at IP2 and IP3
 
because the AMRs for the components are in conformance with the staffs recommended aging
 
management position in GALL AMRs IV.B2-5, IV.B2-14, IV.B2-25, IV.B2-33, and IV.B2-38.
Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.9 criteria. For those line items that apply to LRA Section 3.1.2.2.9, the
 
staff determines that the LRA is consistent with the GALL Report, and that the applicants
 
Commitment 30 will adequately address management of loss of preload in the RVI bolting, hold-
 
down springs, and fasteners so that the intended functions will be maintained consistent with
 
the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-272 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 that could occur in steel steam generator feedwater impingement plates and supports exposed to secondary feedwater, stating that this aging effect is not applicable because the IP SG design employs no feedwater
 
impingement plate.
SRP-LR Section 3.1.2.2.10 states that loss of material due to erosion may occur in steel steam generator feedwater impingement plates and supports exposed to secondary feedwater.
The staff verified that the replacement steam generators (SGs) at IP are Westinghouse Model 44F SGs and that this SG design does not include steel SG impingement plates or supports.
 
Thus, based on this review, the staff finds that the applicant has provided an acceptable basis
 
for concluding that the staffs recommended guidance in SRP-LR Section 3.1.2.2.10 is not
 
applicable to the IP SGs because the new SGs are not designed with feedwater impingement
 
plates and supports that are exposed to secondary water.
Based on the above, the staff concludes that recommended guidance in SRP-LR Section 3.1.2.2.10 does not apply to IP.
3.1.2.2.11  Cracking Due to Flow-Induced Vibration
 
The staff reviewed LRA Section 3.1.2.2.11 against the criteria in SRP-LR Section 3.1.2.2.11.
 
LRA Section 3.1.2.2.11 addresses cracking due to flow-induced vibration of BWR steam dryers by stating that this aging effect is not applicable to IP, which are PWRs.
SRP-LR Section 3.1.2.2.11 states that cracking due to flow-induced vibration could occur for the BWR stainless steel steam dryers exposed to reactor coolant.
The staff finds that SRP-LR Section 3.1.2.2.11 is not applicable to IP because IP2 and IP3 are PWRs and the staff guidance in this SRP-LR section is only applicable to the design of steam
 
dryers in BWR-designed reactors.
Based on the above, the staff concludes that the guidance in SRP-LR Section 3.1.2.2.11 does not apply to IP.
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 irradiation-assisted stress corrosion cracking (IASCC) in PWR stainless steel reactor vessel internal (RVI) components
 
exposed to reactor coolant, stating that, to manage cracking such components, Entergy
 
maintains the Water Chemistry Control - Primary and Secondary Program and will (1)
 
participate in the industry programs for investigating and managing aging effects on reactor
 
internals; (2) evaluate and implement the results of the industry programs as applicable to the 3-273 reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals
 
to the staff for review and approval. The applicants commitment to these programs is in the
 
UFSAR Supplement, LRA Appendix A, Sections A.2.1.41 and A.3.1.41.
SRP-LR Section 3.1.2.2.12 states that SCC and IASCC may occur in PWR stainless steel reactor internals exposed to reactor coolant. The existing program controls water chemistry to
 
mitigate these aging effects. The GALL Report recommends no further AMR if the applicant
 
commits in the FSAR supplement (1) to participate in the industry programs for investigating
 
and managing aging effects on reactor internals, (2) to evaluate and implement the results of
 
the industry programs as applicable to the reactor internals, and (3) upon completion of these
 
programs, but not less than 24 months before entering the period of extended operation, to
 
submit an inspection plan for reactor internals to the staff for review and approval.
The staff verified that Entergy has made the applicable commitment for these AMRs in Commitment 30, which was provided in a letter dated March 24, 2008, and included in UFSAR
 
Supplements A.2.1.41 and A.3.1.41 for the IP2 and IP3 PWR Vessel Internals Programs, respectively.
Thus, based on this review, the staff finds that the applicant has provided an acceptable basis for using Commitment 30 as its basis for aging management of cracking due to SCC or IASCC
 
in these RVI components because the AMRs for the components are in conformance with the
 
staffs recommended aging management position in SRP-LR Section 3.1.2.2.12 and the
 
aforementioned AMRs in GALL AMRs IV.B2-2, IV.B2-8, IV.B2-10, IV.B2-12, IV.B2-24, IV.B2-30, IV.B2-36, and IV.B2-42.
Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.12 criteria. For those line items that apply to LRA Section 3.1.2.2.12, the staff determines that the LRA is consistent with the GALL Report and that the applicants
 
Commitment 30 will adequately address management cracking of the RVI components so that
 
the intended functions will be maintained consistent with the CLB during the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
3.1.2.2.13  Cracking Due to Primary Water Stress Corrosion Cracking
 
The staff reviewed LRA Section 3.1.2.2.13 against the criteria in SRP-LR Section 3.1.2.2.13.
 
LRA Section 3.1.2.2.13 addresses cracking due to PWSCC, stating that the Water Chemistry Control - Primary and Secondary, Inservice Inspection, and Nickel Alloy Inspection programs
 
manage this aging effect for most nickel alloy components. The Nickel Alloy Inspection Program
 
implements applicable NRC orders and will implement applicable (1) bulletins and generic
 
letters and (2) staff-accepted industry guidelines. UFSAR Supplement Sections A.2.1.20 and
 
A.3.1.20 include this commitment.
SRP-LR Section 3.1.2.2.13 states that cracking due to PWSCC may occur in PWR components made of nickel alloy and steel with nickel alloy cladding, including reactor coolant pressure
 
boundary components and penetrations inside the reactor coolant system such as pressurizer
 
heater sheathes and sleeves, nozzles, and other internal components. Except for reactor vessel upper head nozzles and penetrations, the GALL Report recommends ASME Code, Section XI
 
ISI (for Class 1 components) and control of water chemistry. For nickel alloy components, no 3-274 further AMR is necessary if the applicant complies with applicable NRC orders and commits in the FSAR supplement to implement applicable (1) bulletins and generic letters, and (2) staff-
 
accepted industry guidelines.
For Westinghouse-designed PWRs with recirculating SGs, SRP-LR Section 3.1.2.2.13 invokes AMR Item 31 in Table 1 of the GALL Report, Volume 1 and AMR Items IV.A2-12, IV.A2-19, IV.C2-13, IV.C2-21, IV.C2-24, and IV.D1-4, as applicable to the management of cracking due to
 
PWSCC in nickel alloy RV core support pads/lugs; RV bottom mounted instrumentation (BMI)
 
tubes; RCS piping, piping components and piping elements; pressurizer instrumentation
 
nozzles, heater sheaths and sleeves, heater bundle diaphragm plates, manways and flanges;
 
pressurizer surge and steam space nozzles and welds; and SG instrument penetrations and
 
primary side nozzles, safe ends, and welds.
The staff noted that of the possible nickel alloy components listed in the GALL AMRs that are invoked by this SRP-LR item, the Table 2 LRA Tables for the IP2 and IP3 RCS designs only include the following nickel alloy components:  RV core support pads/lugs (Refer to LRA Tables 3.1.2-1-IP2 and 3.1.2-1-IP3)  RV BMI tubes (Refer to LRA Tables 3.1.2-1-IP2 and 3.1.2-1-IP3)  ASME Code Class 1 piping, piping components, and piping elements (Refer to LRA
 
Tables 3.1.2-3-IP2 and 3.1.2-3-IP3)
The staff verified that the applicant appropriately aligned its AMRs for these nickel alloy components to LRA AMR 3.1.1-31, which credits the Water Chemistry Control Program -
 
Primary and Secondary, the Inservice Inspection Program, and the Nickel Alloy Inspection
 
Program to manage PWSCC-induced cracking in the nickel alloy component surfaces that are
 
exposed to the borated treated water environment of the reactor coolant. The staff finds this to
 
be acceptable because it is in conformance with recommendations for aging management in
 
AMR Item 31 in Table 1 of the GALL Report, Volume 1. The staff also verified that for the AMRs
 
on cracking of the nickel alloy RV BMI tubes and nickel alloy ASME Code Class 1 piping, piping components, and piping elements, the applicant credited its Water Chemistry Control Program -
 
Primary and Secondary, Inservice Inspection Program, and Nickel Alloy Inspection Program to
 
manage PWSCC-induced cracking in the nickel alloy component surfaces that are exposed to
 
the treated water environment of the reactor coolant. The staff noted that the AMPs credited for
 
aging management of cracking due to PWSCC is in conformance with the staffs recommended
 
aging management position and the AMPs that are recommended for aging management in
 
SRP-LR Section 3.1.2.2.13 and GALL AMRs IV.A2-19, and IV.C2-13. Based on this review, the
 
staff finds that the crediting of these AMPs for management of cracking in the nickel alloy RV
 
BMI tubes and nickel alloy ASME Code Class 1 piping, piping components, and piping elements
 
is acceptable because it is in conformance with the AMPs that are recommended for aging
 
management in SRP-LR Section 3.1.2.2.13 and in GALL AMRs IV.A2-19 and IV.C2-13.
The staff noted that in the applicants letter of December 18, 2007, the applicant amended its aging management basis in LRA AMR 3.1.1-31 and in the AMRs in LRA Tables 3.1.2-1-IP2 and
 
3.1.2-1-IP3 to credit its Water Chemistry Control Program - Primary and Secondary, its
 
Inservice Inspection Program, and its Nickel Alloy Inspection Program to manage cracking of its
 
RV internals core support lugs (pads). GALL AMR IV.A2-12 recommends that AMPs corresponding to GALL AMP XI.M2, Water Chemistry, and XI.M1, ASME Section XI Inservice
 
Inspection, Subsections, IWB, IWC, and IWD, be credited to manage cracking in RV core 3-275 support pads or lugs. In addition, for RV core support pads or lugs that are made of nickel-alloy materials, GALL AMR IV.A2-12 recommends that PWR applicant provide a commitment on the
 
FSAR supplement to submit a plant-specific AMP to implement applicable (1) Bulletins and
 
Generic Letters and (2) staff-accepted industry guidelines. . The staff verified that the applicant
 
placed this commitment for the nickel-alloy components as part of the applicants UFSAR
 
Supplements A.2.1.30 and A.3.1.30 for the Nickel Alloy Inspection Program, which were
 
amended in the applicants letter of December 18, 2007 to include this commitment. The staff
 
finds that the applicants amended AMR basis for managing cracking of the RV internal core
 
support lugs is acceptable because it is in conformance with the staffs aging management
 
recommendations for these components in GALL AMR IV.A2-12.
The staff also noted that in SRP-LR Section 3.1.2.2.13, the staff states that no further evaluation of cracking due to PWSCC is necessary for ASME Code Class 1 nickel alloy components if
 
PWR applicants for license renewal state in the LRA UFSAR Supplements that they will comply
 
with applicable NRC Orders on nickel alloy cracking and if they place a commitment in their LRA
 
UFSAR supplement to implement applicable (1) Bulletins and Generic Letters and (2) staff-
 
accepted industry guidelines. The staff reviewed LRA Section A.2.1.20, Nickel Alloy Inspection
 
Program, and noted that in the applicants LRA letter of March 12, 2008, the applicant
 
responded to RAI 3.0.3.3.5-2 and committed to: (1) comply with applicable NRC Orders on
 
nickel alloy components and (2) conform to applicable NRC Bulletins, Generic Letters and NRC-
 
staff accepted industry guidelines associated with nickel alloy components. The staff also
 
verified that in the applicants letter of June 11, 2008, the applicant amended UFSAR
 
Supplement Sections A.2.1.20 for the IP2 Nickel Alloy Inspection Program and UFSAR
 
Supplement Section A.3.1.20 for the IP3 Nickel Alloy Inspection Program and placed the nickel
 
alloy commitment referred to in the applicants letter of June 11, 2008, in the appropriate
 
UFSAR Supplement Sections for the applicants Nickel Alloy Inspection Program. The staff
 
noted that this is consistent with the staffs recommended further evaluation guidance and nickel
 
alloy commitment basis that is provided in SRP-LR Section 3.1.2.2.13 and in GALL AMRs
 
IV.A2-12, IV.A2-19, and IV.C2-13 The staff verified that, consistent with the documentation in WCAP-14574-A, which was approved by the staff in a safety evaluation dated October 26, 2000 (ADAMS Accession number
 
ML003763768), the applicants AMRs in the LRA indicated that the IP2 and IP3 pressurizer
 
designs do not include nickel alloy pressurizer components. The staff noted this was consistent
 
with the design basis information for the IP2 and IP3 pressurizer designs that was provided in
 
WCAP-14574-NP-A. Based on this review, the staff finds that the applicant has provided an
 
acceptable basis for concluding that recommendations in GALL AMRs IV.C2-21 and IV.C2-24
 
are not applicable to the IP2 and IP3 LRA because the staff has verified, based on a review of
 
WCAP-14574-NP-A, that the IP2 and IP3 pressurizer designs do not include any nickel alloy
 
pressurizer instrumentation nozzles, heater sheaths and sleeves, heater bundle diaphragm
 
plates, manways and flanges; pressurizer surge and steam space nozzles and welds.
The staff also noted that, in LRA Table 3.1.2-4-IP2 and 3.1.2-4-IP3, the applicant did include AMRs for cracking of the nickel alloy SG primary nozzle closure rings, and that in these AMRs, the applicant credited only its Water Chemistry Control Program - Primary and Secondary to
 
manage cracking in the component surfaces that are exposed to borated treated water.
By letter dated December 30, 2008, the staff issued RAI 3.1.2-1, Part C
, and asked the applicant to justify why the applicant has aligned its AMRs for the SG primary nozzle closure
 
rings to GALL AMR IV.D1-6 which is for SG divider plates, and why the Inservice Inspection
 
Program was not credited in addition to the Water Chemistry Control Program - Primary and 3-276 Secondary to manage cracking due to SCC or PWSCC in the SG primary nozzle closure rings.
This is part of Open Item 3.1.2-1. The issue on whether the AMRs in LRA Tables 3.1.2-4-IP2
 
and 3.1.2-4-IP3 on cracking of nickel alloy SG primary nozzle closure rings need to credit the Inservice Inspection Program as an additional AMP for managing cracking in the SG primary
 
nozzle closure rings is pending acceptable resolution of RAI 3.1.2-1, Part C (Open
 
Item 3.1.2-1).
The applicant responded to RAI 3.1.2-1, Part C in a letter dated January 27, 2009. In this response the applicant explained that GALL AMR IV.D1-6 is only applicable to SG divider plates
 
which are not part of the primary pressure boundary. The applicant also explained that the SG
 
primary closure nozzle closure rings are fabricated from nickel alloy materials, they are not
 
reactor coolant pressure boundary components, and are therefore not subject to ASME Code, Section XI inservice inspection requirements. The staff finds the applicants response to RAI
 
3.1.2-1, Part C provides an acceptable basis for not crediting the ISI program for the SG
 
feedwater nozzle closure rings because the rings are not categorized as ASME Code Class 1
 
reactor coolant pressure boundary components, and because the applicant would only be
 
required to apply the ISI requirements of the applicants Inservice Inspection Program to the
 
rings if they were ASME Code Class 1 reactor coolant pressure components. The staff also
 
finds that the applicant has provided an acceptable basis for not using GALL AMR Item IV.D1-6
 
for the SG feedwater nozzle closure rings because GALL AMP IV.-D1-6 is applicable to SG
 
divider plates made from nickel alloy materials. RAI 3.1.2-1, Part C is resolved and Open
 
Item 3.1.2-1 is closed with respect to the AMPs that need to be credited for aging management
 
of cracking due to PWSCC of the SG feedwater nozzle closure rings.
Based on the programs identified above, and resolution of Open Item 3.1.2-1, Part C, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.13 criteria. For those line items that apply to LRA Section 3.1.2.2.13
, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended functions will be maintained consistent with the CLB
 
during the period of extended operation, as required by 10 CFR 54.21(a)(3).
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 flow-accelerated corrosion, stating that it could occur in steel feedwater inlet rings and supports. The Steam Generator Integrity Program
 
manages loss of material due to flow-accelerated corrosion in the feedwater inlet ring using
 
periodic visual inspections.
SRP-LR Section 3.1.2.2.14 states that wall thinning due to flow accelerated corrosion may occur in steel feedwater inlet rings and supports. The GALL Report references IN 91-19, Steam
 
Generator Feedwater Distribution Piping Damage, for evidence of flow-accelerated corrosion in
 
steam generators and recommends that a plant-specific AMP be evaluated because existing
 
programs may not be capable of mitigating or detecting wall thinning due to flow accelerated
 
corrosion.
For Westinghouse-design PWRs with recirculation SGs, SRP-LR Section 3.1.2.2.14 invokes AMR Item 32 in the GALL Report, Volume 1 and AMR Item IV.D1-26, as applicable to loss of
 
material (wall thinning) due to flow accelerated corrosion in SG FW inlet rings and supports.
3-277 The staff verified that in LRA Tables 3.1.2-4-IP2 and 3.1.2-4-IP3, the applicant includes AMRs on management of loss of material (wall thinning) in the SG feedwater rings and fittings that are
 
made from carbon steel and that are exposed internally to treated water. The staff also verified
 
that in these AMRs, the applicant credits a combination of its Water Chemistry Control Program
 
- Primary and Secondary and its Steam Generator Integrity Program to manage loss of material
 
in the internal SG FW ring surfaces.
The staff noted that in GALL AMR IV.D1-26, the staff recommends that a plant-specific program be evaluated and credited to address operating experience discussed in IN 91-19. The staff
 
requested the applicant to discuss the type of visual inspections that could detect the wall
 
thinning of carbon steel FW rings and supports, as noted in IN 91-19 (Audit Item 199). Although
 
the description of the SG integrity AMP includes other mechanically induced phenomena, such
 
as denting, wear, impingement damage, and fatigue, no details are found in the LRA about how
 
the inspection methods and their evaluation are performed with regard to loss of material in
 
carbon steel FW inlet ring and supports in the IP SGs. In response, dated December 18, 2007, the applicant stated that the SG integrity program includes processes for monitoring and
 
maintaining secondary side components. Visual inspections are performed by qualified vendors.
The staff notes that SGs were replaced at IP2 in 2001 and at IP3 in 1989. Therefore, the FW ring inspections have not been performed in the IP2 SGs, but are scheduled in two of its SGs in
 
2010. However, the FW ring inspections were performed in IP3 SGs in: 1992 (all four), 1997
 
(34SG), 1999 (33SG), 2001 (32SG), and 2007 (31SG and 32SG). The inspections included
 
visual examinations of the outer diameter (OD) of the ring and a fiberscope inspection of the
 
inner diameter (ID) of 5 selected J-nozzles of 36 total and the FW ring tee. The inspection also
 
included various support structures including the feedring hangers. No anomalies were noted
 
other than minor washed out areas of the feedring beneath the outlet of the J-nozzles. The next
 
inspection is scheduled in two SGs in 2013. Therefore, the staff concluded that wall thinning
 
due to flow-accelerated corrosion is properly managed by the SG integrity program and hence, finds it acceptable.
Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.14 criteria. For those line items that apply to LRA Section 3.1.2.2.14, the staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3).
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 dimensions due to void swelling, stating that it could occur in stainless steel and nickel alloy reactor vessel internal components exposed to
 
reactor coolant. To manage changes in dimensions of such components, Entergy will (1)
 
participate in the industry programs for investigating and managing aging effects on reactor
 
internals; (2) evaluate and implement the results of the industry programs as applicable to the
 
reactor internals; and (3) upon completion of these programs, but not less than 24 months
 
before entering the period of extended operation, submit an inspection plan for reactor internals
 
to the staff for review and approval. This commitment is in the UFSAR Supplement, LRA 3-278 Appendix A, Sections A.2.1.41 and A.3.1.41.
SRP-LR Section 3.1.2.2.15 states that changes in dimensions due to void swelling may occur in stainless steel and nickel alloy PWR internal components exposed to reactor coolant. The GALL
 
Report recommends no further AMR if the applicant commits in the FSAR supplement (1) to
 
participate in the industry programs for investigating and managing aging effects on reactor
 
internals, (2) to evaluate and implement the results of the industry programs as applicable to the
 
reactor internals, and (3) upon completion of these programs, but not less than 24 months
 
before entering the period of extended operation, to submit an inspection plan for reactor
 
internals to the staff for review and approval.
For Westinghouse-designed reactor vessel internals, SRP-LR Section 3.1.2.2.15 refers to the staffs guidance in AMR 33 of Table 1 to the GALL Report, Volume 1, and in GALL AMRs IV.B2-1, IV.B2-4, IV.B2-7, IV.B2-11, IV.B2-15, IV.B2-19, IV.B2-23, IV.B2-27, IV.B2-29, IV.B2-35, IV.B2-39, and IV.B2-41, as applicable to the management of changes in dimensions due to void
 
swelling in Westinghouse-designed RVI baffle/former plates; baffle/former bolts; core barrel (CB), CB flange, CB outlet nozzles and thermal shield; flux thimble guide tubes; flux thimble
 
guide tubes; lower internal assembly - fuel alignment pins, lower support plate column bolts, and clevis insert bolts; lower internals assembly - lower core plate radial keys and clevis
 
inserts; lower internals assembly -  lower support casting or forging and lower support columns;
 
RCCA guide tube assemblies - RCCA guide tube bolts and RCCA guide tube support pins;
 
RCCA guide tube assemblies - RCCA guide tubes; upper internals assembly - upper support
 
columns; upper internals assembly - upper support column bolts, upper core plates, and fuel
 
alignment pins; and upper internals assembly - upper support plates, upper core plates, and
 
hold-down springs.
The staff verified that Entergy has made the applicable commitment for these AMRs in Commitment 30, which was provided in Entergy letter dated March 24, 2008, and included in
 
UFSAR Supplements A.2.1.41 and A.3.1.41 for the IP2 and IP3 PWR Vessel Internals
 
Programs, respectively.
Thus, based on this review, the staff finds that the applicant has provided an acceptable basis for using Commitment 30 as its basis for aging management of changes in dimension due to
 
void swelling in these RVI components because the AMRs for the components are in
 
conformance with the staffs recommended aging management position in SRP-LR Section 3.1.2.2.12 and GALL AMRs IV.B2-1, IV.B2-4, IV.B2-7, IV.B2-11, IV.B2-15, IV.B2-19, IV.B2-23, IV.B2-27, IV.B2-29, IV.B2-35, IV.B2-39, and IV.B2-41.
Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.15 criteria. For those line items that apply to LRA Section 3.1.2.2.15, the staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3).
3-279 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 criteria in SRP-LR Section 3.1.2.2.16.
  (1) LRA Section 3.1.2.2.16 addresses cracking due to SCC in stainless steel control rod drive head penetration components and on the primary coolant side of steel steam
 
generator heads clad with stainless steel, stating that the Water Chemistry Control -
 
Primary and Secondary and Inservice Inspection programs manage this aging effect.
 
The Water Chemistry Control - Primary and Secondary, Inservice Inspection, and
 
Reactor Vessel Head Penetration Inspection programs manage cracking of nickel alloy
 
control rod drive head penetration components due to PWSCC. The Reactor Vessel
 
Head Penetration Inspection Program implements applicable NRC orders and will
 
implement applicable (1) bulletins and generic letters and (2) staff-accepted industry
 
guidelines. The UFSAR Supplement, LRA Appendix A, Sections A.2.1.30 and A.3.1.30, state this commitment. The Water Chemistry Control - Primary and Secondary and
 
Steam Generator Integrity programs manage cracking for the steam generator
 
tubesheets.
SRP-LR Section 3.1.2.2.16, Item (1) 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 GALL Report recommends ASME Code, Section XI ISI and control of water chemistry to
 
manage this aging effect and recommends no further AMR for PWSCC of nickel alloy if
 
the applicant complies with applicable NRC orders and commits in the FSAR
 
supplement to implement applicable (1) bulletins and generic letters, and (2) staff-
 
accepted industry guidelines.
The staff noted that, in LRA Tables 3.1.2-1-IP2 and 3.1.2-1-IP3, consistent with GALL Report, the applicant credited its Water Chemistry Control Program - Primary and
 
Secondary and Inservice Inspection Program to manage cracking of the stainless steel
 
CRD pressure housings. The staff noted that this is appropriate for the stainless steel
 
base metals used to fabricate the CRD pressure housings. However, the staff noted that
 
the welds used to join the stainless steel CRD pressure housings to the nickel alloy
 
upper RVCH penetration nozzles (e.g., CRD mechanism penetration nozzles) would
 
normally be fabricated from bimetallic (nickel alloy) weld materials. Thus, the staff noted
 
that for the CRD housing bimetallic weld materials, the applicant did not include the
 
appropriate commitment in UFSAR Supplements A.2.1.20 and A.3.1.20. By letter dated
 
December 30, 2008, the staff issued RAI 3.1.2-1, and asked whether the weld used to
 
secure the CRD housings to the nickel alloy upper RVCH penetration nozzles were
 
made of nickel alloy filler weld materials. If so, the staff requested that the applicant
 
amend the LRA to provide AMRs on the IP2 and IP3 SG CRD pressure housing-to-CRD
 
penetration nozzle welds that credit the Water Chemistry Control Program - Primary and
 
Secondary, the Inservice Inspection Program, and the Nickel Alloy Inspection Program, as bases for managing cracking of these bimetallic (nickel alloy) weld materials along
 
with the appropriate commitment that was made for Nickel alloy components in the
 
applicants letter dated March 12, 2008, as amended by letter dated June 11, 2008. This
 
was identified as Open Item 3.1.2-1, Part A.
3-280 In its response dated January 27, 2009, the applicant clarified that the CETNA nozzles used in the upper RV head designs are fabricated from stainless steel and do not include
 
any nickel alloy base metal or weld materials. Instead, the applicant clarified that the
 
CETNA assemblies are fabricated as follows:
A CET head port adapter is connected to the penetration housing adapter flange, and then connected to the CETNA assembly via a conoseal joint. All CETNA
 
assemblies are sealed to the CET columns with Grafoil seals using a
 
compression collar and a hold down nut with no welds. As shown in the LRA
 
tables, the CETNA are constructed from stainless steel. Based on this
 
supplemental information, the applicant has provided an acceptable basis for
 
concluding that the CETNA assemblies do not need to be within the scope of and
 
managed by the Nickel Alloy Inspection Program because these components do
 
not include any nickel alloy base metal or weld components.
In its response to RAI 3.1.2-1, the applicant also clarified that the only nickel alloy welds associated with the upper RVCH vent nozzles are those nickel alloy welds that join these
 
nozzles to the nickel alloy closure head vent nozzle safe-end. The applicant explained
 
the vent nozzles are carbon steel nozzles with internal stainless steel cladding that are
 
weld to the carbon steel upper RVCH using carbon steel weld materials that have been
 
post weld heat treated. The applicant clarified that the nickel alloy welds associated with
 
the nickel alloy vent nozzle safe ends are within the scope of the applicants Nickel Alloy
 
Inspection Program. Based on this review, the staff finds that the applicant has provided
 
an acceptable basis for concluding that the upper RVCH head vent nozzle-to-upper
 
RVCH welds do not need to be managed by or be within the scope of either the Nickel
 
Alloy Inspection Program or Reactor Vessel Head Penetration Inspection Program
 
because these components and their associated welds are not fabricated from nickel
 
alloy materials.
Based on this review, the staff finds that the applicant has provided an acceptable basis for managing cracking in these upper RVCH head vent nozzles and CETNA nozzles
 
because: (1) the applicant has clarified which of nozzle designs include nickel alloy base
 
metal or weld materials, (2) the applicant has appropriately credited its Nickel Alloy
 
Inspection Program and Water Chemistry Program to manage cracking in the nickel alloy
 
upper RVCH head vent nozzle safe ends and their nickel alloy safe-end-to-nozzle welds, and (3) in the applicants AMRs for the CETNA nozzles and upper RVCH head vent
 
nozzles, as given in LRA Tables 3.1.2-IP2-1 and 3.1.2-IP3, the applicant has
 
appropriately credited its Water Chemistry Program and Inservice Inspection Program to
 
manage any cracking that may develop in the components. RAI 3.1.2-1 is resolved and
 
Open Item 3.1.2-1, Part A is closed with respect to the management of cracking in the
 
upper RVCH head vent nozzles and the CETNA nozzles.
The staff verified that the staffs aging management recommendations in GALL AMR IV.D2-4 for primary side steel SG upper and lower heads, tubesheets and tube-to-
 
tubesheet welds with internal stainless steel or nickel alloy cladding is not applicable to
 
the IP2 LRA because the IP2 is currently designed with Model 44F recirculating SGs, and because the staffs guidance in AMR IV.D2-4 is only applicable to once-through SG
 
designs. The staff noted, however, that for these components, the applicant credited its
 
Water Chemistry Control - Primary and Secondary and Steam Generator Integrity 3-281 Programs to manage cracking due to SCC in the components. The staff noted that this is appropriate for the SG upper and lower heads because the cladding on these
 
components is made from stainless steel and because this is consistent with the staffs
 
recommendations in GALL AMR IV.D2-4 for stainless steel SG cladding that is exposed
 
to the reactor coolant.
The staff noted, however, that the internal cladding for the SG tubesheets is made from nickel alloy material, and that in the LRA, the applicant did not commit to applying any
 
applicable (1) bulletins and generic letters, and (2) staff-accepted industry guidelines to
 
the any nickel alloy cladding associated with the tubesheets. By letter dated December
 
18, 2007, in the response to Audit Item 200, the applicant stated that it is committed to
 
implement NRC Orders, bulletins, generic letters, and staff-accepted industry guidelines
 
associated with nickel alloy cladding associated with the SG tubesheets.
Based on this review, the staff finds that the applicant has created an acceptable basis for managing cracking in these nickel alloy components. This is based on the fact that
 
the applicant is crediting the Water Chemistry Program, the Inservice Inspection
 
Program and either the commitment associated with the Nickel Alloy Inspection Program
 
or Reactor Vessel Penetration Inspection Program to manage cracking in the nickel alloy
 
upper RVCH penetration nozzles or housings. In addition, the applicant will use the
 
Water Chemistry Program, Steam Generator Integrity Program, and commitment
 
associated with Nickel Alloy Inspection Program to manage cracking in the nickel alloy
 
SG tubesheet cladding,    (2) LRA Section 3.1.2.2.16 addresses cracking due to SCC that could occur on stainless steel pressurizer spray heads and cracking due to PWSCC that could occur on nickel
 
alloy pressurizer spray heads. The IP pressurizer spray heads are composed of CASS.
 
LRA Section 3.1.2.2.7 item 2 addresses management of cracking for these components.
SRP-LR Section 3.1.2.2.16 states that cracking due to SCC may occur on stainless steel pressurizer spray heads. Cracking due to PWSCC may occur on nickel alloy pressurizer spray heads. The existing program controls water chemistry to mitigate this aging effect.
 
The GALL Report recommends one-time inspection to confirm that cracking has not
 
occurred. For nickel alloy welded spray heads, the GALL Report recommends no further
 
AMR if the applicant complies with applicable NRC orders and commits in the FSAR
 
supplement to implement applicable (1) bulletins and generic letters, and (2) staff-
 
accepted industry guidelines.
The staff verified that in the applicants AMR on cracking of the IP2 pressurizer spray head, the applicant identifies that the spray heads are made of CASS. Thus, the staff
 
verified that the guidance in SRP-LR Section 3.1.2.2.16 is not applicable to the
 
evaluation of management of cracking in the IP2 and IP3 pressurizer spray heads
 
because the spray heads are not fabricated from nickel alloy materials. The staff s
 
evaluation of the AMRs for managing cracking of the IP2 and IP3 pressurizer spray
 
heads which are made from CASS materials is documented in Section 3.1.2.2.7, Item (2).Based on its review, the staff concludes that the applicants programs, discussed above, meet SRP-LR Section 3.1.2.2.16 criteria for the AMRs that are used to manage cracking in the upper
 
RVCH nozzle tube (i.e., the CRDM penetration nozzles) and housing welds and the SG 3-282 tubesheet cladding. For the AMR items that apply to LRA Section 3.1.2.2.16, the staff determined that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3). Based on this review, the staff has determined that the
 
guidance in SRP-LR Section 3.1.2.2.16.2 is not applicable to the management of cracking in the
 
IP2 and IP3 pressurizer spray heads because the spray heads are not fabricated from nickel
 
alloy materials. The staff evaluates the applicants AMRs for managing cracking of the CASS
 
pressurizer spray heads in SER Section 3.1.2.2.7, Item (2).
3.1.2.2.17  Cracking Due to Stress Corrosion Cracking, Primary Water Stress Corrosion Cracking, and Irradiation-Assisted Stress Corrosion Cracking The staff reviewed LRA Section 3.1.2.2.17 against the criteria in SRP-LR Section 3.1.2.2.17.
 
LRA Section 3.1.2.2.17 addresses cracking due to SCC, PWSCC, and IASCC, stating that they could occur in PWR stainless steel and nickel alloy reactor vessel internals components. To
 
manage cracking for such components, Entergy maintains the Water Chemistry Control -
 
Primary and Secondary Program and will (1) participate in the industry programs for
 
investigating and managing aging effects on reactor internals; (2) evaluate and implement the
 
results of the industry programs as applicable to the reactor internals; and (3) upon completion
 
of these programs, but not less than 24 months before entering the period of extended
 
operation, submit an inspection plan for reactor internals to the staff for review and approval.
 
The applicants commitment to these programs is in the UFSAR Supplement, LRA Appendix A, Sections A.2.1.41 and A.3.1.41.
SRP-LR Section 3.1.2.2.17 states that cracking due to SCC, PWSCC, and IASCC may occur in PWR stainless steel and nickel alloy reactor vessel internals components. The existing program
 
controls water chemistry to mitigate these aging effects; however, the existing program should
 
be augmented to manage these aging effects for reactor vessel internals components. The
 
GALL Report recommends no further AMR if the applicant commits in the FSAR supplement
 
(1) to participate in the industry programs for investigating and managing aging effects on
 
reactor internals, (2) to evaluate and implement the results of the industry programs as
 
applicable to the reactor internals, and (3) upon completion of these programs, but not less than
 
24 months before entering the period of extended operation, to submit an inspection plan for
 
reactor internals to the staff for review and approval.
For Westinghouse-designed reactors, SRP-LR Section 3.1.2.2.17 invokes AMR Item 37 in Table 1 of the GALL Report, Volume 1 and GALL AMR IV.B2-16, IV.B2-20, IV.B2-28, and
 
IV.B2-40, as applicable to the management of cracking due to SCC, PWSCC, or IASCC in
 
Westinghouse RVI lower internals assembly - fuel alignment pins, lower support plate column
 
bolts, and clevis insert bolts; lower internals assembly -  lower core plate, radial keys and clevis
 
inserts; RCCA guide tube assemblies - RCCA guide tubes bolts and RCCA guide tubes support
 
pins; and upper internals assembly -  upper support column bolts, upper core plate alignment
 
pins, and fuel alignment pins. The staffs aging management recommendations in these GALL-
 
based AMRs is the same as that recommended in SRP-LR 3.1.2.2.17.
The staff verified that, in these AMRs, the applicant credited its Water Chemistry Control Program - Primary and Secondary and LRA Commitment No. 30 to manage cracking of
 
stainless steel and nickel alloy reactor vessel internals components. The staff finds that this is 3-283 acceptable because it is in conformance with the guidance in SRP-LR Section 3.1.2.2.17 and in the GALL AMRs that are based on this SRP-LR section. The staff also verified that, for these
 
AMRs (and other AMRs on aging management of the RVI components), Entergy has made the
 
applicable commitment for IP2 and IP3 in Commitment 30, which was provided in Entergy letter
 
dated March 24, 2008, and included in UFSAR Supplement Sections A.2.1.41 and A.3.1.41 for
 
the IP2 and IP3 PWR Vessel Internals Programs, respectively. The staff finds this acceptable
 
because it is in conformance with the staffs recommended aging management position that is
 
given in SRP-LR Section 3.1.2.2.17 and in the GALL AMRs that are based on this SRP-LR
 
section.Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.17 criteria. For those line items that apply to LRA Section 3.1.2.2.17, the staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3).
3.1.2.2.18  Quality Assurance for Aging Management of Nonsafety-Related Components
 
SER Section 3.0.4 documents the staffs evaluation of the applicants QA program. 3.1.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report In LRA Tables 3.1.2-1-IP2 through 3.1.2-4-IP2 and 3.1.2-1-IP3 through 3.1.2-4-IP3, 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 these LRA tables, the applicant indicated, via Notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the
 
GALL Report. The applicant provided more 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 applicants evaluation to determine whether the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB for the period of extended operation. The
 
following sections document the staffs evaluation.
3.1.2.3.1  Reactor VesselSummary of Aging Management Review
 
The staff reviewed LRA Tables 3.1.2-1-IP2 and 3.1.2-1-IP3, which summarize the results of AMR evaluations for the RV component groups. The staffs review did not identify any line items
 
with plant-specific Notes F through J, indicating that the combinations of component type, 3-284 material, environment, and AERM for this system are consistent with the GALL Report.
SER Section 3.1.2.1 documents the staffs evaluation of the line items with Notes A through E.
 
3.1.2.3.2  Reactor Vessel InternalsSummary of Aging Management Review
 
The staff reviewed LRA Tables 3.1.2-2-IP2 and 3.1.2-2-IP3, which summarize the results of AMR evaluations for the RVI component groups. The staffs review did not identify any line
 
items with plant-specific Notes F through J, indicating that the combinations of component type, material, environment, and AERM for this system are consistent with the GALL Report.
SER Section 3.1.2.1 documents the staffs evaluation of the line items with Notes A through E.
 
3.1.2.3.3  Reactor Coolant System and PressurizerSummary of Aging Management Review
 
The staff reviewed LRA Tables 3.1.2-3-IP2 and 3.1.2-3-IP3, which summarize the results of AMR evaluations for the RCPB.
LRA Tables 3.1.2-3-IP2 and 3.1.3-3-IP3 include AMRs on management of fouling in stainless steel RCS HX tubes whose external surfaces are exposed to treated borated water in a greater
 
than 60 degrees C (140 degrees F) environment. In these AMRs, the applicant credits its Water
 
Chemistry ControlPrimary and Secondary Program with managing fouling affecting the heat transfer function of stainless steel HX tubes externally exposed to treated borated water in a
 
greater than 60 degrees C (140 degrees F) environment. These AMRs are marked with a
 
Note H, indicating that this aging effect is not in the GALL Report for this component and
 
material.In Audit Item 190, the staff asked the applicant to explain how it ensures the effectiveness of the water chemistry control. By letter dated December 18, 2007, the applicant stated that fouling of HX tubes occurs due to the lack of effective water chemistry control on the tube surface and that
 
contaminants, such as corrosion products, often deposit on the tube surfaces, which reduces
 
their heat transfer capability. The applicant stated that treating the water chemistry to reduce the development of any contaminants would minimize the fouling of the HX tubes. To verify the
 
effectiveness of the water chemistry programs, the applicant will use the One-Time Inspection Program to inspect the external surfaces of these HX tubes during the period of extended operation. The applicant stated that, to accomplish this, it will amend the AMRs for these HX
 
tubes by adding LRA RCS AMR Note 104, which indicates that a One-Time Inspection will be
 
performed to verify the effectiveness of the Water Chemistry ControlPrimary and Secondary
 
Program in managing aging.
The staff verified that, in the applicants letter of December 18, 2007, the applicant appropriately amended the AMRs on loss of material for these stainless steel HX components by adding LRA
 
RCS AMR Note 104. The staff noted that the applicants amended basis for aging management
 
conforms with other AMRs in the GALL Report, Volume 2, for PWR systems (such as GALL AMR V.A-16) in which a program corresponding to GALL AMP XI.M2, Water Chemistry, is
 
recommended for aging management of loss of heat transfer capability due to fouling in stainless steel HX tubes exposed to treated water, and for which a program corresponding to GALL AMP XI.M32, One-Time Inspection, is recommended for verification of the effectiveness
 
of the water chemistry program in managing this aging effect. Thus, the staff finds the
 
applicants basis for aging management to be acceptable because (1) the implementation of the 3-285 Water Chemistry ControlPrimary and Secondary Program would minimize the buildup of contaminants that could lead to corrosion products and fouling in HX tubes, (2) the
 
implementation of the One-Time Inspection Program would verify that this process is not
 
occurring, and (3) this approach conforms with the staffs aging management basis in GALL
 
AMR V.A-16.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL
 
Report. The staff finds that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.3.4  Steam GeneratorSummary of Aging Management Review
 
The staff reviewed LRA Tables 3.1.2-4-IP2 and 3.1.2-4-IP3, which summarize the results of AMR evaluations for the SG component groups.
LRA Tables 3.1.2-4-IP2 and 3.1.2-4-IP3 include AMRs on management of fouling in nickel alloy SG tubes whose internal surfaces are exposed to treated borated water and whose external
 
surfaces are exposed to treated water. In these AMRs, the applicant credits its Water Chemistry
 
ControlPrimary and Secondary Program with managing the loss of heat transfer function due
 
to fouling on internal surfaces that are exposed to treated borated water and whose external
 
surfaces are exposed to treated water. These AMRs are marked with Note H, indicating that this
 
aging effect is not in the GALL Report for this component and material.
In Audit Item 190, the staff asked the applicant to explain how it would ensure the effectiveness of the water chemistry control. By letter dated December 18, 2007, the applicant stated that
 
fouling of SG tubes occurs due to the lack of effective water chemistry control on the tube
 
surface and that contaminants, such as corrosion products, often deposit on the tube surfaces, which reduces their heat transfer capability. The applicant stated that treating the water
 
chemistry to reduce the development of any contaminants would minimize the fouling of the SG
 
tubes. To verify the effectiveness of the water chemistry programs, the applicant will use the
 
One-Time Inspection Program to inspect the external surfaces of these SG tubes during the
 
period of extended operation. The applicant stated that, to accomplish this, it will amend the
 
AMRs for these tubes by adding LRA RCS AMR Note 104, which indicates that a One-Time
 
Inspection will be performed to verify the effectiveness of the Water Chemistry ControlPrimary
 
and Secondary Program in managing aging.
The staff verified that, in the applicants letter of December 18, 2007, the applicant had appropriately amended the AMRs on loss of heat transfer function due to fouling for these nickel
 
alloy SG components by adding LRA RCS AMR Note 104. The staff noted that the applicants
 
amended basis for aging management conforms with other AMRs in the GALL Report, Volume 2, for PWR systems (such as GALL AMR V.A-16) in which a program corresponding to GALL AMP XI.M2, Water Chemistry, is recommended for aging management of loss of heat transfer capability due to fouling in HX tubes exposed to treated water type environments, and for which a program corresponding to GALL AMP XI.M32, One-Time Inspection, is
 
recommended for verification of the effectiveness of the water chemistry program in managing
 
this aging effect. Thus, the staff finds the applicants basis for aging management to be
 
acceptable because (1) the implementation of the Water Chemistry ControlPrimary and
 
Secondary Program would minimize the buildup of contaminants that could lead to corrosion 3-286 products and fouling in SG tubes, (2) the implementation of the One-Time Inspection Program would be used to verify that this is not occurring, and (3) this approach conforms with the staffs
 
aging management basis in GALL AMR V.A-16.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL
 
Report. The staff finds that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
====3.1.3 Conclusion====
 
The staff concludes that the applicant has provided sufficient information to demonstrate that the effects of aging for the RV, RVI, and RCS components within the scope of license renewal
 
and subject to an AMR will be adequately managed so that the intended functions will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). 3.2  Aging Management of Engineered Safety Features Systems This section of the SER documents the staffs review of the applicants AMR results for the
 
following engineered safety feature (ESF) system components and component groups:  RHR system  CS system  containment isolation support system  safety injection system  containment penetrations 3.2.1  Summary of Technical Information in the Application LRA Section 3.2 provides AMR results for the ESF system components and component groups.
LRA Table 3.2.1, Summary of Aging Management Programs for Engineered Safety Features
 
Evaluated in Chapter V of NUREG-1801, is a summary comparison of the applicants AMRs
 
with those evaluated in the GALL Report for the ESF system components and component
 
groups.The applicants AMRs evaluated and incorporated applicable plant-specific and industry operating experience in the determination of AERMs. The plant-specific evaluation included
 
CRs and discussions with appropriate site personnel to identify AERMs. The applicants review
 
of industry operating experience included a review of the GALL Report and operating
 
experience issues identified since the issuance of the GALL Report.
 
====3.2.2 Staff====
Evaluation The staff reviewed LRA Section 3.2 to determine whether the applicant provided sufficient information to demonstrate that the effects of aging for the ESF system components within the
 
scope of license renewal and subject to an AMR will be adequately managed so that the
 
intended functions will be maintained consistent with the CLB for the period of extended 3-287 operation, as required by 10 CFR 54.21(a)(3).
The staff conducted an onsite audit of AMRs to verify the applicants claim that certain AMRs are consistent with the GALL Report. The staff did not repeat its review of the matters described
 
in the GALL Report; however, the staff did verify that the material presented in the LRA is
 
applicable and that the applicant identified the appropriate GALL Report AMRs. SER
 
Section 3.0.3 documents the staffs evaluations of the AMPs. SER Section 3.2.2.1 documents
 
the details of the staffs audit evaluation.
During an onsite audit, the staff also selected AMRs consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicants additional
 
evaluations are consistent with the SRP-LR Section 3.2.2.2 acceptance criteria. SER
 
Section 3.2.2.2 documents the staffs evaluations.
The staff also conducted a technical review of the remaining AMRs not consistent with or not addressed in the GALL Report. The technical review evaluated whether the applicant identified
 
all plausible aging effects and whether the aging effects listed are appropriate for the material-
 
environment combinations specified. SER Sections 3.2A.2.3 (for IP2) and 3.2B.2.3 (for IP3)
 
document the staffs evaluations.
For components that the applicant claimed are not applicable or require no aging management, the staff reviewed the AMR line items and the plants operating experience to verify the
 
applicants claims.
Table 3.2-1 summarizes the staffs evaluation of components, aging effects 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 System Components in the GALL Report Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff 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 AMP 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 (see SER Section
 
3.2.2.2.2) 3-288 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation 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 corrosionWater Chemistry and One-Time InspectionYes Water Chemistry Control -
Primary and Secondary and One-Time InspectionConsistent with GALL Report (see
 
SER Section
 
3.2.2.2.3(1))
Stainless steel
 
piping, piping components, and piping elements
 
exposed to soil (3.2.1-4)Loss of material due to pitting
 
and crevice corrosion A plant-specific AMP is to be evaluated. Yes Not applicable Not applicable (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 corrosionWater Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (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 Oil Analysis and One-Time InspectionConsistent with GALL Report (see
 
SER Section
 
3.2.2.2.3(4))Partially encased
 
stainless steel tanks with breached moisture barrier exposed to raw water
 
(3.2.1-7)Loss of material due to pitting
 
and crevice corrosion A plant-specific AMP is to be evaluated for
 
pitting and crevice corrosion of tank bottoms because moisture and water can egress under the tank due to cracking
 
of the perimeter seal from weathering. Yes Not applicable Not applicable (see SER Section 3.2.2.2.3(5))
Stainless steel
 
piping, piping components, piping elements, and tank
 
internal surfaces exposed to condensation (internal)
(3.2.1-8)Loss of material due to pitting
 
and crevice corrosion A plant-specific AMP is to be evaluated.
Yes One-Time InspectionConsistent with GALL Report (see SER Section 3.2.2.2.3(6))
3-289 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation Steel, stainless steel, and copper alloy HX tubes exposed to lubricating oil
 
(3.2.1-9)Reduction of heat transfer due to fouling Lubricating Oil Analysis and One-Time Inspection Yes Oil Analysis and One-Time InspectionConsistent with GALL Report (see
 
SER Section 3.2.2.2.4(1))
Stainless steel HX tubes exposed to treated water (3.2.1-10)
Reduction of heat transfer due to fouling Water Chemistry and One-Time InspectionYes Not applicable Not applicable (see SER Section
 
3.2.2.2.4(2))
Elastomer seals and
 
components in standby gas treatment system
 
exposed to air -
indoor uncontrolled (3.2.1-11)
Hardening and loss of strength
 
due to elastomer degradation A plant-specific AMP is to be evaluated. Yes Not applicable Not applicable to PWRs (see SER
 
Section 3.2.2.2.5)
Stainless steel high-pressure safety injection (HPSI) (charging) pump miniflow orifice exposed to treated borated water
 
(3.2.1-12)
Loss of material due to erosion A plant-specific AMP is to be evaluated for
 
erosion of the orifice due to extended use of the centrifugal
 
HPSI pump for normal charging. Yes Not applicable Not applicable (see SER Section
 
3.2.2.2.6)Steel drywell and
 
suppressionchamber 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 AMP is to be evaluated. Yes Not applicable Not applicable to PWRs (see SER
 
Section 3.2.2.2.7)
Steel piping, piping
 
components, and piping elements exposed to treated water (3.2.1-14)
Loss of material due to general, pitting, and crevice corrosionWater Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (see SER
 
Section 3.2.2.2.8(1))
Steel containment isolation piping, piping components, and piping elements
 
internal surfaces exposed to treated water (3.2.1-15)
Loss of material due to general, pitting, and crevice corrosionWater Chemistry and One-Time InspectionYes Water Chemistry Control -
Primary and Secondary and One-Time InspectionConsistent with GALL Report (see
 
SER Section 3.2.2.2.8(2))
3-290 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation 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 Inspection Yes Oil Analysis and One-Time InspectionConsistent 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 microbiologically
-influenced corrosion Buried Piping and Tanks Surveillance or Buried Piping and Tanks Inspection No YesNot applicable Not applicable (see SER Section
 
3.2.2.2.9)
Stainless steel
 
piping, piping components, and piping elements
 
exposed to treated water > 60
&deg;C (> 140&deg;F)(3.2.1-18)
Cracking due to stress corrosion cracking (SCC)
 
and intergranular stress corrosion
 
cracking (IGSCC)BWR Stress Corrosion Cracking and Water ChemistryNo Not applicable Not applicable to PWRs Steel piping, piping
 
components, and piping elements exposed to steam or treated water (3.2.1-19)
Wall thinning due to flow-
 
accelerated corrosionFlow-Accelerated CorrosionNo Not applicable Not applicable to PWRs Cast austenitic
 
stainless steel piping, piping components, and piping elements
 
exposed to treated water (borated or unborated) > 250
&deg;C (> 482&deg;F)(3.2.1-20)
Loss of fracture toughness due to thermal aging embrittlementThermal Aging Embrittlement of CASSNo Not applicable Not applicable to PWRs High-strength steel
 
closure bolting exposed to air with steam or water
 
leakage (3.2.1-21)
Cracking due to cyclic loading, SCCBolting Integrity No Not applicable Not applicable (see SER Section
 
3.2.2.1.1)
Steel closure bolting exposed to air with steam or water leakage (3.2.1-22)
Loss of material due to general corrosionBolting Integrity No Not applicable Not applicable (see SER Section 3.2.2.1.1) 3-291 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation 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 corrosionBolting Integrity No Bolting Integrity Consistent with GALL Report Steel closure bolting
 
exposed to air -
indoor uncontrolled (external)
 
(3.2.1-24)
Loss of preload due to thermal effects, gasket creep, and self-
 
looseningBolting Integrity No Bolting Integrity Consistent with GALL Report (see
 
SER Section 3.2.2.1.2)
Stainless steel piping, piping components, and piping elements
 
exposed to closed cycle cooling water > 60&deg;C (> 140&deg;F)(3.2.1-25)
Cracking due to SCCClosed-Cycle Cooling Water System No Not applicable Not applicable (see SER Section 3.2.2.1.1)
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 corrosionClosed-Cycle Cooling Water System No Not applicable Not applicable (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 corrosionClosed-Cycle Cooling Water System No Water Chemistry Control - Closed
 
Cooling Water Consistent with GALL Report Stainless steel
 
piping, piping components, piping elements, and HX
 
components exposed to closed-cycle cooling water
 
(3.2.1-28)
Loss of material due to pitting
 
and crevice corrosionClosed-Cycle Cooling Water System No Water Chemistry Control - Closed
 
Cooling Water Consistent with GALL Report Copper alloy piping, piping components, piping elements, and HX components
 
exposed to closed-cycle cooling water (3.2.1-29)
Loss of material due to pitting, crevice, and galvanic corrosionClosed-Cycle Cooling Water System No Water Chemistry Control - Closed
 
Cooling Water Consistent with GALL Report 3-292 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation Stainless steel and copper alloy HX tubes exposed to closed-cycle cooling water (3.2.1-30)
Reduction of heat transfer
 
due to fouling Closed-Cycle Cooling Water System No Water Chemistry Control - Closed
 
Cooling Water Consistent with GALL Report External surfaces of
 
steel components including ducting, piping, ducting
 
closure bolting, and containment isolation piping external
 
surfaces exposed to air - indoor uncontrolled (external);
 
condensation (external) and air -
outdoor (external)
 
(3.2.1-31)
Loss of material due to general
 
corrosion External Surfaces Monitoring No External Surfaces MonitoringConsistent with GALL Report Steel piping and ducting components and internal surfaces exposed to air -
 
indoor uncontrolled (Internal)
(3.2.1-32)
Loss of material due to general
 
corrosion Inspection of Internal Surfaces in
 
Miscellaneous Piping and Ducting Components No Externals Surfaces Monitoring, Fire
 
Protection, or Periodic Surveillance and
 
Preventive MaintenanceConsistent 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 ComponentsNo Not applicable Not applicable (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 ComponentsNo Not applicable Not applicable (see SER Section
 
3.2.2.1.1)
Steel containment
 
isolation piping and components internal surfaces exposed to raw water (3.2.1-35)
Loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion, and foulingOpen-Cycle Cooling Water System No Not applicable Not applicable (see SER Section
 
3.2.2.1.1) 3-293 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation Steel HX components exposed to raw water (3.2.1-36)
Loss of material due to general, pitting, crevice, galvanic, and
 
microbiologically
-influenced corrosion, and foulingOpen-Cycle Cooling Water System No Not applicable Not applicable (see SER Section
 
3.2.2.1.1)
Stainless steel
 
piping, piping components, and piping elements exposed to raw water
 
(3.2.1-37)
Loss of material due to pitting, crevice, and microbiologically-influenced
 
corrosionOpen-Cycle Cooling Water System No Periodic Surveillance and
 
Preventive
 
MaintenanceConsistent with GALL Report (see SER Section
 
3.2.2.1.4)
Stainless steel
 
containment isolation piping and components internal
 
surfaces exposed to raw water (3.2.1-38)
Loss of material due to pitting, crevice, and microbiologically-influenced
 
corrosion, and foulingOpen-Cycle Cooling Water System No Not applicable Not applicable (see SER Section
 
3.2.2.1.1)
Stainless steel HX
 
components exposed to raw water (3.2.1-39)
Loss of material due to pitting, crevice, and microbiologically
-influenced
 
corrosion, and foulingOpen-Cycle Cooling Water System No Not applicable Not applicable (see SER Section
 
3.2.2.1.1)
Steel and stainless
 
steel HX tubes (serviced by open-cycle cooling water) exposed to raw water (3.2.1-40)
Reduction of heat transfer
 
due to fouling Open-Cycle Cooling Water System No Not applicable Not applicable (see SER Section
 
3.2.2.1.1)Copper alloy
 
> 15% Zn piping, piping components, piping elements, and
 
HX components exposed to closed cycle cooling water
 
(3.2.1-41)
Loss of material due to selective leaching Selective Leaching of Materials No Selective LeachingConsistent 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 LeachingConsistent with GALL Report 3-294 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff EvaluationGray 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 MaterialsNo Not applicable Not applicable (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 MaterialsNo Not applicable Not applicable (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
 
corrosionBoric Acid Corrosion No Boric Acid Corrosion PreventionConsistent with GALL Report Steel encapsulation
 
components exposed to air with borated water leakage (internal)
(3.2.1-46)
Loss of material due to general, pitting, crevice and boric acid corrosion Inspection of Internal Surfaces in
 
Miscellaneous Piping and Ducting ComponentsNo Not applicable Not applicable (see SER Section
 
3.2.2.1.1)
Cast austenitic
 
stainless steel piping, piping components, and piping elements
 
exposed to treated borated water
> 250&deg;C (> 482&deg;F)
(3.2.1-47)
Loss of fracture toughness due
 
to thermal aging embrittlementThermal Aging Embrittlement of
 
CASSNo Not applicable Not applicable (see SER Section
 
3.2.2.1.1)
Stainless steel or
 
stainless-steel-clad steel piping, piping components, piping
 
elements, and tanks (including safety injection tanks/accumulators) exposed to treated borated water > 60&deg;C
 
(> 140&deg;F)
 
(3.2.1-48)
Cracking due to SCCWater Chemistry No Water Chemistry Control -
Primary and Secondary Consistent with GALL Report 3-295 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation 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 corrosionWater Chemistry No Water Chemistry Control -
Primary and Secondary Consistent with GALL Report Aluminum piping, piping components, and piping elements exposed to air -
 
indoor uncontrolled (internal/external)
(3.2.1-50)None None NA None Consistent with GALL Report Galvanized steel
 
ducting exposed to air - indoor controlled (external)
 
(3.2.1-51)None None NA Not applicable Not applicable (see SER Section
 
3.2.2.1.1)
Glass piping
 
elements exposed to air - indoor uncontrolled (external), lubricating oil, raw water, treated water, or treated borated water
 
(3.2.1-52)None None NA None Consistent with GALL Report Stainless steel, copper alloy, and nickel alloy piping, piping components, and piping elements exposed to air -
indoor uncontrolled (external)
 
(3.2.1-53)None None NA None Consistent with GALL Report Steel piping, piping
 
components, and piping elements exposed to air -
 
indoor controlled (external)
(3.2.1-54)None None NA Not applicable Not applicable (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 NA None Consistent with GALL Report 3-296 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation Steel, stainless steel, and copper alloy piping, piping components, and
 
piping elements
 
exposed to gas (3.2.1-56)None None NA None Consistent with GALL Report Stainless steel and copper alloy
< 15% Zn piping, piping components, and piping elements exposed to air with borated water
 
leakage (3.2.1-57)None None NA None Consistent with GALL Report The staffs review of the ESF system component groups followed any one of several approaches. In one approach, documented in SER Section 3.2.2.1, the staff reviewed AMR
 
results for components that the applicant indicated are consistent with the GALL Report and
 
require no further evaluation. In the second approach, documented in SER Section 3.2.2.2, the
 
staff reviewed AMR results for components that the applicant indicated are consistent with the
 
GALL Report and for which further evaluation is recommended. In the third approach, documented in SER Sections 3.2A.2.3 (for IP2) and 3.2B.2.3 (for IP3), the staff reviewed AMR
 
results for components that the applicant indicated are not consistent with, or not addressed in, the GALL Report. SER Section 3.0.3 documents the staffs review of AMPs credited to manage
 
or monitor aging effects of the ESF system components. 3.2.2.1  AMR Results Consistent with the GALL Report LRA Section 3.2.2.1 identifies the materials, environments, AERMs, and the following programs that manage aging effects for the ESF system components:  Bolting Integrity Program  Boric Acid Corrosion Prevention Program  Buried Piping and Tanks Inspection Program  External Surfaces Monitoring Program  Heat Exchanger Monitoring Program  Oil Analysis Program  One-Time Inspection Program  Periodic Surveillance and Preventive Maintenance Program  Selective Leaching Program  Water Chemistry Control - Auxiliary Systems Program  Water Chemistry Control - Closed Cooling Water Program  Water Chemistry Control - Primary and Secondary Program 3-297 LRA Tables 3.2.2-1-IP2 through 3.2.2-5-IP2 and 3.2.2-1-IP3 through 3.2.2-5-IP3 summarize the results of AMRs for the ESF systems components and indicate AMRs claimed to be consistent
 
with the GALL Report.
For component groups evaluated in the GALL Report, for which the applicant claimed consistency with the report, where the report does not recommend further evaluation, the staffs
 
audit and review determined whether the plant-specific components of these GALL Report
 
component groups were bounded by the GALL Report evaluation.
For each AMR line item, the applicant stated how the information in the tables aligns with the information in the GALL Report. Notes A through E indicate how the AMR is consistent with the
 
GALL Report. The staff audited these AMRs.
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 applicants AMP was consistent with the
 
GALL Report AMP and whether the AMR was valid for the site-specific conditions.
Note C indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is
 
consistent with the GALL Report AMP. This note indicates that the applicant was unable to find
 
a listing of some system components in the GALL Report; however, the applicant identified in
 
the GALL Report a different component with the same material, environment, aging effect, and
 
AMP as the component under review. The staff audited these line items to verify consistency
 
with the GALL Report. The staff also determined whether the AMR line item of the different
 
component was applicable to the component under review and whether the AMR was valid for
 
the site-specific conditions.
Note D indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes
 
some exceptions to the GALL Report AMP. The staff audited these line items to verify
 
consistency with the GALL Report. The staff verified whether the AMR line item of the different
 
component was applicable to the component under review and whether the identified
 
exceptions to the GALL Report AMPs have been reviewed and accepted. The staff also
 
determined whether the applicants AMP was consistent with the GALL Report AMP and
 
whether the AMR was valid for the site-specific conditions.
Note E indicates that the AMR line item is consistent with the GALL Report for material, environment, and aging effect, but credits a different AMP. The staff audited these line items to
 
verify consistency with the GALL Report. The staff also determined whether the credited AMP would manage the aging effect consistently with the GALL Report AMP and whether the AMR
 
was valid for the site-specific conditions.
3-298 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.
In response to RAIs 2.3A.2.3-1 and 2.3B.2.3-2, by letter dated December 6, 2007, the applicant revised the LRA to include an AMR line item for aluminum valve body with an internal
 
environment of treated air, an external environment of indoor air, and an aging effect of none,
 
and Note C or Note C with plant-specific Note 301.
In response to RAI 2.3A.2.2-1, by letter dated March 12, 2008, the applicant revised the LRA to include several AMR line items associated with the CS (IP2) system which were not previously
 
included within the scope of license renewal under 10 CFR 54.4(a)(2). The AMR line items
 
added included stainless steel bolting, flow indicator, piping, tubing, and valve body with internal
 
environments of treated water or indoor air, external environment of indoor air, an aging effect of
 
loss of material or none, and Notes A or C.
By letter dated June 30, 2009, the applicant submitted an annual update to the LRA, identifying changes made to the CLB that materially affect the contents of the LRA. For the containment
 
isolation support system, the applicant revised LRA Table 3.2.2-3-IP2 to add AMR line items for
 
stainless steel piping exposed internally to treated air with an aging effect of none, and
 
exposed externally to soil with an aging effect of loss of material. These line items were
 
annotated with plant-specific Note 201 and/or Note C.
The staff reviewed the applicants revisions, noted above, and found that the additional AMR results are consistent with the GALL Report for these combinations of materials and
 
environments. On the basis of its review, the staff finds that all applicable aging effects were
 
identified, and the aging effects listed are appropriate for the combination of materials and
 
environments identified.
On the basis of its audit and review, the staff determines that, for AMRs not requiring further evaluation, as identified in LRA Table 3.2.1, the applicants references to the GALL Report are
 
acceptable and no further evaluation is required.
3.2.2.1.1  AMR Results Identified as Not Applicable In LRA Table 3.2.1, the applicant identifies Items 21, 22,25, 26,33, 34, 35, 36,38,39,40,43, 44 , 46, 47 , 51, and 54, as not applicable since the component, material, and environment combination does not exist at IP. For each of these items, the staff reviewed the LRA and the
 
applicant's supporting documents, and confirmed the applicant's claim that the component, material, and environment combination does not exist at IP. On the basis that IP does not have
 
this combination, the staff finds that these AMRs are not applicable to IP.
LRA Table 3.2.1, Line Item 18 addresses stainless steel piping, piping components, and piping elements exposed to treated water >60&deg;C (>140 &deg;F) in BWRs. The LRA states that this line item
 
is only applicable to boiling water reactor (BWR) designs, and, therefore, it is not applicable.
 
Since IP2 and IP3 are both PWRs, the staff finds this line item is not applicable.
LRA Table 3.2.1, Line Item 19 addresses steel piping, piping components, and piping elements exposed to steam or treated water. The LRA states that this line item is only applicable to BWR 3-299 designs, and, therefore, it is not applicable. Since IP2 and IP3 are both PWRs, the staff finds this line item is not applicable.
LRA Table 3.2.1, Line Item 20 addresses cast austenitic stainless steel piping, piping components, and piping elements exposed to treated water (borated or unborated) > 250&deg;C
 
(>482 &deg;F). The LRA states that this line item is only applicable to BWR designs, and, therefore, it is not applicable. Since IP2 and IP3 are both PWRs, the staff finds this line item is not
 
applicable.
3.2.2.1.2  Steel Closure Bolting Exposed to Air-Indoor Uncontrolled
 
In the discussion column of LRA Table 3.2.1, Item 3.2.1-24, the applicant stated that loss of preload is a design-driven effect and not an AERM. This statement is contrary to the GALL
 
Report recommendation. During the audit, the staff asked the applicant to justify why other
 
aging effects are not applicable and why the Bolting Integrity Program (B.1.2) did not take
 
exception to the GALL Report since at Indian Point, loss of preload is not considered an aging
 
effect (Audit Item 270).
In its response dated, December 18, 2007, the applicant stated:
The review of IPEC operating experience did not identify instances in which mechanical components failure was attributable to loss of pressure boundary
 
bolting preload. This is consistent with the EPRI Mechanical Tools (EPRI
 
1010639, Appendix F, Section 3.1) that do not consider loss of preload an aging
 
effect for bolted closures. Gasket creep will normally occur shortly after initial
 
loading, which allows for addressing this mechanism by installing practices and
 
subsequent maintenance of the joint. Self-loosening is also not an aging
 
mechanism but is an event-driven mechanism that occurs due to improper joint
 
design or installation that doesnt properly consider the potential for this
 
mechanism. This would be detected early in component service life and actions
 
would be taken to prevent recurrence.
The program addresses all bolting regardless of size except reactor head closure stud, which are addressed by the Reactor Head Closure Studs Program. The
 
program relies on industry recommendations for comprehensive bolting
 
maintenance, as delineated in EPRI TR-104213 for pressure retaining bolting
 
and structural bolting. The Bolting Integrity Program also includes preventive
 
measures to preclude or minimize loss of preload, which is consistent with the
 
GALL report so an exception to the GALL program description was not required.
Commitment 2 will be clarified to specifically state the Bolting Integrity Program manages loss of preload and loss of material for all external loading.
Clarification to be incorporated into the LRA.
The staff finds the applicants response acceptable, because the Bolting Integrity Program includes preventive measures that preclude or minimize loss of preload. This is consistent with
 
the GALL Report. In the same letter, the applicant amended the LRA to provide clarification as
 
stated above. On this basis, the staff finds the AMR results for this line item acceptable.
3-300 3.2.2.1.3  Loss of Material Due to General Corrosion In the discussion column of LRA Table 3.2.1, Item 3.2.1-32, the applicant stated that loss of material from the internal surfaces of steel components exposed to indoor air is managed by the Externals Surfaces Monitoring, Fire Protection, and Periodic Surveillance and Preventive
 
Maintenance Programs. During the audit, the staff asked the applicant to elaborate on how the
 
Fire Protection Program would manage the loss of carbon steel components and to explain why
 
the associated Table 2 items did not credit this. The staff also asked the applicant to compare the HX (housing) inspection frequency between the Periodic Surveillance and Preventive
 
Maintenance Program proposed by the applicant and the External Surfaces Monitoring Program
 
recommended by the GALL Report (Audit Item 272).
In its response, dated December 18, 2007, the applicant stated:
As in the associated Table 2 line items, either the Fire Protection Program or the Periodic Surveillance and Preventive Maintenance Programs manage loss of
 
material of carbon steel components by periodic visual inspection of component
 
internal surfaces. One or the other program is adequate: both programs are not
 
necessary. Table 3.3.2-12-IP2 and Table 3.3.2-12-IP3 include line items referring
 
to Item 3.2.1-32 and crediting the Fire Protection Program. The associated
 
components are part of the Halon or carbon dioxide gaseous fire protection
 
systems. The specific components referencing Item 3.2.1-32 are distribution
 
header components that are open to the atmosphere resulting in an indoor air
 
internal environment.
The Fire Protection Program manages loss of material for external carbon steel components by visual inspection of external surface. The IP2 cable spreading
 
room Halon fire suppression system is visually inspected under the Fire
 
Protection Program. The IP3 cable spreading room, 480V switchgear room, and
 
EDG [emergency diesel generator] room CO 2 fire suppression system is visually inspected under the Fire Protection Program. For systems where internal carbon
 
steel surfaces are exposed to the same environment as external surfaces, external surfaces will be representative of internal surfaces. Thus, loss of
 
material on internal carbon steel surfaces is also managed by the Fire Protection
 
Program Table 2 items that refer to Table 1 Item 3.2.1-32 credit the PSPM [periodic surveillance and preventive maintenance] for internal surfaces of carbon steel
 
heat exchanger (housing) with an environment of indoor-air. The PSPM Program
 
inspections are performed at least once per 5 years. Loss of material due to
 
corrosion is a long-term aging effect for carbon steel components air in-door (int).
 
The affected components have been in service for the life of the plant without
 
significant corrosion. Based on the slow acting aging mechanisms confirmed by
 
plant operating experience, the inspection frequency of at least once per 5 years
 
is sufficient. The intervals of inspections may be adjusted, as necessary, based
 
on inspection experience. The GALL program Inspection of Internal Surfaces
 
and Miscellaneous Piping and Duct Components includes visual inspections to
 
assure that existing environmental conditions are not causing material
 
degradation that could result in a loss of component intended functions.
 
Locations are chosen to include conditions likely to exhibit these aging effects 3-301 and inspection intervals are established such that they provide timely detection of degradation.
The staff reviewed the AMR result lines referring to Note E and determined that the component type, material, environment, and aging effect are consistent with those of the corresponding line
 
of the GALL Report. The staffs review of the applicant's Periodic Surveillance and Preventive
 
Maintenance Program and its evaluation is documented in SER Sections 3.0.3.3.7. The staff
 
noted that the applicants inspection frequency, which is based on the plant-specific operating
 
experience, will provide for timely detection of aging prior to the loss of intended functions. The
 
staff further noted that the applicants inspection frequency of the periodic visual inspections
 
may increase based on the inspection results. On the basis of its review, the staff finds the
 
applicants response acceptable because (1) the applicants inspection frequency has been
 
adjusted based on their plant specific operating experience, which is consistent with the recommendations provided in GALL AMP XI.M38 and (2) the applicants inspection frequency
 
may be altered based on the inspection results, which may increase the inspection frequency.
 
The staff finds that this program includes activities that are consistent with the
 
recommendations in the GALL Report, and are adequate to manage loss of material of carbon steel HX housings exposed to indoor air through visual inspections.
The staff evaluated the applicants claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicants consideration of recent operating experience
 
and proposals for managing aging effects. On the basis of its review, the staff concludes that
 
the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed
 
consistent with the GALL Report. Therefore, the staff concludes that the applicant has
 
demonstrated that the effects of aging for these components will be adequately managed so
 
that their intended functions will be maintained consistent with the CLB during the period of
 
extended operation, as required by 10 CFR 54.21(a)(3).
The staff reviewed the AMR result lines referring to Note E, as amended by letters dated April 30, 2008, June 11, 2008, and June 30, 2009, and determined that the component type, material, environment, and aging effect are consistent with those of the corresponding line of the GALL
 
Report. The staffs review of the applicants Fire Protection Program and its evaluation is
 
documented in SER Section 3.0.3.2.7. The staffs review of the applicants External Surfaces
 
Monitoring Program and its evaluation is documented in SER Section 3.0.3.2.5. The staff finds
 
that these programs include activities that are consistent with the recommendations in the GALL
 
Report, and are adequate to manage loss of material of carbon steel piping, pump casings (External Surfaces Monitoring Program only), and valve bodies exposed to indoor air through
 
visual inspections.
The staff evaluated the applicants claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicants consideration of recent operating experience
 
and proposals for managing aging effects. On the basis of its review, the staff concludes that
 
the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed
 
consistent with the GALL Report. Therefore, the staff concludes that the applicant has
 
demonstrated that the effects of aging for these components will be adequately managed so
 
that their intended functions will be maintained consistent with the CLB during the period of
 
extended operation, as required by 10 CFR 54.21(a)(3).
3-3023.2.2.1.4 Stainless Steel Piping, Piping Components and Piping Elements Exposed to Raw Water In LRA Tables 3.2.2-1-IP2 and 3.2.2-1-IP3, which cite Table 3.2.1, Item 3.2.1-37, the applicant proposed to manage loss of material of stainless steel piping, piping components and piping
 
elements exposed to raw water using Periodic Surveillance and Preventive Maintenance
 
Program. However, the AMP recommended by the GALL Report for this AERM is GALL AMP XI.M20, Open-Cycle Cooling Water System. The applicant referred to Note E to the Table 2
 
line items indicating that a different AMP is credited.
The staff reviewed the AMR result lines referring to Note E and determined that the component type, material, environment, and aging effect are consistent with those of the corresponding line
 
of the GALL Report. The staffs review of the applicants Periodic Surveillance and Preventive
 
Maintenance Program and its evaluation is documented in SER Section 3.0.3.3.7. The staff
 
finds that this program includes activities that are consistent with the recommendations in the
 
GALL Report, and are adequate to manage loss of material of material of stainless steel piping, piping components and piping elements exposed to raw water through visual inspections.
The staff evaluated the applicants claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicants consideration of recent operating experience
 
and proposals for managing aging effects. On the basis of its review, the staff concludes that
 
the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed
 
consistent with the GALL Report. Therefore, the staff concludes that the applicant has
 
demonstrated that the effects of aging for these components will be adequately managed so
 
that their intended functions will be maintained consistent with the CLB during the period of
 
extended operation, as required by 10 CFR 54.21(a)(3). 3.2.2.2  AMR Results Consistent with the GALL Report for Which Further Evaluation Is Recommended In LRA Section 3.2.2.2, the applicant further evaluated aging management, as recommended by the GALL Report, for the ESF system components and provided information concerning how it
 
will manage the following aging effects:  cumulative fatigue damage  loss of material due to cladding (breach)  loss of material due to pitting and crevice corrosion  reduction of heat transfer due to fouling  hardening and loss of strength due to elastomer degradation  loss of material due to erosion  loss of material due to general corrosion and fouling  loss of material due to general, pitting, and crevice corrosion  loss of material due to general, pitting, crevice, and microbiologically-influenced
 
corrosion QA for aging management of nonsafety-related components 3-303 For component groups evaluated in the GALL Report, for which the applicant claimed consistency with the GALL Report and for which the report recommends further evaluation, the
 
staff audited and reviewed the applicants evaluation to determine whether it adequately
 
addresses the issues further evaluated. In addition, the staff reviewed the applicants further
 
evaluations against the criteria contained in SRP-LR Section 3.2.2.2. The staffs review of the
 
applicants further evaluation follows.
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, Definitions.
Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3
 
documents the staffs review of the applicants evaluation of this TLAA.
During the audit, the staff noted that numerous line items in Tables 3.2.2-1-IP2 and 3.2.2-1-IP3 credit TLAAMetal Fatigue to manage the aging effect of cumulative fatigue damage and indicate that Section 4.3 of the LRA addresses the evaluation. However, in LRA Section 4.3, it
 
appears that the text does not include the discussion for certain components, such as flex hose, flow elements, thermowell, and tubing. The staff asked the applicant to explain the discrepancy (Audit Item 267).
In its response dated December 18, 2007, the applicant stated the following:
The components identified, with the exception of flex hoses, are all considered part of the piping and in-line components line item identified in LRA Table 4.1-1
 
and 4.1-2 and as such are evaluated as part of the system. ASME B31.1 stress
 
analysis is performed as required for the RHR system. These components are
 
addressed by the 7000 cycle discussion in LRA Section 4.3.2 and further details
 
are provided in section 3 of the TLAAMechanical Fatigue report
 
IP-RPT-06-LRD04. The flex hoses should not be included as part of the TLAA
 
evaluation since they isolate portions of the system from each other and would
 
not be part of a specific stress analysis for the system or parts of the system. The
 
line items for the flex hose in the RHR system in Tables 3.2.2-1-IP2 and
 
3.2.2-1-IP3 that identify TLAAMetal Fatigue will be removed.
Clarification to be incorporated into the LRA.
The staff finds the applicants response acceptable, because the applicant has explained that the components identified by the staff, with the exception of flex hoses, are considered piping
 
and in-line components, which will be evaluated as part of their respective systems. The
 
applicant further explained that the discussion in LRA Section 4.3.2 addresses these
 
components. The applicant explained that the component flex hose is not part of a specific
 
stress analysis and agreed to clarify this in the LRA. The staff verified, in the letter dated
 
December 18, 2007, that the applicant amended the LRA to remove the flex hose component
 
with the following material, environment, aging effect and program combination : stainless steel, treated borated water greater than 140 &deg;F, cracking-fatigue and TLAAmetal fatigue from LRA
 
Table 3.2.2-1-1P2. This component/material/environment combination is not applicable to IP3, therefore an amendment to LRA Table 3.2.2-1-1P3 was not required.
3-304 3.2.2.2.2  Loss of Material Due to Cladding (Breach)
The staff reviewed LRA Section 3.2.2.2.2 against the criteria in SRP-LR Section 3.2.2.2.2.
 
LRA Section 3.2.2.2.2 addresses loss of material due to cladding breach. It states that this aging effect is not applicable because there are no stainless-steel-clad steel pump casings in IP
 
ESF systems.
SRP-LR Section 3.2.2.2.2 states that loss of material due to cladding breach may occur in pressurized-water reactor (PWR) steel pump casings with stainless steel cladding exposed to
 
treated borated water.
The staff finds that this item is not applicable because the IP2 and IP3 ESF do not have steel pump casings with stainless steel cladding exposed to treated borated water.
Based on the above, the staff concludes that SRP-LR Section 3.2.2.2.2 criteria do not apply.
 
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 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 for internal surfaces of stainless steel piping and components in containment isolation
 
components exposed to treated water and states that the Water Chemistry Control -
 
Primary and Secondary Program manages this aging effect. The One-Time Inspection
 
Program will confirm the effectiveness of the Water Chemistry Control - Primary and
 
Secondary Program by an inspection of a representative sample of components
 
crediting this program, including those in areas of stagnant flow and other susceptible
 
locations.
SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosion may occur on internal surfaces of stainless steel containment isolation piping, piping
 
components, and piping elements exposed to treated water. The existing AMP monitors
 
and controls water chemistry to mitigate degradation. However, control of water
 
chemistry does not preclude loss of material due to pitting and crevice corrosion at
 
locations with stagnant flow conditions; therefore, the effectiveness of water chemistry
 
control programs should be verified to ensure that corrosion does not occur. The GALL
 
Report recommends further evaluation of programs to verify the effectiveness of water
 
chemistry control programs. A one-time inspection of selected components at
 
susceptible locations is an acceptable method to determine whether an aging effect is
 
occurring or is slowly progressing such that the components intended functions will be
 
maintained during the period of extended operation.
The staff reviewed the Water Chemistry Control - Primary and Secondary Program, which monitors chlorides, fluorides, and dissolved oxygen to limit the contaminants, thus
 
minimizing the occurrences of aging effects and maintaining component ability to
 
perform intended functions. The applicant has stated that the Water Chemistry Control -
 
Primary and Secondary Program will be verified for effectiveness by the One-Time
 
Inspection Program. The One-time Inspection Program provides inspection of selected
 
stainless steel components exposed to treated water at susceptible locations such as 3-305 stagnant areas for loss of material due to pitting and crevice corrosion in applicable ESF systems. The staff evaluated the Water Chemistry ControlPrimary and Secondary
 
Program and the One-time Inspection Program and documented the evaluations in
 
Sections 3.0.3.2.17 and 3.0.3.1.9, respectively. The staff finds that these programs
 
include activities that are consistent with the recommendations in the GALL Report and
 
are adequate to manage loss of material due to pitting and crevice corrosion on internal
 
surfaces of stainless steel containment isolation piping and components exposed to
 
treated water. (2) LRA Section 3.2.2.2.3 addresses loss of material from pitting and crevice corrosion for stainless steel piping and piping components exposed to a soil environment, stating that
 
the Buried Piping and Tanks Inspection Program manages this aging effect. The Buried
 
Piping and Tanks Inspection Program includes (a) preventive measures to mitigate
 
corrosion and (b) inspections to manage the effects of corrosion on the
 
pressure-retaining capability of buried carbon steel, copper alloy, gray cast iron, and
 
stainless steel components. Buried components will be inspected when excavated
 
during maintenance, within 10 years of entering the period of extended operation, and
 
within the first 10 years of the period of extended operation unless opportunistic
 
inspections occur within these 10-year periods.
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.
During the audit, the staff noted that IP3 has two line items in Table 3.2.2-2 (Containment Spray) and Table 3.2.2-4 (Safety Injection Systems), which correspond to
 
GALL Report Item V.D1-26, Piping, Piping Components and Piping Elements, and
 
reference Table 1, Item 3.2.1-4. The staff asked the applicant to explain why IP2 does
 
not have similar items and why the Buried Piping and Tanks Program is adequate for
 
managing the aging effect of loss of material due to pitting and crevice corrosion (Audit
 
Item 268).
In its response, dated December 18, 2007, the applicant stated the following:
GALL V.D1-26 is for buried piping. While the IP3 configuration of this piping includes a section of buried piping exposed to soil, the IP2 piping
 
configuration for these systems does not include buried piping exposed to
 
soil. The Buried Piping and Tanks Program is consistent with the GALL
 
program and includes surveillance and preventive measures to manage
 
loss of material due to the corrosion by protecting the external surface of
 
buried carbon steel piping and tanks.
The staff verified that IP2 does not have ESF piping exposed to soil, and therefore, this item is not applicable to IP2.
On the basis of its review, the staff finds the applicants Buried Piping and Tanks Program adequate to manage the effects of aging for IP3 because the applicants
 
program provide for surveillance and preventive measures that include coating the
 
buried carbon steel piping and tanks on the external surface to mitigate corrosion, which 3-306is consistent with the recommendations in GALL AMP XI.M28. (3) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in BWR stainless steel and aluminum piping and states that this aging effect is not
 
applicable to IP, which are PWRs.
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.
This item is not applicable to IP because IP2 and IP3 are PWRs. On this basis, the staff finds that the SRP-LR 3.2.2.2.3(3) criteria do not apply to IP. (4) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion and states that it could occur in copper alloy and stainless steel piping and components in ESF systems exposed to lubricating oil. The Oil Analysis Program manages loss of
 
material by periodic sampling and analysis of lubricating oil to maintain contaminants
 
within acceptable limits to preserve an environment not conducive to corrosion. The
 
One-Time Inspection Program will use visual inspections or NDEs of representative
 
samples to confirm the effectiveness of the Oil Analysis Program in managing aging
 
effects for components crediting this program.
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 intended functions of components will be maintained during the period of
 
extended operation.
The staff reviewed the Oil Analysis Program, which monitors oil chemical and physical properties, wear metals, contaminants, additives, and water and thus minimizes the
 
occurrence of aging effects and maintains component ability to perform intended functions. The effectiveness of the Oil Analysis Program is verified by the One-Time
 
Inspection Program. The One-Time Inspection Program provides inspection of selected
 
stainless steel and copper alloy components exposed to lubricating oil for loss of
 
material due to pitting and crevice corrosion in applicable ESF systems. The staff
 
evaluated the Oil Analysis and the One-Time Inspection Programs and documented the
 
evaluations in SER Sections 3.0.3.2.12 and 3.0.3.1.9, respectively. The staff finds that
 
these programs include activities that are consistent with the recommendations in the
 
GALL Report and are adequate to manage loss of material due to pitting and crevice
 
corrosion in stainless steel and copper piping and components exposed to lubricating oil. (5) LRA Section 3.2.2.2.3 addresses loss of material from pitting and crevice corrosion. It states that this aging effect is not applicable to IP2 and IP3 ESF system outdoor 3-307 stainless steel tank bottoms exposed to raw water. Their design includes a perimeter seal under the tank lip and grouting behind the seal between the concrete foundation
 
and the tank bottom to a depth of 18 inches which precludes the entry of water leaking
 
from the outside and moving under the tank bottoms.
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.
During the audit, the staff asked the applicant to identify the specific stainless tanks and their functions in the ESF systems that are applicable and to provide the equipment
 
drawings of each applicable tank for onsite review.
As documented in the Audit Report (ADAMS Accession No. ML083540662), the staff reviewed equipment drawings for IP2 and IP3 and confirmed that the design included a fibrated rope seal around the lip of the tank, a 1-inch layer of grout that was placed
 
behind the fibrated rope seal after the tank was welded, and a hot-poured bitumastic put
 
on the outside perimeter of the tank after it was erected. The RWSTs were also erected
 
on an elevated surface which was designed with a gradual decline around the perimeter
 
to preclude outside water from leaking under the tanks.
The staff agrees with the applicants determination that Item (5) of SRP-LR Section 3.2.2.2.3 does not apply to IP ESF systems because the moisture barrier
 
configuration prevents exposure to raw water in the ESF system. (6) LRA Section 3.2.2.2.3 addresses loss of material from pitting and crevice corrosion for ESF stainless steel components internally exposed to condensation and states that the
 
One-Time Inspection Program manages this aging effect by using visual and other non-
 
destructive examination (NDE) techniques to verify that loss of material has not occurred
 
or is so insignificant that no AMP for these components is warranted.
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.
During the audit, the staff asked the applicant to explain how a one-time inspection will be performed on these components and why a One-Time Inspection Program is
 
sufficient to manage the aging effect of loss of material due to pitting and crevice
 
corrosion (Audit Item 269).
In a letter dated December 18, 2007, the applicant responded:
Parameter to be monitored or inspected is wall thickness. Inspection techniques will be visual (VT-I or equivalent) or volumetric (RT or UT)
 
inspection.
The normal internal environment for the gas analyzers is air/gas with material of stainless steel and no aging effects. Since condensation may
 
be possible, a one time inspection was conservatively included to verify 3-308 that unacceptable pitting and crevice corrosion, although not expected, is not occurring, thereby confirming that there is no need for an ongoing
 
aging management program for the period of extended operation. As
 
specified in the One-Time Inspection Program, unacceptable inspection
 
findings will be evaluated in accordance with the site corrective action
 
process to determine the need for subsequent (including periodic)
 
inspections and for monitoring and trending the results.
The staff noted that the One-Time Inspection Program will confirm that loss of material is not occurring or is insignificant for internal stainless steel surfaces exposed to
 
condensation in ESF systems. This program uses visual and other NDE techniques to
 
confirm that loss of material is not occurring or is so insignificant that an AMP for these
 
components is not warranted. The staff evaluated the One-Time Inspection Program and
 
documented the evaluation in SER Section 3.0.3.1.9. The staff finds that this program
 
include activities that are consistent with the recommendations in the GALL Report and
 
are adequate to manage loss of material due to pitting and crevice corrosion for ESF
 
stainless steel components internally exposed to condensation.
Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.2.2.2.3 criteria. For those line items that apply to LRA Section 3.2.2.2.3, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3).
3.2.2.2.4  Reduction of Heat Transfer Due to Fouling
 
The staff reviewed LRA Section 3.2.2.2.4 against the 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 copper alloy HX tubes exposed to lubricating oil in ESF systems and states that the Oil Analysis
 
Program manages this aging effect. This program periodically samples and analyzes
 
lubricating oil to maintain contaminants within acceptable limits to preserve an
 
environment that is not conducive to fouling. The One-Time Inspection Program will use
 
visual inspections or NDEs of representative samples to ascertain whether the Oil
 
Analysis Program has been effective in managing aging effects for components crediting
 
this program.
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 HX 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 components intended functions will be maintained during the period of extended
 
operation.
3-309 The staff reviewed the Oil Analysis Program, which monitors oil chemical and physical properties, excessive metal loss caused by wear, contaminants, additives, and water
 
and thus minimizes the occurrence of aging effects and maintains component ability to
 
perform intended functions. The effectiveness of the Oil Analysis Program is verified by
 
the One-Time Inspection Program. The One-Time Inspection Program provides inspection of stainless steel and copper HX tubes exposed to lubricating oil for reduction
 
of heat transfer due to fouling at susceptible locations where contaminants can
 
accumulate in applicable ESF systems. The staff evaluated the Oil Analysis and the
 
One-Time Inspection Programs and documented the evaluations in SER
 
Sections 3.0.3.2.12 and 3.0.3.1.9, respectively. The staff finds that these programs
 
include activities that are consistent with the recommendations in the GALL Report and are adequate to manage reduction of heat transfer due to fouling in copper HX tubes
 
exposed to lubricating oil. (2) LRA Section 3.2.2.2.4 addresses reduction of heat transfer due to fouling for stainless steel HX tubes exposed to treated water. It states that this aging effect is not applicable because there are no stainless steel HX tubes with an intended function of heat transfer
 
exposed to treated water in the ESF systems.
SRP-LR Section 3.2.2.2.4 states that reduction of heat transfer due to fouling may occur in stainless steel HX tubes exposed to treated water.
The staff agrees that Item (2) of SRP-LR Section 3.2.2.2.4 does not apply to IP ESF systems because IP2 and IP3 do not have stainless steel HX tubes exposed to treated
 
water with an intended function of heat transfer in the ESF systems.
Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.2.2.2.4 criteria. For those line items that apply to LRA Section 3.2.2.2.4, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3).
3.2.2.2.5  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, stating that this aging effect is not applicable to IP, which are PWRs.
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 airindoor uncontrolled.
This item is not applicable to IP because IP2 and IP3 are PWRs. On this basis, the staff finds that SRP-LR 3.2.2.2.5 criteria do not apply to IP.
Based on the above, the staff concludes that SRP-LR Section 3.2.2.2.5 criteria do not apply.
3-310 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 in the stainless steel high-pressure safety injection (HPSI) pump miniflow recirculation orifice exposed to treated borated
 
water and states that this aging effect is not applicable because IP2 and IP3 use separate
 
positive displacement pumps for normal makeup to the RCS.
SRP-LR Section 3.2.2.2.6 states that loss of material due to erosion may occur in the stainless steel HPSI pump miniflow recirculation orifice exposed to treated borated water.
During its review, the staff examined the applicants updated final safety analysis report and associated plant drawings to verify the applicants statement that the HPSI pumps were
 
infrequently used. The staff noted that the HPSI miniflow recirculation lines containing flow
 
orifices are used only during emergency core cooling system injection or during HPSI pump
 
testing. The staff also noted that HPSI pumps are actuated only during testing and are not used
 
during normal charging. Since loss of material due to erosion can occur in these components
 
only if they are frequently operated, the staff finds that erosion is not plausible for IP HPSI
 
pumps and flow orifices. On this basis, the staff agrees that SRP-LR Section 3.2.2.2.6 criterion
 
does not apply to IP2 and IP3 ESF systems.
Based on the above, the staff concludes that SRP-LR Section 3.2.2.2.6 criteria do not apply.
 
3.2.2.2.7  Loss of Material Due to General Corrosion and Fouling
 
The staff reviewed LRA Section 3.2.2.2.7 against the criteria in SRP-LR Section 3.2.2.2.7.
 
LRA Section 3.2.2.2.7 addresses loss of material due to general corrosion and fouling on steel drywell and suppression chamber spray system nozzle and flow orifice internal surfaces
 
exposed to airindoor uncontrolled and states that this aging effect is not applicable to IP, which are PWRs.
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 the suppression chamber spray system nozzle and flow orifice
 
internal surfaces exposed to airindoor uncontrolled and may cause plugging of the spray
 
nozzles and flow orifices.
This item applies to BWR steel drywell and the suppression chamber spray system and is therefore not applicable to IP because IP2 and IP3 are PWRs. On this basis, the staff finds that
 
that SRP-LR Section 3.2.2.2.7 criteria do not apply to IP.
Based on the above, the staff concludes that SRP-LR Section 3.2.2.2.7 criteria do not apply.
 
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 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 steel piping, piping components, and piping elements exposed to 3-311 treated water and states that this aging effect is not applicable to IP, which are PWRs.
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.
This line item is not applicable to IP because IP2 and IP3 are PWRs. On this basis, the staff finds that the SRP-LR criteria do not apply to IP. (2) LRA Section 3.2.2.2.8 addresses loss of material due to general, pitting, and crevice corrosion for primary containment penetration steel piping and components exposed to
 
treated water and states that the Water Chemistry ControlPrimary and Secondary
 
Program manages this aging effect. The One-Time Inspection Program will confirm the
 
effectiveness of the Water Chemistry ControlPrimary and Secondary Program by an
 
inspection of a representative sample of components crediting this program, including
 
those in areas of stagnant flow and other susceptible locations.
SRP-LR Section 3.2.2.2.8 states that loss of material due to general, pitting, and crevice corrosion may occur on the internal surfaces of steel containment isolation piping, piping
 
components, and piping elements exposed to treated water. The existing AMP monitors
 
and controls water chemistry to mitigate degradation. However, control of water
 
chemistry does not preclude loss of material due to general, pitting, and crevice
 
corrosion at locations with stagnant flow conditions. Therefore, the effectiveness of
 
water chemistry control programs should be verified to ensure that corrosion does not
 
occur. The GALL Report recommends further evaluation of programs to verify the
 
effectiveness of water chemistry control programs. A one-time inspection of selected
 
components at susceptible locations is an acceptable method to determine whether an
 
aging effect is occurring or is slowly progressing such that the components intended
 
functions will be maintained during the period of extended operation.
The staff reviewed the Water Chemistry ControlPrimary and Secondary Program which monitors chlorides, fluorides, and dissolved oxygen to limit the contaminants and
 
thus minimizes the occurrence of aging effects and maintains component ability to
 
perform intended functions. The applicant has stated that the Water Chemistry Control
 
Primary and Secondary Program will be verified for effectiveness by the One-Time
 
Inspection Program. The One-time Inspection Program provides inspections of selected
 
steel components exposed to treated water at susceptible locations, such as stagnant
 
areas for loss of material due to general, pitting, and crevice corrosion in applicable ESF
 
systems. The staff evaluated the Water Chemistry ControlPrimary and Secondary
 
Program and the One-time Inspection Program and documented the evaluations in SER
 
Sections 3.0.3.2.17 and 3.0.3.1.9, respectively. The staff finds that these programs
 
include activities that are consistent with the recommendations in the GALL Report and
 
are adequate to manage loss of material due to general, pitting, and crevice corrosion on
 
internal surfaces of containment isolation piping and components exposed to treated
 
water.(3) LRA Section 3.2.2.2.8 addresses loss of material due to general, pitting, and crevice corrosion for steel piping and ESF system components exposed to lubricating oil and
 
states that the Oil Analysis Program manages this aging effect by periodic sampling and
 
analysis of lubricating oil to maintain contaminants within acceptable limits to preserve 3-312 an environment not conducive to corrosion. The One-Time Inspection Program will use visual inspections or NDEs of representative samples to verify that the Oil Analysis
 
Program has been effective in managing aging effects for components crediting this
 
program.SRP-LR Section 3.2.2.2.8 states that loss of material due to general, pitting, and crevice corrosion may occur in steel piping, piping components, and piping elements exposed to
 
lubricating oil. The existing program periodically samples and analyzes lubricating oil to
 
maintain contaminants within acceptable limits, thereby preserving an environment not
 
conducive to corrosion. However, control of lube oil contaminants may not always be
 
fully effective in precluding corrosion. Therefore, the effectiveness of lubricating oil
 
control should be verified to ensure that corrosion does not occur. The GALL Report
 
recommends further evaluation to verify the effectiveness of lubricating oil programs. A
 
one-time inspection of selected components at susceptible locations is an acceptable
 
method to ensure that corrosion does not occur and that intended functions of
 
components will be maintained during the period of extended operation.
The staff reviewed the Oil Analysis Program, which monitors oil chemical and physical properties, excessive metal loss caused by wear, contaminants, additives, and water
 
and thus minimizes the occurrence of aging effects and maintains component ability to
 
perform intended functions. The One-Time Inspection Program verifies the effectiveness
 
of the Oil Analysis Program. The One-Time Inspection Program provides inspection of
 
steel piping and components exposed to lubricating oil for loss of material due to
 
general, pitting, and crevice corrosion at susceptible locations where contaminants can
 
accumulate in applicable ESF systems. The staff evaluated the Oil Analysis and the
 
One-Time Inspection Programs and documented the evaluations in SER
 
Sections 3.0.3.2.12 and 3.0.3.1.9, respectively. The staff finds that these programs
 
include activities that 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 and components exposed to lubricating oil.
Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.2.2.2.8 criteria. For those line items that apply to LRA Section 3.2.2.2.8, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3).
3.2.2.2.9  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 microbiologically-influenced corrosion in steel piping (with or without coating or wrapping),
piping components, and piping elements buried in soil and states that this aging effect is not
 
applicable because there are no buried carbon steel components in ESF systems with intended
 
functions for license renewal at IP2 or IP3.
3-313 SRP-LR Section 3.2.2.2.9 states that loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion may occur in steel (with or without coating or wrapping)
 
piping, piping components, and piping elements buried in soil.
In the LRA, the applicant stated that SRP-LR Section 3.2.2.2.9 does not apply to the IP ESF systems because there are no buried carbon steel components in ESF systems with intended
 
functions for license renewal at IP. During the audit and review, the staff verified that there is no
 
buried carbon steel piping associated with the ESF systems at IP. On this basis, the staff finds
 
that SRP-LR Section 3.2.2.2.9 criteria do not apply to IP.
Based on the above, the staff concludes that SRP-LR Section 3.2.2.2.9 criteria do not apply.
 
3.2.2.2.10  Quality Assurance for Aging Management of Nonsafety-Related Components
 
SER Section 3.0.4 documents the staffs evaluation of the applicants QA program. 3.2A.2.3  IP2 AMR Results Not Consistent with or Not Addressed in the GALL Report 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-IP2 through 3.2.2-5-IP2, the applicant indicated, via Notes F through J, that the
 
combination of component type, material, environment, and AERM does not correspond to a
 
line item in the GALL Report. The applicant provided additional 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 applicants evaluation to determine whether the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB for the period of extended operation. The
 
following sections document the staffs evaluation.
3.2A.2.3.1  Residual Heat Removal System - Summary of Aging Management Review -
LRA Table 3.2.2-1-IP2 The staff reviewed LRA Table 3.2.2-1-IP2, which summarizes the results of AMR evaluations for the residual heat removal system component groups.
In LRA Table 3.2.2-1-IP2, the applicant proposed to manage reduction of heat transfer in stainless steel HX tube sides exposed to an internal environment of treated borated water by
 
using the Water Chemistry ControlPrimary and Secondary Program. The applicant used
 
Note G to indicate that the environment for this component and material is not in the GALL
 
Report.
3-314 SER Section 3.0.3.2.17 documents the staffs evaluation of the Water Chemistry Control Primary and Secondary Program. The staff finds that the Water Chemistry ControlPrimary
 
and Secondary Program monitors chlorides, fluorides, and dissolved oxygen to limit the
 
contaminants and thus minimizes the occurrence of aging effects and maintains component
 
ability to perform intended functions. The Water Chemistry ControlPrimary and Secondary
 
Program is consistent with the GALL Report, with no exceptions, and in accordance with the
 
latest revision of the EPRI water chemistry guidelines. The applicant also stated that the One-
 
Time Inspection Program will verify the effectiveness of the Water Chemistry ControlPrimary
 
and Secondary Program in managing aging effects. On the basis of the review discussed above
 
and the applicants plant-specific and industry operating experience, the staff finds that the
 
Water Chemistry ControlPrimary and Secondary Program will adequately manage the aging effect of fouling in stainless steel HX tube-side components exposed to an internal environment
 
of borated water.
In LRA Table 3.2.2-1-IP2, the applicant proposed to manage loss of material due to wear in stainless steel HX tube sides exposed to an external environment of treated water by using the
 
Heat Exchanger Monitoring Program. The applicant used Note H to indicate that the aging effect
 
for this component and material is not in the GALL Report.
SER Section 3.0.3.3.3 documents the staffs evaluation of the Heat Exchanger Monitoring Program. The staff finds that the Heat Exchanger Monitoring Program includes periodic visual
 
inspection or NDEs to detect loss of material due to wear on the outside tube surfaces. The staff confirms that IP2 RHR HXs and the RHR pump seal coolers are included in the scope of the
 
Heat Exchanger Monitoring Program. On this basis, the staff finds that the aging effect of loss of material due to wear in stainless steel HX tube sides exposed to an external environment of treated water will be adequately managed by using the Heat Exchanger Monitoring Program.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed 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 functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.2A.2.3.2  Containment Spray System - Summary of Aging Management Review -
LRA Table 3.2.2-2-IP2 The staff reviewed LRA Table 3.2.2-2-IP2, which summarizes the results of AMR evaluations for the CS system component groups.
In LRA Table 3.2.2-2-IP2, the applicant used Note G and identified no aging effects for the stainless steel flow element, spray nozzles, piping, tubing, and valves exposed to an interior
 
environment of plant indoor air. This line item is similar to Item VF-12 in the GALL Report, which
 
is for stainless steel piping, piping components, and piping elements in an external environment
 
of airindoor uncontrolled. Because the LRA item is similar to the GALL Report item for that
 
material and environment, the staff finds that the exposure of stainless steel material to plant
 
indoor air will not result in AERMs during the period of extended operation.
In LRA Table 3.2.2-2-IP2, the applicant proposed to manage loss of material in stainless steel piping and valves exposed to an external environment of plant indoor air by using the External
 
Surfaces Monitoring Program. The applicant used Note G to indicate that the environment for 3-315 this component and material is not in the GALL Report.
The staff finds that the applicants External Surfaces Monitoring Program performs periodic visual inspections of external surfaces during system engineer walkdowns. These walkdowns
 
are performed at least every refueling outage. SER Section 3.0.3.2.5 documents the staffs
 
evaluation of the External Surfaces Monitoring Program. The staff finds that the aging effect of
 
loss of material in stainless steel piping and valves exposed to an external environment of plant indoor air will be adequately managed by using the External Surfaces Monitoring Program.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed 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 functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.2A.2.3.3  Containment Isolation Support System - Summary of Aging Management Review -
LRA Table 3.2.2-3-IP2 The staff reviewed LRA Table 3.2.2-3-IP2, which summarizes the results of AMR evaluations for the containment isolation support system component groups. All AMR results in the table had
 
Notes A through E. The staffs evaluation of these line items is documented in SER
 
Section 3.2.2.1.
On the basis of its review, as documented in SER Section 3.2.2.1, the staff finds that all AMR results described in LRA Table 3.2.2-3-IP3 are consistent with the GALL Report.
3.2A.2.3.4  Safety Injection System - Summary of Aging Management Review -
LRA Table 3.2.2-4-IP2 The staff reviewed LRA Table 3.2.2-4-IP2, which summarizes the results of AMR evaluations for the safety injection system component groups.
In LRA Table 3.2.2-4-IP2, the applicant used Note G and identified no aging effects for stainless steel piping, tubing, and valves exposed to an interior environment of plant indoor air. This line
 
item is similar to Item VF-12 in the GALL Report, which is for stainless steel piping, piping
 
components, and piping elements in an external environment of airindoor uncontrolled.
 
Because the LRA item is similar to the GALL Report item for that material and environment, the
 
staff finds that the exposure of stainless steel material to plant indoor air will not result in aging that will be of concern during the period of extended operation.
In LRA Table 3.2.2-4-IP2, the applicant proposed to manage loss of material in stainless steel piping and tanks exposed to an external environment of outdoor air by using the External
 
Surfaces Monitoring Program. The applicant used Note G to indicate that the environment for
 
this component and material is not in the GALL Report.
The staff finds that the applicants External Surfaces Monitoring Program performs periodic visual inspections of external surfaces during system engineer walkdowns. SER
 
Section 3.0.3.2.5 documents the staffs evaluation of the External Surfaces Monitoring Program.
 
The staff finds that the aging effect of loss of material in stainless steel piping and tanks
 
exposed to an external environment of outdoor air will be adequately managed by using the 3-316 External Surfaces Monitoring Program.In LRA Table 3.2.2-4-IP2, the applicant proposed to manage fouling in copper alloy HX tubes exposed to an external environment of plant indoor air by using the Periodic Surveillance and
 
Preventive Maintenance Program. The applicant used Note G to indicate that the environment
 
for this component and material is not in the GALL Report.
SER Section 3.0.3.3.7 documents the staffs evaluation of the Periodic Surveillance and Preventive Maintenance Program. The staff finds that the Periodic Surveillance and Preventive
 
Maintenance Program includes periodic inspections and tests of the equipment. The staff
 
confirms that IP2 recirculation pump motor cooling coils are included in the scope of the
 
Periodic Surveillance and Preventive Maintenance Program. On this basis, the staff finds that the aging effect of fouling in copper alloy HX tubes exposed to an external environment of plant indoor air will be adequately managed by using the Periodic Surveillance and Preventive
 
Maintenance Program.
In LRA Table 3.2.2-1-IP2, the applicant proposed to manage loss of material due to wear in stainless steel HX tube sides exposed to an external environment of treated water by using the
 
Heat Exchanger Monitoring Program. The applicant used Note H to indicate that the aging effect
 
for this component and material is not in the GALL Report.
SER Section 3.0.3.3.3 documents the staffs evaluation of the Heat Exchanger Monitoring Program. The staff finds that the Heat Exchanger Monitoring Program includes periodic visual
 
inspection or NDEs to detect loss of material due to wear on the outside tube surfaces. The staff confirms that IP2 RHR HXs and the RHR pump seal coolers are included in the scope of the
 
Heat Exchanger Monitoring Program. On this basis, the staff finds that the aging effect of loss of material due to wear in stainless steel HX tube sides exposed to an external environment of treated water will be adequately managed by using the Heat Exchanger Monitoring Program.
In LRA Table 3.2.2-4-IP2, the applicant used Note G and identified no aging effects for stainless steel piping, tubing, and valve bodies in the safety injection system exposed to airindoor
 
internal environments. The applicant did not credit any AMPs for these component, material, and environment combinations because it concluded that there are no AERMs for these
 
components exposed to airindoor internal environments.
The staff verified that, although the GALL Report does not include AMR items for aging of stainless steel components exposed to airindoor environments, the report does include AMR
 
Item V.F-12 with an AMR for stainless steel piping components exposed to external airindoor
 
environments and the position that there are no AERMs for stainless steel components exposed
 
to such environments. The staff verified that no operating experience implies that stainless steel
 
component surfaces exposed to airindoor environments have no AERMs. Thus, the staff finds
 
it valid to conclude that there are no AERMs for the surfaces of stainless steel piping, tubing, and valve bodies exposed to airindoor internal environments. On the basis of this finding, the
 
staff concludes that the applicant need not credit any AMPs for these component, environment, material, and aging effect combinations.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed 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 functions will be maintained consistent with the CLB 3-317 for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.2A.2.3.5  Containment Penetrations - Summary of Aging Management Review -
LRA Table 3.2.2-5-IP2 The staff reviewed LRA Table 3.2.2-5-IP2, which summarizes the results of AMR evaluations for the containment penetrations component groups.
In LRA Table 3.2.2-5-IP2, the applicant used Note G and identified no aging effects for the stainless steel flow element, piping, regulator, sampler housing, tubing, and valves exposed to
 
an interior environment of plant indoor air. These line items are similar to Item VF-12 in the
 
GALL Report, which is for stainless steel piping, piping components, and piping elements in an
 
external environment of airindoor uncontrolled. Because the LRA item is similar to the GALL
 
Report item for that material and environment, the staff finds that the exposure of stainless steel
 
material to plant indoor air will not result in aging that will be of concern during the period of
 
extended operation.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL
 
Report. The staff finds that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.2B.2.3  IP3 AMR Results Not Consistent with or Not Addressed in the GALL Report 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-IP3 through 3.2.2-5-IP3, the applicant indicated, via Notes F through J, that the
 
combination of component type, material, environment, and AERM does not correspond to a
 
line item in the GALL Report. The applicant provided additional 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 applicants evaluation to determine whether the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB for the period of extended operation. The
 
following sections document the staffs evaluation.
3.2B.2.3.1  Residual Heat Removal System - Summary of Aging Management Review -
LRA Table 3.2.2-1-IP3 The staff reviewed LRA Table 3.2.2-1-IP3, which summarizes the results of AMR evaluations for the residual heat removal system component groups.
3-318 In LRA Table 3.2.2-1-IP3, the applicant proposed to manage reduction of heat transfer in stainless steel HX tube sides exposed to an internal environment of treated borated water by
 
using the Water Chemistry ControlPrimary and Secondary Program. The applicant used
 
Note G to indicate that the environment for this component and material is not in the GALL
 
Report.SER Section 3.0.3.2.17 documents the staffs evaluation of the Water Chemistry Control Primary and Secondary Program. The staff finds that the Water Chemistry ControlPrimary
 
and Secondary Program monitors chlorides, fluorides, and dissolved oxygen to limit the
 
contaminants and thus minimizes the occurrence of aging effects and maintains component
 
ability to perform its intended functions. The Water Chemistry ControlPrimary and Secondary
 
Program is consistent with the GALL Report, with no exceptions, and in accordance with the
 
latest revision of the EPRI water chemistry guidelines. The applicant also stated that the One-
 
Time Inspection Program will verify the effectiveness of the Water Chemistry ControlPrimary
 
and Secondary Program in managing aging effects. On the basis of the review discussed above
 
and the applicants plant-specific and industry operating experience, the staff finds that the
 
Water Chemistry ControlPrimary and Secondary Program will adequately manage the aging effect of fouling in stainless steel HX tube side components exposed to an internal environment
 
of borated water.
In LRA Table 3.2.2-1-IP3, the applicant proposed to manage loss of material due to wear in stainless steel HX tube sides exposed to an external environment of treated water by using the
 
Heat Exchanger Monitoring Program. The applicant used Note H to indicate that the aging effect
 
for this component and material is not in the GALL Report.
SER Section 3.0.3.3.3 documents the staffs evaluation of the Heat Exchanger Monitoring Program. The staff finds that the Heat Exchanger Monitoring Program includes periodic visual
 
inspection or NDEs to detect loss of material due to wear on the outside tube surfaces. The staff confirmed that IP3 RHR HXs and the RHR pump seal coolers are included in the scope of the
 
Heat Exchanger Monitoring Program. On this basis, the staff finds that the aging effect of loss of material due to wear in stainless steel HX tube sides exposed to an external environment of treated water will be adequately managed by using the Heat Exchanger Monitoring Program.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed 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 functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.2B.2.3.2  Containment Spray System - Summary of Aging Management Review -
LRA Table 3.2.2-2-IP3 The staff reviewed LRA Table 3.2.2-2-IP3, which summarizes the results of AMR evaluations for the containment spray system component groups.
During the audit, the staff noted that for IP3 on LRA pages 3.2-48 to 3.2-51, 11 line items reference Note G and the plant-specific Note 202. Note G states that the GALL Report does not
 
include the environment for this component and material. Note 202 states that the treated water
 
environment contains sodium hydroxide. The staff asked the applicant to explain how the AMPs 3-319 listed in each line item will manage the aging effects for the material and environment for the specified component (Audit Item 356).
In its response dated December 18, 2007, the applicant stated the following:
Per audit items 90 and 91, components exposed to sodium hydroxide are managed by the Periodic Surveillance and Preventive Maintenance Program.
 
The LRA line items in Table 3.2.2-2-IP3 will be revised to replace the Water
 
Chemistry Control - Auxiliary Systems with Periodic Surveillance and Preventive
 
Maintenance (PSPM) Program as the aging management program for
 
components with Notes G and 202.
The PSPM Program will perform visual or other NDE inspections on the inside surfaces of a representative sample of stainless steel components exposed to
 
sodium hydroxide once every five years to manage loss of material and cracking.
Clarification to be incorporated into the LRA.
By letter dated June 30, 2009, the applicant submitted an annual update to the LRA, identifying changes made to the CLB that materially affect the contents of the LRA. As a result of an
 
engineering change, the applicant modified the buffer chemical in the containment spray system
 
from sodium hydroxide (liquid injection) to sump baskets containing sodium tetraborate. The
 
AMR line items affected by this change are those discussed above in the response to the audit
 
questions. The applicant stated that the sodium hydroxide injection components are retired in
 
place and are disconnected and drained. The applicant further stated that the sump baskets
 
have no license renewal intended function and are not in scope for license renewal. The staff
 
determined that these components no longer have an intended function that meets any of the
 
criteria in 10 CFR 54.4(a). Therefore, the staff finds that the removal of the components from the
 
scope of license renewal is acceptable.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed 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 functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.2B.2.3.3  Containment Isolation Support System - Summary of Aging Management Review -
LRA Table 3.2.2-3-IP3 The staff reviewed LRA Table 3.2.2-3-IP3, which summarizes the results of AMR evaluations for the containment isolation support system component groups. All AMR results in the table had
 
Notes A through E. The staffs evaluation of these line items is documented in SER
 
Section 3.2.2.1.
On the basis of its review, as documented in SER Section 3.2.2.1, the staff finds that all AMR results described in LRA Table 3.2.2-3-IP3 are consistent with the GALL Report.
3-320 3.2B.2.3.4  Safety Injection System - Summary of Aging Management Review -
LRA Table 3.2.2-4-IP3 The staff reviewed LRA Table 3.2.2-4-IP3, which summarizes the results of AMR evaluations for the safety injection system component groups.
In LRA Table 3.2.2-4-IP3, the applicant used Note G and identified no aging effects for stainless steel piping, tubing, and valves exposed to an interior environment of plant indoor air. This line
 
item is similar to Item VF-12 in the GALL Report, which is for stainless steel piping, piping
 
components, and piping elements in an external environment of airindoor uncontrolled.
 
Because the LRA item is similar to the GALL Report item for that material and environment, the
 
staff finds that the exposure of stainless steel material to plant indoor air will not result in aging that will be of concern during the period of extended operation.
In LRA Table 3.2.2-4-IP3, the applicant proposed to manage loss of material in stainless steel piping and tanks exposed to an external environment of outdoor air by using the External
 
Surfaces Monitoring Program. The applicant used Note G to indicate that the environment for
 
this component and material is not in the GALL Report.
The staff finds that the applicants External Surfaces Monitoring Program performs periodic visual inspections of external surfaces during system engineer walkdowns. SER
 
Section 3.0.3.2.5 documents the staffs evaluation of the External Surfaces Monitoring Program.
 
The staff finds that the aging effect of loss of material in stainless steel piping and tanks
 
exposed to an external environment of outdoor air will be adequately managed by using the
 
External Surfaces Monitoring Program.In LRA Table 3.2.2-4-IP3, the applicant proposed to manage fouling in copper alloy HX tubes exposed to an external environment of plant indoor air by using the Periodic Surveillance and
 
Preventive Maintenance Program. The applicant used Note G to indicate that the environment
 
for this component and material is not in the GALL Report.
SER Section 3.0.3.3.7 documents the staffs evaluation of the Periodic Surveillance and Preventive Maintenance Program. The staff finds that the Periodic Surveillance and Preventive
 
Maintenance Program includes periodic inspections and tests of the equipment. The staff
 
confirmed that IP3 recirculation pump motor cooling coils are included in the scope of the
 
Periodic Surveillance and Preventive Maintenance Program. On this basis, the staff finds that the aging effect of fouling in copper alloy HX tubes exposed to an external environment of plant indoor air will be adequately managed by using the Periodic Surveillance and Preventive
 
Maintenance Program.
In LRA Table 3.2.2-1-IP3, the applicant proposed to manage loss of material due to wear in stainless steel HX tube sides exposed to an external environment of treated water by using the
 
Heat Exchanger Monitoring Program. The applicant used Note H to indicate that the aging effect
 
for this component and material is not in the GALL Report.
SER Section 3.0.3.3.3 documents the staffs evaluation of the Heat Exchanger Monitoring Program. The staff finds that the Heat Exchanger Monitoring Program includes periodic visual
 
inspection or NDEs to detect loss of material due to wear on the outside tube surfaces. The staff confirmed that IP3 RHR HXs and the RHR pump seal coolers are included in the scope of the
 
Heat Exchanger Monitoring Program. On this basis, the staff finds that the aging effect of loss of 3-321material due to wear in copper alloy HX tube sides exposed to an external environment of lube oil will be adequately managed by using the Heat Exchanger Monitoring Program.
In LRA Table 3.2.2-4-IP3, the applicant used Note G and identified no aging effects for stainless steel piping, tubing, and valve bodies in the safety injection system exposed to airindoor
 
internal environments. The applicant did not credit any AMPs for these components, material, and environment combinations because it concluded that there are no AERMs for these
 
components exposed to airindoor internal environments.
The staff verified that, although the GALL Report does not include AMR items on aging of stainless steel components exposed to airindoor environments, the report does include AMR
 
Item V.F-12 with an AMR for stainless steel piping components exposed to external airindoor
 
environments and the position that there are no AERMs for stainless steel components exposed
 
to such environments. The staff verified that no operating experience implies that stainless steel
 
component surfaces exposed to airindoor environments have no AERMs. Thus, the staff finds
 
it valid to conclude that there are no AERMs for surfaces of stainless steel piping, tubing, and
 
valve bodies exposed to airindoor internal environments. On the basis of this finding, the staff
 
concludes that the applicant need not credit any AMPs for these component, environment, material, and aging effect combinations.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed 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 functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.2B.2.3.5  Containment Penetrations - Summary of Aging Management Review -
LRA Table 3.2.2-5-IP3 The staff reviewed LRA Table 3.2.2-5-IP3, which summarizes the results of AMR evaluations for the containment penetrations component groups.
In LRA Table 3.2.2-5-IP3, the applicant used Note G and identified no aging effects for the stainless steel flow element, piping, regulator, sampler housing, tubing, and valves exposed to
 
an interior environment of plant indoor air. This line item is similar to Item VF-12 in the GALL
 
Report, which is for stainless steel piping, piping components, and piping elements in an
 
external environment of airindoor uncontrolled. Because the LRA item is similar to the GALL
 
Report item for that material and environment, the staff finds that the exposure of stainless steel
 
material to plant indoor air will not result in aging that will be of concern during the period of
 
extended operation.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL
 
Report. The staff finds that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-322 3.2.3  Conclusion The staff concludes that the applicant has provided sufficient information to demonstrate that the effects of aging for the ESF system components within the scope of license renewal and
 
subject to an AMR will be adequately managed so that the intended functions will be maintained
 
consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). 3.3  Aging Management of Auxiliary Systems This section of the SER documents the staffs review of the applicants AMR results for the
 
following auxiliary systems components and component groups of:  spent fuel pit cooling  SW CCW compressed air  nitrogen chemical and volume control  primary makeup water  HVAC containment cooling and filtration  control room HVAC  fire protectionwater  fire protectionCO 2,Halon, and RCP oil collection systems  fuel oil  EDG security generator  Appendix R diesel generators  city water  plant drains  miscellaneous systems in scope for 10 CFR 54.4(a)(2) 3.3.1  Summary of Technical Information in the Application LRA Section 3.3 provides AMR results for the auxiliary systems components and component groups. LRA Table 3.3.1, Summary of Aging Management Programs for Auxiliary Systems
 
Evaluated in Chapter VII of NUREG-1801, is a summary comparison of the applicants AMRs
 
with those evaluated in the GALL Report for the auxiliary systems components and component
 
groups.The applicants AMRs evaluated and incorporated applicable plant-specific and industry operating experience in the determination of AERMs. The plant-specific evaluation included
 
CRs and discussions with appropriate site personnel to identify AERMs. The applicants review
 
of industry operating experience included a review of the GALL Report and operating
 
experience issues identified since the issuance of the GALL Report.
3-323 3.3.2  Staff Evaluation The staff reviewed LRA Section 3.3 to determine whether the applicant had 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 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 conducted an onsite audit of AMRs to verify the applicants claim that certain AMRs are consistent with the GALL Report. The staff did not repeat its review of the matters described
 
in the GALL Report; however, the staff did verify that the material presented in the LRA is
 
applicable and that the applicant identified the appropriate GALL Report AMRs. SER
 
Section 3.0.3 documents the staffs evaluations of the AMPs. SER Section 3.3.2.1 presents
 
details of the staffs evaluation.
In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicants further evaluations
 
are consistent with the SRP-LR Section 3.3.2.2 acceptance criteria. SER Section 3.3.2.2
 
documents the staffs evaluations.
The staff also conducted a technical review of the remaining AMRs not consistent with or not addressed in the GALL Report. The technical review evaluated whether all plausible aging
 
effects have been identified and whether the aging effects listed are appropriate for the
 
combinations of material and environment specified. SER Sections 3.3A.2.3 (for IP2) and
 
3.3B.2.3 (for IP3) document the staffs evaluations.
For components that the applicant claimed are not applicable or require no aging management, the staff reviewed the AMR line items and the plants operating experience to verify the
 
applicants claims.
Table 3.3-1 summarizes the staffs evaluation of components, aging effects or mechanisms, and AMPs listed in LRA Section 3.3 and addressed in the GALL Report. Table 3.3-1  Staff Evaluation for Auxiliary System Components in the GALL Report Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation Steel cranes -
structural girders exposed to air -
indoor uncontrolled (external)
(3.3.1-1)Cumulative fatigue damage TLAA to be evaluated for structural girders of cranes. See the
 
SRP-LR, Section 4.7
 
for generic guidance for meeting the requirements of
 
10 CFR 54.21(c)(1). Yes TLAA Consistent with GALL Report (see SER
 
Section 3.3.2.2.1) 3-324 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff 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 Consistent with GALL Report (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 (see SER Section
 
3.3.2.2.2)
Stainless steel
 
piping, piping components, and piping elements
 
exposed to sodium
 
pentaborate solution > 60&deg;C (> 140&deg;F)(3.3.1-4)Cracking due to SCCWater Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (see SER Section 3.3.2.2.3(1))
Stainless steel and stainless clad steel heat exchanger components exposed to treated water > 60&deg;C (> 140&deg;F)(3.3.1-5)Cracking due to SCC A plant specific AMP is to be evaluated. Yes Not applicable Not Applicable (see SER Section 3.3.2.2.3(2))
Stainless steel diesel
 
engine exhaust piping, piping components, and
 
piping elements exposed to diesel exhaust (3.3.1-6)Cracking due to SCC A plant specific AMP is to be evaluated. Yes Not applicable Not Applicable (see SER Section 3.3.2.2.3(3))
3-325 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation Stainless steel non-regenerative heat exchanger components exposed
 
to treated borated water > 60
&deg;C (> 140&deg;F)(3.3.1-7)Cracking due to SCC and cyclic loadingWater Chemistry and a plant-specific verification program.
 
An acceptable
 
verification program is to include temperature and radioactivity monitoring of the shell side water, and eddy current testing of tubes. Yes Water Chemistry Control -
Primary and Secondary, and One Time InspectionConsistent with GALL Report (see SER
 
Section 3.3.2.2.4(1))
Stainless steel
 
regenerative heat exchanger components exposed
 
to treated borated water > 60
&deg;C (> 140&deg;F)(3.3.1-8)Cracking due to SCC and cyclic loadingWater Chemistry and a plant-specific
 
verification program. The AMP is to be augmented by verifying the absence of cracking due to SCC and cyclic loading. A plant specific AMP is to be
 
evaluated.Yes Water Chemistry Control - Primary and Secondary , and One Time Inspection ProgramConsistent with GALL Report (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
 
loadingWater Chemistry and a plant-specific
 
verification program. The AMP is to be augmented by verifying the absence of cracking due to SCC and cyclic
 
loading. A plant
 
specific AMP is to be evaluated.Yes Water Chemistry Control - Primary and Secondary Consistent with GALL Report (see SER Section 3.3.2.2.4(3))
High-strength steel
 
closure bolting exposed to air with steam or water
 
leakage.(3.3.1-10)
Cracking due to SCC, cyclic loadingBolting 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 AMP is to be evaluated.
Yes Periodic Surveillance and
 
Preventive MaintenanceConsistent with GALL Report (see SER Section 3.3.2.2.5(1))
3-326 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation Elastomer lining exposed to treated water or treated borated water
 
(3.3.1-12)
Hardening and loss of strength due to elastomer
 
degradation A plant-specific AMP is to be evaluated.
Yes Periodic Surveillance and
 
Preventive MaintenanceConsistent with GALL Report (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-absorbingcapacity and loss of material
 
due to general corrosion A plant specific AMP is to be evaluated.
Yes Boral Surveillance, and Water Chemistry Control -
Primary and Secondary Consistent with 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 Oil Analysis, and  One-Time InspectionConsistent 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 Oil Analysis, and  One-Time InspectionConsistent with GALL Report (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 tankYes Oil Analysis, and One-Time InspectionConsistent with GALL Report (see SER Section 3.3.2.2.7(1))
Steel piping, piping
 
components, and piping elements exposed to treated water (3.3.1-17)
Loss of material due to general, pitting, and crevice corrosionWater Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (see SER
 
Section 3.3.2.2.7(2))
Stainless steel and
 
steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust (3.3.1-18)
Loss of material/general (steel only), pitting and crevice corrosion A plant specific AMP is to be evaluated.
Yes Periodic Surveillance and
 
Preventive Maintenance,One-Time Inspection, and
 
Fire Protection Consistent with GALL Report (see SER Section 3.3.2.2.7(3))
3-327 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff EvaluationSteel (with or without coating or wrapping) piping, piping components, and
 
piping elements
 
exposed to soil (3.3.1-19)
Loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion Buried Piping and Tanks Surveillance or Buried Piping and Tanks Inspection No Yes Buried Piping and Tanks InspectionConsistent 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 microbiologically
-influenced
 
corrosion, and
 
foulingFuel Oil Chemistry and One-Time
 
InspectionYes Fuel Oil Chemistry. and One-Time InspectionConsistent 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 microbiologically
-influenced corrosion, and fouling Lubricating Oil Analysis and One-Time InspectionYes Oil Analysis, and  One-Time InspectionConsistent 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 Not applicable to PWRs (see SER Section 3.3.2.2.10(1))
Stainless steel and steel with stainless steel cladding heat exchanger components exposed to treated water (3.3.1-23)
Loss of material due to pitting
 
and crevice corrosionWater Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (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 corrosionWater Chemistry and One-Time Inspection Yes Water Chemistry, and One-Time InspectionConsistent with GALL Report (see SER
 
Section 3.3.2.2.10(2))
3-328 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff EvaluationCopper alloy HVAC piping, piping components, piping elements exposed to
 
condensation (external)
(3.3.1-25)
Loss of material due to pitting
 
and crevice corrosion A plant-specific AMP is to be evaluated. Yes External Surfaces Monitoring, and Periodic Surveillance and
 
Preventive MaintenanceConsistent 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 Oil Analysis, and One-Time InspectionConsistent with GALL Report (see SER
 
Section 3.3.2.2.10(4))
Stainless steel HVAC
 
ducting and aluminum HVAC piping, piping
 
components and piping elements exposed to
 
condensation
 
(3.3.1-27)
Loss of material due to pitting
 
and crevice corrosion A plant-specific AMP is to be evaluated. Yes Bolting Integrity, External Surfaces Monitoring, Periodic Surveillance and
 
Preventive Maintenance,and One-Time
 
InspectionConsistent with GALL Report (see SER Section 3.3.2.2.10(5))Copper alloy fire
 
protection piping, piping components, and piping elements
 
exposed to condensation (internal)
 
(3.3.1-28)
Loss of material due to pitting
 
and crevice corrosion A plant-specific AMP is to be evaluated.
Yes Periodic Surveillance and
 
Preventive MaintenanceConsistent with GALL Report (see SER
 
Section 3.3.2.2.10(6))
Stainless steel
 
piping, piping components, and piping elements
 
exposed to soil (3.3.1-29)
Loss of material due to pitting and crevice corrosion A plant-specific AMP is to be evaluated. Yes Not applicable Not applicable. There are no buried
 
stainless steel components in the auxiliary systems.
(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 corrosionWater Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (see SER
 
Section 3.3.2.2.10(8))
3-329 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff EvaluationCopper alloy piping, piping components, and piping elements exposed to treated water (3.3.1-31)
Loss of material due to pitting, crevice, and galvanic corrosionWater Chemistry and One-Time InspectionYes Not applicable Not applicable to PWRs (see SER
 
Section 3.3.2.2.11)
Stainless steel, aluminum and copper alloy piping, piping components, and piping elements exposed to fuel oil (3.3.1-32)
Loss of material due to pitting, crevice, and microbiologically-influenced
 
corrosionFuel Oil Chemistry and One-Time
 
InspectionYes Diesel Fuel Monitoring, One-Time Inspection, Periodic Surveillance and Preventive
 
MaintenanceConsistent with GALL Report (see SER Section 3.3.2.2.12(1))
Stainless steel
 
piping, piping components, and piping elements
 
exposed to lubricating oil (3.3.1-33)
Loss of material due to pitting, crevice, and microbiologically-influenced
 
corrosion Lubricating Oil Analysis and One-Time InspectionYes Oil Analysis, and One-Time InspectionConsistent 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 AMP is to be evaluated. Yes Not applicable Not applicable (see SER Section
 
3.3.2.2.13)Steel with stainless
 
steel cladding pump casing exposed to treated borated water
 
(3.3.1-35)
Loss of material due to cladding
 
breach A plant-specific AMP is to be evaluated.
Reference NRC IN 94-63, Boric Acid
 
Corrosion of Charging Pump Casings Caused by
 
Cladding Cracks. Yes Not applicable Not applicable (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-absorbingcapacity due to boraflex degradationBoraflex Monitoring No Not applicable Not applicable to PWRs (see SER
 
Section 3.3.2.1.1)
Stainless steel
 
piping, piping components, and piping elements
 
exposed to treated water > 60
&deg;C (> 140&deg;F)(3.3.1-37)
Cracking due to SCC, intergranular
 
SCC BWR Reactor Water Cleanup System No Not applicable Not applicable to PWRs (see SER Section 3.3.2.1.1) 3-330 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation Stainless steel piping, piping components, and piping elements
 
exposed to treated water > 60
&deg;C (> 140&deg;F)(3.3.1-38)
Cracking due to SCC BWR SCC and Water Chemistry No Not applicable Not applicable to PWRs (see SER Section 3.3.2.1.1)
Stainless steel BWR
 
spent fuel storage racks exposed to treated water > 60
&deg;C (> 140&deg;F)(3.3.1-39)
Cracking due to SCCWater Chemistry No Not applicable Not applicable to PWRs (see SER Section 3.3.2.1.1)
Steel tanks in diesel fuel oil system exposed to air -
outdoor (external)
 
(3.3.1-40)
Loss of material due to general, pitting, and crevice corrosion Aboveground Steel Tanks No Aboveground Steel Tanks Consistent with GALL Report High-strength steel
 
closure bolting exposed to air with steam or water
 
leakage (3.3.1-41)
Cracking due to cyclic loading, SCCBolting Integrity No Not applicable Not applicable. High-strength steel closure
 
bolting is not used in the auxiliary systems (see SER Section
 
3.3.2.1.1)
Steel closure bolting exposed to air with steam or water leakage (3.3.1-42)
Loss of material due to general
 
corrosionBolting Integrity No Not applicable Not applicable. This line item was not
 
used. Loss of material of steel closure bolting was addressed by other items including 3.3.1-43, 3.3.1-44
 
and 3.3.1-55 (see SER Section 3.3.2.1.2)
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 corrosionBolting Integrity No Bolting Integrity Consistent with GALL Report Steel compressed air system closure bolting exposed to condensation
 
(3.3.1-44)
Loss of material due to general, pitting, and crevice corrosionBolting Integrity No Bolting Integrity Consistent with GALL Report 3-331 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation Steel closure bolting exposed to air -
indoor uncontrolled (external)
 
(3.3.1-45)
Loss of preload due to thermal effects, gasket
 
creep, and self-
 
looseningBolting Integrity No Bolting Integrity Consistent with GALL Report (See SER
 
Section 3.3.2.1.4)
Stainless steel and
 
stainless clad steel piping, piping components, piping
 
elements, and heat exchanger components exposed to closed cycle
 
coolingwater > 60
&deg;C (> 140&deg;F)(3.3.1-46)
Cracking due to SCCClosed-Cycle Cooling Water System No Water Chemistry Control - Closed Cooling Water, and One-Time
 
Inspection for Water Chemistry Consistent with GALL Report Steel piping, piping
 
components, piping elements, tanks, and heat exchanger
 
components exposed to closed cycle cooling water (3.3.1-47)
Loss of material due to general, pitting, and crevice corrosionClosed-Cycle Cooling Water System No Water Chemistry Control - Closed
 
Cooling Water, and One-Time Inspection for Water Chemistry Consistent with GALL Report Steel piping, piping components, piping elements, tanks, and heat exchanger
 
components exposed to closed cycle cooling water (3.3.1-48)
Loss of material due to general, pitting, crevice, and galvanic corrosionClosed-Cycle Cooling Water System No Water Chemistry Control - Closed
 
Cooling Water Consistent with GALL Report Stainless steel; steel with stainless steel cladding heat exchanger components exposed to closed cycle cooling water
 
(3.3.1-49)
Loss of material due to microbiologically-influenced corrosionClosed-Cycle Cooling Water System No Water Chemistry Control - Closed
 
Cooling Water Consistent with GALL Report 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 corrosionClosed-Cycle Cooling Water System No Water Chemistry Control - Closed
 
Cooling Water, and One-Time Inspection for Water Chemistry Consistent with GALL Report 3-332 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff EvaluationCopper 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 corrosionClosed-Cycle Cooling Water System No Water Chemistry Control - Closed
 
Cooling Water, and One-Time Inspection for Water Chemistry Consistent with GALL Report Steel, stainless steel, and copper alloy heat exchanger tubes
 
exposed to closed cycle cooling water (3.3.1-52)
Reduction of heat transfer
 
due to fouling Closed-Cycle Cooling Water System No Water Chemistry Control - Closed
 
Cooling Water, and One-Time Inspection for Water Chemistry 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 Periodic Surveillance and
 
Preventive Maintenance See SER Section 3.3.2.1.3 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 MonitoringNo One-Time Inspection See SER Section 3.3.2.1.3 Steel ducting closure
 
bolting exposed to air - indoor uncontrolled (external)
 
(3.3.1-55)
Loss of material due to general
 
corrosion External Surfaces Monitoring No External Surfaces MonitoringConsistent with GALL Report Steel HVAC ducting
 
and components external surfaces exposed to air -
 
indoor uncontrolled (external)
(3.3.1-56)
Loss of material due to general
 
corrosion External Surfaces Monitoring No External Surfaces Monitoring, and Periodic Surveillance and
 
Preventive MaintenanceConsistent with GALL Report Steel piping and
 
components external surfaces exposed to air - indoor
 
uncontrolled (External)
(3.3.1-57)
Loss of material due to general
 
corrosion External Surfaces Monitoring No External Surfaces MonitoringConsistent with GALL Report 3-333 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff 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 External Surfaces Monitoring, Fire
 
Protection, and Periodic Surveillance and Preventive MaintenanceConsistent 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 External Surfaces Monitoring, and Periodic Surveillance and
 
Preventive MaintenanceConsistent 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 External Surfaces MonitoringConsistent with GALL Report Elastomer fire barrier
 
penetration seals exposed to air - outdoor or
 
air - indoor uncontrolled (3.3.1-61)
Increased hardness, shrinkage and loss of strength due to weathering Fire Protection No Fire Protection This line item was not used for auxiliary systems. (See SER Section 3.3.2.1.1)
Aluminum piping, piping components, and piping elements exposed to raw water
 
(3.3.1-62)
Loss of material due to pitting
 
and crevice corrosionFire Protection No One-Time Inspection, and
 
Service Water Integrity The components to which this line item
 
applies are included in scope under criterion 10 CFR
 
54.4(a)(2) and are listed in series 3.3.2-19-xx tables. (See
 
SER Section
 
3.3.2.1.6)
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 This line item was not used for auxiliary systems. (See SER Section 3.3.2.1.1 Steel piping, piping components, and piping elements exposed to fuel oil
 
(3.3.1-64)
Loss of material due to general, pitting, and crevice corrosion Fire Protection and Fuel Oil Chemistry No Fire Protection, and Diesel Fuel MonitoringConsistent with GALL Report 3-334 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff 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
 
ProgramNo Fire Protection, and Structures
 
MonitoringThis line item was not used for auxiliary systems. (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
 
ProgramNo Fire Protection, and Structures
 
MonitoringThis line item was not used for auxiliary systems. Reinforced
 
concrete structural fire barriers are
 
evaluated as structural components in Section 3.5 of the
 
LRA.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
 
ProgramNo Fire Protection, and Structures
 
MonitoringThis line item was not used for auxiliary systems. (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 microbiologically
-influenced corrosion, and foulingFire Water System No Fire Water System Consistent with GALL Report Stainless steel
 
piping, piping components, and piping elements exposed to raw water (3.3.1-69)
Loss of material due to pitting
 
and crevice corrosion, and foulingFire Water System No Fire Water System Consistent with GALL ReportCopper alloy piping, piping components, and piping elements exposed to raw water
 
(3.3.1-70)
Loss of material due to pitting, crevice, and microbiologically
-influenced
 
corrosion, and foulingFire Water System No Fire Water System Consistent with GALL Report 3-335 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation 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 Periodic Surveillance and
 
Preventive Maintenance See SER Section 3.3.2.1.6 Steel HVAC ducting
 
and components internal surfaces exposed to
 
condensation (internal)
 
(3.3.1-72)
Loss of material due to general, pitting, crevice, and (for drip
 
pans and drain
 
lines)microbiologically-influenced
 
corrosion Inspection of Internal Surfaces in
 
Miscellaneous Piping and Ducting Components No Periodic Surveillance and
 
Preventive
 
Maintenance, and External
 
Surfaces Monitoring See SER Section 3.3.2.1.7 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 Periodic Surveillance and
 
Preventive
 
Maintenance, and Structures MonitoringThis line item was not used in the auxiliary systems tables. (See
 
SER Section 3.3.2.1.1)
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 Periodic Surveillance and
 
Preventive Maintenance, and Structures
 
MonitoringThis line item was not used. Steel crane rails are evaluated as
 
structural components in Section 3.5.
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 Periodic Surveillance and
 
Preventive MaintenanceThe components to which this line item
 
applies are included in scope under criterion 10 CFR
 
54.4(a)(2) and are
 
listed in series 3.3.2-19-xx tables in systems other than service water. (See SER Section 3.3.2.1.5)
Steel piping, piping
 
components, and piping elements (without lining/
coating or with degraded lining/coating) exposed to raw water
 
(3.3.1-76)
Loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion, fouling, and
 
lining/coating
 
degradationOpen-Cycle Cooling Water System No Service Water Integrity
 
Program, and
 
Periodic Surveillance and Preventive
 
MaintenanceConsistent with GALL Report 3-336 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation Steel heat exchanger components exposed to raw water (3.3.1-77)
Loss of material due to general, pitting, crevice, galvanic, and
 
microbiologically-influenced corrosion, and foulingOpen-Cycle Cooling Water System No Service Water Integrity 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 corrosionOpen-Cycle Cooling Water System No Service Water Integrity Consistent with GALL Report. Stainless steel and copper alloy components exposed to raw water are
 
addressed in other items including 3.3.1-79 and 3.3.1-81.
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 foulingOpen-Cycle Cooling Water System No Service Water Integrity, and One-Time InspectionConsistent 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 microbiologically-influenced
 
corrosionOpen-Cycle Cooling Water System No Service Water Integrity Consistent with GALL ReportCopper alloy piping, piping components, and piping elements, exposed to raw water
 
(3.3.1-81)
Loss of material due to pitting, crevice, and microbiologically-influenced
 
corrosion, and foulingOpen-Cycle Cooling Water System No Service Water Integrity Consistent with GALL ReportCopper alloy heat
 
exchanger components exposed to raw water
 
(3.3.1-82)
Loss of material due to pitting, crevice, galvanic, and
 
microbiologically
-influenced corrosion, and foulingOpen-Cycle Cooling Water System No Service Water Integrity 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 Service Water Integrity Consistent with GALL Report 3-337 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff EvaluationCopper 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 LeachingConsistent with GALL ReportGray 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 LeachingConsistent with GALL ReportStructural 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 ProgramNo Not applicable to auxiliary systems. This line item was not used. Structural steel of the new fuel
 
storage rack assembly is evaluated as a
 
structural component in Section 3.5. (See SER Section
 
3.3.2.1.1)
Boraflex spent fuel
 
storage racks neutron-absorbing sheets exposed to treated borated water (3.3.1-87)
Reduction of neutron-absorbingcapacity due to boraflex degradationBoraflex Monitoring No Boraflex Monitoring, and Water Chemistry Control - Primary and Secondary Consistent with GALL Report 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
 
corrosionBoric Acid Corrosion No Boric Acid Corrosion PreventionConsistent with GALL Report Steel bolting and
 
external surfaces exposed to air with borated water
 
leakage (3.3.1-89)
Loss of material due to boric acid
 
corrosionBoric Acid Corrosion No Boric Acid Corrosion PreventionConsistent with GALL Report 3-338 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation Stainless steel and steel with stainless steel cladding piping, piping components, piping elements, tanks, and fuel storage racks
 
exposed to treated borated water > 60&deg;C (> 140&deg;F)(3.3.1-90)
Cracking due to SCCWater Chemistry No Water Chemistry Control - Primary and Secondary Consistent with GALL Report Stainless steel and steel with stainless steel cladding piping, piping components, and piping elements exposed to treated borated water
 
(3.3.1-91)
Loss of material due to pitting and crevice corrosionWater Chemistry No Water Chemistry Control -
Primary and Secondary Consistent with GALL Report Galvanized steel
 
piping, piping components, and piping elements
 
exposed to air -
indoor uncontrolled (3.3.1-92)None None NA Not applicable.
No Aging Effect
 
Mechanism or AMP Not applicable.
Galvanized steel
 
surfaces are evaluated as steel for the auxiliary systems.
(See SER Section 3.3.2.1.1)
Glass piping elements exposed to air, air - indoor uncontrolled (external), fuel oil, lubricating oil, raw water, treated water, and treated borated water (3.3.1-93)None None NA Not applicable.
No Aging Effect
 
Mechanism or AMP Not applicable (See SER Section
 
3.3.2.1.1)
Stainless steel and nickel alloy piping, piping components, and piping elements
 
exposed to air -
indoor uncontrolled (external)
 
(3.3.1-94)None None NA Not applicable.
No Aging Effect
 
Mechanism or AMP Not applicable (See SER Section
 
3.3.2.1.1) 3-339 Component Group (GALL Report Item No.)Aging Effect/
MechanismAMP in GALL Report Further Evaluation in GALL ReportAMP in LRA, Supplements, orAmendmentsStaff Evaluation Steel and aluminum piping, piping components, and piping elements
 
exposed to air -
 
indoor controlled (external)
 
(3.3.1-95)None None NA Not applicable.
No Aging Effect
 
Mechanism or AMP Not applicable (See SER Section
 
3.3.2.1.1)
Steel and stainless
 
steel piping, piping components, and
 
piping elements in concrete (3.3.1-96)None None NA Not applicable.
No Aging Effect
 
Mechanism or AMP Not applicable (See SER Section
 
3.3.2.1.1)
Steel, stainless steel, aluminum, and copper alloy piping, piping components, and piping elements exposed to gas (3.3.1-97)None None NA Not applicable.
No Aging Effect
 
Mechanism or AMP Not applicable (See SER Section
 
3.3.2.1.1)
Steel, stainless steel, and copper alloy piping, piping components, and
 
piping elements
 
exposed to dried air (3.3.1-98)None None NA Not applicable.
No Aging Effect
 
Mechanism or AMP Not applicable (See SER Section
 
3.3.2.1.1)
Stainless steel and copper alloy
< 15% Zn piping, piping components, and piping elements exposed to air with borated water leakage (3.3.1-99)None None NA Not applicable.
No Aging Effect
 
Mechanism or AMPNot applicable. There are no copper alloy
 
components exposed to air with borated water leakage in the auxiliary systems.
(See SER Section 3.3.2.1.1)
The staffs review of the auxiliary systems component groups followed any one of several approaches. In one approach, documented in SER Section 3.3.2.1, the staff reviewed AMR
 
results for components that the applicant indicated are consistent with the GALL Report and
 
require no further evaluation. In the second approach, documented in SER Section 3.3.2.2, the
 
staff reviewed AMR results for components that the applicant indicated are consistent with the
 
GALL Report and for which further evaluation is recommended. In the third approach, documented in SER Sections 3.3A.2.3 (for IP2) and 3.3B.2.3 (for IP3), the staff reviewed AMR
 
results for components that the applicant indicated are not consistent with, or not addressed in, the GALL Report. The staffs review of AMPs credited to manage or monitor aging effects of the
 
auxiliary systems components is documented in SER Section 3.0.3.
3-3403.3.2.1  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 the auxiliary systems components:  Aboveground Steel Tanks Program  Bolting Integrity Program  Boraflex Monitoring Program  Boral Surveillance Program  Boric Acid Corrosion Prevention Program  Buried Piping and Tanks Inspection Program  Diesel Fuel Monitoring Program  External Surfaces Monitoring Program  Fire Protection Program  Fire Water System Program  Flow-Accelerated Corrosion Program  Heat Exchanger Monitoring Program  Oil Analysis Program  One-Time Inspection Program  Periodic Surveillance and Preventive Maintenance Program  Selective Leaching Program  Service Water Integrity Program  Water Chemistry Control - Auxiliary Systems Program  Water Chemistry Control - Closed Cooling Water Program  Water Chemistry Control - Primary and Secondary Program LRA Tables 3.3.2-1-IP2 through 3.3.2-18-IP2, 3.3.2-1-IP3 through 3.3.2-18-IP3, 3.3.2-19-1-IP2 through 3.3.2-19-44-IP2, and 3.3.2-19-1-IP3 through 3.3.2-19-65-IP3 summarize the results of
 
AMRs for the auxiliary system components and indicate AMRs claimed to be consistent with the
 
GALL Report.
For component groups evaluated in the GALL Report, for which the applicant claimed consistency with the report, where the report does not recommend further evaluation, the staffs
 
audit and review determined whether the plant-specific components of these GALL Report
 
component groups were bounded by the GALL Report evaluation.
For each AMR line item, the applicant stated how the information in the tables aligns with the information in the GALL Report. Notes A through E indicate how the AMR is consistent with the
 
GALL Report. The staff audited these AMRs.
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 applicants AMP was consistent with the 3-341 GALL Report AMP and whether the AMR was valid for the site-specific conditions.
Note C indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is
 
consistent with the GALL Report AMP. This note indicates that the applicant was unable to find
 
a listing of some system components in the GALL Report; however, the applicant identified in
 
the GALL Report a different component with the same material, environment, aging effect, and
 
AMP as the component under review. The staff audited these line items to verify consistency
 
with the GALL Report. The staff also determined whether the AMR line item of the different
 
component was applicable to the component under review and whether the AMR was valid for
 
the site-specific conditions.
Note D indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes
 
some exceptions to the GALL Report AMP. The staff audited these line items to verify
 
consistency with the GALL Report. The staff verified whether the AMR line item of the different
 
component was applicable to the component under review and whether the identified
 
exceptions to the GALL Report AMPs have been reviewed and accepted. The staff also
 
determined whether the applicants 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
 
auxiliary systems components that are subject to an AMR.
In response to RAI 2.3A.4.5-1, by letter dated January 4, 2008, the applicant revised the LRA to include several AMR line items associated with IP1 condensate storage tank and piping to the
 
IP2 condensers which were not previously included in scope under 10 CFR 54.4(a)(3). The
 
AMR line items added included carbon steel piping, tank and valve body with an internal
 
environment of treated air, an external environment of outdoor air, an aging effect of loss of
 
material, and Note A or Note A with plant-specific Note 314.
In response to RAI 2.1-1, Part (b), by letter dated February 13, 2008, the applicant revised the LRA to include several AMR line items associated with chlorination system which were not
 
previously included within the scope of license renewal under 10 CFR 54.4(a)(2). The AMR line
 
items added included carbon steel bolting, piping, and valve body with an internal environment
 
of treated air, an external environment of indoor air, an aging effect of loss of material, and
 
Note A.
3-342 In response to RAI 2.3A.2.2-1, by letter dated March 12, 2008, the applicant revised the LRA to include several AMR line items associated with the component cooling water and building vent
 
sampling (IP3) systems which were not previously included within the scope of license renewal
 
under 10 CFR 54.4(a)(2). The AMR line items added included stainless steel bolting, piping, tubing, filter housing and valve body with internal environments of treated water or indoor air, an
 
external environment of indoor air, an aging effect of loss of material or none, and Notes A or
 
C. Also added were carbon steel bolting, flow element, heat exchanger housing, piping, strainer
 
housing, thermowell, and valve body with an internal environment of treated water, an external
 
environment of indoor air, an aging effect of loss or material, and Notes A, B, or C.
In response to RAI 2.2B-2, by letter dated March 12, 2008, the applicant revised the LRA to include several AMR line items associated with the hydrogen system which was not previously
 
included within the scope of license renewal under 10 CFR 54.4(a)(2). The AMR line items
 
added included carbon steel bolting, stainless steel bolting, stainless steel piping, stainless steel
 
valve bodies, and copper alloy >15 percent zinc valve bodies with an internal environment of
 
gas, an external environment of indoor air, an aging effect of loss of material (for carbon steel
 
bolting only) or none, and Notes A or C.
In response to RAI 2.3.0-2, by letter dated March 12, 2008, the applicant revised the LRA to add AMR line items associated with the reactor coolant pump motor upper and lower bearing heat
 
exchangers that were not previously identified as subject to an AMR. The AMR line items added
 
included carbon steel heat exchanger bonnet and tubes with an internal environment of treated
 
water, external environments of indoor air or lube oil, an aging effect of loss of material, and
 
Notes A or D.
By letter dated April 30, 2008, the applicant amended the LRA to reflect the installation of the IP2 SBO/Appendix R diesel generator. In the amendment, the applicant revised LRA Table
 
3.3.2-16-IP2 to reflect the changes to the AMRs as a result of the modification. The revised
 
AMR line items included numerous components of various materials, environments, and aging
 
effects with Notes A through E. The staffs evaluation of the AMR line item with Note E is
 
documented in SER Section 3.2.2.1.3.
By letter dated June 11, 2008, the applicant submitted an annual update to the LRA, which included a clarification to components included within the scope of license renewal for 10 CFR
 
54.4(a)(2) as a result of the regional inspections. The applicant revised several LRA tables in the 3.3.2-19-XX series to add numerous components made of carbon steel, stainless steel, gray
 
cast iron, elastomer, and glass exposed to internal environments of treated water, treated water
 
>140&deg;F, indoor air, and raw water, and external environment of indoor air. The revised AMR line
 
items included numerous aging effects with Notes A through E. The staffs evaluation of the
 
AMR line items with Note E is documented in SER Sections 3.2.2.1.3, 3.3.2.1.3, 3.3.2.1.9, 3.3.2.1.11, 3.3.2.2.5(1), 3.3.2.2.5(2), and 3.4.2.2.1.
By letter dated June 30, 2009, the applicant submitted an annual update to the LRA, identifying changes made to the CLB that materially affect the contents of the LRA. For the plant drains
 
system, the applicant revised LRA Tables 3.3.2-18-IP2 and 3.3.2-18-IP3 to add gray cast iron
 
valve bodies exposed internally to indoor air with an aging effect of loss of material, and
 
exposed externally to indoor air with an aging effect of none, and Notes A and E, respectively.
 
The staffs evaluation of the AMR line item with Note E is documented in SER Section 3.2.2.1.3.
 
For the security generator system, the applicant replaced carbon steel flexible bellows with 3-343 stainless steel flexible bellows, and listed the aging effect and AMP as none. The applicant annotated this line item with Note C.
The staff reviewed the applicants revisions, noted above, and found that the additional AMR results are consistent with the GALL Report for these combinations of materials and
 
environments. On the basis of its review, the staff finds that all applicable aging effects were
 
identified, and the aging effects listed are appropriate for the combination of materials and
 
environments identified.
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 applicants references to the GALL Report are
 
acceptable and no further staff review is required.
3.3.2.1.1 AMR Results Identified as Not Applicable LRA Table 3.3.1, Line Item 36 addresses the reduction of neutron-absorbing capacity due to boraflex degradation in boraflex spent fuel storage racks neutron-absorbing sheets exposed to
 
treated water in BWRs. The LRA states that this line item is only applicable to Boiling Water
 
Reactor designs, and, therefore, it is not applicable. Since IP2 and IP3 are both PWRs, the staff
 
finds this to be consistent with the GALL Report, and, therefore, acceptable.
LRA Table 3.3.1, Line Item 37 addresses cracking due to SCC and intergranular SCC in stainless steel piping, piping components, and piping elements exposed to treated water >60&deg;C
 
(>140&deg;F) in BWRs. The LRA states that this line item is only applicable to Boiling Water Reactor
 
designs, and, therefore, it is not applicable. Since IP2 and IP3 are both PWRs, the staff finds
 
this to be consistent with the GALL Report, and, therefore, acceptable.
LRA Table 3.3.1, Line Item 38 addresses cracking due to SCC in stainless steel piping, piping components, and piping elements exposed to treated water >60&deg;C (>140&deg;F) in BWRs. The LRA
 
states that this line item is only applicable to Boiling Water Reactor designs, and, therefore, it is
 
not applicable. Since IP2 and IP3 are both PWRs, the staff finds this to be consistent with the
 
GALL Report, and, therefore, acceptable.
LRA Table 3.3.1, Line Item 39 addresses cracking due to SCC in stainless steel spent fuel storage racks exposed to treated water >60&deg;C (>140&deg;F) in BWRs. The LRA states that this line
 
item is only applicable to Boiling Water Reactor designs, and, therefore, it is not applicable.
 
Since IP2 and IP3 are both PWRs, the staff finds this to be consistent with the GALL Report, and, therefore, acceptable.
LRA Table 3.3.1, Line Item 41 addresses cracking due to cyclic loading, SCC in high-strength steel closure bolting exposed to air with steam or water leakage. The LRA states that high-
 
strength steel bolts are not used in the Non-Class 1 auxiliary systems. During the audit the staff
 
confirmed that the bolting used in Non-Class 1 components is not high strength steel, and that
 
no high strength steel bolts were identified by the applicant during its aging management review
 
of auxiliary systems. The staff finds this to be consistent with the GALL Report and, therefore, acceptable.
LRA Table 3.3.1, Line Item 61 addresses increased hardness, shrinkage and loss of strength due to weathering in elastomeric seals exposed to air - outdoor or air - indoor uncontrolled.
 
This line item was not used in the auxiliary systems tables. Fire barrier seals are evaluated as 3-344 structural components in SER Section 3.5. Cracking and the change in material properties of elastomer seals are managed by the Fire ProtectionProgram. SER Section 3.5.2.3.4
 
documents the staffs evaluation of this item.
LRA Table 3.3.1, Line Item 63 addresses loss of material due to wear in steel fire rated doors exposed to air - outdoor or air - indoor uncontrolled. The GALL Report recommends that loss of
 
material due to wear of steel fire doors be managed by the Fire Protection Program. The LRA
 
states that this line item was not used in the auxiliary systems tables. Steel fire doors are
 
evaluated as structural components in Section 3.5, Structures and Component Supports. SER
 
Section 3.5.2.1 documents the staffs evaluation of this item.
LRA Table 3.3.1, Line Item 65 addresses concrete cracking and spalling of reinforced concrete fire barriers (walls, ceilings, and floors) exposed to uncontrolled indoor air. The GALL Report
 
recommends that concrete cracking and spalling be managed by the Fire Protection and
 
Structures Monitoring Program. The LRA states that this line item was not used in the auxiliary
 
systems tables. Reinforced concrete fire barriers are evaluated as structural components in
 
Section 3.5, Structures and Component Supports. SER Sections 3.5.2.3 and 3.5.2.4 document
 
the staffs evaluation of this item.
LRA Table 3.3.1, Line Item 66 addresses concrete cracking and spalling of reinforced concrete fire barriers (walls, ceilings, and floors) exposed to outdoor air. The GALL Report recommends
 
that concrete cracking and spalling be managed by the Fire Protection and Structures
 
Monitoring Program. The LRA states that this line item was not used in the auxiliary systems
 
tables. Reinforced concrete fire barriers are evaluated as structural components in Section 3.5, Structures and Component Supports. SER Section 3.5.2.3 documents the staffs evaluation of
 
this item.
LRA Table 3.3.1, Line Item 67 addresses loss of material due to corrosion of embedded steel of reinforced concrete fire barriers exposed to uncontrolled outdoor or indoor air. The GALL Report
 
recommends that concrete cracking and spalling be managed by the Fire Protection and
 
Structures Monitoring Program. The LRA states that this line item was not used in the auxiliary
 
systems tables. Reinforced concrete fire barriers are evaluated as structural components in
 
Section 3.5, Structures and Component Supports. SER Section 3.5.2.3 documents the staffs
 
evaluation of this item.
LRA Table 3.3.1, Line Item 73 addresses loss of material due to general corrosion in steel crane structural girders in load handling system exposed to air- indoor uncontrolled (external). The
 
GALL Report recommends that the loss of material due to wear be managed by the inspection
 
of overhead heavy load and light load (related to refueling) handling systems. The LRA states
 
that this line item was not used in the auxiliary systems tables. Steel crane structural girders are
 
evaluated as structural components in Section 3.5, Structures and Component Supports. Loss
 
of material for steel crane structural components is managed by the Periodic Surveillance and
 
Preventive Maintenance and Structures Monitoring Programs using periodic visual or other NDE
 
techniques. SER Section 3.5.2.3 documents the staffs evaluation of this item.
LRA Table 3.3.1, Line Item 74 addresses loss of material due to wear in steel crane rails exposed to uncontrolled indoor air. The GALL Report recommends that the loss of material due
 
to wear be managed by the inspection of overhead heavy load and light load (related to
 
refueling) handling systems. The LRA states that this line item was not used in the auxiliary
 
systems tables. Steel crane rails are evaluated as structural components in Section 3.5, 3-345 Structures and Component Supports. SER Section 3.5.2.3 documents the staffs evaluation of this item.
LRA Table 3.3.1, Line Item 86 addresses loss of material due to general, pitting, and crevice corrosion in structural steel (new fuel storage rack assembly) exposed to air - indoor
 
uncontrolled (external). The GALL Report recommends that these aging mechanisms be
 
managed by the Structures Monitoring Program. The LRA states that this line item was not used
 
in the auxiliary systems tables. Structural steel of the new fuel storage rack is evaluated as a
 
structural component in Section 3.5, Structures and Component Supports, of the LRA. The staff
 
finds this to be consistent with the GALL Report and, therefore, is acceptable.
LRA Table 3.3.1, Line Item 92 addresses the lack of an aging effect in galvanized steel piping, piping components, and piping elements exposed to uncontrolled indoor air. Since there is no
 
aging effect applicable to these components when exposed to indoor air, the GALL Report does
 
not recommend any AMP. Therefore this line item is identified in the LRA as not applicable.
 
Although this specific line item is not applicable, the LRA states that galvanized steel surfaces
 
of the auxiliary systems are evaluated as steel. The staff finds this is consistent with the GALL
 
Report and, therefore, is acceptable.
LRA Table 3.3.1, Line Item 93 addresses the lack of an aging effect in glass piping elements exposed to air, air - indoor uncontrolled (external), fuel oil, lubricating oil, raw water, treated
 
water, and treated borated water. Since there is no aging effect applicable to these components
 
when exposed to uncontrolled indoor air, fuel oil, lubricating oil, raw water, treated water, or
 
treated borated water, the GALL Report does not recommend any AMP. Therefore, this line
 
item is identified in the LRA as not applicable. The staff finds this is consistent with the GALL
 
Report and, therefore, is acceptable.
LRA Table 3.3.1, Line Item 94 addresses the lack of an aging effect in stainless steel and nickel alloy piping, piping components, and piping elements exposed to uncontrolled indoor air (external). Since there is no aging effect applicable to these components when exposed to
 
indoor air, the GALL Report does not recommend any AMP. In addition, the LRA states that there are no nickel alloy components exposed to uncontrolled indoor air in the auxiliary systems.
 
The staff finds that the classification of this line item in the LRA as not applicable is consistent
 
with the GALL Report and, therefore is acceptable.
LRA Table 3.3.1, Line Item 95 addresses the lack of an aging effect in steel and aluminum piping, piping components, and piping elements exposed to indoor controlled air (external).
 
Since there is no aging effect applicable to these components when exposed to indoor air, the
 
GALL Report does not recommend any AMP. The LRA also states that since all indoor air
 
environments are conservatively considered to be uncontrolled. There are no steel or aluminum components in the auxiliary systems that are exposed to indoor controlled air. The staff finds
 
that the classification of this line item in the LRA as not applicable is consistent with the GALL
 
Report and, therefore is acceptable.
LRA Table 3.3.1, Line Item 96 addresses the lack of an aging effect in steel and stainless steel piping, piping components, and piping elements in concrete. Since there is no aging effect
 
applicable to these components when exposed to concrete, the GALL Report does not
 
recommend any AMP. The staff finds that the classification of this line item in the LRA as not
 
applicable is consistent with the GALL Report and, therefore is acceptable.
3-346 LRA Table 3.3.1, Line Item 97 addresses the lack of an aging effect in steel, stainless steel, aluminum, and copper alloy piping, piping components, and piping elements exposed to gas.
 
Since there is no aging effect applicable to these components when exposed to gas, the GALL
 
Report does not recommend any AMP. The staff finds that the classification of this line item in
 
the LRA as not applicable is consistent with the GALL Report and, therefore is acceptable.
LRA Table 3.3.1, Line Item 98 addresses the lack of an aging effect in steel, stainless steel, and copper alloy piping, piping components, and piping elements exposed to dried air. Since there is
 
no aging effect applicable to these components when exposed to dried air, the GALL Report
 
does not recommend any AMP. The staff finds that the classification of this line item in the LRA
 
as not applicable is consistent with the GALL Report and, therefore is acceptable.
LRA Table 3.3.1, Line Item 99 addresses the lack of an aging effect in stainless steel and copper alloy <15 percent zinc piping, piping components, and piping elements exposed to air
 
with borated water leakage . Since there is no aging effect applicable to stainless steel
 
components when exposed to air with borated water leakage, the GALL Report does not
 
recommend any AMP. In addition, the LRA states that there are no copper alloy components
 
exposed to air with borated water leakage in the auxiliary systems. The staff finds that the
 
classification of this line item in the LRA as not applicable is consistent with the GALL Report
 
and, therefore is acceptable.
3.3.2.1.2  Loss of Material Due to General Corrosion
 
LRA Table 3.3.1, Line Item 42 addresses loss of material due to general corrosion in steel closure bolting exposed to air with steam or water leakage. The GALL Report recommends the
 
Bolting Integrity AMP to manage loss of material in these components. The LRA states that this
 
line item was not used since loss of material due to general corrosion in steel closure bolting
 
exposed to air with steam or water leakage is addressed by other line items, including 3.3.1-43, 3.3.1-44 and 3.3.1-55. During the audit the staff questioned if bolting in the auxiliary systems at
 
IP is exposed to air with steam or water leakage (Audit Item 219). In its response, dated
 
December 18, 2007, the applicant stated that IP2 and IP3 do not have bolting exposed to air
 
with leakage as a normal environment for bolted connections for auxiliary systems. The
 
applicant further stated that if a leak occurs, it is corrected under the site corrective action or
 
corrective maintenance programs. Therefore, as identified in Table 3.3-1, Item 3.3.1-42 was not
 
used. The Bolting Integrity Program is applied to steel closure bolting as indicated by other
 
items including 3.3.1-43, 3.3.1-44 and 3.3.1-55. Since IP does not have bolting exposed to air
 
with leakage as a normal environment for bolted connections for auxiliary systems, and the
 
applicant appropriately uses the Bolting Integrity AMP for steel closure bolting consistent with
 
the GALL Report, the staff finds this acceptable.
3.3.2.1.3  Loss of Material Due to General, Pitting, and Crevice Corrosion
 
LRA Table 3.3.1, Line Item 53 addresses loss of material due to general and pitting corrosion for steel compressed air system piping, piping components, and piping elements exposed to
 
condensation (internal). Rather than using the Compressed Air Monitoring Program, the
 
applicant uses the Periodic Surveillance and Maintenance Program to manage this aging effect.
 
The staff finds that this is acceptable because the program will use periodic visual inspections
 
or other NDE techniques to manage this aging.
3-347 By letter dated June 11, 2008, the applicant amended its LRA to state that carbon valve bodies exposed internally to condensation have an aging effect of loss of material in LRA Table
 
3.3.2-19-48-IP3. For these AMR line items the applicant proposed the Periodic Surveillance and
 
Maintenance Program. These AMR line items referenced LRA Table 3.3.1, Line Item 53.
By letter dated June 12, 2009, the applicant amended its LRA to state that carbon steel filter housing, piping, tubing, trap, strainer housing, tank and valve bodies exposed internally to
 
condensation have an aging effect of loss of material in the IP1 Station Air System. For these
 
AMR line items the applicant proposed the Periodic Surveillance and Maintenance Program.
 
These AMR line items referenced LRA Table 3.3.1, line item 53.
LRA Table 3.3.1, Line Item 54 addresses loss of material due to pitting and crevice corrosion for stainless steel compressed air system piping, piping components, and piping elements exposed
 
to condensation (internal). Rather than using the Compressed Air Monitoring Program, the
 
applicant uses the One-Time Inspection Program to manage this aging effect. The staff finds
 
this acceptable because visual or other NDE techniques will be used to inspect a representative
 
sample of the internal surfaces to confirm the absence of significant loss of material.
By letter dated June 12, 2009, the applicant amended its LRA to state that stainless steel tubing, piping, strainer and valve bodies exposed internally or externally to condensation have
 
an aging effect of loss of material in the IP1 Station Air System. For these AMR line items the
 
applicant proposed the One-Time Inspection Program. These AMR line items referenced LRA
 
Table 3.3.1, Line Item 54. 3.3.2.1.4Loss of Preload Due to Thermal Effects, Gasket Creep and Self-loosening LRA Table 3.3.1, Line Item 45 addresses loss of preload due to thermal effects, gasket creep and self-loosening of steel closure bolting exposed to uncontrolled indoor air. The GALL Report
 
recommends the Bolting Integrity Aging Management Program to manage loss of preload in
 
these components. The LRA states that loss of preload due to stress relaxation (creep) is not an
 
applicable aging effect for auxiliary systems because it is only a concern for very high
 
temperature applications (>700&#xba; F per ASME Code, Section II, Part D, Table 4) and bolting in
 
auxiliary systems operates at <700&#xba; F. The LRA further states that other issues such as gasket
 
creep and loosening that may result in pressure boundary joint leakage are improper design or
 
maintenance issues and that improper bolting application (design) and maintenance issues are
 
current plant operational concerns and are not related to aging effects or mechanisms that
 
require management during the period of extended operation. In the LRA, the applicant further
 
states that actions have been taken to address NUREG-1339, Resolution to Generic Safety
 
Issue 29, Bolting Degradation or Failure in Nuclear Power Plants. These actions include
 
implementation of good bolting practices in accordance with EPRI NP-5067, Good Bolting
 
Practices.
During the audit, the staff questioned the applicant about loss of preload (Audit Item 201). By letter dated December 18, 2007, the applicant responded to this question
 
by taking the position that loss-of preload is event driven and not an aging effect. The
 
staff questioned the applicant about how a loss of preload is currently managed and
 
requested the applicant to describe (a) the operating experience with loss of bolt pre-
 
load and (b) how the absence or loss of bolt pre-load is confirmed (Audit Item 220). In its
 
response, dated December 18, 2007, the applicant stated that loss of preload is
 
managed by the Bolting Integrity Program which includes preventive measures to 3-348 preclude or minimize loss of preload and cracking. The applicant further stated that during the period of extended operation, the Bolting Integrity Program will be consistent with the program described in the Gall Report, Section XI.M18. As stated in this section
 
of the GALL Report under detection of aging effects, the absence of loss of bolt preload
 
is confirmed by visual examination during system leakage testing of all pressure-
 
retaining Class 1, 2 and 3 components, according to Tables IWB 2500-1, IWC 2500-1, and IWD 2500-1, respectively. In addition, the applicant states that degradation of the
 
closure bolting due to crack initiation, loss of prestress, or loss of material due to
 
corrosion of the closure bolting would result in leakage. The extent and schedule of
 
inspections, in accordance with Tables IWB 2500-1, IWC 2500-1, and IWD 2500-1, combined with periodic system walkdowns, assure detection of leakage before the
 
leakage becomes excessive. For other pressure retaining bolting, periodic system
 
walkdowns assure detection of leakage before the leakage becomes excessive. With
 
regard to operating experience, the applicant stated it has been consistent with that
 
experienced within the industry.
In a letter dated December 18, 2007, the applicant clarified Commitment 2 to specifically state that the Bolting Integrity Program manages loss of preload and loss of material for
 
all external loading. The applicant also stated that the clarification will be incorporated
 
into the LRA (response to Audit Questions 241 and 270). In attachment 1 to this letter, the applicant amended the LRA to incorporate this change.
The staff finds the applicants response acceptable, because the Bolting Integrity Program includes preventive measures that preclude or minimize loss of preload. This is consistent with
 
the GALL Report. On this basis, the staff finds the AMR results for this line item acceptable.3.3.2.1.5Hardening and Loss of Strength Due to Elastomer Degradation; Loss of Material Due to Erosion LRA Table 3.3.1, Line Item 75 addresses hardening and loss of strength due to elastomer degradation; loss of material due to erosion in elastomer seals and components exposed to raw
 
water. The GALL Report recommends that these aging effects be managed by the Open-Cycle
 
Cooling Water System. The LRA states that the components to which this line item applies are included in scope under criterion 10 CFR 54.4(a)(2) and are listed in series 3.3.2-19-XX tables
 
in systems other than service water. The Periodic Surveillance and Preventive Maintenance
 
Program uses periodic visual inspections of internal and external surfaces of components to
 
manage cracking and change of material properties in elastomeric components exposed to raw
 
water. The staff finds the Periodic Surveillance and Preventive Maintenance Program
 
appropriately manages the applicable aging effects for elastomer components within scope
 
under criterion 10 CFR 54.4(a)(2), and is, therefore, acceptable.
The staff evaluated the applicants claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicants consideration of recent operating experience
 
and proposals for managing 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 functions will be maintained consistent with the CLB during the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
3-349 3.3.2.1.6  Loss of Material Due to Pitting and Crevice Corrosion LRA Table 3.3.1, Line Item 62 addresses loss of material due to pitting and crevice corrosion for aluminum piping, piping components, and piping elements exposed to raw water. The GALL
 
Report recommends using the Fire Protection Program to manage this aging effect. The
 
applicant proposes using the One-Time Inspection Program and the Service Water Integrity
 
Program to manage the aging. The staff finds this to be acceptable because the One-Time
 
Inspection Program will use visual and other NDE techniques to determine if degradation has
 
occurred and the Service Water Integrity Program uses periodic inspections to ensure that
 
degradation is not occurring.
LRA Table 3.3.1, Line Item 71 addresses loss of material due to general, pitting, crevice, and (for drip pans and drain lines) microbiologically-influenced corrosion in steel piping, piping
 
components, and piping elements exposed to moist air or condensation (Internal). The GALL
 
Report states that these aging effects should be managed by inspection of internal surfaces in
 
miscellaneous piping and ducting components. The LRA states that the Periodic Surveillance
 
and Preventive Maintenance Program uses periodic visual inspections to manage loss of
 
material for internal surfaces of steel ducting and components exposed to condensation. The
 
LRA further states that the External Surfaces Monitoring Program manages loss of material for
 
external carbon steel components of the service water system exposed to condensation, by
 
visual inspection of external surfaces. For systems where internal carbon steel surfaces are
 
exposed to the same environment as external surfaces, the LRA states that external surface
 
conditions will be representative of internal surfaces. Thus, loss of material on internal carbon
 
steel surfaces of the service water system exposed to condensation is also managed by the
 
External Surfaces Monitoring Program. During the audit, the applicant was requested to identify
 
and describe the applications of the External Surfaces Monitoring Program to manage loss of
 
material for internal surfaces exposed to condensation and to justify its conclusion that the
 
environment is the same (Audit Item 224). In its response, dated December 18, 2007, the
 
applicant stated that the internal surfaces and external surfaces are exposed to the same
 
environment and are subject to the same aging effects. Therefore, the condition of the external
 
surfaces will be representative of the condition of the internal surfaces. The applicant further
 
stated that the identification of a significant loss of material on the external surfaces will result in
 
appropriate corrective actions to internal surfaces as well as external. In this manner, the
 
External Surfaces Monitoring Program will manage loss of material on internal carbon steel
 
surfaces exposed to indoor air. The staff finds this to be consistent with the GALL Report and, therefore, acceptable.
3.3.2.1.7  Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced Corrosion LRA Table 3.3.1, Line Item 72, addresses loss of material due to general, pitting, crevice, and (for drip pans and drain lines) microbiologically influenced corrosion of steel HVAC ducting and
 
components internal surfaces exposed to condensation. The GALL Report recommends that the
 
loss of material and MIC of the internal surfaces of steel HVAC ducting be managed by
 
inspection of internal surfaces. The LRA states that loss of material on internal carbon steel
 
surfaces of the service water system exposed to condensation is managed by the External
 
Surfaces Monitoring Program. In response to Audit Question 224, dated December 18, 2007, the applicant stated that the internal surfaces are exposed to the same environment and subject
 
to the same aging effects as the external surfaces. Based on its review of the applicants
 
response, the staff agrees that the external surfaces will be representative of the condition of 3-350 the internal surfaces.
3.3.2.1.8  Hardening and Loss of Strength Due To Elastomer Degradation; Loss Of Material Due To Erosion By letter dated June 12, 2009, the applicant amended its LRA to state that elastomer expansion joints in the Circulating Water System and the Wash Water System exposed to internally to raw
 
water have the aging effects of cracking and change in material properties.
LRA Table 3.3.1, Line Item 75 addresses hardening and loss of strength due to elastomer degradation; loss of material due to erosion in elastomer seals and components exposed to raw
 
water. The GALL Report recommends that these aging effects be managed by the Open-Cycle
 
Cooling Water System. The Periodic Surveillance and Preventive Maintenance Program uses
 
periodic visual inspections of internal and external surfaces of components to manage cracking
 
and change of material properties in elastomeric components exposed to raw water. The staff
 
finds the Periodic Surveillance and Preventive Maintenance Program appropriately manages
 
the applicable aging effects for elastomer components, and is therefore acceptable.
The staff evaluated the applicants claim of consistency with the GALL Report. 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. 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 functions will be maintained consistent with the CLB during the period of
 
extended  operation, as required by 10 CFR 54.21(a)(3).
3.3.2.1.9  Loss of Material due to General, Pitting, Crevice, and Microbiologically Influenced Corrosion, Fouling, and Lining/Coating Degradation LRA Table 3.3.1, Line Item 76 addresses loss of material due to general, pitting, crevice, and microbiologically influenced corrosion, fouling, and lining/coating degradation in steel piping, piping components, and piping elements (without lining/coating or with degraded lining/coating)
 
exposed to raw water. The GALL Report recommends that these aging effects be managed by
 
the Open-Cycle Cooling Water System.
By letter dated June 11, 2008, the applicant amended LRA Table 3.3.2-19-31-IP2 to state that carbon steel pump casings exposed internally to raw water with the aging effect of loss of
 
material will be managed by Periodic Surveillance and Preventive Maintenance Program.
By letter dated June 12, 2009, the applicant amended its LRA to state that carbon steel nozzles, valve bodies and piping in the Wash Water System exposed to internally to raw water have the
 
aging effect of loss of material. Furthermore, for the river water service system the applicant
 
amended its LRA to state that carbon steel piping and valve bodies and gray cast iron pump
 
casings exposed internally to raw water have the aging effect of loss of material.
The applicant proposes to manage the effects of aging using the Periodic Surveillance and Preventive Maintenance Program. The staffs review of the Periodic Surveillance and Preventive
 
Maintenance Program is documented in SER Section 3.0.3.3.7. The Periodic Surveillance and
 
Preventive Maintenance Program enhancements add new activities to the plants preventive maintenance and surveillance programs, which generally implement preventive maintenance
 
and surveillance testing activities through repetitive tasks or routine monitoring of plant 3-351 operations. On the basis of its review, the staff finds that because these components will be inspected periodically for loss of material, the aging effect for these component/environment
 
combinations will be effectively managed by this aging management program.
The staff evaluated the applicants claim of consistency with the GALL Report. 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. 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 functions will be maintained consistent with the CLB during the period of
 
extended  operation, as required by 10 CFR 54.21(a)(3).
3.3.2.1.10  Loss of Material Due to Pitting and Crevice Corrosion, and Fouling
 
LRA Table 3.3.1, Line Item 79, addresses loss of material due to pitting and crevice corrosion, and fouling of stainless steel piping, piping components, and piping elements exposed to raw water. The GALL Report recommends that this aging effect for these components be managed
 
by the Open-Cycle Cooling Water System AMP. The LRA states that loss of material for some
 
stainless steel piping, piping components, and piping elements will be managed by the One-
 
Time Inspection Program. The staffs evaluation of the One-Time Inspection Program is
 
documented in SER Section 3.0.3.1.9. The One-Time Inspection Program uses visual or other
 
NDE techniques to confirm the absence of significant loss of material. The staff finds that use of
 
the One-Time Inspection Program to detect loss of material in stainless steel piping, piping
 
components and piping elements exposed to raw water is acceptable.
By letter dated June 12, 2009, the applicant amended its LRA to state that stainless steel flex hose, pump casing, tubing and valve bodies in the wash water system exposed to internally or
 
externally to raw water have the aging effects of loss of material. Furthermore, for the river
 
water service system the applicant amended its LRA to state that stainless steel tubing and
 
valve bodies exposed internally to raw water have the aging effect of loss of material.
LRA Table 3.3.1, Line Item 79 addresses loss of material due to pitting and crevice corrosion, and fouling in Stainless steel piping, piping components, and piping elements exposed to raw
 
water. The GALL Report recommends that these aging effects be managed by the Open-Cycle
 
Cooling Water System.
The applicant proposes to manage the effects of aging using the Periodic Surveillance and Preventive Maintenance Program. The staffs review of the Periodic Surveillance and Preventive
 
Maintenance Program is documented in SER Section 3.0.3.3.7. The Periodic Surveillance and
 
Preventive Maintenance Program enhancements add new activities to the plants preventive maintenance and surveillance programs, which generally implement preventive maintenance
 
and surveillance testing activities through repetitive tasks or routine monitoring of plant
 
operations. On the basis of its review, the staff finds that because these components will be
 
inspected periodically for loss of material, the aging effect for these component/environment
 
combinations will be effectively managed by this aging management program.
The staff evaluated the applicants claim of consistency with the GALL Report. 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. Therefore, the staff concludes that the applicant
 
has demonstrated that the effects of aging for these components will be adequately managed 3-352 so that their intended functions will be maintained consistent with the CLB during the period of extended  operation, as required by 10 CFR 54.21(a)(3).
3.3.2.1.11  Loss of Material due to Pitting and Crevice Corrosion
 
By letter dated June 11, 2008, the applicant amended its LRA to state that for stainless steel heat exchanger housings exposed internally to treated borated water with an aging effect of loss
 
of material will be managed by the Water Chemistry Control - Primary and Secondary Program
 
in LRA Table 3.3.2-19-5-IP2. The staff noted that the applicant referenced LRA Table 3.3.1, Line Item 3.3.1-91.
LRA Table 3.3.1, Line Item 91 addresses loss of material due to pitting and crevice corrosion for stainless steel and steel with stainless steel cladding piping, piping components and piping
 
elements exposed to treated borated water. The staff noted that the GALL Report recommends a program that corresponds to GALL AMP XI.M2, Water Chemistry, for aging management.
 
The staffs evaluation of the Water Chemistry Control - Primary and Secondary Program is
 
documented in SER Section 3.0.3.2.17. The staff determined that the applicants Water Chemistry Control - Primary and Secondary Program is consistent with GALL AMP XI.M2. The
 
staff finds the applicants use of the Water Chemistry Control - Primary and Secondary Program
 
to be consistent with the recommendations of the GALL Report.
Based on its review of the program identified above, the staff determines that the applicants proposed program is acceptable for managing the aging effect in the applicable components.
 
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 aging management, as recommended by the GALL Report, for the auxiliary system components and provides information concerning how
 
it will manage the following aging effects:  cumulative fatigue damage  reduction of heat transfer due to fouling  cracking due to SCC  cracking due to SCC and cyclic loading  hardening and loss of strength due to elastomer degradation  reduction of neutron-absorbing capacity and loss of material due to general corrosion  loss of material due to general, pitting, and crevice corrosion  loss of material due to general, pitting, crevice, and microbiologically-influenced
 
corrosion loss of material due to general, pitting, crevice, microbiologically-influenced corrosion
 
and fouling 3-353 loss of material due to pitting and crevice corrosion  loss of material due to pitting, crevice, and galvanic corrosion  loss of material due to pitting, crevice, and microbiologically-influenced corrosion  loss of material due to wear  loss of material due to cladding breach  QA for aging management of nonsafety-related components For component groups evaluated in the GALL Report, for which the applicant claimed consistency with the report and for which the report recommends further evaluation, the staff
 
audited and reviewed the applicants evaluation to determine whether it adequately addressed
 
the issues further evaluated. In addition, the staff reviewed the applicants further evaluations
 
against the criteria contained in SRP-LR Section 3.3.2.2. The staffs review of the applicants
 
further evaluation follows.
3.3.2.2.1  Cumulative Fatigue Damage
 
Fatigue is an age-related degradation mechanism caused by cyclic stressing of a component by either mechanical or thermal stresses. SRP-LR Section 3.3.2.2.1 states that fatigue is a TLAA
 
as defined in 10 CFR 54.3 and that TLAAs are required to be evaluated in accordance with
 
10 CFR 54.21(c). This TLAA is addressed separately in Section 4.3, Metal Fatigue Analysis or
 
Section 4.7, Other Plant-Specific Time-Limited Aging Analyses of the SRP-LR.
LRA Section 3.3.2.2.1 states that TLAAs are evaluated in accordance with 10 CFR 54.21(c) and that the evaluation of this TLAA is addressed in Section 4.3.2. This is consistent with SRP-LR
 
Section 3.3.2.2.1 and is, therefore, acceptable.
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 in stainless steel heat exchanger tubes exposed to treated water, stating that this aging effect is not applicable
 
because at IP, there are no stainless steel heat exchanger tubes exposed to treated water in
 
the auxiliary systems with an intended function of heat transfer.
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 staff confirmed that there are no stainless steel heat exchanger tubes exposed to treated water in the auxiliary systems with an intended function of heat transfer.
Based on the above, the staff concludes that SRP-LR Section 3.3.2.2.2 criteria do not apply.
 
3.3.2.2.3  Cracking Due to Stress Corrosion Cracking
 
The staff reviewed LRA Section 3.3.2.2.3 against the criteria in SRP-LR Section 3.3.2.2.3.
3-354  (1) LRA Section 3.3.2.2.3 addresses cracking due to SCC in the stainless steel components of a BWR standby liquid control (SLC) system, stating that this aging effect is not
 
applicable to IP, which are PWRs.
SRP-LR Section 3.3.2.2.3 states that cracking due to SCC could occur in the stainless steel piping, piping components, and piping elements of the BWR standby liquid control
 
system that are exposed to sodium pentaborate solution greater than 60&deg;C (140&deg;F).
IP2 and IP3 are PWRs and do not have SLC systems. Based on the above, the staff concludes that this item is not applicable to IP.    (2) LRA Section 3.3.2.2.3 addresses cracking due to SCC in stainless steel and stainless steel clad heat exchanger components exposed to treated water greater than 140&deg;F, stating that this aging effect is not applicable because for IP, the only stainless steel heat
 
exchanger components in the auxiliary systems exposed to treated water greater than
 
140&deg;F are in the steam generator secondary side sample coolers.
SRP-LR Section 3.3.2.2.3 states that cracking due to SCC may occur in stainless steel and stainless clad steel heat exchanger components exposed to treated water greater
 
than 60&deg;C (140&deg;F).
During the audit the staff requested the applicant to describe how cracking due to SCC in the secondary side sample coolers was addressed in the LRA (Audit Item 214). In its
 
response, dated December 18, 2007, the applicant states that the steam generator
 
secondary side sample coolers are included in scope for 54.4(a)(2) for potential spatial
 
interaction. Although the tube side of the heat exchanger can experience temperatures
 
above 140&deg;F, it has no intended function because the potential for spatial interaction is
 
prevented by the shell. In addition, the shell side of the coolers does not experience
 
temperatures above 140&deg;F.
The staff agrees with the applicant that the tube side of the heat exchanger is not with the scope of license renewal because there is no spatial interaction as a result of the
 
presence of the shell, and the shell side of the coolers is not within scope of license
 
renewal because they do not reach a high enough temperature for SCC to occur.    (3) LRA Section 3.3.2.2.3 addresses cracking due to SCC in stainless steel diesel engine exhaust piping exposed to diesel exhaust, stating that this aging effect is not applicable
 
because at IP, the stainless steel exhaust components are not subject to significant
 
moisture accumulation that would allow cracking to occur.
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.During the audit, the staff confirmed that the stainless steel exhaust components are not subject to significant moisture accumulation that would allow cracking to occur. In
 
addition, the staff requested the applicant to define the intended function of the diesel
 
exhaust piping for license renewal and to state if the piping was subject to aging
 
management under any credited AMP (Audit Item 215). In its response, dated December
 
18, 2007, the applicant stated that stainless steel piping exposed to diesel exhaust has a 3-355 pressure boundary intended function, and that exhaust system components are inspected for loss of material under the Periodic Surveillance and Preventive
 
Maintenance Program at least once every six years during the period of extended
 
operation. The GALL Report identifies aging effects for this material/environment
 
combination of stress corrosion cracking and loss of material. As discussed, insignificant
 
moisture accumulation is present to allow cracking to occur. The aging effect of concern
 
is a loss of material which will be inspected for periodically during the extended period of
 
operation. The staff finds that this approach is consistent with the GALL Report and is
 
therefore acceptable.
Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.3 criteria. For those line items that apply to LRA Section 3.3.2.2.3, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3).
3.3.2.2.4  Cracking Due to Stress Corrosion Cracking and Cyclic Loading
 
The staff reviewed LRA Section 3.3.2.2.4 against the 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 140&deg;F in the chemical and volume control system, stating that the
 
Water Chemistry Control - Primary and Secondary Program manages this aging effect.
 
The program is augmented by the One-Time Inspection Program to verify the absence
 
of cracking by visual and volumetric NDE techniques. Absence of tube and tubesheet
 
cracking is also verified by monitoring of reactor coolant system leakage and radiation
 
levels in the component cooling water system. Temperature monitoring, a much less
 
sensitive technique, is not used.
SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occur in stainless steel PWR nonregenerative heat exchanger components exposed to treated
 
borated water greater than 60&deg;C (140&deg;F) in the chemical and volume control system.
 
The existing AMP monitors and controls primary water chemistry in PWRs to manage
 
the aging effects of cracking due to SCC. However, control of water chemistry does not
 
preclude cracking due to SCC and cyclic loading; therefore, the effectiveness of water
 
chemistry control programs should be verified to ensure that cracking does not occur.
 
The GALL Report recommends that a plant-specific AMP be evaluated to verify the
 
absence of cracking due to SCC and cyclic loading to ensure that these aging effects
 
are adequately managed. An acceptable verification program is to include temperature
 
and radioactivity monitoring of the shell side water and eddy current testing of tubes.
During the audit, the staff asked the applicant to identify the specific component inspections currently included in the existing program that are credited for license
 
renewal (Audit Item 52). In its response, dated December 18, 2007, the applicant stated
 
that the existing site eddy current heat exchanger inspection program includes safety-
 
related and nonsafety-related heat exchangers. The GALL Report recommends that this
 
testing be augmented by temperature and radioactivity monitoring of the shell side
 
water. The staff verified that the applicants program confirms the absence of cracking by 3-356 monitoring leakage of the RCS and the radiation levels in the component cooling water system. The applicants method of verifying the absence of cracking due to SCC and
 
cyclic loading is equivalent to the approach recommended in GALL Report, and is, therefore, acceptable.    (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 140&deg;F, stating that the Water Chemistry Control - Primary and Secondary
 
Program manages this aging effect. The regenerative heat exchanger is of all-welded
 
construction and inspections are not possible. The Water Chemistry Control - Primary
 
and Secondary Program is augmented by the One-Time Inspection Program to verify the
 
absence of cracking by visual and volumetric NDE techniques with components in
 
similar environments.
SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occur in stainless steel PWR regenerative heat exchanger components exposed to treated
 
borated water greater than 60&deg;C (140&deg;F). The existing AMP monitors and controls
 
primary water chemistry in PWRs to manage the aging effects of cracking due to SCC.
 
However, control of water chemistry does not preclude cracking due to SCC and cyclic
 
loading; therefore, the effectiveness of water chemistry control programs should be
 
verified to ensure that cracking does not occur. The GALL Report recommends that a
 
plant-specific AMP be evaluated to verify the absence of cracking due to SCC and cyclic
 
loading to ensure that these aging effects are adequately managed.
The staff confirmed that the Water Chemistry Control - Primary and Secondary Program manages cracking of stainless steel regenerative heat exchanger components exposed
 
to treated borated water and that the all-welded construction of the heat exchanger
 
negates the possibility of inspection. The absence of cracking will be determined by the
 
One-Time Inspection Program which includes the use of visual and volumetric NDE
 
techniques of components in similar environments. The staff finds that the use of the
 
One-Time inspection program is consistent with the GALL Report recommendation to
 
verify the absence of cracking due to SCC and cyclic loading, and is therefore
 
acceptable.  (3) LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading in the stainless steel pump casing of PWR high-pressure pumps in the chemical and volume control
 
system (CVCS), stating that the Water Chemistry Control - Primary and Secondary
 
program manages loss of material for the pump casing. CVCS stainless steel charging
 
pump casings are exposed to treated borated water below the 140&deg;F threshold for SCC;
 
consequently, they do not specifically credit the Water Chemistry Control - Primary and
 
Secondary Program to manage cracking due to SCC. The Periodic Surveillance and
 
Preventive Maintenance Program manages charging pump cracking due to cyclic
 
loading by visual inspections of external casing surfaces for signs of cracking or leakage
 
during the regularly scheduled quarterly pump surveillances.
SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occur in the stainless steel pump casing for the PWR high-pressure pumps in the chemical and
 
volume control system. The existing AMP monitors and controls primary water chemistry
 
in PWRs to manage the aging effects of cracking due to SCC. However, control of water
 
chemistry does not preclude cracking due to SCC and cyclic loading; therefore, the 3-357 effectiveness of water chemistry control programs should be verified to ensure that cracking does not occur. The GALL Report recommends that a plant-specific AMP be
 
evaluated to verify the absence of cracking due to SCC and cyclic loading to ensure that
 
these aging effects are adequately managed.
The staff confirmed that loss of material for the CVCS pump casing is adequately managed by the Water Chemistry Control - Primary and Secondary program. The staff
 
also verified that stainless steel CVCS charging pump casings are exposed to treated
 
borated water that is below the 140&deg;F threshold for SCC and that the absence of
 
cracking due to SCC and cyclic loading is verified by the Periodic Surveillance and
 
Preventive Maintenance Program, which includes visual inspections of external casing
 
surfaces for signs of cracking or leakage during the regularly scheduled quarterly pump
 
surveillances. The staff finds that the applicants approach is consistent with the GALL
 
Report, and is, therefore, acceptable.
Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.4 criteria. For those line items that apply to LRA Section 3.3.2.2.4, 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
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3).
3.3.2.2.5  Hardening and Loss of Strength Due to Elastomer Degradation
 
The staff reviewed LRA Section 3.3.2.2.5 against the criteria in SRP-LR Section 3.3.2.2.5.
  (1) LRA Section 3.3.2.2.5 addresses cracking and change in material properties due to elastomer degradation in elastomer flexible connections of auxiliary and other systems
 
exposed to air - indoor, stating that the Periodic Surveillance and Preventive
 
Maintenance Program manages these aging effects by periodic visual inspections and
 
physical manipulation of the flexible connections for whether the components have
 
experienced aging that would affect performance of intended functions.
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.
By letter dated June 11, 2008, the applicant amended LRA Table 3.3.2-19-9-IP3 to state that elastomer expansion joints exposed externally to air-indoor with an aging effect of
 
cracking and change in material properties will be managed by the Periodic Surveillance
 
and Maintenance Program. The applicant referenced LRA Table 3.3.1, Line
 
Item 3.3.1-11.
The staff confirmed that cracking and change in material properties due to elastomer degradation in elastomer flexible connections of auxiliary and other systems exposed to
 
air - indoor, are managed by the Periodic Surveillance and Preventive Maintenance
 
Program. The staff also verified that the AMP includes periodic visual inspections to
 
detect the effects of aging before they could affect a components ability to accomplish 3-358 its intended function.    (2) LRA Section 3.3.2.2.5 addresses cracking and change in material properties due to elastomer degradation in auxiliary system components, stating that the Periodic
 
Surveillance and Preventive Maintenance Program manages them by periodic visual
 
inspections of a representative sample of interior and exterior elastomer surfaces for
 
whether the components have experienced aging that would affect performance of
 
intended functions.
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.
By letter dated June 11, 2008, the applicant amended LRA Table 3.3.2-19-9-IP3 to state that elastomer expansion joints exposed internally to treated water with an aging effect
 
of cracking and change in material properties will be managed by the Periodic
 
Surveillance and Maintenance Program. The applicant referenced LRA Table 3.3.1, Line
 
Item 3.3.1-12.
The staff confirmed that change in material properties of elastomer exposed to treated water is managed by the Periodic Surveillance and Preventive Maintenance Program.
 
The staff also verified that the AMP includes periodic visual inspections of a
 
representative sample of interior and exterior elastomer surfaces to detect the effects of
 
aging before they could affect a components ability to accomplish its intended function.
Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.5 criteria. For those line items that apply to LRA Section 3.3.2.2.5, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3).
3.3.2.2.6  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 in Boral spent fuel storage racks exposed to a treated borated water
 
environment, stating that the Boral Surveillance Program uses coupon samples to manage
 
these aging effects by periodically monitoring physical and chemical properties of the absorber
 
material. The Boral Surveillance Program is supplemented by the Water Chemistry Control -
 
Primary and Secondary Program.
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 3-359 recommends further evaluation of a plant-specific AMP to ensure that these aging effects are adequately managed.
The staff confirmed that reduction of neutron-absorbing capacity and loss of material due to general corrosion in Boral spent fuel storage racks exposed to a treated borated water
 
environment is adequately managed by the Boral Surveillance Program and Water Chemistry
 
Control - Primary and Secondary Program. The staff also verified that the program includes the
 
use of periodic coupon samples to monitor the physical and chemical properties of the absorber
 
material.Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.6 criteria. For those line items that apply to LRA Section 3.3.2.2.6, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3).
3.3.2.2.7  Loss of Material Due to General, Pitting, and Crevice Corrosion
 
The staff reviewed LRA Section 3.3.2.2.7 against the criteria in SRP-LR Section 3.3.2.2.7.
  (1) LRA Section 3.3.2.2.7(1) addresses steel piping and components in auxiliary systems exposed to lubricating oil and managed by the Oil Analysis Program, which periodically
 
samples and analyzes lubricating oil to maintain contaminants within acceptable limits
 
and preserve an environment not conducive to corrosion. The One-Time Inspection Program will use visual inspection or nondestructive examination of representative
 
samples to confirm the effectiveness of the Oil Analysis Program in managing aging
 
effects for components that credit it. Steel piping components and tanks of the reactor
 
coolant pump oil collection system are not exposed continuously to a lubricating oil
 
environment maintained by the Oil Analysis Program and do not credit it for managing
 
loss of material. Instead these components are managed by the One-Time Inspection
 
Program, which will use visual or volumetric NDE techniques to inspect a representative
 
sample of the internal surfaces for significant corrosion.
SRP-LR Section 3.3.2.2.7 states that loss of material due to general, pitting, and crevice corrosion may occur in steel piping, piping components, and piping elements, including
 
the tubing, valves, and tanks in the reactor coolant pump oil collection system, exposed
 
to lubricating oil (as part of the fire protection system). The existing AMP periodically
 
samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube
 
oil contaminants may not always be fully effective in precluding corrosion; therefore, the
 
effectiveness of lubricating oil control should be verified to ensure that corrosion does
 
not occur. The GALL Report recommends further evaluation of programs to manage
 
corrosion to verify the effectiveness of the lubricating oil program. A one-time inspection
 
of 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 3-360 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 confirmed that the Oil Analysis Program and One-Time Inspection Program will manage the loss of material due to general, pitting, and crevice corrosion in steel piping and related components of auxiliary systems exposed to lubricating oil. The staff also
 
verified that the Oil Analysis Program includes periodic sampling and analysis to ensure
 
contaminants are maintained within acceptable limits, and that the effectiveness of this
 
program will be confirmed by the One-Time Inspection Program which includes visual
 
inspections or non-destructive examinations to ensure that corrosion is not occurring
 
and that the components intended function will be maintained during the period of
 
extended operation.
The staff also verified that the effects of aging on steel piping components and tanks of the reactor coolant pump oil collection system will be adequately managed. The tanks
 
and piping components are not continuously exposed to a lubricating oil environment.
 
Loss of material in these components is managed by the One-Time Inspection Program
 
which includes visual inspections and NDE techniques to inspect a representative
 
sample of the internal surfaces to assure there is no significant corrosion. During an
 
audit, the staff asked the applicant to identify what actions will be taken if degradation is
 
discovered by the One-Time Inspection Program (Audit Item 218). In its response, dated
 
December 18, 2007, the applicant stated that, in addition to verifying the effectiveness of
 
an AMP, the One-Time Inspection Program is utilized to confirm the absence of an aging
 
effect where either (a) an aging effect is not expected to occur but there is insufficient
 
data to completely rule it out, or (b) an aging effect is expected to progress very slowly.
 
For the RCP oil collection system, the applicant stated that the One-Time Inspection
 
Program will confirm that either the aging effect is not occurring, or the aging effect is
 
occurring very slowly as not to affect component intended functions. In either event, the
 
One-Time Inspection Program serves as the means of detecting aging effects and
 
triggering additional action in response to any adverse findings. The staff confirmed that
 
any unacceptable inspection findings identified during the One-Time Inspection Program
 
will be evaluated in accordance with the site corrective action process to determine the
 
need for subsequent (including periodic) inspections and for monitoring and trending the
 
results.Since a one time inspection of RCP oil collection system components after over 30 years of operation will provide valid information regarding whether ongoing periodic
 
inspections through the period of extended operation is warranted, the staff finds that
 
this is an acceptable method of ensuring that the intended functions of RCP oil collection
 
system components will be maintained during the period of extended operation.    (2) LRA Section 3.3.2.2.7 addresses loss of material due to general, pitting, and crevice corrosion in steel components in the BWR reactor water cleanup and shutdown cooling
 
systems exposed to treated water, stating that this aging effect is not applicable to IP, which are PWRs.
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 3-361 reactor water cleanup and shutdown cooling systems exposed to treated water.
IP2 and IP3 are PWRs and do not have reactor water cleanup and shutdown cooling systems. This item is not applicable to IP.    (3) LRA Section 3.3.2.2.7(3) addresses loss of material due to general (steel only) pitting and crevice corrosion for carbon steel and stainless steel diesel exhaust piping and
 
components exposed to diesel exhaust in the EDG, Appendix R diesel generator, and
 
security generator systems, stating that the Periodic Surveillance and Preventive
 
Maintenance Program manages this aging effect for these components by periodic
 
visual inspections. Additionally, the One-Time Inspection Program will inspect a
 
representative sample of the internal surfaces of EDG system stainless steel
 
components by visual or volumetric NDE techniques. The Fire Protection Program by
 
visual inspections manages loss of material from fire protection system carbon steel
 
diesel exhaust piping and components. These inspections in the Periodic Surveillance
 
and Preventive Maintenance, One-Time Inspection, and Fire Protection programs will
 
manage the aging effect of loss of material so component intended functions will not be
 
affected.SRP-LR Section 3.3.2.2.7 states that loss of material due to general (steel only), pitting, and crevice corrosion may occur in steel and stainless steel diesel exhaust piping, piping
 
components, and piping elements exposed to diesel exhaust. The GALL Report
 
recommends further evaluation of a plant-specific AMP to ensure that the aging effect is
 
adequately managed.
The staff confirmed that the Periodic Surveillance and Preventive Maintenance, One-Time Inspection, and Fire Protection Programs will adequately manage the loss of
 
material due to general (steel only) pitting and crevice corrosion for carbon steel and
 
stainless steel diesel exhaust piping and components exposed to diesel exhaust in the
 
EDG, Appendix R Diesel Generator, and security generator systems. Specifically, loss of
 
material is managed by periodic visual inspections performed under the Periodic
 
Surveillance and Preventive Maintenance Program. For stainless steel components of
 
the emergency diesel generator systems, the effectiveness of the Periodic Surveillance
 
and Preventive Maintenance Program is verified by the One-time Inspection Program to
 
ensure that loss of material is not occurring, and that the components intended function
 
will be maintained during the period of extended operation. Loss of material in carbon
 
steel diesel exhaust piping and components of the Appendix R Diesel Generator is
 
managed by the Fire Protection Program which includes visual inspections of the diesel
 
exhaust piping and components. The staff verified that the One-Time Inspection and Fire
 
Protection Programs will manage the loss of material such that the intended function of
 
the Appendix R Diesel Generator exhaust piping components will not be affected.
Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.7 criteria. For those line items that apply to LRA Section 3.3.2.2.7, the
 
staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3).
3-362 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, and crevice corrosion, and MIC for carbon steel (with or without coating or wrapping) piping and components buried in
 
soil in the auxiliary systems, stating that the Buried Piping and Tanks Inspection Program
 
manages this aging effect by (a) preventive measures to mitigate corrosion and (b) inspections
 
to manage the effects of corrosion on the pressure-retaining capability of buried carbon steel
 
components. Buried components will be inspected when excavated during maintenance. There
 
will be inspections within ten years before the period of extended operation and within the first
 
ten years of the period unless opportunistic inspections occur within these ten-year periods.
 
This program will manage the aging effect of loss of material so component intended functions
 
will not be affected.
SRP-LR Section 3.3.2.2.8 states that loss of material due to general, pitting, and crevice corrosion, and MIC may occur in steel (with or without coating or wrapping) piping, piping
 
components, and piping elements buried in soil. Buried piping and tanks inspection programs
 
rely on industry practice, frequency of pipe excavation, and operating experience to manage the
 
effects of loss of material from general, pitting, and crevice corrosion and MIC. The
 
effectiveness of the buried piping and tanks inspection program should be verified to evaluate
 
an applicants inspection frequency and operating experience with buried components, ensuring
 
that loss of material does not occur.
The staff confirmed that the Buried Piping and Tanks Inspection Program will adequately manage the loss of material due to general, pitting, and crevice corrosion, and MIC which may
 
occur in steel (with or without coating or wrapping) piping, piping components, and piping
 
elements buried in soil. The staff also verified that the effectiveness of this AMP will be
 
confirmed by inspection of buried components when excavated during maintenance. In addition, an inspection will be performed within ten years of entering the period of extended operation
 
and within ten years after entering the period of extended operation, unless an opportunistic
 
inspection occurred within these ten-year periods.
During the audit the staff requested the applicant to describe the operating experience it had in the area of handling buried steel piping, piping components, piping elements, and tanks (with or
 
without coating or wrapping) exposed to soil and how this plant specific and industry operating
 
experience is planned to be evaluated and utilized in the developing this program (Audit
 
Item 242). In its response, dated December 18, 2007, the applicant stated that since 2000, two
 
condition reports were initiated as a result of underground leaks, and that the piping in both
 
cases was nonsafety-related and not in the scope of license renewal. The applicant also stated
 
that no other buried piping repair or replacement was identified during its review of operating
 
experience and that the Buried Piping and Tanks Inspection Program will be implemented consistent with the corresponding program described in the Gall Report, Section XI.M34, Buried
 
Piping and Tanks Inspection.
Based on the program identified above, the staff concludes that the applicants program meets 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 3-363 functions will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.2.9  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 criteria in SRP-LR Section 3.3.2.2.9.
  (1) LRA Section 3.3.2.2.9 (1) addresses loss of material due to general, pitting, and crevice corrosion, and MIC for carbon steel piping and components exposed to fuel oil, stating
 
that the Diesel Fuel Monitoring Program manages these components by sampling and
 
monitoring fuel oil quality for whether it remains within the limits specified by the ASTM
 
standards. Maintaining parameters within limits prevents significant loss of material. The
 
One-Time Inspection Program will use visual inspection or NDE of representative
 
samples to confirm the effectiveness of the Diesel Fuel Monitoring Program in managing
 
aging effects for components that credit it.
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
 
maintained during the period of extended operation.
The staff confirmed that loss of material due to general, pitting, crevice, MIC, and fouling of steel piping, piping components, piping elements, and tanks exposed to fuel oil was
 
managed by the Diesel Fuel Monitoring Program, and that the AMP monitors and
 
controls contamination of fuel oil within limits specified in ASTM standards. In addition, the staff confirmed that the effectiveness of the Diesel Fuel Monitoring Program will be
 
verified by the One-Time Inspection Program, which includes measures to confirm that
 
unacceptable degradation of a component is not occurring and its intended function will
 
be maintained during the period of extended operation. This approach is consistent with
 
the GALL Report and is, therefore, acceptable.    (2) LRA Section 3.3.2.2.9 addresses loss of material due to general, pitting, and crevice corrosion, and MIC for carbon steel heat exchanger components exposed to lubricating
 
oil, stating that the Oil Analysis Program manages this aging effect by periodic sampling
 
and analysis of lubricating oil to maintain contaminants within acceptable limits and
 
preserve an environment not conducive to corrosion. The One-Time Inspection Program
 
will use visual inspections or NDEs of representative samples to confirm the effectiveness of the Oil Analysis Program in managing aging effects for components that
 
credit it.
3-364 SRP-LR Section 3.3.2.2.9 states that loss of material due to general, pitting, and crevice corrosion, MIC, and fouling may occur in steel heat exchanger components exposed to
 
lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to
 
maintain contaminants within acceptable limits, thereby preserving an environment not
 
conducive to corrosion. However, control of lube oil contaminants may not always be
 
fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil
 
control should be verified to ensure that corrosion does not occur. The GALL Report
 
recommends further evaluation of programs to manage corrosion to verify the
 
effectiveness of lubricating oil programs. A one-time inspection of 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 confirmed that loss of material due to general, pitting, and crevice corrosion, MIC, and fouling in steel heat exchanger components exposed to lubricating oil is adequately managed by the existing Oil Analysis Program which includes periodic
 
sampling and analysis to maintain contaminants within acceptable limits. In addition, the
 
staff confirmed that the effectiveness of the Oil Analysis Program will be verified by the
 
One-Time Inspection Program, which includes measures to confirm that corrosion is not
 
occurring and that component intended functions will be maintained during the period of
 
extended operation. This approach is consistent with the GALL Report and is, therefore, acceptable.
Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.9 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
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3).
3.3.2.2.10  Loss of Material Due to Pitting and Crevice Corrosion
 
The staff reviewed LRA Section 3.3.2.2.10 against the criteria in SRP-LR Section 3.3.2.2.10.
  (1) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in steel piping with elastomer lining exposed to treated borated water, stating that this
 
aging effect is not applicable to IP, which are PWRs.
SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice corrosion may occur in BWR and PWR steel piping with elastomer lining or stainless
 
steel cladding that are exposed to treated water and treated borated water if the cladding
 
or lining is degraded.
The staff confirmed that there are no elastomer-lined steel components within the scope of license renewal for auxiliary systems. This item does not apply to IP.  (2) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in stainless steel and aluminum piping, piping components, and piping elements and in
 
heat exchanger components of stainless steel and of steel with stainless steel cladding
 
exposed to treated water, stating that in the auxiliary systems there are no aluminum 3-365 components exposed to treated water. The applicant compares aging management results for loss of material in stainless steel auxiliary system components exposed to
 
treated water to the GALL Report lines for the ESF and steam and power conversion (S&PC) systems considering PWR water chemistry programs because the
 
corresponding line for auxiliary systems considers only BWR chemistry. Consistent with
 
the GALL Report lines for the ESF and S&PC systems, the Water Chemistry Control -
 
Primary and Secondary Program manages loss of material due to pitting and crevice
 
corrosion for stainless steel components exposed to treated water. The One-Time
 
Inspection Program will confirm effectiveness of the program by an inspection of a
 
representative sample of components crediting it, including those in areas of stagnant
 
flow and other susceptible locations.
SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice corrosion may occur in stainless steel and aluminum piping, piping components, piping
 
elements, and for stainless steel and steel with stainless steel cladding heat exchanger
 
components exposed to treated water. The existing AMP monitors and controls reactor
 
water chemistry to manage the aging effects of loss of material from pitting and crevice
 
corrosion. However, high concentrations of impurities in crevices and with stagnant flow
 
conditions may cause pitting or crevice corrosion; therefore, the effectiveness of water
 
chemistry control programs should be verified to ensure that corrosion does not occur.
 
The GALL Report recommends further evaluation of programs to manage loss of
 
material from pitting and crevice corrosion to verify the effectiveness of water chemistry
 
control programs. A one-time inspection of 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 confirmed that there are no aluminum piping components exposed to treated water in the auxiliary systems and that the loss of material due to pitting and crevice
 
corrosion of stainless steel piping, piping components, piping elements, and stainless
 
steel and steel with stainless steel cladding heat exchanger components exposed to
 
treated water is adequately managed by the existing Water Chemistry Control Primary -
 
Secondary Program which monitors and controls reactor water chemistry. In addition, the staff confirmed that the effectiveness of the Water Chemistry Program will be verified
 
by the One-Time Inspection Program, which includes measures to confirm that corrosion
 
is not occurring and that component intended functions will be maintained during the
 
period of extended operation. This approach is consistent with the GALL Report and is, therefore, acceptable.    (3) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion for copper alloy components exposed to condensation (external) in the HVAC and other
 
systems, stating that the External Surfaces Monitoring and Periodic Surveillance and
 
Preventive Maintenance programs manage this aging effect by periodic visual
 
inspections and other NDE techniques so component intended functions will not be
 
affected.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.
3-366 By letter dated June 12, 2009, the applicant amended its LRA to state that copper alloy tubing exposed externally to condensation has the aging effect of loss of material in the
 
Service Water System. For these AMR line items the applicant proposed the External
 
Surfaces Monitoring Program.
The staff confirmed that loss of material due to pitting and crevice corrosion for copper alloy components exposed to condensation (external) in the HVAC and other systems is
 
adequately managed by the existing External Surfaces Monitoring and Periodic
 
Surveillance and Preventive Maintenance AMPs. The staff also verified that these
 
programs include periodic visual inspections and NDE techniques to confirm that the
 
intended function of components is not affected. This approach is consistent with the
 
GALL Report and is, therefore, acceptable.  (4) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion for copper alloy components exposed to lubricating oil in auxiliary systems, stating that
 
the Oil Analysis Program manages this aging effect by periodic sampling and analysis of
 
lubricating oil to maintain contaminants within acceptable limits and preserve an
 
environment not conducive to corrosion. The One-Time Inspection Program will use
 
visual inspections or NDEs of representative samples to confirm the effectiveness of the
 
Oil Analysis Program in managing aging effects for components that credit it.
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 confirmed that the existing Oil Analysis Program adequately manages loss of material in copper alloy piping components exposed to lubricating oil by periodic
 
sampling and analysis to maintain oil contaminants within acceptable limits. In addition, the staff confirmed that the effectiveness of the Oil Analysis Program will be verified by
 
the One-Time Inspection Program, which includes measures to confirm that corrosion is
 
not occurring and that component intended functions will be maintained during the
 
period of extended operation. This approach is consistent with the GALL Report and is, therefore, acceptable.    (5) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion for aluminum piping and components and stainless steel components exposed to
 
condensation, stating that this aging effect requires management for HVAC and other
 
systems. The Bolting Integrity, External Surfaces Monitoring, Periodic Surveillance and
 
Preventive Maintenance, and One-Time Inspection programs will manage loss of 3-367 material in aluminum or stainless steel components exposed internally or externally to condensation by periodic visual inspection with the Periodic Surveillance and Preventive
 
Maintenance Program using other NDE techniques as appropriate to manage loss of
 
component material.
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.
By letter dated June 12, 2009, the applicant amended its LRA to state that stainless steel bolting that is externally exposed to condensation has the aging effect of loss of
 
material in the Service Water System. For this AMR line item the applicant proposed the
 
Bolting Integrity Program. In the same letter the applicant amended its LRA to state that
 
stainless steel piping, tubing and valve bodies exposed externally to condensation have
 
an aging effect of loss of material in the Service Water System. For these AMR line
 
items the applicant proposed the External Surfaces Monitoring Program.
The staff confirmed that the Bolting Integrity, External Surfaces Monitoring, One-Time Inspection, and Periodic Surveillance and Preventive Maintenance AMPs adequately
 
manage the loss of material due to pitting and crevice corrosion for aluminum piping and
 
components and stainless steel components exposed to condensation. The staff also
 
verified that these programs include periodic visual inspections and NDE techniques to
 
manage loss of component material and confirm that their intended function is not
 
affected. This approach is consistent with the GALL Report and is, therefore, acceptable.  (6) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in copper alloy fire protection system piping, piping components, and piping elements
 
exposed to internal condensation, stating that at IP, there are no copper alloy
 
components exposed to condensation in the fire protection systems. However, this item
 
can be applied to copper alloy components exposed to internal condensation in other
 
systems. The Periodic Surveillance and Preventive Maintenance Program will manage
 
loss of material in copper alloy components exposed internally to condensation, through
 
the use of periodic visual inspections or other NDE techniques.
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.By letter dated June 12, 2009, the applicant amended its LRA to state that copper alloy
>15% Zn heat exchanger tubes that are internally exposed to condensation have the
 
aging effect of loss of material in the Instrument Air System. For these AMR line items
 
the applicant proposed the Periodic Surveillance and Preventive Maintenance Program.
 
In the same letter the applicant amended its LRA to state that copper alloy tubing and
 
valve bodies that are internally exposed to condensation have the aging effect of loss of
 
material in the IP1 Station Air System. For these AMR line items the applicant proposed 3-368 the Periodic Surveillance and Preventive Maintenance Program.
The staff confirmed that there are no copper alloy components exposed to condensation in the fire protection systems and that loss of material due to pitting and crevice
 
corrosion in copper alloy components of other systems that are exposed to internal
 
condensation is adequately managed by the Periodic Surveillance and Preventive
 
Maintenance Program which includes periodic visual inspections and NDE techniques to
 
manage loss of component material and confirm that the intended function of
 
components is not affected. This approach is consistent with the GALL Report and is, therefore, acceptable.  (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, stating
 
that this aging effect is not applicable because at IP, there are no stainless steel piping
 
components exposed to soil in the auxiliary 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.
The staff verified that there are no stainless steel piping components exposed to soil in the auxiliary systems. This item is not applicable to IP.    (8) 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 of the BWR Standby
 
Liquid Control System that are exposed to sodium pentaborate solution, stating that this
 
aging effect is not applicable to IP, which are PWRs.
SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice corrosion may occur in stainless steel piping, piping components, and piping elements of
 
the BWR standby liquid control system exposed to sodium pentaborate solution.
IP2 and IP3 are PWRs and do not have Standby Liquid Control Systems. The staff agrees that this item is not applicable to IP.
Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.10 criteria. For those line items that apply to LRA Section 3.3.2.2.10, the staff determines that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3).
3.3.2.2.11  Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion
 
The staff reviewed LRA Section 3.3.2.2.11 against the criteria in SRP-LR Section 3.3.2.2.11.
 
LRA Section 3.3.2.2.11 addresses loss of material in copper alloy auxiliary system components exposed to a BWR treated water environment, stating that this aging effect is not applicable to
 
IP, which are PWRs.
3-369 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.
This item pertains to loss of material in copper alloy auxiliary system components exposed to a BWR treated water environment. IP2 and IP3 are PWRs. The staff agrees that this item is not
 
applicable to IP.
Based on the above, the staff concludes that SRP-LR Section 3.3.2.2.11 criteria do not apply.
 
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 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 and crevice corrosion, and MIC in stainless steel and copper alloy piping and components exposed to fuel oil, stating that the Diesel Fuel Monitoring Program manages this aging effect for most of
 
these components. There are no aluminum components exposed to fuel oil in the
 
auxiliary systems. The Diesel Fuel Monitoring Program samples and monitors fuel oil
 
quality for whether it remains within the limits specified by ASTM standards. Maintaining
 
parameters within limits prevents significant loss of material. The One-Time Inspection
 
Program will use visual inspections or NDEs of representative samples to confirm the
 
effectiveness of the Diesel Fuel Monitoring Program in managing aging effects for
 
components that credit it. The Periodic Surveillance and Preventive Maintenance
 
Program will manage loss of material for the stainless steel components of the
 
emergency fuel oil trailer transfer tank by periodic visual inspections.
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 confirmed that there are no aluminum components exposed to fuel oil in the auxiliary systems. In addition, the staff verified that the loss of material due to pitting and
 
crevice corrosion, and MIC in stainless steel and copper alloy piping, piping
 
components, and piping elements exposed to fuel oil is managed by the Diesel Fuel
 
Monitoring Program and that the program includes sampling and monitoring of fuel oil to
 
ensure it remains within limits specified in ASTM standards. In addition, the staff
 
confirmed that the effectiveness of the Diesel Fuel Monitoring Program will be verified by
 
the One Time Inspection Program, which includes measures to confirm that loss of
 
material is not occurring and that component intended functions will be maintained
 
during the period of extended operation. For the stainless steel components of the 3-370 emergency fuel oil trailer transfer tank, loss of material will be managed by periodic visual inspections performed in accordance with the Periodic Surveillance and
 
Preventive Maintenance Program. This approach is consistent with the GALL Report
 
and is, therefore, acceptable.  (2) LRA Section 3.3.2.2.12 addresses loss of material due to pitting and crevice corrosion, and MIC in most stainless steel piping and components exposed to lubricating oil, stating that the Oil Analysis Program manages this aging effect by periodic sampling and
 
analysis of lubricating oil to maintain contaminants within acceptable limits and preserve
 
an environment not conducive to corrosion. The One-Time Inspection Program will use
 
visual inspections or NDEs of representative samples to confirm the effectiveness of the
 
Oil Analysis Program in managing aging effects for components that credit it. Stainless
 
steel piping components of the reactor coolant pump oil collection system are not
 
exposed continuously to a lubricating oil environment maintained by the Oil Analysis
 
Program and do not credit it for managing loss of material. Instead the One-Time
 
Inspection Program manages these components by using visual or volumetric NDE
 
techniques to inspect a representative sample of the internal surfaces for significant
 
corrosion.
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 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 confirmed that loss of material due to pitting, crevice, and MIC in most stainless steel piping and components exposed to lubricating oil is managed by the Oil Analysis
 
Program which includes periodic sampling and analysis of lubricating oil to maintain
 
contaminants within acceptable limits. In addition, the staff confirmed that the
 
effectiveness of the Oil Analysis Program will be verified by the One Time Inspection
 
Program, which includes measures to confirm that loss of material is not occurring and
 
that component intended functions will be maintained during the period of extended
 
operation.
Since stainless steel piping components of the reactor coolant pump oil collection system are not continuously exposed to a lubricating oil environment the Oil Analysis
 
Program is not credited to manage the effects of aging. For these components, the staff
 
verified that the absence of significant corrosion will be confirmed by the One-Time
 
Inspection Program which includes NDE techniques to inspect a representative sample
 
of the internal surfaces.
Based on the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.3.2.2.12 criteria. For those line items that apply to LRA Section 3.3.2.2.12, 3-371 the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3).
3.3.2.2.13  Loss of Material Due to Wear
 
The staff reviewed LRA Section 3.3.2.2.13 against the criteria in SRP-LR Section 3.3.2.2.13.
 
LRA Section 3.3.2.2.13 addresses loss of material due to wear in the elastomer seals and components exposed to air - indoor uncontrolled (internal or external), stating that this aging
 
effect is not applicable because at IP, in the auxiliary systems, the expansion joints are fixed at
 
both ends and do not contact any other components such that wear could occur.
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.
The staff confirmed that expansion joints in the auxiliary system are fixed at both ends and do not contact any other components. Because of this configuration, the staff agrees that that wear
 
in the elastomer seals can not occur. However, change in material properties and cracking of
 
elastomer components are managed by the Periodic Surveillance and Preventive Maintenance
 
Program. Since wear can not occur, loss of material due to wear in the elastomer seals is not
 
applicable to IP auxiliary systems.
Based on the above, the staff concludes that SRP-LR Section 3.3.2.2.13 criteria do not apply.
 
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 cracking due to underclad cracking in PWR steel charging pump casings with stainless steel cladding exposed to treated borated water, stating that this
 
aging effect is not applicable because the charging pump casings are not clad but made of
 
stainless steel.
SRP-LR Section 3.3.2.2.14 states that loss of material due to cladding breach (also referred to as underclad cracking may occur in PWR steel charging pump casings with stainless steel
 
cladding exposed to treated borated water. The GALL Report references IN 94-63 and
 
recommends further evaluation of a plant-specific AMP to ensure that the aging effect is
 
adequately managed.
The staff confirmed that the charging pump casings at IP are made of stainless steel and are not clad. This item is not applicable to IP.
Based on the above, the staff concludes that SRP-LR Section 3.3.2.2.14 criteria do not apply.
 
3.3.2.2.15  Quality Assurance for Aging Management of Nonsafety-Related Components SER Section 3.0.4 documents the staffs evaluation of the applicants QA program.
3-3723.3A.2.3  AMR Results Not Consistent with or Not Addressed in the GALL Report In LRA Tables 3.3.2-1-IP2 through 3.3.2-18-IP2 and 3.3.2-19-1-IP2 through 3.3.2-19-44-IP2, 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-IP2 through 3.3.2-18-IP2 and 3.3.2-19-1-IP2 through 3.3.2-19-44-IP2, the applicant indicated, via Notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant
 
provided further information about how it will manage the aging effects. Specifically, note F
 
indicates that the material for the AMR line item component is not evaluated in the GALL
 
Report. Note G indicates that the environment for the AMR line item component and material is
 
not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line item
 
component, material, and environment combination is not evaluated in the GALL Report. Note I
 
indicates that the aging effect identified in the GALL Report for the line item component, material, and environment combination is not applicable. Note J indicates that neither the
 
component nor the material and environment combination for the line item is evaluated in the
 
GALL Report.
For component type, material, and environment combinations not evaluated in the GALL Report, the staff reviewed the applicants evaluation to determine whether the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB for the period of extended operation. The
 
staffs evaluation is documented in the following sections. 3.3A.2.3.1 Service Water System - Summary of Aging Management Review -
LRA Table 3.3.2-2-IP2 The staff reviewed LRA Table 3.3.2-2-IP2, which summarizes the results of AMR evaluations for the service water system component groups.
The LRA table referenced Note F for titanium material used in heat exchanger shells and tubes internally and externally exposed to raw water are subject to cracking, fouling, and loss of
 
material which are managed by the Service Water Integrity Program. The staffs review of the
 
Service Water Integrity Program is documented in SER Section 3.0.3.1.14. Titanium
 
components are not addressed in the GALL Report. However, as stated in the Metals Handbook
 
Desk Edition, copyright 1985, by the American Society for Metals, titanium is a corrosion
 
resistant material; therefore, the applicant is conservative in addressing the aging effects of
 
concern for titanium heat exchanger components. The Service Water Integrity Program inspects
 
components for erosion, corrosion, and biofouling to confirm the heat transfer capability of
 
safety-related heat exchangers cooled by service water. Chemical treatment with biocides and
 
sodium hypochlorite and periodic cleaning and flushing of loops infrequently used are methods
 
for controlling fouling within the heat exchangers and managing loss of material in service water
 
components.
On the basis of its review, including the applicants plant-specific operating experience, the staff finds that the aging effects of cracking, fouling, and loss of material of titanium material used in
 
heat exchanger shells and tubes exposed to raw water will be adequately managed by the
 
Service Water Integrity Program.
3-373 The LRA table also referenced Note F for titanium heat exchanger tubes externally exposed to treated water with loss of material as the aging effect, and Water Chemistry Control - Primary
 
and Secondary Program as the AMP. The staffs evaluation of this program is documented in
 
SER Section 3.0.3.2.17. The program includes periodic monitoring and control of known
 
detrimental contaminants such as chlorides, fluorides, dissolved oxygen, and sulfate
 
concentrations below the levels known to result in loss of material or cracking. Water chemistry
 
control is in accordance with industry guidelines such as EPRI TR-105714 for primary water
 
chemistry, and EPRI TR-102134 for secondary water chemistry. The One-Time Inspection Program for Water Chemistry utilizes inspections or NDEs of representative samples to verify
 
that the Water Chemistry Control - Primary and Secondary Program has been effective at
 
managing aging effects. Because chemistry will be monitored, and the One-Time Inspection
 
Program will verify the effectiveness of the water chemistry control, the staff finds the applicants
 
AMR results for this material/environment combination acceptable.
The LRA table referenced Note F for titanium heat exchanger shell externally exposed to condensation with no aging effect and no AMP. The staff notes that in LRA Table 3.3.2-9-IP2, the applicant uses Note F for the same material/environment combination, but cites an aging
 
effect of loss of material and states that it will be managed by the Periodic Surveillance and
 
Preventive Maintenance Program. This appears to be a discrepancy. This was identified as
 
Open Item 3.3-1.
By letter dated January 27, 2009, the applicant stated that LRA Table 3.3.2-2-IP2 is correct for the titanium heat exchanger shell externally exposed to condensation with no aging effect and
 
no AMP, and that LRA Table 3.3.2-9-IP2 was corrected to be consistent with Table 3.3.2-2-IP2.
 
According to the Metals Handbook Desk Edition, copyright 1985, by the American Society for
 
Metals, titanium is extremely resistant to corrosion in many aggressive environments. The
 
Metals Handbook also states that resistance to general corrosion has been ascribed to a thin, inert film that forms rapidly on the surface when titanium is exposed to air and to passive films
 
that form on the surface in certain aggressive media. Because titanium is a highly corrosion
 
resistant material, and the environment (condensation) is not corrosive or aggressive, the staff
 
finds the applicants AMR results to be acceptable. Thus, Open Item 3.3-1, with respect to the
 
different aging effects for the same environment, is closed.
The LRA table referenced Note G for nickel alloy valve bodies externally exposed to condensation having an aging effect of loss of material and using the External Surfaces
 
Monitoring Program to manage the effects of aging. SER Section 3.0.3.2.5 documents the
 
staffs review of the External Surfaces Monitoring Program. While the GALL Report does not
 
contain this specific material/environment combination, a similar material/environment
 
combinations exists in GALL Report with loss of material as the aging effect that use the
 
External Surfaces Monitoring AMP to manage the effects of aging (e.g., GALL Report Tables
 
V.C, V.E, and VII.I, Line items V.C-2, V.E-10, VII.I-11, respectively). The External Surfaces
 
Monitoring Program manages aging effects through visual inspection of external surfaces for
 
evidence of material loss. Because periodic inspections of the external surfaces of the valve
 
bodies will be performed, the staff finds the applicants AMR results acceptable.
The LRA table referenced Note H for copper alloy >15 percent zinc (inhibited) heat exchanger tubes exposed to treated water (external) with an aging effect of loss of material-wear managed
 
by the Service Water Integrity Program. As noted above, the program includes component
 
inspections for erosion, corrosion, and biofouling to verify the heat transfer capability of safety-3-374 related heat exchangers cooled by service water. Because the heat exchanger tubes will be periodically inspected for loss of material, the staff finds the applicants AMR results 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 functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.3A.2.3.2 Component Cooling Water System - Summary of Aging Management Review -
LRA Table 3.3.2-3-IP2 The staff reviewed LRA Table 3.3.2-3-IP2, which summarizes the results of AMR evaluations for the component cooling water system component groups.
The LRA table referenced Note F for aluminum bronze material used in a heat exchanger tubesheet Internally exposed to raw water and externally exposed to treated water with the
 
aging effect being loss of material. The AMPs for the raw water environment are the Selective
 
Leaching and Service Water Integrity Programs, and the AMPs for the treated water
 
environment are the Selective Leaching and the Water Chemistry Control-Closed Cooling Water
 
Programs. The staffs review of these programs is documented in SER Sections 3.0.3.1.13 (Selective Leaching Program), 3.0.3.1.14 (Service Water Integrity Program), and 3.0.3.2.16 (Water Chemistry Control-Closed Cooling Water Program).
Loss of material in both environments will be managed by the Selective Leaching Program which will include a one-time visual inspection, hardness measurement (where feasible based
 
on form and configuration) or other industry-accepted mechanical inspection techniques of
 
selected components that may be susceptible to selective leaching to determine whether loss of
 
material due to selective leaching has occurred and whether the process will affect component
 
ability to perform intended functions through the period of extended operation.
The Service Water Integrity Program will also manage the loss of material for the raw water (internal) environment. The Service Water Integrity Program inspects components for erosion, corrosion, and biofouling to confirm the heat transfer capability of safety-related heat
 
exchangers cooled by service water. Chemical treatment with biocides and sodium hypochlorite
 
and periodic cleaning and flushing of loops infrequently used are methods for controlling fouling
 
within the heat exchangers and managing loss of material in service water components.
The GALL Report does not address components made of aluminum bronze material specifically. However, in Table IX.C of the GALL Report, aluminum bronze material is addressed in the discussion of copper alloy components. Table IX.C states that aluminum
 
bronze < 8 percent aluminum components are resistant to SCC, selective leaching and pitting
 
and crevice corrosion, and aluminum bronze components > 8 percent aluminum may be
 
susceptible to the aforementioned aging effects. The applicant conservatively assumed that the
 
aluminum bronze contains > 8 percent aluminum, which implies that SCC is a potential aging
 
effect.The Water Chemistry Control-Closed Cooling Water Program will manage the loss of material for the treated water (external) environment as well as SCC.The Water Chemistry Control -
 
Closed Cooling Water Program includes preventive measures that manage loss of material, 3-375 cracking, or fouling for components in closed cooling water systems. This program also includes performance of periodic visual inspections which are capable of detecting SCC.
The staff finds that the applicants AMR results for aluminum bronze material credit appropriate AERMs and AMPs. The staffs review of the referenced AMPs has verified that the aging effect
 
identified will be adequately managed so that the intended functions will be maintained
 
consistent with the CLB for the period of extended operation and is therefore acceptable.
The LRA table referenced Note H for heat exchanger (tubes) constructed from copper alloy >15 percent zinc (inhibited) exposed to treated water (external) having the aging effect loss of
 
material-wear that is managed by the Heat Exchanger Monitoring and the Service Water
 
Integrity AMPs. The aging effect identified in the GALL Report for this material/environment is
 
loss of material, which is addressed by another line item in LRA Table 3.3.2-3-IP2. The aging
 
effect identified in the LRA is in addition to that prescribed by the GALL Report. The Heat
 
Exchanger Monitoring Program uses visual or other NDE techniques to inspect heat exchangers
 
for loss of material. The Service Water Integrity Program inspects components for erosion, corrosion, and biofouling to confirm the heat transfer capability of safety-related heat exchangers cooled by service water. Chemical treatment with biocides and sodium hypochlorite
 
and periodic cleaning and flushing of loops infrequently used are methods for controlling fouling
 
within the heat exchangers and managing loss of material in SW components. The staffs review
 
of the referenced AMPs has verified that the aging effect identified will be adequately managed
 
so that the intended functions will be maintained consistent with the CLB for the period of
 
extended operation and is therefore acceptable.
The LRA table referenced Note H for stainless steel heat exchanger (tubes) exposed to treated water (external) with an aging effect of loss of material-wear that is managed by the Heat
 
Exchanger Monitoring Program. The aging effect identified in the GALL Report for this
 
material/environment is loss of material, which is addressed by another line item in LRA
 
Table 3.3.2-3-IP2. The aging effect identified in the LRA is in addition to that prescribed by the
 
GALL Report. The Heat Exchanger Monitoring Program uses visual or other NDE techniques to
 
inspect heat exchangers for loss of material. The staffs review of the referenced AMP has
 
verified that the aging effect identified will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB for the period of extended operation and is
 
therefore acceptable.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL
 
Report. The staff finds that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.3A.2.3.3 Chemical and Volume Control System - Summary of Aging Management Review
- LRA Table 3.3.2-6-IP2 The staff reviewed LRA Table 3.3.2-6-IP2, which summarizes the results of AMR evaluations for the chemical and volume control system component groups.
The LRA table referenced Note H for heat exchanger (tubes) constructed from copper alloy externally exposed to lube oil and stainless steel externally exposed to treated water, with an
 
aging effect of loss of material-wear managed by the Heat Exchanger Monitoring AMP. The 3-376 aging effect identified in the LRA is in addition to that prescribed by the GALL Report. The staffs evaluation of the Heat Exchanger Monitoring Program is documented in SER Section
 
3.0.3.3.3. This program uses visual inspections or other NDE techniques of heat exchangers for
 
loss of material. Because the heat exchanger tubes will be periodically inspected for loss of
 
material, the staff finds the applicants AMR results 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 functions will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.3A.2.3.4 Primary Makeup Water System - Summary of Aging Management Review -
LRA Table 3.3.2-7-IP2 The staff reviewed LRA Table 3.3.2-7-IP2, which summarizes the results of AMR evaluations for the primary makeup water system component groups.
The applicant referenced Note G for the stainless steel bolting exposed to outdoor air (external) with the aging effect of loss of material with}}

Latest revision as of 09:24, 14 January 2025

Lr Hearing - IP Final SER
ML092530506
Person / Time
Site: Indian Point  Entergy icon.png
Issue date: 08/12/2009
From:
Office of Nuclear Reactor Regulation
To:
Division of License Renewal
References
Download: ML092530506 (934)
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